Federal Register Vol. 81, No.68,
Federal Register Volume 81, Issue 68 (April 8, 2016)
Federal Register Volume 81, Issue 68 (April 8, 2016)
| Page Range | 20523-21221 | |
| FR Document |
Document Created: 2015-12-31 23:05:02
Document Modified: 2015-12-31 23:05:02
| Page and Subject | |
|---|---|
| 81 FR 20672 - Notice of Rescheduled Public Meetings for the Draft Programmatic Environmental Impact Statement for the Outer Continental Shelf (OCS) Oil and Gas Leasing Program: 2017-2022 | |
| 81 FR 20720 - Open Meeting of the Taxpayer Advocacy Panel Tax Forms and Publications Project Committee | |
| 81 FR 20672 - Government in the Sunshine Act Meeting Notice | |
| 81 FR 20525 - Importation of Fresh Andean Blackberry and Raspberry Fruit From Ecuador Into the Continental United States | |
| 81 FR 20528 - Importation of Fresh Peppers From Ecuador Into the United States | |
| 81 FR 20575 - Importation of Fresh Pitahaya Fruit From Ecuador Into the Continental United States | |
| 81 FR 20669 - Notice of Realty Action: Recreation and Public Purposes Act Classification of Public Lands in Uinta County, WY | |
| 81 FR 20667 - Notice of Realty Action: Classification for Lease and Subsequent Conveyance for Recreation and Public Purposes of Public Lands (N-94234) for a Park in the Southwest Portion of the Las Vegas Valley, Clark County, NV | |
| 81 FR 20606 - National Advisory Committee for Implementation of the National Forest System Land Management Planning Rule | |
| 81 FR 20591 - Texas Regulatory Program | |
| 81 FR 20617 - National Advisory Committee | |
| 81 FR 20616 - National Advisory Committee on Racial, Ethnic and Other Populations | |
| 81 FR 20598 - Approval and Promulgation of Air Quality Implementation Plans; Pennsylvania; Measurement and Reporting of Condensable Particulate Matter Emissions | |
| 81 FR 20633 - Flubendiamide; Notice of Intent To Cancel Pesticide Registrations | |
| 81 FR 20616 - Census Scientific Advisory Committee | |
| 81 FR 20543 - Air Plan Approval and Designation of Areas; MS; Redesignation of the DeSoto County, 2008 8-Hour Ozone Nonattainment Area to Attainment | |
| 81 FR 20535 - Trichloroethylene; Significant New Use Rule | |
| 81 FR 20606 - Black Hills National Forest Advisory Board | |
| 81 FR 20651 - Meeting Notice for the President's Advisory Council on Faith-Based and Neighborhood Partnerships | |
| 81 FR 20606 - Public Quarterly Meeting of the Board of Directors | |
| 81 FR 20619 - Circular Welded Carbon-Quality Steel Pipe From Pakistan: Preliminary Affirmative Countervailing Duty Determination and Alignment of Final Countervailing Duty Determination With Final Antidumping Duty Determination | |
| 81 FR 20639 - Submission for OMB Review; Contractor Information Worksheet; GSA Form 850 | |
| 81 FR 20638 - Information Collection; General Services Administration Acquisition Regulation; Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery (GSA) | |
| 81 FR 20617 - Notification of Proposed Production Activity; Max Home, LLC; Subzone 158F (Upholstered Furniture); Iuka and Fulton, Mississippi | |
| 81 FR 20618 - Diamond Sawblades and Parts Thereof From the People's Republic of China: Final Results of Antidumping Duty Changed Circumstances Review | |
| 81 FR 20674 - Notice of Lodging of Proposed Consent Decree Second Modification Under The Clean Water Act | |
| 81 FR 20633 - ENVIRONMENTAL IMPACT STATEMENTS; NOTICE OF AVAILABILITY | |
| 81 FR 20545 - Fluazinam; Pesticide Tolerances | |
| 81 FR 20675 - Notice of Public Comment Period on the Presentation of the Forensic Science Discipline Review Framework | |
| 81 FR 20633 - Certain New Chemicals; Receipt and Status Information for February 2016 | |
| 81 FR 20651 - Office of the National Coordinator for Health Information Technology; Medicare Access and CHIP Reauthorization Act of 2015; Request for Information Regarding Assessing Interoperability for MACRA | |
| 81 FR 20693 - Submission for OMB Review; Comments Request | |
| 81 FR 20719 - Meeting of the Council on Underserved Communities Advisory Board | |
| 81 FR 20627 - Notice of Availability of Record of Decision for the Final Environmental Impact Statement for Military Readiness Activities at the Naval Weapons Systems Training Facility Boardman, Oregon | |
| 81 FR 20622 - Mid-Atlantic Fishery Management Council (MAFMC); Public Meetings | |
| 81 FR 20623 - Pacific Fishery Management Council; Public Meeting | |
| 81 FR 20720 - List of Countries Requiring Cooperation With an International Boycott | |
| 81 FR 20529 - Drawbridge Operation Regulation; Annisquam River and Blynman Canal, Gloucester, MA | |
| 81 FR 20582 - Proposed Modification of the San Diego, CA, Class B Airspace Area; Public Meetings | |
| 81 FR 20688 - Virgil C. Summer Nuclear Station, Units 2 and 3 South Carolina Electric & Gas Company; Control Rod Drive Mechanism Motor Generator Set Field Relay Change | |
| 81 FR 20690 - Vogtle Electric Generating Plant Units 3 and 4; Southern Nuclear Operating Company, Inc. Georgia Power Company, Oglethorpe Power Corporation, MEAG Power SPVM, LLC., MEAG Power SPVJ, LLC., MEAG Power SPVP, LLC., and the City of Dalton, Georgia | |
| 81 FR 20528 - Energy Conservation Program: Test Procedures for Commercial Clothes Washers; Correction | |
| 81 FR 20626 - Defense Science Board; Notice of Federal Advisory Committee Meeting | |
| 81 FR 20671 - Notice of Availability of the Draft Environmental Impact Statement for the Enefit American Oil Utility Corridor Project, Uintah County, Utah | |
| 81 FR 20550 - List of Fisheries for 2016 | |
| 81 FR 20625 - Threat Reduction Advisory Committee; Notice of Closed Federal Advisory Committee Meeting | |
| 81 FR 20719 - Renewal of the Regional Resource Stewardship Council Charter | |
| 81 FR 20649 - Agency Information Collection Activities: Submission to OMB for Review and Approval; Public Comment Request | |
| 81 FR 20719 - Meeting of the Regional Resource Stewardship Council | |
| 81 FR 20615 - Notice of Public Meeting of the Texas State Advisory Committee | |
| 81 FR 20673 - Agency Information Collection Activities; Proposed eCollection eComments Requested; Financial Capability Form | |
| 81 FR 20643 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
| 81 FR 20624 - Procurement List Deletions | |
| 81 FR 20637 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
| 81 FR 20638 - Formations of, Acquisitions by, and Mergers of Savings and Loan Holding Companies | |
| 81 FR 20624 - Procurement List Proposed Addition and Deletions | |
| 81 FR 20656 - National Institute of Dental & Craniofacial Research; Notice of Closed Meeting | |
| 81 FR 20658 - Cooperative Research and Development Agreement (CRADA) Opportunity for Development of an Assay To Detect Genetic Markers Related to Elevated Serum Tryptase in Familial Tryptasemia and Mast Cell Activation Disorders | |
| 81 FR 20657 - National Institute of Allergy and Infectious Diseases; Notice of Closed Meeting | |
| 81 FR 20657 - Center for Scientific Review; Notice of Closed Meetings | |
| 81 FR 20658 - Prospective Grant of Start-up Exclusive License: Therapeutics and PMA-Approved Diagnostics for Alzheimer's Disease (intranasal delivery), Parkinson's Disease, Neuropathy,Neuropathic Pain, Peripheral Neuropathy, Diabetic Neuropathy, Neurapraxia, Axonotmesis and Neurotmesis | |
| 81 FR 20655 - Office of the Director, National Institutes of Health; Notice of Meeting | |
| 81 FR 20657 - National Institute of Mental Health; Notice of Closed Meetings | |
| 81 FR 20659 - National Institute of Environmental Health Sciences; Notice of Closed Meeting | |
| 81 FR 20678 - Data Users Advisory Committee; Notice of Meeting and Agenda | |
| 81 FR 20674 - Agency Information Collection Activities; Proposed eCollection eComments Requested | |
| 81 FR 20647 - Submission for OMB Review; Comment Request | |
| 81 FR 20688 - Notice of Intent To Seek Approval To Extend a Current Information Collection | |
| 81 FR 20637 - Agency Information Collection Activities: Comment Request | |
| 81 FR 20676 - Agency Information Collection Activities; Proposed eCollection eComments Requested; Campus Program Grantee Needs and Progress Assessment Tool | |
| 81 FR 20677 - Agency Information Collection Activities; Proposed eCollection; eComments Requested; Renewal of a Currently Approved Collection: Office of Justice Programs' Community Partnership Grants Management System (GMS) | |
| 81 FR 20523 - Family and Medical Leave Act; Definition of Spouse | |
| 81 FR 20694 - Excepted Service | |
| 81 FR 20696 - Submission for Review: Application for Refund of Retirement Deductions (CSRS), SF 2802 and Current/Former Spouse's Notification of Application for Refund of Retirement Deductions Under the Civil Service Retirement System, SF 2802A, 3206-0128 | |
| 81 FR 20618 - Reporting for Calendar Year 2015 on Offsets Agreements Related to Sales of Defense Articles or Defense Services to Foreign Countries or Foreign Firms | |
| 81 FR 20583 - Certain Natural Gas and Electric Power Contracts | |
| 81 FR 20647 - Agency Information Collection Activities; Proposed Collection; Comment Request; Guidance for Industry on How To Submit Information in Electronic Format to the Center for Veterinary Medicine Using the Food and Drug Administration Electronic Submission Gateway | |
| 81 FR 20628 - Notice of Commission Staff Attendance | |
| 81 FR 20631 - Michigan Electric Transmission Company, LLC v. Midcontinent Independent System Operator, Inc. as Agent for Consumers Energy Company; Notice of Complaint | |
| 81 FR 20629 - Notice of Effectiveness of Exempt Wholesale Generator Status | |
| 81 FR 20628 - Combined Notice of Filings #1 | |
| 81 FR 20629 - Transcontinental Gas Pipe Line Company, LLC; Notice of Availability of the Environmental Assessment for the Proposed New York Bay Expansion Project | |
| 81 FR 20630 - Combined Notice of Filings | |
| 81 FR 20627 - Combined Notice of Filings | |
| 81 FR 20631 - Combined Notice of Filings #1 | |
| 81 FR 20626 - TRICARE Demonstration Project for the Philippines | |
| 81 FR 20622 - Notice of Availability of a Draft NOAA/NESDIS Commercial Space Activities Assessment Process | |
| 81 FR 20672 - Certain Surgical Stapler Devices and Components Thereof; Commission Decision Not To Review an Initial Determination Terminating the Investigation in Its Entirety Based on a Consent Order Stipulation and Proposed Consent Order; Issuance of Consent Order; Termination of Investigation | |
| 81 FR 20661 - Final Flood Hazard Determinations | |
| 81 FR 20699 - Madison ETF Trust and Madison ETF Advisers, LLC; Notice of Application | |
| 81 FR 20718 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Designation of a Longer Period for Commission Action on a Proposed Rule Change To List and Trade Shares of the JPMorgan Diversified Alternative ETF | |
| 81 FR 20697 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing of a Proposed Rule Change, as Modified by Amendment No. 2 Thereto, Relating to AIM Retained Orders | |
| 81 FR 20709 - Self-Regulatory Organizations; Bats BZX Exchange, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Changes in Connection With the Operation of the Exchange's Equity Options Platform | |
| 81 FR 20711 - Self-Regulatory Organizations; Bats EDGX Exchange, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Changes in Connection With the Operation of the Exchange's Equity Options Platform | |
| 81 FR 20716 - Self-Regulatory Organizations; Miami International Securities Exchange LLC; Notice of Filing of a Proposed Rule Change To Amend the Exchange's Amended and Restated By-Laws | |
| 81 FR 20714 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend FINRA Rule 6184 (Transactions in Exchange-Traded Managed Fund Shares (“NextShares”)) | |
| 81 FR 20614 - Rural Broadband Access Loans and Loan Guarantees Program | |
| 81 FR 20615 - Information Collection Activity; Comment Request | |
| 81 FR 20650 - National Advisory Council on Nurse Education and Practice; Notice of Meeting | |
| 81 FR 20530 - Update to Product Lists | |
| 81 FR 20656 - Office of the Director; Notice of Charter Renewal | |
| 81 FR 20656 - National Library of Medicine; Notice of Closed Meetings | |
| 81 FR 20659 - Submission for OMB Review; 30-Day Comment Request; The Framingham Heart Study (NHLBI) | |
| 81 FR 20524 - Supplemental Nutrition Assistance Program: Review of Major Changes in Program Design and Management Evaluation Systems; Approval of Information Collection Request | |
| 81 FR 20607 - Inviting Applications for Value-Added Producer Grants | |
| 81 FR 20673 - Pressure Sensitive Plastic Tape From Italy, Determination | |
| 81 FR 20668 - Notice of Intent To Prepare an Environmental Impact Statement for the Crescent Point Energy Utah Federal-Tribal Well Development Project, Duchesne and Uintah Counties, Utah | |
| 81 FR 20670 - Notice of Availability of the Final Programmatic Environmental Impact Statement To Evaluate the Use of Herbicides on Public Lands Administered by the Bureau of Land Management | |
| 81 FR 20642 - Common Formats for Reporting on Health Care Quality and Patient Safety | |
| 81 FR 20640 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
| 81 FR 20646 - Proposed Information Collection Activity; Comment Request | |
| 81 FR 20529 - Drawbridge Operation Regulation; North Landing River, Chesapeake, VA | |
| 81 FR 20666 - Endangered Species; Receipt of Applications for Permit | |
| 81 FR 20579 - Risk-Based Capital Guidelines: Implementation of Capital Requirements for Global Systemically Important Bank Holding Companies | |
| 81 FR 20678 - Rollins College; AmerenUE (Formerly Union Electric Company); and Outfront Media, LLC (Formerly Gannett Outdoor Companies, Operating as Outdoor Systems, Inc., Subsequently CBS Outdoor Systems, Inc.): Technical Amendment to, and Revocation of, Permanent Variances | |
| 81 FR 20680 - Nucor Steel Connecticut Incorporated; Grant of a Permanent Variance | |
| 81 FR 20592 - Safety Zones; Sector Upper Mississippi River Annual and Recurring Safety Zones Update | |
| 81 FR 20540 - Approval and Promulgation of Air Quality Implementation Plans; Pennsylvania; Attainment Plan and Base Year Inventory for the North Reading Area for the 2008 Lead National Ambient Air Quality Standards | |
| 81 FR 21208 - Amendments to Class Exemptions 75-1, 77-4, 80-83 and 83-1 | |
| 81 FR 21181 - Amendment to and Partial Revocation of Prohibited Transaction Exemption (PTE) 86-128 for Securities Transactions Involving Employee Benefit Plans and Broker-Dealers; Amendment to and Partial Revocation of PTE 75-1, Exemptions From Prohibitions Respecting Certain Classes of Transactions Involving Employee Benefits Plans and Certain Broker-Dealers, Reporting Dealers and Banks. | |
| 81 FR 21147 - Amendment to and Partial Revocation of Prohibited Transaction Exemption (PTE) 84-24 for Certain Transactions Involving Insurance Agents and Brokers, Pension Consultants, Insurance Companies, and Investment Company Principal Underwriters | |
| 81 FR 21139 - Amendment to Prohibited Transaction Exemption (PTE) 75-1, Part V, Exemptions From Prohibitions Respecting Certain Classes of Transactions Involving Employee Benefit Plans and Certain Broker-Dealers, Reporting Dealers and Banks | |
| 81 FR 21089 - Class Exemption for Principal Transactions in Certain Assets Between Investment Advice Fiduciaries and Employee Benefit Plans and IRAs | |
| 81 FR 21002 - Best Interest Contract Exemption | |
| 81 FR 20946 - Definition of the Term “Fiduciary”; Conflict of Interest Rule-Retirement Investment Advice | |
| 81 FR 20600 - Air Plan Approval; North Carolina; Prong 4-2008 Ozone, 2010 NO2, | |
| 81 FR 20665 - Federal Property Suitable as Facilities To Assist the Homeless | |
| 81 FR 20912 - Treatment of Certain Interests in Corporations as Stock or Indebtedness | |
| 81 FR 20858 - Inversions and Related Transactions | |
| 81 FR 20588 - Inversions and Related Transactions | |
| 81 FR 20587 - Partial Withdrawal of Proposed Application of Section 367 to a Section 351 Exchange Resulting From a Transaction Described in Section 304(a)(1); Partial Withdrawal of Proposed Guidance for Determining Stock Ownership | |
| 81 FR 20722 - Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines |
Issue
Animal and Plant Health Inspection Service
Food and Nutrition Service
Forest Service
Rural Business-Cooperative Service
Rural Utilities Service
Census Bureau
Foreign-Trade Zones Board
Industry and Security Bureau
International Trade Administration
National Oceanic and Atmospheric Administration
Navy Department
Federal Energy Regulatory Commission
Agency for Healthcare Research and Quality
Centers for Medicare & Medicaid Services
Children and Families Administration
Food and Drug Administration
Health Resources and Services Administration
National Institutes of Health
Coast Guard
Federal Emergency Management Agency
Fish and Wildlife Service
Land Management Bureau
Ocean Energy Management Bureau
Surface Mining Reclamation and Enforcement Office
Employee Benefits Security Administration
Labor Statistics Bureau
Occupational Safety and Health Administration
Federal Aviation Administration
Pipeline and Hazardous Materials Safety Administration
Internal Revenue Service
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
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U.S. Office of Personnel Management.
Final rule.
The U.S. Office of Personnel Management (OPM) is revising the definition of
This final rule is effective on May 9, 2016.
Kurt Springmann by email at
The U.S. Office of Personnel Management is issuing a final regulation that revises the definition of
Two Federal agencies administer regulations governing FMLA. The Department of Labor (DOL) issues regulations for title I of FMLA, which covers non-Federal employees and certain Federal employees not covered under title II. OPM issues regulations for title II of FMLA, which covers most Federal employees. Title II of FMLA directs OPM to prescribe regulations that are consistent, to the extent appropriate, with regulations prescribed by the Secretary of Labor to carry out title I of FMLA. (See 5 U.S.C. 6387.) DOL published its final regulations on the definition of
On June 26, 2013, the U.S. Supreme Court ruled in
On June 23, 2014, at 79 FR 35497, OPM published a notice of proposed rulemaking to change the definition of
The three commenters who opposed the change cited religious and traditional beliefs as reasons for adhering to a definition of marriage that applies only to opposite-sex couples. One supported equal benefits for same-sex couples, but did not agree with redefining marriage as other than between one man and one woman. Another maintained that the Government should not impose this change on States that had previously banned same-sex marriage. The change to the definition complies with the Supreme Court's ruling in
Six commenters urged OPM to maintain support for the
Two commenters asked that OPM consider amending the definition of
Three commenters noted that the phrase “in a same-sex or common law marriage” used in the definition of
One commenter said the Federal Government should take legislative action to meet the needs of working families excluded by FMLA because of the business-size threshold and employee tenure and hours-worked requirements. These exclusions do not apply to Federal employees covered by title II of FMLA and, regardless, legislation is outside the scope of the regulations. The same commenter expressed the need for paid family leave. FMLA does not authorize paid family leave; therefore, this comment is outside the scope of the regulations.
A Federal agency suggested adding “at the time of the marriage ceremony” in four places within the definition of
We made a minor editorial change to the definition of
The Office of Management and Budget has reviewed this rule in accordance with E.O. 13563 and 12866.
I certify that this regulation will not have a significant economic impact on a substantial number of small entities because it will apply only to Federal agencies and employees.
Government employees.
Accordingly, OPM amends 5 CFR part 630 as follows:
5 U.S.C. 6311; § 630.205 also issued under Pub. L. 108-411, 118 Stat 2312; § 630.301 also issued under Pub. L. 103-356, 108 Stat. 3410 and Pub. L. 108-411, 118 Stat 2312; § 630.303 also issued under 5 U.S.C. 6133(a); §§ 630.306 and 630.308 also issued under 5 U.S.C. 6304(d)(3), Pub. L. 102-484, 106 Stat. 2722, and Pub. L. 103-337, 108 Stat. 2663; subpart D also issued under Pub. L. 103-329, 108 Stat. 2423; § 630.501 and subpart F also issued under E.O. 11228, 30 FR 7739, 3 CFR, 1974 Comp., p. 163; subpart G also issued under 5 U.S.C. 6305; subpart H also issued under 5 U.S.C. 6326; subpart I also issued under 5 U.S.C. 6332, Pub. L. 100-566, 102 Stat. 2834, and Pub. L. 103-103, 107 Stat. 1022; subpart J also issued under 5 U.S.C. 6362, Pub. L 100-566, and Pub. L. 103-103; subpart K also issued under Pub. L. 105-18, 111 Stat. 158; subpart L also issued under 5 U.S.C. 6387 and Pub. L. 103-3, 107 Stat. 23; and subpart M also issued under 5 U.S.C. 6391 and Pub. L. 102-25, 105 Stat. 92.
(1) Was entered into in a State that recognizes such marriages, or
(2) If entered into outside of any State, is valid in the place where entered into and could have been entered into in at least one State.
Food and Nutrition Service, USDA.
Final rule; notice of approval of Information Collection Request (ICR).
The final rule entitled Supplemental Nutrition Assistance Program: Review of Major Changes in Program Design and Management Evaluation Systems was published on January 19, 2016. The Office of Management and Budget (OMB) cleared the associated information collection requirements (ICR) on March 10, 2016. This document announces approval of the ICR.
The ICR associated with the final rule published in the
Mary Rose Conroy, Chief, Program Design Branch, Program Development Division, Food and Nutrition Service, USDA, 3101 Park Center Drive, Alexandria, Virginia 22302, (703) 305-2803, or
The final rule entitled Supplemental Nutrition Assistance Program: Review of Major Changes in Program Design and Management Evaluation Systems was published on January 19, 2016. The Office of Management and Budget (OMB) cleared the associated information collection requirements (ICR) on March 10, 2016. This document announces approval of the ICR. The ICR for this rule approved the creation of a new information collection, which has been assigned the OMB Control Number 0584-0579.
Animal and Plant Health Inspection Service, USDA.
Final rule.
We are amending the fruits and vegetables regulations to allow the importation of fresh Andean blackberry and raspberry fruit from Ecuador into the continental United States. As a condition of entry, the fruit will have to be produced in accordance with a systems approach that includes requirements for importation in commercial consignments from a pest free production site within a certified low pest prevalence area for fruit flies, and pest monitoring and trapping. The fruit will also have to be accompanied by a phytosanitary certificate issued by the national plant protection organization of Ecuador bearing an additional declaration stating that the consignment was produced and prepared for export in accordance with the requirements of the systems approach. This action will allow for the importation of fresh Andean blackberry and raspberry fruit from Ecuador while continuing to provide protection against the introduction of quarantine pests into the continental United States.
Effective May 9, 2016.
Ms. Claudia Ferguson, M.S., Senior Regulatory Policy Specialist, Regulatory Coordination and Compliance, Imports, Regulations and Manuals, PPQ, APHIS, (301) 851-2352; email:
Under the regulations in “Subpart-Fruits and Vegetables” (7 CFR 319.56-1 through 319.56-74, referred to below as the regulations), the Animal and Plant Health Inspection Service (APHIS) of the U.S. Department of Agriculture prohibits or restricts the importation of fruits and vegetables into the United States from certain parts of the world to prevent plant pests from being introduced into and spread within the United States.
On April 24, 2015, we published in the
In the proposed rule, we noted that the PRA rated three plant pests as having a high pest risk potential for following the pathway of fresh Andean blackberry and raspberry fruit from Ecuador into the continental United States:
We determined in the PRA that measures beyond standard port of arrival inspection will adequately mitigate the risks posed by these plant pests and proposed a systems approach that includes requirements for importation in commercial consignments from a pest free production site within a certified low pest prevalence area for fruit flies, pest monitoring, and pest trapping. We also proposed that the fruit be imported in commercial consignments only and accompanied by a phytosanitary certificate issued by the national plant protection organization (NPPO) of Ecuador stating that the consignment was produced and prepared for export in accordance with the systems approach.
We solicited comments concerning our proposal for 60 days ending June 23, 2015. We received five comments during the comment period from members of the public and an employee of a foreign NPPO. The comments are discussed below.
Two commenters stated that the importation of fresh Andean blackberry and raspberry fruit into the continental United States should not be allowed due to the associated plant pest risk. One of these commenters added that production of blackberry and raspberry fruit in the United States, along with existing import agreements with other countries, renders importation of Andean blackberry and raspberry fruit from Ecuador unnecessary.
We are making no changes in response to these comments. Under the Plant Protection Act (7 U.S.C. 7701
One commenter stated that while the PRA lists Medfly as having a high pest risk potential for following the pathway of Andean blackberries and raspberries imported into the continental United States from Ecuador, the production site requirements we propose do not require mitigation for Medfly beyond standard commercial production and inspection. The commenter requested that we include an additional mitigation measure for Medfly and that we gradually reduce the requirements to commercial production and inspection only.
Another commenter observed that we currently do not require mitigations for Medfly beyond standard commercial production and inspection for raspberries imported from other countries with this pest, including Colombia, Costa Rica, El Salvador, France, Guatemala, Honduras, Nicaragua, and Panama. The commenter asked why no additional mitigations exist to prevent Medfly from following the pathway of raspberries imported into the continental United States from these countries and from Ecuador. The commenter stated that raspberries from all production sites in these countries should be inspected and undergo additional mitigation if they have the potential for bringing Medfly to the continental United States.
We respect the concerns of these commenters regarding the potential introduction of Medfly into the continental United States. However, as we noted in the RMD and the proposed rule, Andean blackberries and raspberries have been established in the scientific literature as being poor hosts for both Medfly and
We also noted in the proposed rule that a slightly stronger host status potential exists for
One commenter stated that requiring the production sites of Andean blackberry and raspberry fruit to be free of
We agree with the commenter that given the low temperature and high altitude, the areas in Ecuador in which blackberry and raspberry production sites are located are generally inhospitable to the establishment of
One commenter, concerned about potential economic impacts to raspberry and blackberry growers in the United States resulting from imports of Andean raspberry and blackberry from Ecuador, requested that we provide more data on the potential impact to these growers.
In the economic analysis accompanying this rule, we gathered and analyzed data sufficient to determine that this action will not have a significant economic impact on small domestic growers. Between 2008 and 2012, the United States imported 37.22 million pounds of fresh raspberries and between 2011 and 2013 imported 63 million pounds of fresh blackberries. Comparing the volume level of these imports with the proposed maximum level of imports from Ecuador, the Ecuadorian import share would be less than 0.4 percent of the U.S. import share for these fruits.
The same commenter asked what costs APHIS will incur in monitoring and auditing Ecuador's implementation of the systems approach.
APHIS conducts monitoring of production areas and trapping practices, audits of trap records, and other tasks necessary to ensure that the NPPO of Ecuador is implementing the systems approach. The costs of conducting these tasks are included in the APHIS budget.
The commenter also asked if the costs would be feasible for Ecuadorian blackberry and raspberry farmers and whether the regulation imposes burdens on these farmers.
Under Executive Order 12866 and the Regulatory Flexibility Act, we are required to analyze the potential regulatory and economic effects of this action on small entities within the United States. We therefore have not researched the economic effects of this action on Ecuadorian blackberry and raspberry farmers.
Therefore, for the reasons given in the proposed rule, we are adopting the proposed rule as a final rule, without change.
This final rule has been determined to be not significant for the purposes of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.
In accordance with the Regulatory Flexibility Act, we have analyzed the potential economic effects of this action on small entities. The analysis is summarized below. Copies of the full analysis are available by contacting the person listed under
The final rule will allow importation into the continental United States of fresh Andean blackberry (
The majority of U.S. raspberry and blackberry farms are in three States—California, Oregon, and Washington. They are classified within the North American Industry Classification System under “Berry except Strawberry Farming” (NAICS 111334). For this industry classification, a business is considered to be a small entity if its annual receipts are not more than $750,000. The average 2012 market value of crops sold by farms in this category was less than $135,000. We infer that most fresh raspberry and blackberry fruit production is by small entities.
Over the 5-year period 2008-2012, U.S. raspberry and blackberry production for the fresh market averaged about 96 million pounds and 4 million pounds per year, respectively, for a total of about 100 million pounds, or about 45,372 MT. Expected annual imports from Ecuador of less than 180 MT will be the equivalent of less than 0.4 percent of U.S. production.
Under these circumstances, the Administrator of the Animal and Plant Health Inspection Service has determined that this action will not have a significant economic impact on a substantial number of small entities.
This final rule allows fresh Andean blackberry and raspberry fruit to be imported into the continental United States from Ecuador. State and local laws and regulations regarding fresh Andean blackberry and raspberry fruit imported under this rule will be preempted while the fruit is in foreign commerce. Fresh fruits are generally imported for immediate distribution and sale to the consuming public, and remain in foreign commerce until sold to the ultimate consumer. The question of when foreign commerce ceases in other cases must be addressed on a case-by-case basis. No retroactive effect will be given to this rule, and this rule will not require administrative proceedings before parties may file suit in court challenging this rule.
In accordance with section 3507(d) of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
APHIS is committed to compliance with the E-Government Act to promote the use of the Internet and other information technologies, to provide increased opportunities for citizen access to Government information and services, and for other purposes. For information pertinent to E-Government Act compliance related to this rule, please contact Ms. Kimberly Hardy, APHIS' Information Collection Coordinator, at (301) 851-2727.
Coffee, Cotton, Fruits, Imports, Logs, Nursery stock, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Rice, Vegetables.
Accordingly, we are amending 7 CFR part 319 as follows:
7 U.S.C. 450, 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Andean blackberries (
(a)
(2) APHIS will be directly involved with the NPPO of Ecuador in monitoring and auditing implementation of the systems approach.
(3) Andean blackberry and raspberry fruit from Ecuador may be imported into the continental United States in commercial consignments only.
(b)
(2) All places of production that participate in the export program must be approved by and registered with the NPPO of Ecuador. APHIS reserves the right to conduct oversight visits in the event of pest interceptions or other problems.
(3) The NPPO of Ecuador or their designee must conduct a fruit fly trapping program for the detection of
(4) The NPPO of Ecuador must maintain records of trap placement, trap checks, and any captures of
(5) The NPPO of Ecuador must maintain a quality control program, approved by APHIS, to monitor or audit the trapping program in accordance with the operational workplan.
(c)
(2) While in use for exporting Andean blackberries and raspberries to the continental United States, the packinghouses may only accept fruit from registered production sites.
(3) If a single
(d)
Animal and Plant Health Inspection Service, USDA.
Final rule; technical amendment.
In a final rule published in the
Effective April 8, 2016.
Ms. Claudia Ferguson, M.S., Senior Regulatory Policy Specialist, Regulatory Coordination and Compliance, Imports, Regulations and Manuals, PPQ, APHIS, (301) 851-2352; email:
In a final rule
Coffee, Cotton, Fruits, Imports, Logs, Nursery stock, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Rice, Vegetables.
Accordingly, we are amending 7 CFR part 319 as follows:
7 U.S.C. 450, 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Final rule; correcting amendments.
The Department of Energy (DOE) published a final rule in the
This correction is effective April 8, 2016.
Bryan Berringer, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Program, EE-5B, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-0371. Email:
Jennifer Tiedeman, U.S. Department of Energy, Office of the General Counsel, GC-33, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 287-6111. Email:
Energy conservation standards for commercial clothes washers (CCWs) are codified at 10 CFR 431.156. Pursuant to 10 CFR 431.154, the test procedures for clothes washers at 10 CFR part 430, subpart B, appendix J1 must be used to test CCWs to determine compliance with the current energy conservation standards codified at 10 CFR 431.156(b).
DOE published a final rule on March 7, 2012, establishing a new test procedure for clothes washers at 10 CFR part 430, subpart B, appendix J2. 77 FR 13887.
DOE published another final rule on December 3, 2014, revising the test procedure provisions for CCWs at 10 CFR 431.154 to specify that the test procedures for clothes washers at appendix J2 must be used to determine compliance with any amended standards for CCWs based on appendix J2 efficiency metrics published after December 3, 2014. 79 FR 71624.
DOE then published a final rule on December 15, 2014, amending the energy conservation standards for CCWs, which are codified at 10 CFR 431.156(c). 79 FR 74492. These amended standards are based on appendix J2 efficiency metrics, and compliance with the amended standards is required beginning January 1, 2018.
This final rule correction (1) removes obsolete CCW standards listed at 10 CFR 431.156(a), (2) redesignates paragraphs (b) and (c) of 10 CFR 431.156 as paragraphs (a) and (b), and (3) amends the CCW test procedure provisions at 10
The regulatory reviews conducted for this rulemaking are those set forth in the December 3, 2014 final rule that originally codified amendments to DOE's test procedures for commercial clothes washers. 79 FR 71624. The amendments from that final rule became effective January 2, 2015.
Pursuant to the Administrative Procedure Act, 5 U.S.C. 553(b), DOE has determined that notice and prior opportunity for comment on this rule are unnecessary and contrary to the public interest. The amended CCW standards codified at 10 CFR 431.156(c) correspond to the “amended standards based on appendix J2 efficiency metrics published after December 3, 2014” referenced in 10 CFR 431.154. This correction is needed to ensure clarity regarding the amended CCW standards for which the appendix J2 test procedure must be used. This final rule also removes obsolete regulatory provisions.
Administrative practice and procedure, Energy conservation, Household appliances.
For the reasons stated in the preamble, DOE amends part 431 of chapter II, subchapter D, of title 10 of the Code of Federal Regulations, by making the following correcting amendments:
42 U.S.C. 6291-6317.
The test procedures for clothes washers in appendix J1 to subpart B of part 430 of this chapter must be used to test commercial clothes washers to determine compliance with the energy conservation standards at § 431.156(a). The test procedures for clothes washers in appendix J2 to subpart B of part 430 of this chapter must be used to determine compliance with the energy conservation standards at § 431.156(b).
Coast Guard, DHS.
Notice of deviation from drawbridge regulation.
The Coast Guard has issued a temporary deviation from the operating schedule that governs the Blynman (SR127) Bridge across the Annisquam River and Blynman Canal at mile 0.0 at Gloucester, MA. This deviation is necessary to facilitate public safety during a public event, the annual Saint Peter's Fiesta 5K Road Race. This deviation allows the bridge to remain closed for thirty minutes to facilitate public safety.
This deviation is effective from 6:15 p.m. to 6:45 p.m. on June 23, 2016.
The docket for this deviation, [USCG-2016-0275] is available at
If you have questions on this temporary deviation, call or email Mr. Jim Rousseau, First Coast Guard District Bridge Branch, Coast Guard; telephone 617-223-8619, email
The Blynman (SR 127) Bridge across the Annisquam River and Blynman Canal, mile 0.0, at Gloucester, Massachusetts, has a vertical clearance in the closed position of 8.2 feet at mean high water and 16 feet at mean low water. The existing bridge operating regulations are found at 33 CFR 117.586.
The owner of the bridge, Massachusetts Department of Transportation, requested a temporary deviation from the normal operating schedule to facilitate a public event, the Annual Saint Peter's Fiesta 5K Road Race.
Under this temporary deviation, the Blynman (SR 127) Bridge may remain in the closed position for thirty minutes between 6:15 p.m. and 6:45 p.m. on Thursday June 23, 2016.
The waterways are transited by commercial and seasonal recreational vessels of various sizes. There is an alternate route for vessel traffic around Cape Ann. Also, vessels that can pass under the closed draws during this closure may do so at all times.
The Coast Guard will inform the users of the waterways through our Local and Broadcast Notice to Mariners of the change in operating schedule for the bridge so that vessels can arrange their transits to minimize any impact caused by the temporary deviation.
In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the effective period of this temporary deviation. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Coast Guard, DHS.
Notice of temporary deviation from drawbridge regulations; modification.
The Coast Guard has modified a temporary deviation from the operating schedule that governs the S165 (North Landing Road) Bridge across the North Landing River, mile 20.2, at Chesapeake, VA. This modified deviation is necessary to perform emergency bridge repairs and provide for safe navigation.
This modified deviation is effective without actual notice from April 8, 2016 through 6 p.m. on June 30, 2016. For the purposes of enforcement, actual notice will be used from April 4, 2016, until April 8, 2016.
The docket for this deviation, [USCG-2016-0181] is available at
If you have questions on this modified temporary deviation, call or email Mr. Hal R. Pitts, Bridge Administration Branch Fifth District, Coast Guard, telephone 757-398-6222, email
On March 11, 2016, the Coast Guard published a temporary deviation entitled “Drawbridge Operation Regulation; North Landing River, Chesapeake, VA” in the
The United States Army Corps of Engineers, Norfolk District Office, who owns and operates the S165 (North Landing Road) Bridge, has requested a modified temporary deviation from the currently published deviation to perform additional repairs to the south swing span of the bridge due to damage sustained as a result of a vessel allision with the bridge.
Under this modified temporary deviation, the north span of the bridge will open-to-navigation on the hour and half hour, upon request, from 6 a.m. to 7 p.m., and on demand from 7 p.m. to 6 a.m. The north and south spans of the bridge will open to navigation concurrently, with the south span only opening partially due to damage, upon request, for: (1) Scheduled openings at 9:30 a.m. for vessels transiting southeast, (2) 10:30 a.m. for vessels transiting northwest, and (3) at noon and 2 p.m. for two-way vessel traffic through the bridge, Monday through Friday. The horizontal clearance of the bridge with the south span closed-to-navigation is 38 feet and the horizontal clearance of the bridge with the south span partially open-to-navigation is 70 feet. The modified temporary deviation is necessary to relieve vessel congestion and provide for safe navigation on the waterway. The bridge is a double swing draw bridge and has a vertical clearance in the closed position of 6 feet above mean high water.
The North Landing River is used by a variety of vessels including small U.S. government and public vessels, small commercial vessels, tug and barge, and recreational vessels. The Coast Guard has carefully considered the nature and volume of vessel traffic on the waterway in publishing this temporary deviation.
During the closure times there will be limited opportunity for vessels which are able to safely pass through the bridge in the closed position to do so. Vessels able to safely pass through the bridge in the closed position may do so, after receiving confirmation from the bridge tender that it is safe to transit through the bridge. The north span of the bridge will be able to open for emergencies. The Coast Guard will also inform the users of the waterways through our Local and Broadcast Notices to Mariners of the change in operating schedule for the bridge so that vessel operators can arrange their transit to minimize any impact caused by the temporary deviation.
In accordance with 33 CFR 117.35(e), the drawbridge must return to its regular operating schedule immediately at the end of the effective period of this temporary deviation. This deviation from the operating regulations is authorized under 33 CFR 117.35.
Postal Regulatory Commission.
Final rule.
The Commission is updating the product lists. This action reflects a publication policy adopted by Commission order. The referenced policy assumes periodic updates. The updates are identified in the body of this document. The product lists, which is re-published in its entirety, includes these updates.
David A. Trissell, General Counsel, at 202-789-6800.
This document identifies updates to the product lists, which appear as 39 CFR Appendix A to Subpart A of Part 3020—Mail Classification Schedule. Publication of the updated product lists in the
1. Priority Mail Contract 171 (MC2016-48 and CP2016-63) (Order No. 2977), added January 5, 2016.
2. Priority Mail Contract 170 (MC2016-47 and CP2016-62) (Order No. 2978), added January 5, 2016.
3. Priority Mail Contract 176 (MC2016-54 and CP2016-69) (Order No. 2981), added January 6, 2016.
4. Priority Mail Express Contract 31 (MC2016-61 and CP2016-76) (Order No. 2982), added January 6, 2016.
5. Priority Mail Express, Priority Mail & First-Class Package Service Contract 7 (MC2016-55 and CP2016-70) (Order No. 2983), added January 6, 2016.
6. Priority Mail Contract 177 (MC2016-57 and CP2016-72) (Order No. 2984), added January 6, 2016.
7. Priority Mail & First-Class Package Service Contract 11 (MC2016-62 and CP2016-77) (Order No. 2985), added January 6, 2016.
8. Priority Mail Contract 179 (MC2016-63 and CP2016-78) (Order No. 2986), added January 6, 2016.
9. Priority Mail Contract 180 (MC2016-64 and CP2016-79) (Order No. 2987), added January 6, 2016.
10. Priority Mail Contract 183 (MC2016-67 and CP2016-82) (Order No. 2988), added January 6, 2016.
11. Priority Mail & First-Class Package Service Contract 10 (MC2016-58 and CP2016-73) (Order No. 2989), added January 6, 2016.
12. Priority Mail Express & Priority Mail Contract 26 (MC2016-56 and CP2016-71) (Order No. 2990), added January 6, 2016.
13. Priority Mail Contract 175 (MC2016-53 and CP2016-68) (Order No. 2991), added January 6, 2016.
14. Priority Mail Contract 181 (MC2016-65 and CP2016-80) (Order No. 2992), added January 6, 2016.
15. Priority Mail Contract 178 (MC2016-60 and CP2016-75) (Order No. 2993), added January 6, 2016.
16. Priority Mail Express & Priority Mail Contract 27 (MC2016-59 and CP2016-74) (Order No. 2995), added January 6, 2016.
17. Priority Mail Contract 184 (MC2016-66 and CP2016-81) (Order No. 2996), added January 6, 2016.
18. Priority Mail Express, Priority Mail & First-Class Package Service Contract 8 (MC2016-72 and CP2016-87) (Order No. 2997), added January 7, 2016.
19. Priority Mail & First-Class Package Service Contract 12 (MC2016-70 and CP2016-85) (Order No. 2998), added January 7, 2016.
20. Priority Mail Contract 185 (MC2016-69 and CP2016-84) (Order No. 2999), added January 7, 2016.
21. Priority Mail Contract 186 (MC2016-71 and CP2016-86) (Order No. 3001), added January 7, 2016.
22. First-Class Package Service Contract 41 (MC2016-73 and CP2016-88) (Order No. 3002), added January 7, 2016.
23. Priority Mail Contract 182 (MC2016-68 and CP2016-83) (Order No. 3004), added January 7, 2016.
24. Priority Mail Contract 172 (MC2016-49 and CP2016-64) (Order No. 3006), added January 8, 2016.
25. First-Class Package Service Contract 40 (MC2016-51 and CP2016-66) (Order No. 3007), added January 8, 2016.
26. Priority Mail Contract 173 (MC2016-50 and CP2016-65) (Order No. 3009), added January 8, 2016.
27. First-Class Package Service Contract 42 (MC2016-74 and CP2016-91) (Order No. 3018), added January 12, 2016.
28. Parcel Select Contract 13 (MC2016-75 and CP2016-93) (Order No. 3023), added January 12, 2016.
29. Priority Mail & First-Class Package Service Contract 13 (MC2016-76 and CP2016-98) (Order No. 3067), added February 10, 2016.
30. Priority Mail Contract 165 (MC2016-39 and CP2016-48) (Order No. 3069), added February 12, 2016.
31. Priority Mail Contract 166 (MC2016-40 and CP2016-49) (Order No. 3070), added February 12, 2016.
32. Priority Mail Contract 167 (MC2016-41 and CP2016-50) (Order No. 3071), added February 12, 2016.
33. Priority Mail Contract 168 (MC2016-42 and CP2016-51) (Order No. 3072), added February 12, 2016.
34. Priority Mail Contract 169 (MC2016-43 and CP2016-52) (Order No. 3073), added February 12, 2016.
35. Priority Mail Contract 174 (MC2016-52 and CP2016-67) (Order No. 3074), added February 12, 2016.
36. Priority Mail Express, Priority Mail & First-Class Package Service Contract 9 (MC2016-78 and CP2016-103) (Order No. 3102), added February 26, 2016.
37. First-Class Package Service Contract 43 (MC2016-81 and CP2016-106) (Order No. 3110), added February 29, 2016.
38. Priority Mail Contract 188 (MC2016-80 and CP2016-105) (Order No. 3111), added February 29, 2016.
39. Priority Mail Contract 187 (MC2016-79 and CP2016-104) (Order No. 3112), added February 29, 2016.
40. Priority Mail Express Contract 32 (MC2016-77 and CP2016-102) (Order No. 3116), added February 29, 2016.
41. First-Class Package Service Contract 44 (MC2016-82 and CP2016-107) (Order No. 3120), added March 1, 2016.
42. Priority Mail Contract 189 (MC2016-83 and CP2016-108) (Order No. 3135), added March 8, 2016.
43. Priority Mail Express Contract 33 (MC2016-87 and CP2016-112) (Order No. 3136), added March 8, 2016.
44. Priority Mail Contract 190 (MC2016-84 and CP2016-109) (Order No. 3138), added March 8, 2016.
45. Priority Mail & First-Class Package Service Contract 14 (MC2016-88 and CP2016-113) (Order No. 3139), added March 8, 2016.
46. Priority Mail Contract 192 (MC2016-86 and CP2016-111) (Order No. 3140), added March 8, 2016.
47. Priority Mail Contract 191 (MC2016-85 and CP2016-110) (Order No. 3141), added March 8, 2016.
48. Priority Mail & First-Class Package Service Contract 15 (MC2016-89 and CP2016-114) (Order No. 3147), added March 10, 2016.
49. Priority Mail Contract 195 (MC2016-92 and CP2016-117) (Order No. 3152), added March 15, 2016.
50. Priority Mail Contract 193 (MC2016-90 and CP2016-115) (Order No. 3153), added March 15, 2016.
51. Priority Mail Contract 194 (MC2016-91 and CP2016-116) (Order No. 3154), added March 15, 2016.
52. Priority Mail Express Contract 34 (MC2016-93 and CP2016-118) (Order No. 3155), added March 15, 2016.
53. International Merchandise Return Service Agreements with Foreign Postal Operators Non-Published Rates 2 (MC2016-94 and CP2016-119) (Order No. 3160), added March 17, 2016.
54. Priority Mail Contract 196 (MC2016-95 and CP2016-120) (Order No. 3174), added March 22, 2016.
55. First-Class Package Service Contract 45 (MC2016-96 and CP2016-121) (Order No. 3176), added March 23, 2016.
56. Priority Mail Contract 199 (MC2016-100 and CP2016-128) (Order No. 3188), added March 29, 2016.
57. Global Expedited Package Services Contracts Non-Published Rates 10 (MC2016-97 and CP2016-122) (Order No. 3189), added March 29, 2016.
58. Priority Mail Contract 198 (MC2016-99 and CP2016-127) (Order No. 3191), added March 29, 2016.
59. First-Class Package Service Contract 46 (MC2016-103 and CP2016-131) (Order No. 3192), added March 29, 2016.
60. Priority Mail Contract 200 (MC2016-101 and CP2016-129) (Order No. 3194), added March 30, 2016.
61. Priority Mail Express & Priority Mail Contract 28 (MC2016-106 and CP2016-134) (Order No. 3195), added March 30, 2016.
62. First-Class Package Service Contract 47 (MC2016-104 and CP2016-132) (Order No. 3198), added March 30, 2016.
63. Priority Mail & First-Class Package Service Contract 16 (MC2016-105 and CP2016-133) (Order No. 3199), added March 30, 2016.
64. Parcel Select Contract 14 (MC2016-102 and CP2016-130) (Order No. 3200), added March 30, 2016.
65. Priority Mail Express Contract 35 (MC2016-107 and CP2016-135) (Order No. 3201), added March 30, 2016.
66. Priority Mail Contract 197 (MC2016-98 and CP2016-126) (Order No. 3202), added March 30, 2016.
The following negotiated service agreements have expired and are being deleted from the Mail Classification Schedule:
1. Priority Mail Contract 44 (MC2013-2 and CP2013-2) (Order No. 1508).
2. Express Mail & Priority Mail Contract 11 (MC2013-1 and CP2013-1) (Order No. 1509).
3. Priority Mail Contract 50 (MC2013-26 and CP2013-34) (Order No. 1608).
4. Priority Mail Contract 51 (MC2013-31 and CP2013-40) (Order No. 1632).
5. Express Mail Contract 13 (MC2013-32 and CP2013-41) (Order No. 1640).
6. Priority Mail Contract 52 (MC2013-35 and CP2013-46) (Order No. 1646).
7. Priority Mail Contract 53 (MC2013-36 and CP2013-47) (Order No. 1650).
8. Priority Mail Contract 54 (MC2013-37 and CP2013-48) (Order No. 1653).
9. Express Mail Contract 14 (MC2013-41 and CP2013-53) (Order No. 1673).
10. Priority Mail Contract 55 (MC2013-40 and CP2013-52) (Order No. 1675).
11. Priority Mail Contract 48 (MC2013-16 and CP2013-15) (Order No. 1548).
12. Express Mail Contract 11 (MC2011-14 and CP2011-50) (Order No. 644).
Administrative practice and procedure, Postal Service.
For the reasons discussed in the preamble, the Postal Regulatory Commission amends chapter III of title 39 of the Code of Federal Regulations as follows:
39 U.S.C. 503; 3622; 3631; 3642; 3682.
(An asterisk (*) indicates an organizational class or group, not a Postal Service product.)
By the Commission.
Environmental Protection Agency (EPA).
Final rule.
Under the Toxic Substance Control Act (TSCA), EPA is finalizing a significant new use rule (SNUR) for trichloroethylene (TCE). The significant new use is the manufacture or processing for use in a consumer product, with an exception for use of TCE in cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray. Persons subject to the SNUR will be required to notify EPA at least 90 days before commencing any manufacturing or processing of TCE for a significant new use. The required notification will provide EPA with the opportunity to evaluate the intended use and, if necessary based on the information available at that time, an opportunity to protect against potential unreasonable risks, if any, from that activity before it occurs.
This final rule is effective June 7, 2016.
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPPT-2014-0697, is available at
You may be potentially affected by this action if you manufacture, process, or distribute in commerce chemical substances and mixtures. The following list of North American Industrial Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers determine whether this document applies to them. Potentially affected entities may include:
• Textile Product Mills (NAICS code 314).
• Wood Product Manufacturing (NAICS code 321).
• Printing and Related Support Activities (NAICS code 323).
• Chemical Manufacturing (NAICS code 325).
• Plastics and Rubber Product Manufacturing (NAICS code 326).
• Primary Metal Manufacturing (NAICS code 331).
• Fabricated Metal Product Manufacturing (NAICS code 332).
• Machinery Manufacturing (NAICS code 333).
• Computer and Electronic Product Manufacturing (NAICS code 334).
• Electrical Equipment, Appliance, and Component Manufacturing (NAICS code 335).
• Transportation Equipment Manufacturing (NAICS code 336).
• Furniture and Product Related Manufacturing (NAICS code 337).
• Miscellaneous Manufacturing (NAICS code 339).
• Clothing and Clothing Accessory Stores (NAICS code 488).
• Warehousing and Storage (NAICS code 493).
• Repair and Maintenance (NAICS code 811).
• National Security and International Affairs (NAICS code 928).
Other types of entities not listed in this unit could also be affected. The NAICS codes have been provided to assist you and others in determining whether this action might apply to certain entities.
This action may also affect certain entities through pre-existing import certification and export notification rules under TSCA. Persons who import any chemical substance governed by a final SNUR are subject to the TSCA section 13 (15 U.S.C. 2612) import certification requirements and the corresponding regulations at 19 CFR 12.118 through 12.127; see also 19 CFR 127.28. Those persons must certify that the shipment of the chemical substance complies with all applicable rules and orders under TSCA, including any SNUR requirements. The EPA policy in support of import certification appears at 40 CFR part 707, subpart B. In addition, any persons who export or intend to export a chemical substance that is the subject of this final rule are subject to the export notification provisions of TSCA section 12(b) (15 U.S.C. 2611(b)), (see 40 CFR 721.20), and must comply with the export notification requirements in 40 CFR part 707, subpart D.
To determine whether you or your business may be affected by this action, you should carefully examine the applicability provisions in 40 CFR 721.5. If you have any questions regarding the applicability of this action to a particular entity, consult the technical information contact listed under
Section 5(a)(2) of TSCA (15 U.S.C. 2604(a)(2)) authorizes EPA to determine that a use of a chemical substance is a “significant new use.” EPA must make this determination by rule after considering all relevant factors, including those listed in TSCA section 5(a)(2). Once EPA determines that a use of a chemical substance is a significant new use, TSCA section 5(a)(1)(B) requires persons to submit a significant new use notice (SNUN) to EPA at least 90 days before they manufacture (including import) or process the chemical substance for that use (15 U.S.C. 2604(a)(1)(B)). As described in Unit V., the general SNUR provisions are found at 40 CFR part 721, subpart A.
This final SNUR will require persons to notify EPA at least 90 days before commencing the manufacture (including import) or processing of TCE for use in a consumer product except for use in cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray.
The SNUR was proposed in the
This SNUR is necessary to ensure that EPA receives timely advance notice of any future manufacturing and processing of TCE for new uses that may produce changes in human and environmental exposures. The rationale and objectives for this SNUR are explained in Unit III.
EPA has evaluated the potential costs of establishing SNUR reporting requirements for potential manufacturers and processors of TCE. This analysis (Ref. 2), which is available in the docket, is discussed in Unit IX., and is briefly summarized here.
In the event that a SNUN is submitted, costs are estimated to be less than $8,900 per SNUN submission for large business submitters and $6,500 for small business submitters. These estimates include the cost to prepare and submit the SNUN and the payment of a user fee. The SNUR requires first-time submitters of any TSCA section 5 notice to register their company and key users with the CDX reporting tool, deliver a CDX electronic signature to EPA, and establish and use a Pay.gov E-payment account before they may submit a SNUN, for a cost of approximately $200 per firm. However, these activities are only required of first time submitters of section 5 notices. In addition, for persons exporting a substance that is the subject of a SNUR, a one-time notice to EPA must be provided for the first export or intended export to a particular country, which is estimated to be approximately $80 per notification.
This final SNUR applies to TCE (Chemical Abstract Services Registry Number (CASRN) 79-01-6) manufactured (including import) or processed for use in any consumer product, except for use in cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray. A consumer product is defined at 40 CFR 721.3 as “a chemical substance that is directly, or as part of a mixture, sold or made available to consumers for their use in or around a permanent or temporary household or residence, in or around a school, or in recreation.”
As discussed in detail in Units II and III of the proposed rule (80 FR 47441; August 7, 2015), TCE has the potential to induce neurotoxicity, immunotoxicity, developmental toxicity, liver toxicity, kidney toxicity, endocrine effects, and several forms of cancer (Ref. 3). EPA is concerned about the adverse health effects of TCE resulting from commercial and consumer uses of the chemical substance. In EPA's final risk assessment of TCE, released on June 25, 2014, the Agency identified risks to workers using TCE and to bystanders for use as degreasers and a spot-cleaner in dry cleaning uses, and EPA also identified health risks to consumers using spray aerosol degreasers and spray fixatives (Ref. 3).
EPA believes that any additional use of this chemical substance in consumer products could significantly increase human exposure, and that such exposures should not occur without an opportunity for EPA review and control as appropriate. However, as discussed in Unit II of the proposed rule (80 FR 47441; August 7, 2015), based on review of Safety Data Sheets and the National Institutes of Health's Household Products Database, EPA believes that cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray presently contain TCE and are therefore ongoing uses of this chemical. EPA believes that other consumer products do not presently contain TCE. Spray fixative product use was discontinued by September 1, 2015, as described in Unit II.A of the proposed rule (80 FR 47441).
Consistent with EPA's past practice for issuing SNURs under TSCA section 5(a)(2), EPA's decision to promulgate a SNUR for a particular chemical use need not be based on an extensive evaluation of the hazard, exposure, or potential risk associated with that use. Rather, the Agency action is based on EPA's determination that if the use begins or resumes, it may present a risk that EPA should evaluate under TSCA before the manufacturing or processing for that use begins. Since the new use does not currently exist, deferring a detailed consideration of potential risks or hazards related to that use is an effective use of resources. If a person decides to begin manufacturing or processing the chemical for the use, the notice to EPA allows EPA to evaluate the use according to the specific parameters and circumstances surrounding that intended use.
Based on the considerations in Unit III.A., EPA will achieve the following objectives with regard to the significant new use(s) that are designated in this final rule:
1. EPA will receive notice of any person's intent to manufacture or process TCE for the described significant new use before that activity begins.
2. EPA will have an opportunity to review and evaluate data submitted in a SNUN before the notice submitter begins manufacturing or processing TCE for the described significant new use.
3. EPA will be able to regulate prospective manufacturers or processors of TCE before the described significant new use of the chemical substance occurs, provided that regulation is warranted pursuant to TSCA section 5(e), 5(f), 6, or 7.
Section 5(a)(2) of TSCA states that EPA's determination that a use of a chemical substance is a significant new use must be made after consideration of all relevant factors including:
1. The projected volume of manufacturing and processing of a chemical substance.
2. The extent to which a use changes the type or form of exposure of human beings or the environment to a chemical substance.
3. The extent to which a use increases the magnitude and duration of exposure of human beings or the environment to a chemical substance.
4. The reasonably anticipated manner and methods of manufacturing, processing, distribution in commerce, and disposal of a chemical substance.
In addition to these factors enumerated in TSCA section 5(a)(2), the statute authorizes EPA to consider any other relevant factors.
To determine what would constitute a significant new use of TCE, as discussed in Unit II of the proposed rule (80 FR 47441), EPA considered relevant information about the toxicity of the substance, likely human exposures and environmental releases associated with possible uses, and the four factors listed in section 5(a)(2) of TSCA (80 FR 47441). EPA has determined as the significant new use: Manufacture or processing for any use in a consumer product, except for use in cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray. Because
General provisions for SNURs appear under 40 CFR part 721, subpart A. These provisions describe persons subject to the rule, recordkeeping requirements, exemptions to reporting requirements, and applicability of the rule to uses occurring before the effective date of the final rule.
Provisions relating to user fees appear at 40 CFR part 700. According to 40 CFR 721.1(c), persons subject to SNURs must comply with the same notice requirements and EPA regulatory procedures as submitters of Premanufacture Notices (PMNs) under TSCA section 5(a)(1)(A). In particular, these requirements include the information submissions requirements of TSCA section 5(b) and 5(d)(1), the exemptions authorized by TSCA section 5(h)(1), (h)(2), (h)(3), and (h)(5), and the regulations at 40 CFR part 720. Once EPA receives a SNUN, EPA may take regulatory action under TSCA section 5(e), 5(f), 6, or 7 to control the activities on which it has received the SNUN. If EPA does not take action, EPA is required under TSCA section 5(g) to explain in the
Persons who export or intend to export a chemical substance identified in a proposed or final SNUR are subject to the export notification provisions of TSCA section 12(b). The regulations that interpret TSCA section 12(b) appear at 40 CFR part 707, subpart D. In accordance with 40 CFR 707.60(b), this final SNUR does not trigger export notification for articles. Persons who import a chemical substance identified in a final SNUR are subject to the TSCA section 13 import certification requirements, codified at 19 CFR 12.118 through 12.127; see also 19 CFR 127.28. Those persons must certify that the shipment of the chemical substance complies with all applicable rules and orders under TSCA, including any SNUR requirements. The EPA policy in support of import certification appears at 40 CFR part 707, subpart B.
As discussed in the
EPA recognizes that TSCA section 5 does not usually require developing any particular test data before submission of a SNUN. There are two exceptions:
1. Development of test data is required where the chemical substance subject to the SNUR is also subject to a test rule under TSCA section 4 (see TSCA section 5(b)(1)); and
2. Development of test data may be necessary where the chemical substance has been listed under TSCA section 5(b)(4) (see TSCA section 5(b)(2)).
In the absence of a section 4 test rule or a section 5(b)(4) listing covering the chemical substance, persons are required to submit only test data in their possession or control and to describe any other data known to or reasonably ascertainable by them (15 U.S.C. 2604(d); 40 CFR 721.25, and 40 CFR 720.50). However, as a general matter, EPA recommends that SNUN submitters include data that would permit a reasoned evaluation of risks posed by the chemical substance during its manufacture, processing, use, distribution in commerce, or disposal. EPA encourages persons to consult with the Agency before submitting a SNUN. As part of this optional pre-notice consultation, EPA would discuss specific data it believes may be useful in evaluating a significant new use. SNUNs submitted for significant new uses without any test data may increase the likelihood that EPA will take action under TSCA section 5(e) to prohibit or limit activities associated with this chemical.
SNUN submitters should be aware that EPA will be better able to evaluate SNUNs that provide detailed information on:
• Human exposure and environmental releases that may result from the significant new uses of the chemical substance;
• Potential benefits of the chemical substance; and
• Information on risks posed by the chemical substances compared to risks posed by potential substitutes.
EPA recommends that submitters consult with the Agency prior to submitting a SNUN to discuss what data may be useful in evaluating a significant new use. Discussions with the Agency prior to submission can afford ample time to conduct any tests that might be helpful in evaluating risks posed by the substance. According to 40 CFR 721.1(c), persons submitting a SNUN
EPA has evaluated the potential costs of establishing SNUR reporting requirements for potential manufacturers and processors of the chemical substance included in this final rule (Ref. 2). In the event that a SNUN is submitted, costs are estimated at approximately $8,900 per SNUN submission for large business submitters and $6,500 for small business submitters. These estimates include the cost to prepare and submit the SNUN, and the payment of a user fee. Businesses that submit a SNUN would be subject to either a $2,500 user fee required by 40 CFR 700.45(b)(2)(iii), or, if they are a small business with annual sales of less than $40 million when combined with those of the parent company (if any), a reduced user fee of $100 (40 CFR 700.45(b)(1)). EPA's complete economic analysis is available in the public docket for this final rule (Ref. 2).
Under section 12(b) of TSCA and the implementing regulations at 40 CFR part 707, subpart D, exporters must notify EPA if they export or intend to export a chemical substance or mixture for which, among other things, a rule has been proposed or promulgated under TSCA section 5. For persons exporting a substance that is the subject of a SNUR, a one-time notice to EPA must be provided for the first export or intended export to a particular country. The total costs of export notification will vary by chemical, depending on the number of required notifications (
The Agency reviewed and considered all comments received related to the proposed rule. Copies of all comments are available in the docket for this action (EPA-HQ-OPPT-2014-0697). A discussion of the major comments germane to the rulemaking and the Agency's responses follow.
TSCA section 6 provides authority for EPA to ban or restrict the manufacture (including import), processing, distribution in commerce, and use of chemicals, as well as any manner or method of disposal. EPA identified TCE for risk evaluation as part of its Work Plan for Chemical Assessment under TSCA. TCE is used in industrial and commercial processes, and also has some limited uses in consumer products. In the June 2014 TSCA Work Plan Chemical Risk Assessment, EPA identified risks associated with commercial degreasing and some consumer uses. EPA is initiating rulemaking under TSCA section 6 to address these risks. Specifically, EPA will determine whether the use of TCE in some commercial degreasing uses, as a spotting agent in dry cleaning, and in certain consumer products presents an unreasonable risk to human health and the environment such that regulation is warranted under TSCA section 6.
Under section 5(a)(2), EPA is neither required to determine that a particular new use of any chemical substances presents, nor even that it may present, an unreasonable risk to human health or the environment. Rather, EPA issues a SNUR for a particular new use of a
The following is a listing of the documents that are specifically referenced in this document. The docket includes these documents and other information considered by EPA, including documents that are referenced within the documents that are included in the docket, even if the referenced document is not physically located in the docket. For assistance in locating these other documents, please consult the technical person listed under
1. EPA. Trichloroethylene (TCE); Significant New Use Rule; TCE in Certain Consumer Products; Proposed Rule.
2. EPA. Economic Analysis for the Final Significant New Use Rule for Trichloroethylene (TCE). March 10, 2016.
3. EPA. TSCA Workplan Chemical Risk Assessment—Trichloroethylene: Degreasing, Spot Cleaning and Arts & Crafts Uses; Supporting and Related Material. June 25, 2014.
4. EPA. Significant New Uses of Certain Chemical Substances; Final Rule.
This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011).
This action does not impose any new information collection burden under the PRA, 44 U.S.C. 3501
An agency may not conduct or sponsor, and a person is not required to respond to a collection of information that requires OMB approval under the PRA, unless it has been approved by OMB and displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in title 40 of the CFR, after appearing in the
Pursuant to section 605(b) of the RFA, 5 U.S.C. 601
A SNUR applies to any person (including small or large entities) who intends to engage in any activity described in the rule as a “significant new use.” By definition of the word “new” and based on all information currently available to EPA, it appears that no small or large entities presently engage in such activities. Since this SNUR will require a person who intends to engage in such activity in the future to first notify EPA by submitting a SNUN, no economic impact will occur unless someone files a SNUN to pursue a significant new use in the future or forgoes profits by avoiding or delaying the significant new use. Although some small entities may decide to conduct such activities in the future, EPA cannot presently determine how many, if any, there may be. However, EPA's experience to date is that, in response to the promulgation of SNURs covering over 1,000 chemical substances, the Agency receives only a handful of notices per year. During the six year period from 2005-2010, only three submitters self-identified as small in their SNUN submission (Ref. 2). EPA believes the cost of submitting a SNUN is relatively small compared to the cost of developing and marketing a chemical new to a firm or marketing a new use of the chemical and that the requirement to submit a SNUN generally does not have a significant economic impact.
Therefore, EPA believes that the potential economic impact of complying with this final SNUR is not expected to be significant or adversely impact a substantial number of small entities. In a SNUR that published as a final rule on August 8, 1997 (62 FR 42690) (FRL-5735-4), the Agency presented its general determination that proposed and final SNURs are not expected to have a significant economic impact on a substantial number of small entities.
Based on EPA's experience with proposing and finalizing SNURs, State, local, and Tribal governments have not been impacted by these rulemakings, and EPA does not have any reason to believe that any State, local, or Tribal government would be impacted by this rulemaking. As such, the requirements of sections 202, 203, 204, or 205 of UMRA, 2 U.S.C. 1531-1538, do not apply to this action.
This action will not have a substantial direct effect on States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132 (64 FR 43255, August 10, 1999).
This final rule does not have Tribal implications because it is not expected to have any effect (
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997), as applying only to those regulatory actions that concern environmental health or safety risks that EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk.
This final rule is not subject to Executive Order 13211 (66 FR 28355, May 22, 2001), because this action is not expected to affect energy supply, distribution, or use.
Since this action does not involve any technical standards, section 12(d) of NTTAA, 15 U.S.C. 272 note, does not apply to this action.
This final rule does not invoke special consideration of environmental justice related issues as delineated by Executive Order 12898 (59 FR 7629, February 16, 1994), because EPA has determined that this action will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations. This action does not affect the level of protection provided to human health or the environment.
This action is subject to the CRA, 5 U.S.C. 801
Environmental protection, Reporting and recordkeeping requirements.
Environmental protection, Chemicals, Hazardous substances, Reporting and recordkeeping requirements.
Therefore, 40 CFR chapter I is amended as follows:
7 U.S.C. 135
15 U.S.C. 2604, 2607, and 2625(c).
(a)
(2) Manufacture or processing for use in a consumer product except for use in cleaners and solvent degreasers, film cleaners, hoof polishes, lubricants, mirror edge sealants, and pepper spray.
(b) [Reserved]
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA) is approving a state implementation plan (SIP) revision submitted by the Commonwealth of Pennsylvania (Pennsylvania). The revision demonstrates attainment of the 2008 lead national ambient air quality standards (NAAQS) in the North Reading 2008 lead nonattainment area (North Reading Area or Area). The attainment plan includes the base year emissions inventory, an analysis of reasonably available control technology (RACT), reasonably available control measures (RACM), and reasonable further progress (RFP), modeling demonstration of lead attainment, and contingency measures for the Area. EPA is approving Pennsylvania's lead attainment plan with the base year emissions inventory for the North Reading Area as a revision to Pennsylvania's SIP in accordance with the requirements of the Clean Air Act (CAA).
This final rule is effective on May 9, 2016.
EPA has established a docket for this action under Docket ID Number EPA-R03-OAR-2015-0773. All documents in the docket are listed in the
Ellen Schmitt, (215) 814-5787, or by email at
On January 11, 2016 (81 FR 1136), EPA published a notice of proposed rulemaking (NPR) for the Commonwealth of Pennsylvania. In the NPR, EPA proposed approval of a revision to Pennsylvania's SIP for the purpose of demonstrating attainment of the 2008 lead NAAQS in the North Reading Area. The formal SIP revision was submitted by Pennsylvania on August 12, 2015.
On November 12, 2008 (73 FR 66964), EPA revised the lead NAAQS, lowering the level from 1.5 micrograms per cubic meter (μg/m
On November 22, 2010, EPA designated Alsace and Muhlenberg Townships and the Laureldale Borough, all of which are located in Berks County, Pennsylvania, as the North Reading Area for its nonattainment status with the 2008 lead NAAQS. 76 FR 72097. The designation of the North Reading Area as nonattainment for the 2008 lead NAAQS triggered requirements under section 191(a) of the CAA, requiring Pennsylvania to submit a SIP revision with a plan for how the Area will attain the 2008 lead NAAQS, as expeditiously as practicable, but no later than December 31, 2015.
Section 179(a)(1) of the CAA establishes specific consequences if EPA finds that a state has failed to submit a SIP or, with regard to a submitted SIP, if EPA determines it is incomplete or if EPA disapproves it. Additionally, any of these findings also triggers an obligation for EPA to promulgate a federal implementation plan (FIP) if the state has not submitted, and EPA has not approved, the required SIP within 2 years of the finding pursuant to section 110(c) of the CAA. On February 25, 2014, the EPA issued a finding that Pennsylvania failed to make the required nonattainment SIP submission for the North Reading Area. 79 FR 10391. With this final approval by EPA of Pennsylvania's North Reading attainment plan SIP in accordance with section 172(c) of the CAA, the Agency no longer has any obligation to issue a FIP for the North Reading Area in accordance with section 110(c) of the CAA.
On August 12, 2015, Pennsylvania through the Department of Environmental Protection (PADEP) submitted an attainment plan for the North Reading Area as a SIP revision which includes a base year emissions inventory, an attainment demonstration, an analysis of RACM and RACT, provisions for RFP, and contingency measures.
The SIP revision also includes paragraph 3 of a consent order and agreement (COA), dated June 15, 2015, between Exide Technologies (Exide) and PADEP and paragraphs 5 and 22 of a COA, dated June 12, 2015, between Yuasa Battery, Inc (Yuasa) and PADEP. EPA's analysis of the submitted attainment plan includes a review of these elements for the North Reading Area.
EPA's approval of the attainment plan is based on the Agency's finding that the Area meets all lead NAAQS attainment plan requirements under CAA sections 172, 191, and 192. Due to monitored ambient air quality violations in early 2013, before a major source of lead began idling, the Area did not attain the NAAQS, over 36 consecutive three-month periods, by December 2015, the attainment date. However, as a result of implementation of PADEP's August 12, 2015 SIP revision, EPA and PADEP expect the North Reading Area will attain the 2008 lead NAAQS on the basis of 2014-2016 ambient air quality data. EPA is approving the base year emissions inventory submitted with the plan, as well as the RACM/RACT and RFP analyses, the attainment demonstration including modeling, and the contingency measures for the North Reading Area.
Other specific requirements of the SIP submittal attainment plan for the North Reading Area and the rationale for EPA's proposed action are explained in the NPR and its accompanying Technical Support Documents (TSDs) and will not be restated here.
EPA is approving the lead attainment plan for the North Reading Area and paragraph 3 of the COA between PADEP and Exide and paragraphs 5 and 22 of the COA between PADEP and Yuasa, as submitted on August 12, 2015 as a revision to the Pennsylvania SIP. EPA has determined that the SIP meets the applicable requirements of the CAA. Specifically, EPA is taking final action to approve Pennsylvania's August 12, 2015 SIP submission which includes the attainment demonstration, base year emissions inventory, RACM/RACT and RFP analyses, and contingency measures.
With the EPA's final approval of Pennsylvania's North Reading attainment plan submittal, EPA no longer has any obligation to promulgate a FIP for the North Reading Area pursuant to sections 110(c) or 172(c) of the CAA.
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely approves state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• does not impose an information collection burden under the provisions
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
In addition, this rule does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), because the SIP is not approved to apply in Indian country located in the state, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 7, 2016. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action approving Pennsylvania's SIP revision containing the attainment plan and base year inventory for the 2008 lead NAAQS in the North Reading Area may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Lead.
40 CFR part 52 is amended as follows:
42 U.S.C. 7401
(e) * * *
(1) * * *
(z) EPA approves as a revision to the Pennsylvania state implementation plan the 2010 base year emissions inventory for the North Reading, Pennsylvania nonattainment area for the 2008 lead NAAQS. This SIP revision was submitted by the Secretary of the Pennsylvania Department of Environmental Protection on August 10, 2015. This submittal consists of the 2010 base year emissions inventories for all relevant sources in the North Reading nonattainment area for the pollutant lead (Pb).
(b) EPA approves the state implementation plan for the North Reading, Pennsylvania nonattainment area for the 2008 lead NAAQS. This SIP revision including reasonably available control measures, reasonably available control technology, contingency measures, and attainment demonstration was submitted by the Secretary of the Pennsylvania Department of Environmental Protection on August 10, 2015.
Environmental Protection Agency (EPA).
Final rule.
On December 11, 2015, the State of Mississippi, through the Mississippi Department of Environment Quality (MDEQ), submitted a request for the Environmental Protection Agency (EPA) to redesignate the portion of Mississippi that is within the Memphis, Tennessee-Mississippi-Arkansas (Memphis, TN-MS-AR) 2008 8-hour ozone nonattainment area (hereafter referred to as the “Memphis, TN-MS-AR Area” or “Area”) and a related State Implementation Plan (SIP) revision containing a maintenance plan for the Area. EPA is taking the following separate final actions related to the December 11, 2015, redesignation request and SIP revision: Determining that the Memphis, TN-MS-AR Area is attaining the 2008 8-hour ozone national ambient air quality standards (NAAQS); approving the State's plan for maintaining attainment of the 2008 8-hour ozone NAAQS in the Area, including the motor vehicle emission budgets (MVEBs) for nitrogen oxides (NO
This rule will be effective May 9, 2016.
EPA has established a docket for this action under Docket Identification No. EPA-R04-OAR-2015-0743. All documents in the docket are listed on the
Sean Lakeman of the Air Regulatory Management Section, Air Planning and Implementation Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303-8960. Mr. Lakeman may be reached by phone at (404) 562-9043 or via electronic mail at
On May 21, 2012, EPA designated areas as unclassifiable/attainment or nonattainment for the 2008 8-hour ozone NAAQS that was promulgated on March 27, 2008.
On December 11, 2015, MDEQ requested that EPA redesignate Mississippi's portion of the Memphis, TN-MS-AR Area to attainment for the 2008 8-hour ozone NAAQS and submitted a SIP revision containing the State's plan for maintaining attainment of the 2008 8-hour ozone standard in the Area, including the MVEBs for NO
Approval of Mississippi's redesignation request changes the legal designation of DeSoto County in the Mississippi portion of the Memphis, TN-MS-AR Area, found at 40 CFR 81.325, from nonattainment to attainment for the 2008 8-hour ozone NAAQS. Approval of Mississippi's associated SIP revision also incorporates a plan into the SIP for maintaining the 2008 8-hour ozone NAAQS in the Mississippi portion of the Memphis, TN-MS-AR Area through 2027. The maintenance plan establishes NO
EPA is taking three separate final actions regarding Mississippi's December 11, 2015, request to redesignate the Mississippi portion of the Memphis, TN-MS-AR Area to attainment and associated SIP revision. First, EPA is determining that the Memphis, TN-MS-AR Area is attaining the 2008 8-hour ozone NAAQS.
Second, EPA is approving and incorporating the maintenance plan for the Memphis, TN-MS-AR Area, including the NO
Third, EPA is determining that Mississippi has met the criteria under CAA section 107(d)(3)(E) for redesignation of the State's portion of the Memphis, TN-MS-AR Area from nonattainment to attainment for the 2008 8-hour ozone NAAQS. On this basis, EPA is approving Mississippi's redesignation request. As mentioned above, approval of the redesignation request changes the official designation of DeSoto County in the Mississippi portion of the Memphis, TN-MS-AR Area for the 2008 8-hour ozone NAAQS from nonattainment to attainment, as found at 40 CFR part 81.
EPA is also notifying the public that EPA finds the newly-established NO
Under the CAA, redesignation of an area to attainment and the accompanying approval of a maintenance plan under section 107(d)(3)(E) are actions that affect the status of a geographical area and do not impose any additional regulatory requirements on sources beyond those imposed by state law. A redesignation to attainment does not in and of itself create any new requirements, but rather results in the applicability of requirements contained in the CAA for areas that have been redesignated to attainment. Moreover, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable Federal regulations.
• Are not significant regulatory actions subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• do not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• are certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• do not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• do not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• are not economically significant regulatory actions based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• are not significant regulatory actions subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• are not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• will not have disproportionate human health or environmental effects under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by June 7, 2016. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements.
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Volatile organic compounds.
Environmental protection, Air pollution control.
40 CFR parts 52 and 81 are amended as follows:
42 U.S.C. 7401
(e) * * *
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Final rule.
This regulation establishes tolerances for residues of fluazinam in or on cabbage, mayhaw, the cucurbit vegetable crop group 9, and the tuberous and corm vegetable subgroup 1C and amends the existing tolerance for “vegetable,
This regulation is effective April 8, 2016. Objections and requests for hearings must be received on or before June 7, 2016, and must be filed in accordance with the instructions provided in 40 CFR part 178 (see also Unit I.C. of the
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPP-2015-0197, is available at
Susan Lewis, Registration Division (7505P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; main telephone number: (703) 305-7090; email address:
You may be potentially affected by this action if you are an agricultural producer, food manufacturer, or pesticide manufacturer. The following list of North American Industrial Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers determine whether this document applies to them. Potentially affected entities may include:
• Crop production (NAICS code 111).
• Animal production (NAICS code 112).
• Food manufacturing (NAICS code 311).
• Pesticide manufacturing (NAICS code 32532).
You may access a frequently updated electronic version of EPA's tolerance regulations at 40 CFR part 180 through the Government Printing Office's e-CFR site at
Under FFDCA section 408(g), 21 U.S.C. 346a, any person may file an objection to any aspect of this regulation and may also request a hearing on those objections. You must file your objection or request a hearing on this regulation in accordance with the instructions provided in 40 CFR part 178. To ensure proper receipt by EPA, you must identify docket ID number EPA-HQ-OPP-2015-0197 in the subject line on the first page of your submission. All objections and requests for a hearing must be in writing, and must be received by the Hearing Clerk on or before June 7, 2016. Addresses for mail and hand delivery of objections and hearing requests are provided in 40 CFR 178.25(b).
In addition to filing an objection or hearing request with the Hearing Clerk as described in 40 CFR part 178, please submit a copy of the filing (excluding any Confidential Business Information (CBI)) for inclusion in the public docket. Information not marked confidential pursuant to 40 CFR part 2 may be disclosed publicly by EPA without prior notice. Submit the non-CBI copy of your objection or hearing request, identified by docket ID number EPA-HQ-OPP-2015-0197, by one of the following methods:
•
•
•
In the
EPA is combining the existing tolerance for the melon subgroup 9A tolerance with the proposed squash/cucumber subgroup 9B tolerance and establishing a tolerance for the entire cucurbit vegetable crop group 9, rather than just subgroup 9B. The reason for these changes is explained in Unit IV.C.
Section 408(b)(2)(A)(i) of FFDCA allows EPA to establish a tolerance (the legal limit for a pesticide chemical residue in or on a food) only if EPA determines that the tolerance is “safe.” Section 408(b)(2)(A)(ii) of FFDCA defines “safe” to mean that “there is a reasonable certainty that no harm will result from aggregate exposure to the pesticide chemical residue, including all anticipated dietary exposures and all other exposures for which there is reliable information.” This includes exposure through drinking water and in residential settings, but does not include occupational exposure. Section 408(b)(2)(C) of FFDCA requires EPA to give special consideration to exposure of infants and children to the pesticide chemical residue in establishing a tolerance and to “ensure that there is a reasonable certainty that no harm will result to infants and children from aggregate exposure to the pesticide chemical residue. . . .”
Consistent with FFDCA section 408(b)(2)(D), and the factors specified in FFDCA section 408(b)(2)(D), EPA has reviewed the available scientific data and other relevant information in support of this action. EPA has
EPA has evaluated the available toxicity data and considered its validity, completeness, and reliability as well as the relationship of the results of the studies to human risk. EPA has also considered available information concerning the variability of the sensitivities of major identifiable subgroups of consumers, including infants and children.
The liver is a primary target organ for fluazinam and numerous liver effects were observed in rats, mice, and dogs after oral and dermal exposure. After inhalation exposure, portal of entry effects (increased lung/bronchial weights, alveolar macrophages and peribronchiolar proliferation) were seen.
Clinical signs were observed in an acute oral neurotoxicity study in rats; decreases in motor activity and soft stools were seen on the day of dosing at the limit dose. These effects were attributed to systemic toxicity and were not considered to be evidence of frank neurotoxicity. In two subchronic neurotoxicity studies (evaluated together) in rats, no evidence of neurotoxicity was observed. A neurotoxic lesion was observed initially in long-term studies in mice and dogs; however, the lesion is reversible and was later attributed to the presence of an impurity (Impurity-5) in the technical material. A NOAEL for the impurity was determined (based on the maximum concentration of Impurity-5 in technical grade fluazinam), equivalent to a NOAEL for central nervous system (CNS) effects of 20 mg/kg/day for technical grade fluazinam. The current acute and chronic reference doses selected for risk assessment are lower than the determined NOAEL and thus, protective of any possible neurotoxic effects resulting from exposure to Impurity-5.
In an immunotoxicity study in mice, significant suppressions of anti-SRBC AFC assay response were demonstrated at the highest dose tested indicating potential immunotoxicity. However, clear NOAELs and LOAELs were identified for the effects seen in the study and the points of departure (PODs) and endpoints selected for risk assessment are protective of immunotoxic effects.
There was no evidence of increased quantitative or qualitative susceptibility in the rabbit developmental or rat reproduction studies. However, quantitative susceptibility was seen in rat developmental and developmental neurotoxicity (DNT) studies where fetal/offspring effects were observed in the absence of maternal toxicity. The concern is low for the increased susceptibility noted in the studies since clear NOAELs are established, and the most sensitive endpoints/PODs are used for risk assessment and are protective of the observed susceptibility. Therefore, the Food Quality Protection Act (FQPA) safety factor (SF) has been reduced to 1x.
Fluazinam is classified as having “Suggestive evidence of carcinogenicity, but not sufficient to assess human carcinogenic potential,” based on increases in thyroid gland follicular cell tumors in male rats and increases in hepatocellular tumors in male mice. Although there is evidence of thyroid tumors in male rats and liver tumors in male mice, the NOAEL used (1.12 mg/kg/day) for establishing the chronic reference dose (cRfD) is approximately 3-fold lower than the lowest dose that induced tumors (3.8 mg/kg/day). The Agency has determined that quantification of cancer risk using a non-linear approach (cRfD) would adequately account for all chronic toxicity, including carcinogenicity, which could result from exposure to fluazinam.
Specific information on the studies received and the nature of the adverse effects caused by fluazinam as well as the no-observed-adverse-effect-level (NOAEL) and the lowest-observed-adverse-effect-level (LOAEL) from the toxicity studies can be found at
Once a pesticide's toxicological profile is determined, EPA identifies toxicological points of departure (POD) and levels of concern to use in evaluating the risk posed by human exposure to the pesticide. For hazards that have a threshold below which there is no appreciable risk, the toxicological POD is used as the basis for derivation of reference values for risk assessment. PODs are developed based on a careful analysis of the doses in each toxicological study to determine the dose at which no adverse effects are observed (the NOAEL) and the lowest dose at which adverse effects of concern are identified (the LOAEL). Uncertainty/safety factors are used in conjunction with the POD to calculate a safe exposure level—generally referred to as a population-adjusted dose (PAD) or a reference dose (RfD)—and a safe margin of exposure (MOE). For non-threshold risks, the Agency assumes that any amount of exposure will lead to some degree of risk. Thus, the Agency estimates risk in terms of the probability of an occurrence of the adverse effect expected in a lifetime. For more information on the general principles EPA uses in risk characterization and a complete description of the risk assessment process, see
A summary of the toxicological endpoints for fluazinam used for human risk assessment is discussed in Unit III.B. of the final rule published in the
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These simulation models take into account data on the physical, chemical, and fate/transport characteristics of fluazinam and its transformation products. Further information regarding EPA drinking water models used in pesticide exposure assessment can be found at
Based on the First Index Reservoir Screening Tool (FIRST) and the Pesticide Root Zone Model Ground Water (PRZM GW) models, the estimated drinking water concentrations (EDWCs) for total residues of fluazinam and its transformation products for acute exposures are estimated to be 226 parts per billion (ppb) for surface water and 137 ppb for ground water and for chronic exposures are estimated to be 37.8 ppb for surface water and 119 ppb for ground water.
Modeled estimates of drinking water concentrations were directly entered into the dietary exposure model. For the acute dietary risk assessment, the water concentration value of 226 ppb was used to assess the contribution to drinking water, and for the chronic dietary risk assessment, the water concentration of value 119 ppb was used to assess the contribution to drinking water.
3.
Fluazinam is currently registered for the following uses that could result in residential exposures: golf course turf. EPA assessed residential exposure using the following assumptions: Only short-term dermal exposure is expected for residential post-application scenarios for children, teens, and adults who could potentially be exposed when they play golf on treated turf. No other residential exposures are expected. Further information regarding EPA standard assumptions and generic inputs for residential exposures may be found at
4.
EPA has not found fluazinam to share a common mechanism of toxicity with any other substances, and fluazinam does not appear to produce a toxic metabolite produced by other substances. For the purposes of this tolerance action, therefore, EPA has assumed that fluazinam does not have a common mechanism of toxicity with other substances. For information regarding EPA's efforts to determine which chemicals have a common mechanism of toxicity and to evaluate the cumulative effects of such chemicals, see EPA's Web site at
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i. The toxicity database for fluazinam is complete.
ii. Although indications of neurotoxicity and immunotoxicity were observed in the database for fluazinam, there were clear NOAELs for these effects, and the endpoints and doses for risk assessment are protective of the potential effects.
iii. There is no evidence that fluazinam results in increased susceptibility in the rabbit developmental or rat reproduction studies. However, quantitative susceptibility was seen in rat developmental and DNT studies where fetal/offspring effects were observed in
iv. There are no residual uncertainties identified in the exposure databases. The dietary food exposure assessments were performed based on 100 PCT and tolerance-level residues for all commodities except apples, where anticipated residues were used in the chronic assessment. EPA made conservative (protective) assumptions in the ground and surface water modeling used to assess exposure to fluazinam and its transformation products in drinking water. EPA used similarly conservative assumptions to assess post-application exposure of children. These assessments will not underestimate the exposure and risks posed by fluazinam.
EPA determines whether acute and chronic dietary pesticide exposures are safe by comparing aggregate exposure estimates to the acute PAD (aPAD) and chronic PAD (cPAD). For linear cancer risks, EPA calculates the lifetime probability of acquiring cancer given the estimated aggregate exposure. Short-, intermediate-, and chronic-term risks are evaluated by comparing the estimated aggregate food, water, and residential exposure to the appropriate PODs to ensure that an adequate MOE exists.
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Using the exposure assumptions described in this unit for short-term exposures, EPA has concluded the combined short-term food, water, and residential exposures result in aggregate MOEs of 690 for children 6 to <11 years old, 820 for youth 11 to <16 years old and 890 for adults. Because EPA's level of concern for fluazinam is a MOE of 100 or below, these MOEs are not of concern.
4.
An intermediate-term adverse effect was identified; however, fluazinam is not registered for any use patterns that would result in intermediate-term residential exposure. Intermediate-term risk is assessed based on intermediate-term residential exposure plus chronic dietary exposure. Because there is no intermediate-term residential exposure and chronic dietary exposure has already been assessed under the appropriately protective cPAD (which is at least as protective as the POD used to assess intermediate-term risk), no further assessment of intermediate-term risk is necessary, and EPA relies on the chronic dietary risk assessment for evaluating intermediate-term risk for fluazinam.
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6.
An adequate Gas Chromatography with Electron Capture Detector (GC/ECD) method is available for enforcing fluazinam tolerances on plant commodities.
The method may be requested from: Chief, Analytical Chemistry Branch, Environmental Science Center, 701 Mapes Rd., Ft. Meade, MD 20755-5350; telephone number: (410) 305-2905; email address:
In making its tolerance decisions, EPA seeks to harmonize U.S. tolerances with international standards whenever possible, consistent with U.S. food safety standards and agricultural practices. EPA considers the international maximum residue limits (MRLs) established by the Codex Alimentarius Commission (Codex), as required by FFDCA section 408(b)(4). The Codex Alimentarius is a joint United Nations Food and Agriculture Organization/World Health Organization food standards program, and it is recognized as an international food safety standards-setting organization in trade agreements to which the United States is a party. EPA may establish a tolerance that is different from a Codex MRL; however, FFDCA section 408(b)(4) requires that EPA explain the reasons for departing from the Codex level.
The Codex has not established MRLs for fluazinam for any of the commodities covered by this action.
Because the tolerance level for the existing melon subgroup 9A is the same as the squash/cucumber subgroup 9B tolerance the Agency is establishing, the Agency is combining the tolerances for the two subgroups and establishing a tolerance for the entire cucurbit vegetable crop group 9.
Therefore, tolerances are established for residues of fluazinam (3-chloro-N-[3-chloro-2,6-dinitro-4-(trifluoromethyl)phenyl]-5-(trifluoromethyl)-2-pyridinamine), including its metabolites and degradates in or on mayhaw at 2.0 ppm; cabbage at 3.0 ppm; cucurbit vegetables crop group 9 at 0.07 ppm; and vegetable, tuberous and corm, subgroup 1C at 0.02 ppm. In addition, the existing tolerance on the vegetable,
This action establishes tolerances under FFDCA section 408(d) in response to a petition submitted to the Agency. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled “Regulatory Planning and Review” (58 FR 51735, October 4, 1993). Because this action has been exempted from review under Executive Order 12866, this action is not subject to Executive Order 13211, entitled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001) or Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997). This action does not contain any information collections subject to OMB approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Since tolerances and exemptions that are established on the basis of a petition under FFDCA section 408(d), such as the tolerances in this final rule, do not require the issuance of a proposed rule, the requirements of the Regulatory Flexibility Act (RFA) (5 U.S.C. 601
This action directly regulates growers, food processors, food handlers, and food retailers, not States or tribes, nor does this action alter the relationships or distribution of power and responsibilities established by Congress in the preemption provisions of FFDCA section 408(n)(4). As such, the Agency has determined that this action will not have a substantial direct effect on States or tribal governments, on the relationship between the national government and the States or tribal governments, or on the distribution of power and responsibilities among the various levels of government or between the Federal Government and Indian tribes. Thus, the Agency has determined that Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999) and Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000) do not apply to this action. In addition, this action does not impose any enforceable duty or contain any unfunded mandate as described under Title II of the Unfunded Mandates Reform Act (UMRA) (2 U.S.C. 1501
This action does not involve any technical standards that would require Agency consideration of voluntary consensus standards pursuant to section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) (15 U.S.C. 272 note).
Pursuant to the Congressional Review Act (5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
Therefore, 40 CFR chapter I is amended as follows:
21 U.S.C. 321(q), 346a and 371.
The additions read as follows:
(a) * * * (1) * * *
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule.
The National Marine Fisheries Service (NMFS) publishes its final List of Fisheries (LOF) for 2016, as required by the Marine Mammal Protection Act (MMPA). The final LOF for 2016 reflects new information on interactions between commercial fisheries and marine mammals. NMFS must classify each commercial fishery on the LOF into one of three categories under the MMPA based upon the level of mortality and serious injury of marine mammals that occurs incidental to each fishery. The classification of a fishery on the LOF determines whether participants in that fishery are subject to certain provisions of the MMPA, such as registration, observer coverage, and take reduction plan (TRP) requirements. In addition, NMFS begins publishing online fact sheets for Category III fisheries on a rolling basis.
The effective date of this final rule is May 9, 2016.
Chief, Marine Mammal and Sea Turtle Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Silver Spring, MD 20910.
Lisa White, Office of Protected Resources, 301-427-8494; Allison Rosner, Greater Atlantic Region, 978-281-9328; Jessica Powell, Southeast Region, 727-824-
Section 118 of the MMPA requires NMFS to place all U.S. commercial fisheries into one of three categories based on the level of incidental mortality and serious injury of marine mammals occurring in each fishery (16 U.S.C. 1387(c)(1)). The classification of a fishery on the LOF determines whether participants in that fishery may be required to comply with certain provisions of the MMPA, such as registration, observer coverage, and take reduction plan requirements. NMFS must reexamine the LOF annually, considering new information in the Marine Mammal Stock Assessment Reports (SARs) and other relevant sources, and publish in the
The definitions for the fishery classification criteria can be found in the implementing regulations for section 118 of the MMPA (50 CFR 229.2). The criteria are also summarized here.
The fishery classification criteria consist of a two-tiered, stock-specific approach that first addresses the total impact of all fisheries on each marine mammal stock and then addresses the impact of individual fisheries on each stock. This approach is based on consideration of the rate, in numbers of animals per year, of incidental mortalities and serious injuries of marine mammals due to commercial fishing operations relative to the potential biological removal (PBR) level for each marine mammal stock. The MMPA (16 U.S.C. 1362 (20)) defines the PBR level as the maximum number of animals, not including natural mortalities, that may be removed from a marine mammal stock while allowing that stock to reach or maintain its optimum sustainable population. This definition can also be found in the implementing regulations for section 118 of the MMPA (50 CFR 229.2).
Additional details regarding how the categories were determined are provided in the preamble to the final rule implementing section 118 of the MMPA (60 FR 45086, August 30, 1995).
Because fisheries are classified on a per-stock basis, a fishery may qualify as one Category for one marine mammal stock and another Category for a different marine mammal stock. A fishery is typically classified on the LOF at its highest level of classification (
The tier analysis requires a minimum amount of data, and NMFS does not have sufficient data to perform a tier analysis on certain fisheries. Therefore, NMFS has classified certain fisheries by analogy to other Category I or II fisheries that use similar fishing techniques or gear that are known to cause mortality or serious injury of marine mammals, or according to factors discussed in the final LOF for 1996 (60 FR 67063, December 28, 1995) and listed in the regulatory definition of a Category II fishery: “In the absence of reliable information indicating the frequency of incidental mortality and serious injury of marine mammals by a commercial fishery, NMFS will determine whether the incidental mortality or serious injury is `frequent,' `occasional,' or `remote' by evaluating other factors such as fishing techniques, gear used, methods used to deter marine mammals, target species, seasons and areas fished, qualitative data from logbooks or fisher reports, stranding data, and the species and distribution of marine mammals in the area, or at the discretion of the Assistant Administrator for Fisheries” (50 CFR 229.2).
Further, eligible commercial fisheries not specifically identified on the LOF are deemed to be Category II fisheries until the next LOF is published (50 CFR 229.2).
The LOF includes a list of marine mammal species and/or stocks incidentally killed or injured in each commercial fishery. The list of species and/or stocks incidentally killed or injured includes “serious” and “non-serious” documented injuries as described later in the List of Species and/or Stocks Incidentally Killed or Injured in the Pacific Ocean and the Atlantic Ocean, Gulf of Mexico, and Caribbean sections. To determine which species or stocks are included as incidentally killed or injured in a fishery, NMFS annually reviews the information presented in the current SARs and injury determination reports. The SARs are based upon the best available scientific information and provide the most current and inclusive information on each stock's PBR level and level of interaction with commercial fishing operations. The best available scientific information used in the SARs reviewed for the 2016 LOF generally summarizes data from 2008-2012. NMFS also reviews other sources of new information, including injury determination reports, bycatch estimation reports, observer data, logbook data, stranding data, disentanglement network data, fisher self-reports (
For fisheries with observer coverage, species or stocks are generally removed from the list of marine mammal species and/or stocks incidentally killed or injured if no interactions are documented in the five-year timeframe summarized in that year's LOF. For fisheries with no observer coverage and for observed fisheries with evidence indicating that undocumented interactions may be occurring (
The best available information on the level of observer coverage and the spatial and temporal distribution of observed marine mammal interactions is presented in the SARs. Data obtained from the observer program and observer coverage levels are important tools in estimating the level of marine mammal mortality and serious injury in commercial fishing operations. Starting with the 2005 SARs, each SAR includes an appendix with detailed descriptions of each Category I and II fishery on the LOF, including the observer coverage in those fisheries. The SARs generally do not provide detailed information on observer coverage in Category III fisheries because, under the MMPA, Category III fisheries are generally not required to accommodate observers aboard vessels due to the remote likelihood of mortality and serious injury of marine mammals. Fishery information presented in the SARs' appendices and other resources referenced during the tier analysis may include: Level of observer coverage, target species, levels of fishing effort, spatial and temporal distribution of fishing effort, characteristics of fishing gear and operations, management and regulations, and interactions with marine mammals. Copies of the SARs are available on the NMFS Office of Protected Resources Web site at:
This rule includes three tables that list all U.S. commercial fisheries by LOF Category. Table 1 lists all of the commercial fisheries in the Pacific Ocean (including Alaska); Table 2 lists all of the commercial fisheries in the Atlantic Ocean, Gulf of Mexico, and Caribbean; and Table 3 lists all U.S.-authorized commercial fisheries on the high seas. A fourth table, Table 4, lists all commercial fisheries managed under applicable take reduction plans (TRPs) or take reduction teams (TRTs).
Beginning with the 2009 LOF, NMFS includes high seas fisheries in Table 3 of the LOF, along with the number of valid High Seas Fishing Compliance Act (HSFCA) permits in each fishery. As of 2004, NMFS issues HSFCA permits only for high seas fisheries analyzed in accordance with the National Environmental Policy Act (NEPA) and the Endangered Species Act (ESA). The authorized high seas fisheries are broad in scope and encompass multiple specific fisheries identified by gear type. For the purposes of the LOF, the high seas fisheries are subdivided based on gear type (
HSFCA permits are valid for five years, during which time Fishery Management Plans (FMPs) can change. Therefore, some vessels/participants may possess valid HSFCA permits without the ability to fish under the permit because it was issued for a gear type that is no longer authorized under the most current FMP. For this reason, the number of HSFCA permits displayed in Table 3 is likely higher than the actual U.S. fishing effort on the high seas. For more information on how NMFS classifies high seas fisheries on the LOF, see the preamble text in the final 2009 LOF (73 FR 73032; December 1, 2008). Additional information about HSFCA permits can be found at:
Starting with the 2010 LOF, NMFS developed summary documents, or fishery fact sheets, for each Category I and II fishery on the LOF. These fishery fact sheets provide the full history of each Category I and II fishery, including: When the fishery was added to the LOF, the basis for the fishery's initial classification, classification changes to the fishery, changes to the list of species and/or stocks incidentally killed or injured in the fishery, fishery gear and methods used, observer coverage levels, fishery management and regulation, and applicable TRPs or TRTs, if any. These fishery fact sheets are updated after each final LOF and can be found under “How Do I Find Out if a Specific Fishery is in Category I, II, or III?” on the NMFS Office of Protected Resources' Web site:
Owners of vessels or gear engaging in a Category I or II fishery are required under the MMPA (16 U.S.C. 1387(c)(2)), as described in 50 CFR 229.4, to register with NMFS and obtain a marine mammal authorization to lawfully take non-endangered and non-threatened marine mammals incidental to
NMFS has integrated the MMPA registration process, implemented through the Marine Mammal Authorization Program (MMAP), with existing state and Federal fishery license, registration, or permit systems for Category I and II fisheries on the LOF. Participants in these fisheries are automatically registered under the MMAP and are not required to submit registration or renewal materials. In the Pacific Islands, West Coast, and Alaska regions, NMFS will issue vessel or gear owners an authorization certificate via U.S. mail or with their state or Federal license or permit at the time of issuance or renewal. In the Greater Atlantic Region, NMFS will issue vessel or gear owners an authorization certificate via U.S. mail automatically at the beginning of each calendar year. Certificates may also be obtained by visiting the Greater Atlantic Regional Office Web site (
The authorization certificate, or a copy, must be on board the vessel while it is operating in a Category I or II fishery, or for non-vessel fisheries, in the possession of the person in charge of the fishing operation (50 CFR 229.4(e)). Although efforts are made to limit the issuance of authorization certificates to only those vessel or gear owners that participate in Category I or II fisheries, not all state and Federal license or permit systems distinguish between fisheries as classified by the LOF. Therefore, some vessel or gear owners in Category III fisheries may receive authorization certificates even though they are not required for Category III fisheries. Individuals fishing in Category I and II fisheries for which no state or Federal license or permit is required must register with NMFS by contacting their appropriate Regional Office (see
In Alaska regional and Greater Atlantic regional fisheries, registrations of vessel or gear owners are automatically renewed and participants should receive an authorization certificate by January 1 of each new year. In Pacific Islands regional fisheries, vessel or gear owners receive an authorization certificate by January 1 for state fisheries and with their permit renewal for federal fisheries. In West Coast regional fisheries, vessel or gear owners receive authorization with each renewed state fishing license, the timing of which varies based on target species. Vessel or gear owners who participate in fisheries in these regions and have not received authorization certificates by January 1 or with renewed fishing licenses must contact the appropriate NMFS Regional Office (see
In Southeast regional fisheries, vessel or gear owners' registrations are automatically renewed and participants will receive a letter in the mail by January 1 instructing them to contact the Southeast Regional Office to have an authorization certificate mailed to them or to visit the Southeast Regional Office Web site (
In accordance with the MMPA (16 U.S.C. 1387(e)) and 50 CFR 229.6, any vessel owner or operator, or gear owner or operator (in the case of non-vessel fisheries), participating in a fishery listed on the LOF must report to NMFS all incidental mortalities and injuries of marine mammals that occur during commercial fishing operations, regardless of the category in which the fishery is placed (I, II, or III) within 48 hours of the end of the fishing trip or, in the case of non-vessel fisheries, fishing activity. “Injury” is defined in 50 CFR 229.2 as a wound or other physical harm. In addition, any animal that ingests fishing gear or any animal that is released with fishing gear entangling, trailing, or perforating any part of the body is considered injured, regardless of the presence of any wound or other evidence of injury, and must be reported.
Mortality/injury reporting forms and instructions for submitting forms to NMFS can be found at:
Individuals participating in a Category I or II fishery are required to accommodate an observer aboard their vessel(s) upon request from NMFS. MMPA section 118 states that the Secretary is not required to place an observer on a vessel if the facilities for quartering an observer or performing observer functions are so inadequate or unsafe that the health or safety of the observer or the safe operation of the vessel would be jeopardized; thereby authorizing the exemption of vessels too small to accommodate an observer from this requirement. However, U.S. Atlantic Ocean, Caribbean, or Gulf of Mexico large pelagics longline vessels operating in special areas designated by the Pelagic Longline Take Reduction Plan implementing regulations (50 CFR 229.36(d)) will not be exempted from observer requirements, regardless of their size. Observer requirements can be found in 50 CFR 229.7.
Table 4 in this rule provides a list of fisheries affected by TRPs and TRTs. TRP regulations can be found at 50 CFR 229.30 through 229.37. A description of each TRT and copies of each TRP can be found at:
Information regarding the LOF and the Marine Mammal Authorization Program, including: Registration procedures and forms; current and past LOFs; descriptions of each Category I and II fishery, and some Category III fisheries; observer requirements; and marine mammal mortality/injury reporting forms and submittal
NMFS, Greater Atlantic Regional Fisheries Office, 55 Great Republic Drive, Gloucester, MA 01930-2298, Attn: Allison Rosner;
NMFS, Southeast Region, 263 13th Avenue South, St. Petersburg, FL 33701, Attn: Jessica Powell;
NMFS, West Coast Region, Seattle Office, 7600 Sand Point Way NE., Seattle, WA 98115, Attn: Elizabeth Petras, Protected Resources Division;
NMFS, Alaska Region, Protected Resources, P.O. Box 22668, 709 West 9th Street, Juneau, AK 99802, Attn: Bridget Mansfield; or
NMFS, Pacific Islands Regional Office, Protected Resources Division, 1845 Wasp Blvd., Building 176, Honolulu, HI 96818, Attn: Dawn Golden.
NMFS reviewed the marine mammal incidental mortality and serious injury information presented in the SARs for all fisheries to determine whether changes in fishery classification are warranted. The SARs are based on the best scientific information available at the time of preparation, including the level of mortality and serious injury of marine mammals that occurs incidental to commercial fishery operations and the PBR levels of marine mammal stocks. The information contained in the SARs is reviewed by regional Scientific Review Groups (SRGs) representing Alaska, the Pacific (including Hawaii), and the U.S. Atlantic, Gulf of Mexico, and Caribbean. The SRGs were created by the MMPA to review the science that informs the SARs, and to advise NMFS on marine mammal population status, trends, and stock structure, uncertainties in the science, research needs, and other issues.
NMFS also reviewed other sources of new information, including marine mammal stranding data, observer program data, fisher self-reports through the Marine Mammal Authorization Program, reports to the SRGs, conference papers, FMPs, and ESA documents.
The LOF for 2016 was based on, among other things, stranding data; fisher self-reports; and SARs, primarily the 2014 SARs, which are generally based on data from 2008-2012. The final SARs referenced in this LOF include: 2013 (79 FR 49053, August 19, 2014) and 2014 (80 FR 50599, August 20, 2015). The SARs are available at:
NMFS received four comment letters on the proposed LOF for 2016 (80 FR 58427, September 29, 2015). Comments were received from the Marine Mammal Commission (Commission), Hawaii Longline Association (HLA), West Coast Seafood Processors Association (WCSPA), and a joint letter from Center for Biological Diversity (CBD) and Humane Society of the United States (HSUS).
We do not consider the various Hawaii commercial hook-and-line fisheries on the LOF to be analogous to the Category I or II Hawaii longline fisheries, given, for example, dissimilarities in fishing gear, technique, the number of hooks deployed, and areas fished. Additionally, there are no other hook-and-line fisheries listed as Category I or II on the LOF. At this time, the available information does not support reclassification by analogy of Hawaii hook-and-line fisheries, including the Hawaii troll fishery.
However, given the potential for MHI insular false killer whales to interact with hook-and-line fisheries, we are committed to working with the State of Hawaii and others to assess the frequency and severity of marine mammal interactions in state-managed fisheries and reduce impacts as appropriate. For example, NMFS researchers worked with the Hawaii Department of Land and Natural Resources (DLNR) to analyze marine mammal depredation data on State of Hawaii commercial catch reports (Boggs
The 2016 LOF is based on the 2014 SARs, which report fishery interactions from 2008-2012. NMFS deems this to be the best scientific and commercial information available for the time period examined. During that time period, NMFS estimates a five-year average mortality and serious injury level of 0.9 MHI insular and 0.4 NWHI false killer whales per year incidental to the Hawaii-based deep-set longline fishery from 2008-2012 (Carretta
NMFS is retaining the stocks on the list of marine mammal stocks incidentally killed or injured in the Hawaii deep-set longline fishery. We disagree with HLA's recommended text and are not including it because false killer whale interactions have been observed in the deep-set longline fishery within the area of overlap between the pelagic, MHI insular, and NWHI stocks of false killer whales as defined in the 2014 SAR. While no genetic samples are available to establish stock identity for these takes, all stocks are considered at risk of interacting with longline gear. For a more complete analysis of the methodology for determining mortality and serious injury of MHI insular false killer whales, NMFS refers the commenter to the 2014 SAR.
The 2005 mortalities were each included in the standard five-year data sets (resulting in an average 0.4 mortalities/year) used in LOF Tier I and II analyses for the 2007-2011 LOFs. Because of the uncertainty regarding the whales' stock identity, NMFS used the standard precautionary measure of using the lower PBR of the Western North Pacific stock in each year's LOF analysis, which resulted in both fisheries remaining in Category II for the 2007-2011 LOFs. Once they “aged” out of the standard five-year data set, those mortalities continued to be included in the LOF analyses four additional years (2012-2015) as a precautionary measure due to the rarity of documented humpback takes in purse seine fisheries (only two other humpback whale mortalities were previously documented in purse seine fisheries in Alaska in the mid-1990s, a mother and calf taken in one event) and because the fisheries were unobserved. Although the five-year data set used in the 2016 LOF is 2008-2012, no additional humpback whale mortalities were reported in Alaska Kodiak salmon purse seine and Cook Inlet salmon purse seine fisheries from 2013 through 2015. Further, the PBRs for each the Central and Western North Pacific humpback whale stocks have increased substantially since the initial 2005 mortalities. The PBR for the Central North Pacific humpback whales has increased from 12.9 in the 2006 SAR to 82.8 in the 2014 SAR used for the 2007 and 2016 LOFs, respectively. The PBR for the Western North Pacific humpback whales has likewise increased from 1.3 to 3.0 for those same years. Given the absence of other evidence to the contrary, ten years with no additional mortalities or serious injuries reported (since 2005 via the Stranding Network or fisherman self-reports) and a substantial increase in PBR for both North Pacific humpback whale stocks, NMFS is reclassifying the fisheries as Category III fisheries. NMFS will continue to review the most recent data and changes in these fisheries and will update the LOF, as appropriate.
As described in the preamble of the final 2009 LOF (73 FR 73032, December 1, 2008), the number of participants in the high seas fisheries, Table 3, is drawn from the National Permitting System database and does not necessarily reflect actual fishing activity. As shown on Table 1, there is one vessel actively engaged in longline fishing with a West Coast HMS permit. This vessel also has an HSFCA permit. A number of individuals hold West Coast HMS permits endorsed to longline (and HSFCA permits) but are not actively fishing with this gear type. In addition, a number of vessels fish with a HI pelagics FMP permit, but make landings in the U.S. West Coast, which requires a West Coast HMS FMP permit (see the HMS SAFE for more details). There are over 40 vessels with a HSFCA permit that hold both a HI pelagics HMS permit and a West Coast HMS permit, which allows them to fish with longline on the high seas (under the HI pelagics permit) and land into the U.S. West Coast (under the West Coast HMS permit).
The number of HSFCA permits issued by NMFS changes frequently as new permits are added or renewed, or old permits expire, and does not necessarily reflect the effort or vessels in a fishery. NMFS has promulgated a regulation (80 FR 62488, October 16, 2015) to improve the administration and monitoring of the HSFCA, effective January 14, 2016, and requires vessel operators or owners identify the authorized fishery in which he or she intends to fish when applying for an HSFCA permit. There are eight fisheries authorized on the high seas, including the U.S. West Coast Fisheries for Highly Migratory Species, and this regulation should improve the accuracy of Table 3 in the LOF.
Mid-Atlantic gillnet fisheries have been observed at the following percent coverage from 2009-2013: 3%, 4%, 2%, 2% and 3%, respectively. For this fishery, we recommended the removal of Risso's and white-sided dolphins from the list of species incidentally taken in this fishery. The last observed takes of Risso's and white-sided dolphins occurred in 2007 and 1997 when observer coverage was 4% and 3%, respectively. While observer coverage averaged 2.8% over the last five years, Mid-Atlantic gillnet sampling levels are in the developing to mature stage (
For the Mid-Atlantic mid-water trawl fishery, we proposed to remove short-beaked common dolphin, long-finned pilot whale, and short-finned pilot whale from this fishery. The last documented takes of these species in the Mid-Atlantic mid-water trawl fishery were in 2007. New genetic information on pilot whales (Waring
In the case of the Mid-Atlantic gillnet and Mid-Atlantic mid-water trawl fisheries, NMFS asserts observer coverage is adequate for determining if recent takes of certain species have occurred within these fisheries. The removal of these species from the list of species incidentally killed or injured from these respective fisheries does not impact the classification of the fisheries in question because other species taken are currently influencing the current classification. NMFS will continue to annually monitor bycatch of marine mammals in these fisheries and will make adjustments to Table 2 should incidental mortalities or injuries occur in the future.
NMFS retains the Category III fisheries, WA/OR sardine purse seine and CA anchovy, mackerel, sardine purse seine, as separate and does not merge and re-name the two fisheries “CA/OR/WA anchovy, mackerel, sardine purse seine” fishery, as proposed.
NMFS adds bottlenose dolphin, CA/OR/WA offshore, and humpback whale, CA/OR/WA, to the list of species and/or stocks incidentally killed or injured in the Category III CA spiny lobster fishery.
The following summarizes the changes to the LOF for 2016, including the fisheries listed in the LOF, the estimated number of vessels/persons in a particular fishery, and the species and/or stocks that are incidentally killed or injured in a particular fishery. In the LOF for 2016, NMFS re-classifies three fisheries. Additionally, NMFS adds two fisheries to the LOF and removes six fisheries from the LOF. NMFS makes changes to the list of species and/or stocks killed or injured in certain fisheries and the estimated number of vessels/persons in certain fisheries, as well as certain administrative changes. While detailed information describing each fishery in the LOF is included within the SARs, a Fishery Management Plan, or a TRP, or by state agencies, general descriptive information is important to include in the LOF for improved clarity; starting with the 2016 LOF, NMFS is releasing Category III fishery fact sheets as they are completed. The classifications and definitions of U.S. commercial fisheries for 2016 are identical to those provided in the LOF for 2015 with the changes discussed below. State and regional abbreviations used in the following paragraphs include: AK (Alaska), BSAI (Bering Sea and Aleutian Islands), CA (California), DE (Delaware), FL (Florida), GMX (Gulf of Mexico), HI (Hawaii), MA (Massachusetts), ME (Maine), NC (North Carolina), NY (New York), OR (Oregon), RI (Rhode Island), SC (South Carolina), VA (Virginia), WA (Washington), and WNA (Western North Atlantic).
NMFS reclassifies the Category III Alaska Bering Sea/Aleutian Island Pacific Cod Longline Fishery as Category II.
NMFS reclassifies the Category II Alaska Kodiak Salmon Purse Seine Fishery as Category III.
NMFS reclassifies the Category II Alaska Cook Inlet Salmon Purse Seine Fishery as Category III.
NMFS adds the CA sea cucumber trawl fishery to the LOF as Category III.
NMFS adds the WA/OR Mainstem Columbia River eulachon gillnet fishery to the LOF as Category III.
NMFS removes the Category III WA/OR herring, smelt, shad, sturgeon, bottom fish, mullet, perch, rockfish gillnet fishery from the LOF.
NMFS removes the Category III WA/OR smelt, herring dip net fishery from the LOF.
NMFS renames the Category III “WA (all species) beach seine or drag seine” as the “WA/OR Lower Columbia River salmon seine” fishery.
NMFS divides out three fisheries from the Category III “AK North Pacific
NMFS renames the Category III “WA/OR salmon net pens” fishery as the “WA salmon net pen” fishery.
NMFS renames (by revising, separating, and combining) the Category III “WA/OR sea urchin, other clam, octopus, oyster, sea cucumber, scallop, ghost shrimp, dive, hand/mechanical collection” and “CA sea urchin” fisheries to become the “WA/OR bait shrimp, clam hand, dive or mechanical collection” and “OR/CA sea urchin, sea cucumber dive, hand/mechanical collection” fisheries.
NMFS renames the Category III “WA shellfish aquaculture” fishery as the “WA/OR shellfish aquaculture” fishery.
NMFS updates the estimated number of vessels/persons in the Pacific Ocean (Table 1) as follows:
NMFS adds the southwest Alaska stock of northern sea otters to the list of species and/or stocks killed or injured in the Category II Alaska Peninsula/Aleutian Islands salmon set gillnet fishery.
NMFS adds the U.S. stock of California sea lions, unknown stock of harbor porpoise, unknown stock of harbor seals, California breeding stock of northern elephant seals, unknown stock of Steller sea lions to the species and/or stocks incidentally killed or injured by the Category III CA halibut bottom trawl fishery.
NMFS adds bottlenose dolphin, CA/OR/WA offshore, and humpback whale, CA/OR/WA, to the list of species and/or stocks killed or injured in the Category III CA spiny lobster fishery.
NMFS adds the Northwestern Hawaiian Islands stock of false killer whales to the list of species and/or stocks killed or injured in the Category I Hawaii deep-set longline fishery.
NMFS removes the Palmyra Atoll stock of false killer whales from the list of species and/or stocks killed or injured in the Category I Hawaii deep-set longline fishery.
NMFS adds notation “
NMFS adds the Gulf of Alaska, BSAI transient stock of killer whales to the list of species and/or stocks killed or injured in the Category II Alaska BSAI Pacific cod longline fishery.
NMFS removes notation “
NMFS renames and changes the geographic scope of the Category III “U.S. Mid-Atlantic offshore surf clam/quahog dredge” fishery.
NMFS updates the estimated number of vessels/persons in the Atlantic Ocean, Gulf of Mexico, and Caribbean (Table 2) as follows:
NMFS adds the Gulf of Maine/Bay of Fundy stock of harbor porpoise and the Gulf of Mexico stock of pygmy sperm whale to the list of marine mammal species and/or stocks incidentally killed or injured in the Category I Atlantic Ocean, Caribbean, Gulf of Mexico large pelagics longline fishery.
NMFS adds the Western North Atlantic stock of Risso's dolphin to the list of marine mammal species and/or stocks incidentally killed or injured in the Category II Northeast bottom trawl fishery.
NMFS adds the central Georgia estuarine system stock of bottlenose dolphin to the list of marine mammal species and/or stocks incidentally killed or injured in the Category II Atlantic blue crab trap/pot fishery.
NMFS removes the Western North Atlantic stocks of Risso's dolphin and white-sided dolphin from the list of marine mammal species and/or stocks incidentally killed or injured in the Category I Mid-Atlantic gillnet fishery.
NMFS removes the Western North Atlantic stocks of common dolphin, long-finned pilot whale, and short-finned pilot whale from the list of marine mammal species and/or stocks incidentally killed or injured in the Category II Mid-Atlantic mid-water trawl fishery.
NMFS removes the Western North Atlantic stocks of white-sided dolphin, long-finned pilot whale, and short-finned pilot whale from the list of marine mammal species and/or stocks incidentally killed or injured in the Category II Mid-Atlantic bottom trawl fishery.
NMFS removes the Western North Atlantic stocks of white-sided dolphin and short-finned pilot whale from the list of marine mammal species and/or stocks incidentally killed or injured in the Category II Northeast mid-water trawl fishery.
NMFS removes the Western North Atlantic stock of short-finned pilot whale from the list of marine mammal species and/or stock incidentally killed or injured in the Category II Northeast bottom trawl fishery.
NMFS removes the following Category II high seas fisheries from the List of Fisheries: (1) Western Pacific Pelagic Trawl, (2) Pacific Highly Migratory Species Liners, not elsewhere included (NEI), (3) South Pacific Albacore Troll Liners (NEI), and (4) Western Pacific Pelagic Liners (NEI).
NMFS updates the estimated number of HSFCA permits (Table 3) as follows:
The following tables set forth the list of U.S. commercial fisheries according to their classification under section 118 of the MMPA. Table 1 lists commercial fisheries in the Pacific Ocean (including Alaska); Table 2 lists commercial fisheries in the Atlantic Ocean, Gulf of Mexico, and Caribbean; Table 3 lists commercial fisheries on the high seas; and Table 4 lists fisheries affected by TRPs or TRTs.
In Tables 1 and 2, the estimated number of vessels or persons participating in fisheries operating within U.S. waters is expressed in terms of the number of active participants in the fishery, when possible. If this information is not available, the estimated number of vessels or persons licensed for a particular fishery is provided. If no recent information is available on the number of participants, vessels, or persons licensed in a fishery, then the number from the most recent LOF is used for the estimated number of vessels or persons in the fishery. NMFS acknowledges that, in some cases, these estimates may be inflations of actual effort. For example, the State of Hawaii does not issue fishery-specific licenses, and the number of participants reported in the LOF represents the number of commercial marine license holders who reported using a particular fishing gear type/method at least once in a given year, without considering how many times the gear was used. For these fisheries, effort by a single participant is counted the same whether the fisher used the gear only once or every day. In the Mid-Atlantic and New England fisheries, the numbers represent the potential effort for each fishery, given the multiple gear types for which several state permits may allow. Changes made to Mid-Atlantic and New England fishery participants will not affect observer coverage or bycatch estimates, as observer coverage and bycatch estimates are based on vessel trip reports and landings data. Tables 1 and 2 serve to provide a description of the fishery's potential effort (state and Federal). If NMFS is able to extract more accurate information on the gear types used by state permit holders in the future, the numbers will be updated to reflect this change. For additional information on fishing effort in fisheries found on Table 1 or 2, contact the relevant regional office (contact information included above in
For high seas fisheries, Table 3 lists the number of valid HSFCA permits currently held. Although this likely overestimates the number of active participants in many of these fisheries, the number of valid HSFCA permits is the most reliable data on the potential effort in high seas fisheries at this time. As noted previously in this rule, the number of HSFCA permits listed in Table 3 for the high seas components of fisheries that also operate within U.S. waters does not necessarily represent additional effort that is not accounted for in Tables 1 and 2. Many vessels holding HSFCA permits also fish within U.S. waters and are included in the number of vessels and participants operating within those fisheries in Tables 1 and 2.
Tables 1, 2, and 3 also list the marine mammal species and/or stocks incidentally killed or injured (seriously or non-seriously) in each fishery based on SARs, injury determination reports, bycatch estimation reports, observer data, logbook data, stranding data, disentanglement network data, fisher self-reports (
In Tables 1 and 2, there are several fisheries classified as Category II that have no recent documented mortalities or serious injuries of marine mammals, or fisheries that did not result in a mortality or serious injury rate greater than 1 percent of a stock's PBR level based on known interactions. NMFS has classified these fisheries by analogy to other Category I or II fisheries that use similar fishing techniques or gear that are known to cause mortality or serious injury of marine mammals, as discussed in the final LOF for 1996 (60 FR 67063, December 28, 1995), and according to factors listed in the definition of a “Category II fishery” in 50 CFR 229.2 (
There are several fisheries in Tables 1, 2, and 3 in which a portion of the fishing vessels cross the exclusive economic zone (EEZ) boundary and therefore operate both within U.S. waters and on the high seas. These fisheries, though listed separately between Table 1 or 2 and Table 3, are considered the same fisheries on either side of the EEZ boundary. NMFS has designated those fisheries in each table by a “*” after the fishery's name.
The Chief Counsel for Regulation of the Department of Commerce has certified to the Chief Counsel for Advocacy of the Small Business Administration (SBA) at the proposed rule stage that this rule would not have a significant economic impact on a substantial number of small entities. No comments were received on that certification, and no new information has been discovered to change that conclusion. Accordingly, no regulatory flexibility analysis is required, and none has been prepared.
This rule contains collection-of-information requirements subject to the Paperwork Reduction Act. The collection of information for the registration of individuals under the MMPA has been approved by the Office of Management and Budget (OMB) under OMB control number 0648-0293 (0.15 hours per report for new registrants and 0.09 hours per report for renewals). The requirement for reporting marine mammal mortalities or injuries has been approved by OMB under OMB control number 0648-0292 (0.15 hours per report). These estimates include the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding these reporting burden estimates or any other aspect of the collections of information, including suggestions for reducing burden, to NMFS and OMB (see
Notwithstanding any other provision of law, no person is required to respond to nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a currently valid OMB control number.
This rule has been determined to be not significant for the purposes of Executive Order 12866.
An environmental assessment (EA) was prepared under the National Environmental Policy Act (NEPA) in 1995 and 2005. The 1995 EA examined the effects of regulations implementing section 118 of the 1994 Amendments of the MMPA on the affected environment. The 2005 EA analyzed the environmental impacts of continuing the existing scheme (as described in the 1995 EA) for classifying fisheries on the LOF. The 1995 EA and the 2005 EA concluded that implementation of MMPA section 118 regulations would not have a significant impact on the human environment. NMFS reviewed the 2005 EA in 2009. NMFS concluded that because there were no changes to the process used to develop the LOF and implement section 118 of the MMPA, there was no need to update the 2005 EA. This rule would not change NMFS's current process for classifying fisheries on the LOF; therefore, this rule is not expected to change the analysis or conclusion of the 2005 EA and FONSI, and no update is needed. If NMFS takes a management action, for example, through the development of a TRP, NMFS would first prepare an environmental document, as required under NEPA, specific to that action.
This rule would not affect species listed as threatened or endangered under the Endangered Species Act (ESA) or their associated critical habitat. The impacts of numerous fisheries have been analyzed in various biological opinions, and this rule will not affect the conclusions of those opinions. The
This rule would have no adverse impacts on marine mammals and may have a positive impact on marine mammals by improving knowledge of marine mammals and the fisheries interacting with marine mammals through information collected from observer programs, stranding and sighting data, or take reduction teams.
This rule would not affect the land or water uses or natural resources of the coastal zone, as specified under section 307 of the Coastal Zone Management Act.
Allen, B.M. and R.P. Angliss, editors. 2015. Alaska Marine Mammal Stock Assessments, 2014. NOAA Tech. Memo. NMFS-AFSC-301. 270 p.
Boggs, C.H., D.P. Gonzales, and R.M. Kokubun. 2015. Marine mammals reported under catch lost to predators on fishermen's commercial catch reports to the State of Hawaii, 2003-2014. NMFS Pacific Islands Fisheries Science Center Data Report DR-15-006. 14 p.
Carretta, J.V., E. Oleson, D.W. Weller, A.R. Lang, K.A. Forney, J. Baker, B. Hanson, K Martien, M.M. Muto, M.S. Lowry, J. Barlow, D. Lynch, L. Carswell, R.L. Brownell Jr., D.K. Mattila, and M.C. Hill. 2015. U.S. Pacific Marine Mammal Stock Assessments: 2014. NOAA Technical Memorandum NOAA-TM-NMFS-SWFSC-549. 78 p.
Hatfield, B.B., J.A. Ames, J.A. Estes, M.T. Tinker, A.B. Johnson, M.M. Staedler, and M.D. Harris. 2011. Sea otter mortality in fish and shellfish traps: estimating potential impacts and exploring possible solutions. Endangered Species Research 13:219-229.
McCracken, M.L. 2010. Adjustments to false killer whale and short-finned pilot whale bycatch estimates. NMFS Pacific Islands Fisheries Science Center Working Paper WP-10-007. 23 p.
McCracken, M.L. 2014. Assessment of Incidental Interactions with Marine Mammals in the Hawaii Deep and Shallow Set Fisheries from 2008 through 2012. NMFS Pacific Islands Fisheries Science Center, PIFSC Internal Report IR-14-006. 1 p. + Excel spreadsheet.
NMFS (National Marine Fisheries Service). 2004. Evaluating bycatch: a national approach to standardized bycatch monitoring programs. U.S. Dep. Commer., NOAA Tech. Memo. NMFSF/SPO-66, 108 p. On-line version,
Waring, G.T., E. Josephson, K. Maze-Foley, and P.E. Rosel, editors. 2015a. U.S. Atlantic and Gulf of Mexico Marine Mammal Stocks Assessments, 2014. NOAA Technical Memorandum NOAA-NE-231. 355 p.
Waring, G.T., E. Josephson, K. Maze-Foley, and P.E. Rosel, editors. 2015b. Draft U.S. Atlantic and Gulf of Mexico Marine Mammal Stocks Assessments, 2015. NOAA Technical Memorandum NOAA-NE-xxx. 524 p. Available at:
Animal and Plant Health Inspection Service, USDA.
Proposed rule.
We are proposing to amend the fruits and vegetables regulations to allow the importation of fresh pitahaya fruit into the continental United States from Ecuador. As a condition of entry, the fruit would have to be produced in accordance with a systems approach that would include requirements for fruit fly trapping, pre-harvest inspections, approved production sites, and packinghouse procedures designed to exclude quarantine pests. The fruit would also be required to be imported in commercial consignments and accompanied by a phytosanitary certificate issued by the national plant protection organization of Ecuador stating that the consignment was produced and prepared for export in accordance with the requirements of the systems approach. This action would allow for the importation of fresh pitahaya from Ecuador while continuing to provide protection against the introduction of plant pests into the United States.
We will consider all comments that we receive on or before June 7, 2016.
You may submit comments by either of the following methods:
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Supporting documents and any comments we receive on this docket may be viewed at
Ms. Claudia Ferguson, M.S., Senior Regulatory Policy Specialist, Regulatory Coordination and Compliance, Imports, Regulations and Manuals, PPQ, APHIS, (301) 851-2352; email:
The regulations in “Subpart-Fruits and Vegetables” (7 CFR 319.56-1 through 319.56-75, referred to below as the regulations) prohibit or restrict the importation of fruits and vegetables into the United States from certain parts of the world to prevent the introduction and dissemination of plant pests. The regulations currently do not authorize the importation of fresh pitahaya fruit (sometimes referred to as “dragon fruit”) from Ecuador.
The national plant protection organization (NPPO) of Ecuador has requested that the Animal and Plant Health Inspection Service (APHIS) amend the regulations in order to allow fresh fruit of any color of pitahaya (
As part of our evaluation of Ecuador's request, we prepared a pest risk assessment (PRA) and a risk management document (RMD). Copies of the PRA and the RMD may be obtained from the person listed under
The PRA, titled “Importation of Pitahaya from Ecuador into the Continental United States (August 2013),” evaluates the risks associated with the importation of fresh pitahaya fruit from Ecuador into the United States. The RMD relies upon the findings of the PRA to determine the phytosanitary measures necessary to ensure the safe importation into the continental United States of fresh pitahaya from Ecuador.
The PRA identifies one quarantine pest present in Ecuador that could be introduced into the United States through the importation of fresh pitahaya:
A quarantine pest is defined in § 319.56-2 of the regulations as a pest of potential economic importance to the area endangered thereby and not yet present there, or present but not widely distributed and being officially controlled. Potential plant pest risks associated with the importation of fresh pitahaya from Ecuador into the continental United States were determined by estimating the consequences and likelihood of introduction of quarantine pests into the United States and ranking the risk potential as high, medium, or low. The PRA rated the insect
APHIS has determined that measures beyond standard port of arrival inspection are required to mitigate the risks posed by this plant pest. Therefore, we are proposing to allow the importation of fresh pitahaya from Ecuador into the continental United States produced under a systems approach. The RMD prepared for fresh pitahaya from Ecuador identifies a systems approach of specific mitigation measures against the quarantine pest identified in the PRA and concludes that those measures, along with the general requirements for the importation of fruits and vegetables in the regulations, will be sufficient to prevent the introduction of this pest into the United States. Therefore, we are proposing to add the systems approach to the regulations in a new § 319.56-76. The proposed measures are described below.
Paragraph (a) of proposed § 319.56-76 would require the NPPO of Ecuador to provide an operational workplan to APHIS that details the activities that the NPPO would, subject to APHIS' approval of the workplan, carry out to meet the requirements of proposed § 319.56-76. An operational workplan is an agreement developed between APHIS' Plant Protection and Quarantine program, officials of the NPPO of a foreign government, and, when necessary, foreign commercial entities, that specifies in detail the phytosanitary measures that will be carried out to comply with our regulations governing the importation of a specific commodity. Operational workplans apply only to the signatory parties and establish detailed procedures and guidance for the day-to-day operations of specific import/export programs. Operational workplans also establish how specific phytosanitary issues are dealt with in the exporting country and make clear who is responsible for dealing with those issues. The implementation of a systems approach typically requires an operational workplan to be developed.
Paragraph (b) of proposed § 319.56-76 would require fresh pitahaya from Ecuador to be imported in commercial consignments only. Produce grown commercially is less likely to be infested with plant pests than noncommercial consignments. Noncommercial consignments are more prone to infestations because the commodity is often ripe to overripe, could be of a variety with unknown susceptibility to pests, and is often grown with little or no pest control.
Paragraph (c)(1) of proposed § 319.56-76 would require that all production sites participating in the fresh pitahaya export program be approved by and registered with the NPPO of Ecuador in accordance with the requirements of the operational workplan. Such registration would facilitate traceback of a consignment of pitahayas to the production site in the event that quarantine pests were discovered in the consignment at the packinghouse, or at the first port of arrival into the United States.
Paragraph (c)(2) of proposed § 319.56-76 would require that trees and other structures, other than the crop itself, not shade the crop during the day. No other host of
Paragraph (c)(3) of proposed § 319.56-76 would require the NPPO of Ecuador or its approved designee
Paragraph (c)(4) of proposed § 319.56-76 would require trapping for the fruit fly
Paragraph (c)(5) would state that, if more than an average of 0.07
Paragraph (c)(6) of proposed § 319.56-76 would require the NPPO of Ecuador to maintain records of trap placement, trap checks, and any quarantine pest captures in accordance with the operational workplan. Trapping records would have to be maintained for APHIS' review for at least 1 year.
We are proposing several requirements for packinghouse activities, which would be contained in paragraph (d) of proposed § 319.56-76.
Paragraph (d)(1) would state that the NPPO of Ecuador must monitor packinghouse operations to verify that the packinghouses are complying with the requirements of the systems approach. If the NPPO of Ecuador finds that a packinghouse is not complying with the requirements of the systems approach, no pitahaya fruit from the packinghouse will be eligible for export to the continental United States until APHIS and the NPPO of Ecuador conduct an investigation and both agree that the pest risk has been mitigated.
Paragraph (d)(2) would require that fresh pitahaya be packed in a packinghouse registered with the NPPO of Ecuador. Such registration would facilitate traceback of a consignment of pitahaya fruit to the packinghouse in which it was packed in the event that quarantine pests were discovered in the consignment at the port of first arrival into the United States.
Paragraph (d)(3) would require that the pitahaya be packed within 24 hours of harvest in a pest-exclusionary packinghouse that meets the requirements of the operational workplan. The pitahaya would have to be safeguarded by an insect-proof mesh screen or plastic tarpaulin while in transit to the packinghouse and while awaiting packing. These safeguards would have to remain intact until arrival in the continental United States or the consignment would be denied entry.
Paragraph (d)(4) of proposed § 319.56-76 would require that during the time that the packinghouse is in use for exporting fresh pitahayas to the continental United States, the packinghouse would only be allowed to accept pitahayas from registered production sites. This requirement would prevent such pitahayas intended for export to the continental United States from being exposed to or otherwise mixed with pitahayas that are not produced according to the requirements of the systems approach.
Paragraph (e)(1) of proposed § 319.56-76 would require that a biometric sample of pitahaya fruit jointly agreed upon by APHIS and the NPPO of Ecuador would need to be inspected in Ecuador by the NPPO of Ecuador following post-harvest processing. The biometric sample would be visually inspected for any quarantine pests, and a portion of the fruit would be cut open to detect internal signs of
Paragraph (e)(2) would require that fruit presented for inspection at the port of entry to the United States be identified in the shipping documents accompanying each lot of fruit to specify the production site or sites, in which the fruit was produced, and the packing shed or sheds, in which the fruit was processed, in accordance with the requirements in the operational workplan. This identification would need to be maintained until the fruit is released for entry into the continental United States. The pitahaya fruit are subject to inspection at the port of entry for all quarantine pests of concern, including
To certify that the fresh pitahaya fruit from Ecuador has been grown and packed in accordance with the requirements of proposed § 319.56-76, paragraph (f) would require each consignment of fruit to be accompanied by a phytosanitary certificate issued by the NPPO of Ecuador, with an additional declaration stating that the fruit in the consignment was produced and prepared for export in accordance with the requirements of § 319.56-76.
The proposed rule has been determined to be Not Significant for the purposes of Executive Order 12866 and, therefore, has not been reviewed by the Office of Management and Budget.
In accordance with 5 U.S.C. 603, we have performed an initial regulatory flexibility analysis, which is summarized below, regarding the economic effects of this proposed rule on small entities. Copies of the full analysis are available by contacting the person listed under
Based on the information we have, there is no reason to conclude that adoption of this proposed rule would result in any significant economic effect on a substantial number of small entities. However, we do not currently have all of the data necessary for a comprehensive analysis of the effects of this proposed rule on small entities. Therefore, we are inviting comments on potential effects. In particular, we are interested in determining the number and kind of small entities that may incur benefits or costs from the implementation of this proposed rule.
The proposed rule would amend the regulations to allow the importation of fresh pitahaya (of any color) (
APHIS has been marginally successful in acquiring information on the U.S. market for pitahaya fruit. At this point, we do not know the quantity of pitahaya fruit domestically produced, numbers of U.S. producers, the total quantity imported, or other factors needed to assess likely economic effects of this rule. Vietnam, the largest exporter of pitahaya to the United States, shipped 1,300 metric tons of the fruit to the United States in 2013. It is unknown what percentage of the total supply this represents. Domestically, pitahaya fruit is produced in Hawaii, California, and Florida. Hawaii's pitahaya production is mainly consumed within that State.
The quantity of pitahaya fruit that would be imported from Ecuador is unknown. In 2014, Ecuador exported about 165 metric tons of pitahaya to 32 countries. They have indicated that, if this proposed rule is finalized, they expect to divert 147 shipments to the United States per year. Given that there is no consistent indication of the expected individual size of these shipments, it is unknown what percentage of the total exported tonnage this would represent, or the total quantity of these shipments. Lack of information about the quantity of pitahaya fruit that would be imported, and about the quantities produced by the United States, prevents a clear understanding of what the economic effects of the proposed rule may be.
This proposed rule would allow fresh pitahaya to be imported into the continental United States from Ecuador. If this proposed rule is adopted, State and local laws and regulations regarding fresh pitahaya imported under this rule would be preempted while the fruit is in foreign commerce. Fresh fruit are generally imported for immediate distribution and sale to the consuming public and would remain in foreign commerce until sold to the ultimate consumer. The question of when foreign commerce ceases in other cases must be addressed on a case-by-case basis. If this proposed rule is adopted, no retroactive effect will be given to this rule, and this rule will not require administrative proceedings before parties may file suit in court challenging this rule.
In accordance with section 3507(d) of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
APHIS is proposing to amend the fruits and vegetables regulations to allow the importation of fresh pitahaya fruit into the continental United States from Ecuador. As a condition of entry, the fruit would have to be produced in accordance with a systems approach that would include requirements for fruit fly trapping, pre-harvest inspections, production sites, and packinghouse procedures designed to exclude quarantine pests. The fruit would also be required to be imported in commercial consignments and be accompanied by a phytosanitary certificate issued by the NPPO of Ecuador stating that the consignment was produced and prepared for export in accordance with the requirements in the systems approach.
This action would allow for the importation of fresh pitahaya fruit from Ecuador while continuing to provide
Allowing the importation of fresh pitahaya fruit into the continental United States from Ecuador would require an operational workplan, registered production sites, trapping records, inspections, monitoring, packinghouse registrations, box labeling, shipping documents, and phytosanitary certificates.
We are soliciting comments from the public (as well as affected agencies) concerning our proposed information collection and recordkeeping requirements. These comments will help us:
(1) Evaluate whether the proposed information collection is necessary for the proper performance of our agency's functions, including whether the information will have practical utility;
(2) Evaluate the accuracy of our estimate of the burden of the proposed information collection, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the information collection on those who are to respond (such as through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology;
Copies of this information collection can be obtained from Ms. Kimberly Hardy, APHIS' Information Collection Coordinator, at (301) 851-2727.
The Animal and Plant Health Inspection Service is committed to compliance with the EGovernment Act to promote the use of the Internet and other information technologies, to provide increased opportunities for citizen access to Government information and services, and for other purposes. For information pertinent to E-Government Act compliance related to this proposed rule, please contact Ms. Kimberly Hardy, APHIS' Information Collection Coordinator, at (301) 851-2727.
The Security and Accountability for Every Port Act of 2006
Coffee, Cotton, Fruits, Imports, Logs, Nursery stock, Plant diseases and pests, Quarantine, Reporting and recordkeeping requirements, Rice, Vegetables.
Accordingly, we propose to amend 7 CFR part 319 as follows:
7 U.S.C. 450, 7701-7772, and 7781-7786; 21 U.S.C. 136 and 136a; 7 CFR 2.22, 2.80, and 371.3.
Fresh pitahaya (
(a)
(b)
(c)
(2) Trees and other structures, other than the crop itself, must not shade the crop during the day. No other host of
(3) The production sites must be inspected prior to each harvest by the NPPO of Ecuador or its approved designee in accordance with the operational workplan. An approved designee is an entity with which the NPPO creates a formal agreement that allows that entity to certify that the appropriate procedures have been followed. If APHIS or the NPPO of Ecuador finds that a place of production is not complying with the requirements of the systems approach, no fruit from the place of production will be eligible for export to the continental United States until APHIS and the NPPO of Ecuador conduct an investigation and appropriate remedial actions have been implemented.
(4) The registered production sites must conduct trapping for the fruit fly
(5) If more than an average of 0.07
(6) The NPPO of Ecuador must maintain records of trap placement, checking of traps, and any quarantine pest captures in accordance with the operational workplan. Trapping records must be maintained for APHIS review for at least 1 year.
(d)
(2) All packinghouses that participate in the pitahaya export program must be registered with the NPPO of Ecuador.
(3) The pitahaya fruit must be packed within 24 hours of harvest in a pest-exclusionary packinghouse. The pitahaya must be safeguarded by an insect-proof mesh screen or plastic tarpaulin while in transit to the packinghouse and while awaiting packing. These safeguards must remain intact until arrival in the continental United States or the consignment will be denied entry.
(4) During the time the packinghouse is in use for exporting pitahaya fruit to the continental United States, the packinghouse may only accept pitahaya fruit from registered production sites.
(e)
(2) Pitahaya fruit presented for inspection at the port of entry to the United States must be identified in the shipping documents accompanying each lot of fruit to specify the production site or sites, in which the fruit was produced, and the packing shed or sheds, in which the fruit was processed, in accordance with the requirements in the operational workplan. This identification must be maintained until the fruit is released for entry into the continental United States. The pitahaya fruit are subject to inspection at the port of entry for all quarantine pests of concern, including
(f)
Board of Governors of the Federal Reserve System.
Notice of proposed rulemaking.
The Board of Governors of the Federal Reserve System (Board) is inviting public comment on proposed clarifying revisions (proposed rule) to the Board's rule regarding risk-based capital surcharges for U.S. based global systemically important bank holding companies (GSIB surcharge rule). The proposed rule proposed rule would modify the GSIB surcharge rule to provide that a bank holding company subject to the rule would continue to calculate its method 1 and method 2 GSIB surcharge scores annually using data as of December 31 of the previous calendar year, even though the data will be due quarterly beginning with the June 30, 2016, report. In addition, the proposed rule would clarify that a bank holding company subject to the GSIB surcharge rule is required to calculate its method 2 GSIB surcharge score using systemic indicator amounts expressed in billions of dollars even though the data is reported in millions of dollars. The preamble to the proposed rule also provides clarifying information on how a covered bank holding company should calculate its short-term wholesale funding score for purposes of calculating its method 2 score under the GSIB surcharge rule.
Comments must be received May 13, 2016.
When submitting comments, please consider submitting your comments by email or fax because paper mail in the Washington, DC area and at the Board may be subject to delay. You may submit comments, identified by Docket No. R-1535 and RIN 7100 AE-49, by any of the following methods:
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All public comments will be made available on the Board's Web site at
Anna Lee Hewko, Associate Director, (202) 530-6260, Constance M. Horsley, Assistant Director, (202) 452-5239, Juan C. Climent, Manager, (202) 872-7526, or Holly Kirkpatrick, Supervisory Financial Analyst, (202) 452-2796, Division of Banking Supervision and Regulation; or Benjamin McDonough, Special Counsel, (202) 452-2036, Mark Buresh, Senior Attorney, (202) 452-
Section 165 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) authorizes the Board to establish enhanced prudential standards for bank holding companies with $50 billion or more in total consolidated assets and for nonbank financial companies that the Financial Stability Oversight Council has designated for supervision by the Board.
The GSIB surcharge rule works to mitigate the potential risk that the material financial distress or failure of a GSIB could pose to U.S. financial stability by increasing the stringency of capital standards for GSIBs, thereby increasing the resiliency of these firms. The GSIB surcharge rule takes into consideration the nature, scope, size, scale, concentration, interconnectedness, and mix of activities of each company subject to the rule. These factors are reflected in the GSIB surcharge rule's method 1 and method 2 scores, which use quantitative metrics reported on the FR Y 15 reporting form to measure the firm's systemic footprint. A bank holding company whose method 1 score exceeds a defined threshold is identified as a GSIB. Bank holding companies that are identified as GSIBs under the GSIB surcharge rule must calculate their method 1 and method 2 scores each year using data reported on a firm's FR Y-15 as of December 31 of the prior year. GSIB surcharges are established using these scores, and GSIBs with higher scores are subject to higher GSIB surcharges.
Method 1 uses five equally-weighted categories that are correlated with systemic importance—size, interconnectedness, cross-jurisdictional activity, substitutability, and complexity—and these categories are subdivided into twelve systemic indicators.
The FR Y-15 reporting form collects systemic risk data from U.S. bank holding companies and covered savings and loan holding companies
The FR Y-15, as implemented on December 31, 2012, is an annual report that collects data regarding a firm's systemic risk.
The proposed rule would revise the GSIB surcharge rule to require continued use of a December 31 as-of date for purposes of a bank holding company's calculation of its method 1 and method 2 scores. In particular, the proposed rule would revise sections 217.404 and 217.405 of the GSIB surcharge rule, which are the sections that describe the methodology for calculating a firm's method 1 and method 2 scores, respectively. The revisions to sections 217.404 and 217.405 would clarify that the systemic indicator amount used in the calculations would be drawn from a firm's FR Y-15 as of December 31 of the previous calendar year even after the FR Y-15 becomes a quarterly report.
The proposed rule would revise section 217.405 of the Board's Regulation Q to clarify that, for purposes of calculating its method 2 score, a GSIB should convert its systemic indicator amounts as reported on the FR Y-15 in millions of dollars to billions of dollars. The FR Y-15 requires these data to be reported in millions of dollars, while the fixed coefficients used in the calculation of a firm's method 2 score were determined using aggregate data expressed in billions of dollars.
A firm subject to the GSIB surcharge rule must calculate a short-term wholesale funding score in order to calculate the denominator of its method 2 GSIB surcharge, if any.
As it relates to the numerator used in the short-term wholesale funding score calculation, the GSIB surcharge rule contains a transition provision that directs firms identified as GSIBs to determine the average of their weighted short-term wholesale funding amounts for the GSIB surcharge in effect beginning January 1, 2016, and January 1, 2017, by averaging their weighted short-term wholesale funding amounts on July 31, 2015, August 24, 2015, and September 30, 2015.
The Board seeks comment on all aspects of the proposed revisions to the GSIB surcharge rule.
There is no new collection of information pursuant to the PRA (44 U.S.C. 3501
The Board is providing an initial regulatory flexibility analysis with respect to this proposed rule. The Regulatory Flexibility Act, 5 U.S.C. 601
The proposed rule would apply only to advanced approaches bank holding companies, which, generally, are bank holding companies with total consolidated assets of $250 billion or more, that have total consolidated on-balance sheet foreign exposures of $10 billion or more, that have subsidiary depository institutions that are advanced approaches institutions, or that elect to use the advanced approaches framework.
Because the proposed rule is not likely to apply to any bank holding company with assets of $550 million or less, if adopted in final form, it is not expected to apply to any small bank holding company for purposes of the RFA. The Board does not believe that
In determining the effective date and administrative compliance requirements for new regulations that impose additional reporting, disclosure, or other requirements on state member banks, the Board is required to consider, consistent with the principles of safety and soundness and the public interest, any administrative burdens that such regulations would place on depository institutions, and the benefits of such regulations.
The proposed revision to the Board's GSIB surcharge rule are only applicable to advanced approaches bank holding companies. Therefore, these requirements are not applicable to this proposed rule.
Section 722 of the Gramm-Leach-Bliley Act requires the Board to use plain language in all proposed and final rules published after January 1, 2000. The Board has sought to present the proposed rule in a simple straightforward manner, and invites comment on the use of plain language. For example:
• Has the Board organized the material to suit your needs? If not, how could the Board present the proposed rule more clearly?
• Are the requirements in the proposed rule clearly stated? If not, how could the proposed rule be more clearly stated?
• Do the regulations contain technical language or jargon that is not clear? If so, which language requires clarification?
• Would a different format (grouping and order of sections, use of headings, paragraphing) make the regulation easier to understand? If so, what changes would achieve that?
• Is the section format adequate? If not, which of the sections should be changed and how?
• What other changes can the Board incorporate to make the regulation easier to understand?
Administrative practice and procedure, Banks, Banking, Holding companies, Reporting and recordkeeping requirements, Securities.
For the reasons set forth in the preamble, the Board proposes to amend chapter II of title 12 of the Code of Federal Regulations as follows:
12 U.S.C. 248(a), 321-338a, 481-486, 1462a, 1467a, 1818, 1828, 1831n, 1831o, 1831p-l, 1831w, 1835, 1844(b), 1851, 3904, 3906-3909, 4808, 5365, 5368, 5371.
(b)
(i) The ratio of:
(A) The amount of that systemic indicator, as reported by the bank holding company as of December 31 of the previous calendar year; to
(B) The aggregate global indicator amount for that systemic indicator published by the Board in the fourth quarter of that year;
(ii) Multiplied by 10,000; and
(iii) Multiplied by the indicator weight corresponding to the systemic indicator as set forth in Table 1 of this section.
(b)
(1) The amount of the systemic indicator, as reported by the bank holding company as of December 31 of the previous calendar year, expressed in billions of dollars;
Federal Aviation Administration (FAA), DOT.
Notice of meetings.
This notice announces three fact-finding informal airspace meetings to solicit information from airspace users and others concerning a proposal to amend the Class B airspace area at San Diego, CA. The purpose of these meetings is to provide interested parties an opportunity to present views, recommendations, and comments on the proposal. All comments received during these meetings will be considered prior to any revision or issuance of a notice of proposed rulemaking.
The meetings will be held on Tuesday, June 28, 2016, at 6:00 p.m.; Wednesday, June 29, 2016, at 6:00 p.m.; and Thursday, June 30, 2016, at 6:00 p.m. Doors open 30 minutes prior to the beginning of each meeting. Comments must be received on or before August 15, 2016.
All meetings will be held at San Diego International Airport, Commuter Airport Terminal, 3225 North Harbor Drive, San Diego, CA 92101.
Brian Fagan, FAA Support Manager, Southern California TRACON, 9175
(a) The meetings will be informal in nature and will be conducted by one or more representatives of the FAA Western Service Center and Southern California TRACON. A representative from the FAA will present a briefing on the planned modification to the Class B airspace at San Diego, CA. Each participant will be given an opportunity to deliver comments or make a presentation, although a time limit may be imposed. Only comments concerning the plan to modify the San Diego Class B airspace will be accepted.
(b) The meetings will be open to all persons on a space-available basis. There will be no admission fee to attend and participate. Parking will be validated. Attendees needing parking validation should bring their parking stub to the meeting.
(c) Any person wishing to make a presentation to the FAA panel will be asked to sign in and estimate the amount of time needed for such presentation. This will permit the panel to allocate an appropriate amount of time for each presenter. These meetings will not be adjourned until everyone on the list has had an opportunity to address the panel.
(d) Position papers or other handout material relating to the substance of these meetings will be accepted. Participants wishing to submit handout material should present an original and two copies (three copies total) to the presiding officer. There should be additional copies of each handout available for other attendees.
(e) These meetings will not be formally recorded. However, a summary of comments made at the meeting will be filed in the docket.
49 U.S.C. 106(f), 106(g); 40103, 40113, 40120; E.O.10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.
Commodity Futures Trading Commission; Securities and Exchange Commission.
Proposed guidance.
In accordance with section 712(d)(4) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), the Commodity Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (“SEC”), after consultation with the Board of Governors of the Federal Reserve System (“Board of Governors”), are jointly issuing the CFTC's proposed guidance on certain contracts that provide for rights and obligations with respect to electric power and natural gas. The CFTC invites public comment on all aspects of its proposed guidance.
Comments must be received on or before May 9, 2016.
You may submit comments by any of the following methods:
•
•
•
•
Please submit your comments using only one of these methods.
All comments must be submitted in English, or if not, accompanied by an English translation. Comments will be posted as received to
The CFTC reserves the right, but shall have no obligation, to review, pre-screen, filter, redact, refuse or remove any or all of a submission from
CFTC: David N. Pepper, Special Counsel, Division of Market Oversight, at (202) 418-5565 or
In the final rule further defining the term “swap,” the CFTC and the SEC adopted an interpretation regarding the facts and circumstances in which certain agreements, contracts, or transactions entered into by commercial and non-profit entities should be considered not to be swaps because they are customary commercial arrangements.
Having reviewed these comments, the CFTC proposes to issue guidance regarding particular facts and specific circumstances in which these contracts should be considered not to be “swaps” for purposes of the Commodity Exchange Act (“CEA”).
Commenters described two types of contracts that are similar in some respects, but are used in different situations to provide for rights and obligations that are suitable to the parties' particular needs in those situations, and which are closely tied to compliance with certain regulatory requirements and frameworks. Each is described briefly below.
The CFTC understands that certain types of capacity contracts in electric power markets are used in situations where regulatory requirements from a state public utility commission (“PUC”) obligate load serving entities (“LSEs”) and load serving electric utilities in that state to purchase “capacity” (sometimes referred to as “resource adequacy”)
A commenter said the purchaser does not treat this type of capacity contract as a “hedge” in the same sense as it would otherwise use a commodity option as a financial hedge.
A commenter explained how the payment structure under a capacity contract for resource adequacy is different from the payment structure under a financially-settled commodity option. According to this commenter, capacity contracts do not involve payment of a nominal option premium, followed by payment of the full market price of the electric power if and when the “option” is exercised.
Commenters requested further guidance on whether certain natural gas contracts, which commenters labeled as “peaking supply contracts,” and which are entered into by electric utilities (with or without a minimum gas delivery requirement) should be regulated as swaps.
Linden represented that, under its natural gas service agreements, the LDCs determine when the conditions for interrupting Linden's service are present, and Linden therefore has no control over such conditions. Thus, Linden does not have discretion as to whether and when an interruption of service as described above will occur.
Linden explained that, under the terms of its natural gas service agreements, Linden is required to take natural gas from the LDCs if they supply it. There is no ability for financial settlement under Linden's peaking supply contracts, and natural gas supplied under those peaking supply contracts cannot be re-sold by Linden.
As they have been described by commenters, the natural gas and electric power contracts discussed above are all entered into by commercial market participants, who contemplate physical settlement of the transactions, in response to regulatory requirements, the need to maintain reliable supplies, and practical considerations of storage or transport.
In the Products Release, the CFTC and the SEC (the “Commissions”) adopted an interpretation to assist commercial and non-profit entities in understanding whether certain agreements, contracts, or transactions that they enter into would or would not be regulated as swaps.
The Commissions also explained that the list provided in the Products Release was not intended to be exhaustive and that there may be other, similar types of agreements, contracts, and transactions that also should not be considered to be swaps.
• They do not contain payment obligations, whether or not contingent, that are severable from the agreement, contract, or transaction;
• They are not traded on an organized market or over-the-counter; and . . .
• In the case of commercial arrangements, they are entered into:
—By commercial or non-profit entities as principals (or by their agents) to serve an independent commercial, business, or non-profit purpose, and
—Other than for speculative, hedging, or investment purposes.
The Commissions concluded that in determining whether an agreement, contract, or transaction not enumerated in the Products Release is a swap, the agreement, contract, or transaction will be evaluated based on its particular facts and circumstances,
In the Products Release, the CFTC also addressed certain capacity contracts and peaking supply contracts in the context of the CFTC's interpretation of when an agreement, contract, or transaction with embedded volumetric optionality would be considered a forward contract.
The CFTC clarified that since a key function of an electricity system operator is to ensure grid reliability, demand response agreements, even if not specifically mandated by a system operator, may be properly characterized as the product of regulatory requirements within the meaning of the seventh element of the CFTC's interpretation regarding forward contracts with embedded volumetric optionality. For the avoidance of doubt, the CFTC reiterates that the proposed guidance herein would not affect this interpretation.
Also, the CFTC's interpretations regarding full requirements and output contracts, as provided in the Products Release, would be unaffected by the proposed guidance herein.
Furthermore, the CFTC does not intend that the proposed guidance would supersede or modify a document issued by the CFTC's Office of General Counsel—“Response to Frequently Asked Questions Regarding Certain Physical Commercial Agreements for the Supply and Consumption of Energy,”
In response to the comments, described above, which were provided by market participants regarding certain capacity contracts for electric power and certain peaking supply contracts for natural gas, the CFTC has considered the specific facts and circumstances of these contracts in light of the interpretation in the Products Release of when a contract would be considered not to be a swap because it is a customary commercial arrangement.
The CFTC understands, based on the commenters' descriptions, that the contracts described in Part II.A. above are not traded on an organized market or over-the-counter, and do not have severable payment obligations. Thus, the CFTC preliminarily believes that the contracts described in Part II.A. are consistent with the first two elements of the interpretation in the Products Release.
The CFTC has also considered the contracts described in Part II.A. in light of the statement in the Products Release that, in order not to be considered swaps, the contracts should be entered into “[b]y commercial or non-profit entities as principals (or by their agents) to serve an independent commercial, business, or non-profit purpose, and [o]ther than for speculative, hedging, or investment purposes.”
The CFTC notes that commenters have represented that the contracts described in Part II.A. are entered into in response to regulatory requirements, the need to maintain reliable supplies, and practical considerations of storage or transport which arise in the course of the normal operation of at least one party's business. In this respect, the CFTC preliminarily believes that the contracts described in Part II.A. are similar to certain contracts—namely, sales, servicing and distribution arrangements, and contracts for the purchase of equipment or inventory—listed in the Products Release as commercial contracts that will not be considered swaps.
The CFTC observes that when an entity enters into a purchase contract, it is assured of a supply of the equipment or inventory it will need in the future. Similarly, a service contract assures the availability of a needed service in the future. The contracts described in Part II.A. are similar to the purchase and service contracts enumerated in the Products Release because they appear to satisfy the elements of commercial contracts, transactions or arrangements that are not considered swaps, including that they are entered into by commercial or non-profit entities to assure availability of a commodity, not to hedge against risks arising from a future change in price for the commodity or to serve a speculative or investment purpose.
As stated in the Products Release, whether a particular commercial arrangement is a swap depends on the particular facts and circumstances of the arrangement.
The CFTC believes that it would benefit from public comment about its proposed guidance, and therefore requests public comment on all aspects of its proposed guidance set forth above, and on the following questions:
1. Are there natural gas and electric power contracts that would not qualify as trade options within the scope of CFTC regulation 32.3 but which would be covered by the proposed guidance? If so, should the proposed guidance be limited so that it encompasses only contracts that do qualify as trade options? Why or why not?
2. Does the proposed guidance provide sufficient clarity on whether the specific types of natural gas and electric power contracts in question should or should not be considered to be swaps? If not, how should the guidance be revised to provide more clarity?
3. Are there other facts and circumstances that the CFTC should consider in determining whether the contracts described in Part II.A. are swaps? If so, what are these factors and how should they be considered?
4. Are there contracts (other than those described in Part II.A.) that are entered into by participants in the electric power and natural gas markets and necessitated by, or closely tied to, compliance with regulatory obligations or frameworks that are similar to those described in Part II.A.?
5. Are there other types of commodity contracts, outside of the electric power and natural gas markets, which are necessitated by, or closely tied to, compliance with regulatory obligations or frameworks that should be considered under the interpretation in the Products Release? If so, please describe these contracts and the regulatory obligations and frameworks to which they are closely tied.
6. Are there public interest considerations regarding the natural gas
7. Does the proposed guidance provide sufficient clarity that it does not supersede or modify the CFTC OGC FAQ referenced in footnote 34? Is there any potential overlap between the proposed guidance and the CFTC OGC FAQ that should be further clarified? If so, what elements of the proposed guidance should be clarified to indicate that the proposed guidance does not supersede or modify the CFTC OGC FAQ?
8. With respect to natural gas peaking contracts, are there natural gas providers other than LDCs, such as Intrastate and Interstate Natural Gas Pipelines (as those terms are defined by the Energy Information Administration),
By the Securities and Exchange Commission.
On this matter, Chairman Massad and Commissioners Bowen and Giancarlo voted in the affirmative. No Commissioner voted in the negative.
Today, the CFTC and the Securities and Exchange Commission (SEC), have jointly proposed guidance relating to the appropriate treatment of certain peaking supply and capacity contracts. We are issuing this guidance after considering the useful input we have received from market participants expressing concern about this issue. I support this proposal, as it will properly clarify the treatment of contracts used by many businesses with respect to the supply and delivery of electric power and natural gas.
We have proposed that certain electric power and natural gas contracts should not be considered “swaps” under the Commodity Exchange Act. We have done so because we believe they are examples of customary commercial arrangements as described in the final rule defining the term “swap.”
For example, these contracts are entered into to assure availability of a commodity, not to hedge against risks arising from a future change in price of that commodity or for speculative, or investment purposes. They are typically entered into in response to regulatory requirements, the need to maintain reliable energy supplies, and practical considerations of storage or transport. All of these factors are consistent with what has been set forth in previous commission guidance.
Today's proposed guidance is an important complement to our final rule regarding Trade Options, which will reduce burdens on end-users and allow them to better address commercial risk. I thank my fellow Commissioners Bowen and Giancarlo for joining me in unanimously approving this proposal as well as that final rule.
Internal Revenue Service (IRS), Treasury.
Partial withdrawal of notice of proposed rulemaking.
This document withdraws portions of a notice of proposed rulemaking published in the
As of April 8, 2016, portions of proposed rules (REG-147636-08 and REG-121534-12) published in the
Shane M. McCarrick or David A. Levine, (202) 317-6937.
On February 11, 2009, the Department of Treasury (Treasury Department) and the IRS published in the
On January 17, 2014, the Treasury Department and the IRS published in the
Income taxes, Reporting and recordkeeping requirements.
Accordingly, under the authority of 26 U.S.C. 7805, § 1.367(b)-4(e), (f), and (g) of the notice of proposed rulemaking (REG-147636-08) published in the
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking by cross-reference to temporary regulation.
The Department of Treasury (Treasury Department) and the IRS are issuing temporary regulations that address transactions that are structured to avoid the purposes of sections 7874 and 367 of the Internal Revenue Code (the Code) and certain post-inversion tax avoidance transactions in the Rules and Regulations section of this issue of the
Written or electronic comments and requests for a public hearing must be received by July 7, 2016.
Send submissions to: CC:PA:LPD:PR (REG-135734-14), room 5203, Internal Revenue Service, P.O. Box 7604, Ben Franklin Station, Washington, DC 20224. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG-135734-14), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC 20224, or sent electronically via the Federal eRulemaking Portal at
Concerning the proposed regulations under sections 304, 367, and 7874, Shane M. McCarrick or David A. Levine, (202) 317-6937; concerning the proposed regulations under sections 956 and 7701(l), Rose E. Jenkins, (202) 317-6934 (not toll-free numbers); concerning submissions of comments or requests for a public hearing, Regina Johnson, (202) 317-5177 (not toll-free numbers).
The temporary regulations in the Rules and Regulations section of this issue of the
Certain IRS regulations, including this one, are exempt from the requirements of Executive Order 12866, as supplemented and reaffirmed by Executive Order 13563. Therefore, a regulatory assessment is not required. It has also been determined that section 553(b) of the Administrative Procedure Act (5 U.S.C. Chapter 5) does not apply to these regulations, and because the regulations do not impose a collection of information on small entities, the Regulatory Flexibility Act (5 U.S.C. chapter 6) does not apply. Pursuant to section 7805(f), this notice of proposed rulemaking has been submitted to the Chief Counsel of Advocacy of the Small Business Administration for comment on its impact on small business.
Before these proposed regulations are adopted as final regulations, consideration will be given to any comments that are submitted timely to the IRS as prescribed in this preamble under the
The principal authors of these proposed regulations are Rose E. Jenkins, David A. Levine, and Shane M. McCarrick of the Office of Associate Chief Counsel (International). However, other personnel from the Treasury Department and the IRS participated in their development.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is proposed to be amended as follows:
26 U.S.C. 7805 * * *
Section 1.304-7 also issued under 26 U.S.C. 304(b)(5)(C).
Section 1.367(b)-4 also issued under 26 U.S.C. 367(a), 367(b), and 954(c)(6)(A).
Section 1.956-2 also issued under 26 U.S.C. 956(d) and 956(e).
Section 1.7701(l)-4 also issued under 26 U.S.C. 7701(l) and 954(c)(6)(A).
Section 1.7874-2 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-4 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-6 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-7 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-8 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-9 also issued under 26 U.S.C. 7874(c)(6) and 7874(g).
Section 1.7874-10 also issued under 26 U.S.C. 7874(c)(4) and 7874(g).
Section 1.7874-11 also issued under 26 U.S.C. 7874(g).
Section 1.7874-12 also issued under 26 U.S.C. 7874(g).
[The text of proposed § 1.304-7 is the same as the text of § 1.304-7T published elsewhere in this issue of the
(c) * * *
(3) * * *
(iii) * * *
(C) [The text of the proposed amendment to § 1.367(a)-3(c)(3)(iii)(C) is the same as the text of § 1.367(a)-3T(c)(3)(iii)(C) published elsewhere in this issue of the
(11) * * *
(ii) [The text of the proposed amendment to § 1.367(a)-3(c)(11)(ii) is the same as the text of § 1.367(a)-3T(c)(11)(ii) published elsewhere in this issue of the
(a) [The text of the proposed amendment to § 1.367(b)-4(a) is the same as the text of § 1.367(b)-4T(a) published elsewhere in this issue of the
(b) [The text of the proposed amendment to the introductory text to § 1.367(b)-4(b) is the same as the introductory text of § 1.367(b)-4T(b) published elsewhere in this issue of the
(1) * * *
(i) * * *
(C) [The text of the proposed amendment to § 1.367(b)-4(b)(1)(i)(C) is the same as the text of § 1.367(b)-4T(b)(1)(i)(C) published elsewhere in this issue of the
(d) * * *
(1) [The text of the proposed amendment to § 1.367(b)-4(d)(1) is the same as the text of § 1.367(b)-4T(d)(1) published elsewhere in this issue of the
(e) [The text of the proposed amendment to § 1.367(b)-4(e) is the same as the text of § 1.367(b)-4T(e) published elsewhere in this issue of the
(f) [The text of the proposed amendment to § 1.367(b)-4(f) is the same as the text of § 1.367(b)-4T(f) published elsewhere in this issue of the
(g) [The text of the proposed amendment to § 1.367(b)-4(g) is the same as the text of § 1.367(b)-4T(g) published elsewhere in this issue of the
(h) [The text of proposed § 1.367(b)-4(h) is the same as the text of § 1.367(b)-4T(h) published elsewhere in this issue of the
(a) * * *
(4) [The text of the proposed amendment to § 1.956-2(a)(4) is the same as the text of § 1.956-2T(a)(4) published elsewhere in this issue of the
(c) * * *
(5) [The text of the proposed amendment to § 1.956-2(c)(5) is the same as the text of § 1.956-2T(c)(5) published elsewhere in this issue of the
(d) * * *
(2) [The text of the proposed amendment to § 1.956-2(d)(2) is the same as the text of § 1.956-2T(d)(2) published elsewhere in this issue of the
(i) [The text of the proposed amendment to § 1.956-2(i) is the same as the text of § 1.956-2T(i) published elsewhere in this issue of the
[The text of proposed § 1.7701(l)-4 is the same as the text of § 1.7701(l)-4T published elsewhere in this issue of the
(c) * * *
(2) * * *
(iii) [The text of the proposed amendment to § 1.7874-1(c)(2)(iii) is the same as the text of § 1.7874-1T(c)(2)(iii) published elsewhere in this issue of the
(f) [The text of the proposed amendment to § 1.7874-1(f) is the same as the text of § 1.7874-1T(f) published elsewhere in this issue of the
(h) * * *
(2) [The text of the proposed amendment to § 1.7874-1(h)(2) is the same as the text of § 1.7874-1T(h)(2) published elsewhere in this issue of the
The revisions read as follows:
(a) [The text of the proposed amendment to § 1.7874-2(a) is the same as the text of § 1.7874-2T(a) published elsewhere in this issue of the
(b) * * *
(7) [The text of the proposed amendment to § 1.7874-2(b)(7) is the same as the text of § 1.7874-2T(b)(7) published elsewhere in this issue of the
(8) [The text of the proposed amendment to § 1.7874-2(b)(8) is the same as the text of § 1.7874-2T(b)(8) published elsewhere in this issue of the
(9) [The text of the proposed amendment to § 1.7874-2(b)(9) is the same as the text of § 1.7874-2T(b)(9) published elsewhere in this issue of the
(10) [The text of the proposed amendment to § 1.7874-2(b)(10) is the
(11) [The text of the proposed amendment to § 1.7874-2(b)(11) is the same as the text of § 1.7874-2T(b)(11) published elsewhere in this issue of the
(12) [The text of the proposed amendment to § 1.7874-2(b)(12) is the same as the text of § 1.7874-2T(b)(12) published elsewhere in this issue of the
(13) [The text of the proposed amendment to § 1.7874-2(b)(13) is the same as the text of § 1.7874-2T(b)(13) published elsewhere in this issue of the
(c) * * *
(2) [The text of the proposed amendment to § 1.7874-2(c)(2) is the same as the text of § 1.7874-2T(c)(2) published elsewhere in this issue of the
(4) [The text of the proposed amendment to § 1.7874-2(c)(4) is the same as the text of § 1.7874-2T(c)(4) published elsewhere in this issue of the
(f) * * *
(1) [The proposed amendment to the introductory text of § 1.7874-2(f)(1) is the same as the introductory text of § 1.7874-2T(f)(1) published elsewhere in this issue of the
(iv) [The text of the proposed amendment to § 1.7874-2(f)(1)(iv) is the same as the text of § 1.7874-2T(f)(1)(iv) published elsewhere in this issue of the
(k) * * *
(2) * * *
(l) * * *
(2) [The text of the proposed amendment to § 1.7874-2(l)(2) is the same as the text of § 1.7874-2T(l)(2) published elsewhere in this issue of the
(b) * * *
(4) [The text of the proposed amendment to § 1.7874-3(b)(4) is the same as the text of § 1.7874-3T(b)(4) published elsewhere in this issue of the
(d) * * *
(10) [The text of the proposed amendment to § 1.7874-3(d)(10) is the same as the text of § 1.7874-3T(d)(10) published elsewhere in this issue of the
(f) * * *
(2) [The text of the proposed amendment to § 1.7874-3(f)(2) is the same as the text of § 1.7874-3T(f)(2) published elsewhere in this issue of the
(a) through (c)(1) introductory text [Reserved].
(i) [The text of proposed § 1.7874-4(c)(1)(i) is the same as the text of § 1.7874-4T(c)(1)(i) as revised elsewhere in this issue of the
(ii) [Reserved].
(B) [The text of proposed § 1.7874-4(c)(1)(ii)(B) is the same as the text of § 1.7874-4T(c)(1)(ii)(B) as revised elsewhere in this issue of the
(2) [The text of proposed § 1.7874-4(c)(2) is the same as the text of § 1.7874-4T(c)(2) as revised elsewhere in this issue of the
(d) introductory text through (d)(1) introductory text [Reserved].
(i) [The text of proposed § 1.7874-4(d)(1)(i) is the same as the text of § 1.7874-4T(d)(1)(i) published elsewhere in this issue of the
(ii) [The text of proposed § 1.7874-4(d)(1)(ii) is the same as the text of § 1.7874-4T(d)(1)(ii) as revised elsewhere in this issue of the
(d)(2) through (g) [Reserved].
(h) [The text of proposed § 1.7874-4(h) is the same as the text of § 1.7874-4T(h) as revised elsewhere in this issue of the
(i) introductory text through (i)(5) [Reserved].
(6) [The text of proposed § 1.7874-4(i)(6) is the same as the text of § 1.7874-4T(i)(6) published elsewhere in this issue of the
(i)(7) introductory text through (i)(7)(iii) introductory text [Reserved].
(C) [The text of proposed § 1.7874-4(i)(7)(iii)(C) is the same as the text of § 1.7874-4T(i)(7)(iii)(C) as revised elsewhere in this issue of the
(iv) [The text of proposed § 1.7874-4(i)(7)(iv) is the same as the text of § 1.7874-4T(i)(7)(iv) published elsewhere in this issue of the
(j) introductory text through (j)(6) [Reserved].
(7) [The text of proposed § 1.7874-4(j)(7) is the same as the text of § 1.7874-4T(j)(7) as revised elsewhere in this issue of the
(8) [The text of proposed § 1.7874-4(j)(8) is the same as the text of § 1.7874-4T(j)(8) as revised elsewhere in this issue of the
(9) [The text of proposed § 1.7874-4(j)(9) is the same as the text of § 1.7874-4T(j)(9) published elsewhere in this issue of the
(10) [The text of proposed § 1.7874-4(j)(10) is the same as the text of § 1.7874-4T(j)(10) published elsewhere in this issue of the
(11) [The text of proposed § 1.7874-4(j)(11) is the same as the text of § 1.7874-4T(j)(11) published elsewhere in this issue of the
Example 1 introductory text through Example 1 paragraph (i) [Reserved].
(ii) [The text of proposed paragraph (ii) of Example 1 of § 1.7874-4(j) is the same as the text of paragraph (ii) of Example 1 of § 1.7874-4T(j) as revised elsewhere in this issue of the
Example 2 introductory text through Example 2 paragraph (i) [Reserved].
(ii) [The text of proposed paragraph (ii) of Example 2 of § 1.7874-4(j) is the same as the text of paragraph (ii) of Example 2 of § 1.7874-4T(j) as revised elsewhere in this issue of the
Example 3. [The text of proposed Example 3 of § 1.7874-4(j) is the same as the text of Example 3 of § 1.7874-4T(j) published elsewhere in this issue of the
Example 4. [The text of proposed Example 4 of § 1.7874-4(j) is the same as the text of Example 4 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
Example 5. [The text of proposed Example 5 of § 1.7874-4(j) is the same as the text of Example 5 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
Example 6. [The text of proposed Example 6 of § 1.7874-4(j) is the same as the text of Example 6 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
Example 7. [The text of proposed Example 7 of § 1.7874-4(j) is the same as the text of Example 7 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
Example 8. [The text of proposed Example 8 of § 1.7874-4(j) is the same as the text of Example 8 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
Example 9. [The text of proposed Example 9 of § 1.7874-4(j) is the same as the text of Example 9 of § 1.7874-4T(j) as redesignated and revised elsewhere in this issue of the
(k) introductory text [Reserved].
(1) [The text of proposed § 1.7874-4(k)(1) is the same as the text of § 1.7874-4T(k)(1) published elsewhere in this issue of the
(k)(2) through (k)(3) [Reserved].
[The text of proposed § 1.7874-6 is the same as the text of § 1.7874-6T published elsewhere in this issue of the
[The text of proposed § 1.7874-7 is the same as the text of § 1.7874-7T published elsewhere in this issue of the
[The text of proposed § 1.7874-8 is the same as the text of § 1.7874-8T published elsewhere in this issue of the
[The text of proposed § 1.7874-9 is the same as the text of § 1.7874-9T published elsewhere in this issue of the
[The text of proposed § 1.7874-10 is the same as the text of § 1.7874-10T published elsewhere in this issue of the
[The text of proposed § 1.7874-11 is the same as the text of § 1.7874-11T published elsewhere in this issue of the
[The text of proposed § 1.7874-12 is the same as the text of § 1.7874-12T published elsewhere in this issue of the
Office of Surface Mining Reclamation and Enforcement, Interior.
Proposed rule; public comment period and opportunity for public hearing on proposed amendment.
We, the Office of Surface Mining Reclamation and Enforcement (OSMRE), are announcing receipt of a proposed amendment to the Texas regulatory program (Texas program) under the Surface Mining Control and Reclamation Act of 1977 (SMCRA or the Act). Texas proposes revisions to its regulations regarding annual permit fees. Texas intends to revise its program to improve operational efficiency.
This document gives the times and locations that the Texas program and proposed amendment to that program are available for your inspection, the comment period during which you may submit written comments on the amendment, and the procedures that we will follow for the public hearing, if one is requested.
We will accept written comments on this amendment until 4:00 p.m., c.t., May 9, 2016. If requested, we will hold a public hearing on the amendment on May 3, 2016. We will accept requests to speak at a hearing until 4:00 p.m., c.t. on April 25, 2016.
You may submit comments, identified by SATS No. TX-067-FOR, by any of the following methods:
•
•
•
Instructions: All submissions received must include the agency name and docket number for this rulemaking. For detailed instructions on submitting comments and additional information on the rulemaking process, see the “Public Comment Procedures” heading of the
Docket: For access to the docket to review copies of the Texas program, this amendment, a listing of any scheduled public hearings, and all written comments received in response to this document, you must go to the address listed below during normal business hours, Monday through Friday, excluding holidays. You may receive one free copy of the amendment by contacting OSMRE's Tulsa Field Office or going to
Director: Tulsa Field Office, Office of Surface Mining Reclamation and Enforcement, 1645 South 101st East Avenue, Suite 145, Tulsa, Oklahoma 74128-4629, Telephone: (918) 581-6430.
In addition, you may review a copy of the amendment during regular business hours at the following location: Surface Mining and Reclamation Division, Railroad Commission of Texas, 1701 North Congress Avenue, Capitol Station, P.O. Box 12967, Austin, Texas 78711-2967, Telephone: (512) 463-6900.
Director, Tulsa Field Office. Telephone: (918) 581-6430. Email: Debbie Dale at
Section 503(a) of the Act permits a State to assume primacy for the regulation of surface coal mining and reclamation operations on non-Federal and non-Indian lands within its borders by demonstrating that its program includes, among other things, “a State law which provides for the regulation of surface coal mining and reclamation operations in accordance with the requirements of this Act . . .; and rules and regulations consistent with regulations issued by the Secretary pursuant to this Act.” See 30 U.S.C. 1253(a)(1) and (7). On the basis of these
By letter dated November 17, 2015 (Administrative Record No. TX-705), Texas sent us an amendment to its program under SMCRA (30 U.S.C. 1201
Texas proposes to revise its regulation at 16 Texas Administrative Code (TAC) section 12.108(b) regarding annual permit fees by:
(1) Removing paragraph (b)(1), regarding fees for each acre of land within the permit area on which coal or lignite was actually removed during the calendar year;
(2) Increasing the amount of the fee, from $12.00 to $13.05, for each acre of land within a permit area covered by a reclamation bond on December 31st of the year; and
(3) Increasing the amount of the fee, from $6,540 to $6,600, for each permit in effect on December 31st of the year.
Texas fully funds its share of costs to regulate the coal mining industry with fees paid by the coal industry. Texas charges three fees to meet these costs, a permit application fee and two annual fees as mentioned above. The proposed fee revisions are intended to provide adequate funding to pay the State's cost of operating its regulatory program, and provide incentives for industry to accomplish reclamation and achieve bond release as quickly as possible.
Under the provisions of 30 CFR 732.17(h), we are seeking your comments on whether the amendment satisfies the applicable program approval criteria of 30 CFR 732.15. If we approve the amendment, it will become part of the State program.
If you submit written comments, they should be specific, confined to issues pertinent to the proposed regulations, and explain the reason for any recommended change(s). We appreciate any and all comments, but those most useful and likely to influence decisions on the final regulations will be those that either involve personal experience or include citations to and analyses of SMCRA, its legislative history, its implementing regulations, case law, other pertinent State or Federal laws or regulations, technical literature, or other relevant publications.
We cannot ensure that comments received after the close of the comment period (see
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
If you wish to speak at the public hearing, contact the person listed under
To assist the transcriber and ensure an accurate record, we request, if possible, that each person who speaks at the public hearing provide us with a written copy of his or her comments. The public hearing will continue on the specified date until everyone scheduled to speak has been given an opportunity to be heard. If you are in the audience and have not been scheduled to speak and wish to do so, you will be allowed to speak after those who have been scheduled. We will end the hearing after everyone scheduled to speak and others present in the audience who wish to speak, have been heard.
If only one person requests an opportunity to speak, we may hold a public meeting rather than a public hearing. If you wish to meet with us to discuss the amendment, please request a meeting by contacting the person listed under
This proposed rule is exempted from review by the Office of Management and Budget (OMB) under Executive Order 12866.
When a State submits a program amendment to OSMRE for review, our regulations at 30 CFR 732.17(h) require us to publish a notice in the
Intergovernmental relations, Surface mining, Underground mining.
Coast Guard, DHS.
Notice of proposed rulemaking.
The Coast Guard proposes to amend and update its annual and recurring safety zones that take place in the Coast Guard Sector Upper Mississippi River area of responsibility (AOR). This document informs the public of regularly scheduled events that require additional safety measures through establishing a safety zone. This document also proposes to update the current list of recurring safety zones with revisions, additional events, and removal of events that no longer take place in Sector Upper Mississippi River's AOR. Additionally, this one proposed rulemaking project reduces administrative costs involved in producing separate proposed rules for each individual recurring safety zone and serves to provide notice of the known recurring safety zones throughout the year. We invite your comments on this proposed rulemaking.
Comments and related material must be received by the Coast Guard on or before May 9, 2016.
You may submit comments identified by docket number USCG-2015-1079 using the Federal eRulemaking Portal at
If you have questions about this proposed rulemaking, call or email LCDR Sean Peterson, Chief of Prevention, U.S. Coast Guard; telephone 314-269-2332, email
The Captain of the Port (COTP) Upper Mississippi River is proposing to amend and update its current list of recurring safety zones.
The current list of annual and recurring safety zones occurring in Sector Upper Mississippi River's AOR is published under 33 CFR part 165.801, Table 2. This current list was established through a rulemaking process providing for comment and public participation. No adverse comments were received, resulting in the final rulemaking 80 FR 49911, which was published August 18, 2015. The final rulemaking amended 33 CFR 165.801 to establish the current list of recurring safety zones.
This rulemaking proposes to add to, amend, and update the list of annually recurring safety zones under Table 2 in 33 CFR 165.801 for annual and recurring safety zones in the COTP Upper Mississippi zone.
The Coast Guard is amending and updating the annual and recurring safety zone regulations under 33 CFR part 165 to include the most up to date list of annual and recurring safety zones for events held on or around navigable waters within Sector Upper Mississippi River's AOR. These events include fireworks displays, air shows, festival events, and other recurring marine related safety needs. The current list under 33 CFR 165.801 requires amending to provide new information on existing safety zones, updating to include new safety zones expected to recur annually, and to remove safety zones that are no longer required. Issuing individual regulations for each new safety zone, amendment, or removal of an existing safety zones creates unnecessary administrative costs and burdens. This single proposed rulemaking will considerably reduce administrative overhead and provide the public with notice through publication in the
33 CFR part 165 contains regulations establishing limited access areas on U.S. navigable waters. Section 165.801 lists the established recurring safety zones taking place in the Eighth Coast Guard District separated into tables for each of the seven sectors within the Eighth District. Table 2 lists the recurring safety zones for Sector Upper Mississippi River. This section, and table, requires amendment from time to time to properly reflect the recurring safety zones in Sector Upper Mississippi River's AOR. This proposed rule amends and updates Section 165.801 replacing the current Table 2 for Sector Upper Mississippi River.
Additionally, this proposed rule adds 3 new, modifies 7, and removes 14 recurring safety zones as listed below.
This proposed rule adds 3 new safety zones to Table 2 in § 165.801 as follows:
This proposed rule modifies the following 7 safety zones currently listed in Table 2 in § 165.801 as follows:
This proposed rule removes the following 14 safety zones from the existing Table 2 in § 165.801:
The effect of this proposed rule will be to restrict general navigation in the safety zone during the event. Vessels will experience limited access on the waterway when the safety zones are in effect. Requests to transit into, through, or within a safety zone will be considered and will be allowed only when deemed safe by the COTP Upper Mississippi River, or designated representative.
We developed this proposed rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This NPRM has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, the NPRM has not been reviewed by the Office of Management and Budget.
The Coast Guard expects the economic impact of this proposed rule to be minimal, and therefore a full regulatory evaluation is unnecessary. This proposed rule establishes safety zones limiting access to certain areas under 33 CFR part 165 within Sector Upper Mississippi River's AOR. The effect of this proposed rulemaking will not be significant because these safety zones are limited in scope and duration. Additionally, the public is given advance notification through local forms of notice, the
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.
While some owners or operators of vessels intending to transit these safety zones may be small entities, for the reasons stated in section IV.A. above, this proposed rule would not have a significant economic impact on any vessel owner or operator.
If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.
Also, this proposed rule does not have tribal implications under Executive Order 13175, Consultation and Coordination with Indian Tribal Governments, because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
We have analyzed this proposed rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves rules establishes safety zones limiting access to certain areas under 33 CFR 165 within Sector Upper Mississippi River's AOR. Normally such actions are categorically excluded from further review under paragraph 34(h) of Figure 2-1 of Commandant Instruction M16475.lD. A preliminary environmental analysis checklist and Categorical Exclusion Determination are available in the docket where indicated under
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.
We encourage you to submit comments through the Federal eRulemaking Portal at
We accept anonymous comments. All comments received will be posted without change to
Documents mentioned in this NPRM as being available in the docket, and all public comments, will be in our online docket at
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 165 as follows:
33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Department of Homeland Security Delegation No. 0170.1.
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve a state implementation plan (SIP) revision submitted by the Commonwealth of Pennsylvania. This SIP revision amends two regulations to clarify testing and sampling methods for stationary sources of particulate matter (PM) and add the requirement to measure and report filterable and condensable PM. This action is being taken under the Clean Air Act (CAA).
Written comments must be received on or before May 9, 2016.
Submit your comments, identified by Docket ID Number EPA-R03-OAR-2016-0005 at
Maria A. Pino, (215) 814-2181, or by email at
PM, also known as particle pollution, is a complex mixture of extremely small particles and liquid droplets. Particle pollution is made up of a number of components, including acids (such as nitrates and sulfates), organic chemicals, metals, and soil or dust particles. The
EPA established the first national ambient air quality standard (NAAQS) for coarse particles (PM
On December 1, 2010, EPA revised two test methods for measuring PM emissions from stationary sources. 75 FR 80118. One of the revised methods, called Method 201A, provides the capability to measure the mass of filterable PM
On June 25, 2015, the Commonwealth of Pennsylvania submitted a formal SIP revision that amends chapters 121 and 139 of title 25, Environmental Protection, of the Pennsylvania Code (25 Pa. Code). Methods 201A and 202 are incorporated by reference in Pennsylvania's Source Testing Manual, which is incorporated by reference in 25 Pa. Code, chapter 139, Sampling and Testing. Amendments to chapter 121, in section 121.1, add definitions for the terms “condensable particulate matter” and “filterable particulate matter.” The amendments to 25 Pa. Code section 139.12 explain the process for determining compliance with filterable and condensable PM emission limitations, and explains the compliance demonstration process. Under 25 Pa. Code section 139.12(b), the owner or operator of a stationary source subject to PM emission limitations or to NSR/PSD applicability determinations is required to demonstrate compliance for filterable and condensable PM emissions. The amendment to 25 Pa. Code section 139.53 specifies to whom monitoring reports must be submitted.
EPA is proposing to approve the June 25, 2015 Pennsylvania SIP revision, which amends specific provisions within chapters 121 and 139 of 25 Pa. Code. The amendments clarify testing and sampling methods and reporting requirements for stationary sources of PM and add the requirement to measure and report filterable and condensable PM. This revision meets requirements in section 110 of the CAA and strengthens the Pennsylvania SIP. EPA is soliciting public comments on the issues discussed in this document. These comments will be considered before taking final action.
In this proposed rulemaking action, EPA is proposing to include in a final EPA rule, regulatory text that includes incorporation by reference. In accordance with the requirements of 1 CFR 51.5, EPA is proposing to incorporate by reference the revised Pennsylvania regulations, published in the Pennsylvania Bulletin, Vol. 44 No. 15, April 12, 2014, and effective on April 12, 2014. EPA has made, and will continue to make, these documents generally available electronically through
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely approves state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this proposed action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993);
• does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible
In addition, this rulemaking action, proposing to approve amendments to Pennsylvania's regulations regarding testing and sampling methods for stationary sources of PM, including filterable and condensable PM, does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), because the SIP is not approved to apply in Indian country located in the Commonwealth, and EPA notes that it will not impose substantial direct costs on tribal governments or preempt tribal law.
Environmental protection, Air pollution control, Incorporation by reference, Particulate matter, Reporting and recordkeeping requirements.
42 U.S.C. 7401
Environmental Protection Agency.
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve portions of revisions to the North Carolina State Implementation Plan (SIP), submitted by the North Carolina Department of Environment and Natural Resources (NC DENR), addressing the Clean Air Act (CAA or Act) visibility transport (prong 4) infrastructure SIP requirements for the 2008 8-hour Ozone, 2010 1-hour Nitrogen Dioxide (NO
Comments must be received on or before April 29, 2016.
Submit your comments, identified by Docket ID No EPA-R04-OAR-2016-0072 at
Sean Lakeman of the Air Regulatory Management Section, Air Planning and Implementation Branch, Air, Pesticides and Toxics Management Division, U.S. Environmental Protection Agency, Region 4, 61 Forsyth Street SW., Atlanta, Georgia 30303-8960. Mr. Lakeman can be reached by telephone at (404) 562-9043 or via electronic mail at
By statute, SIPs meeting the requirements of sections 110(a)(1) and (2) of the CAA are to be submitted by states within three years after promulgation of a new or revised NAAQS to provide for the implementation, maintenance, and enforcement of the new or revised NAAQS. EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of sections 110(a)(1) and 110(a)(2) as “infrastructure SIP” submissions. Sections 110(a)(1) and (2) require states to address basic SIP elements such as for monitoring, basic program requirements, and legal authority that are designed to assure attainment and maintenance of the newly established or revised NAAQS. More specifically, section 110(a)(1) provides the procedural and timing requirements for infrastructure SIPs. Section 110(a)(2) lists specific elements that states must meet for the infrastructure SIP requirements related to a newly established or revised NAAQS. The contents of an infrastructure SIP submission may vary depending upon the data and analytical tools available to the state, as well as the provisions already contained in the state's implementation plan at the time in which the state develops and submits the submission for a new or revised NAAQS.
Section 110(a)(2)(D) has two components: 110(a)(2)(D)(i) and 110(a)(2)(D)(ii). Section 110(a)(2)(D)(i) includes four distinct components, commonly referred to as “prongs,” that must be addressed in infrastructure SIP submissions. The first two prongs, which are codified in section 110(a)(2)(D)(i)(I), are provisions that prohibit any source or other type of emissions activity in one state from contributing significantly to nonattainment of the NAAQS in another state (prong 1) and from interfering with maintenance of the NAAQS in another state (prong 2). The third and fourth prongs, which are codified in section 110(a)(2)(D)(i)(II), are provisions that prohibit emissions activity in one state from interfering with measures required to prevent significant deterioration of air quality in another state (prong 3) or from interfering with measures to protect visibility in another state (prong 4). Section 110(a)(2)(D)(ii) requires SIPs to include provisions ensuring compliance with sections 115 and 126 of the Act, relating to interstate and international pollution abatement.
Through this action, EPA is proposing to approve the prong 4 portions of North Carolina's infrastructure SIP submissions for the 2008 8-hour Ozone, 2010 1-hour NO
On March 12, 2008, EPA revised the 8-hour Ozone NAAQS to 0.075 parts per million.
On January 22, 2010, EPA established a new 1-hour primary NAAQS for NO
On June 2, 2010, EPA revised the primary SO
On December 14, 2012, EPA revised the primary annual PM
The requirement for states to make a SIP submission of this type arises out of section 110(a)(1). Pursuant to section 110(a)(1), states must make SIP submissions “within 3 years (or such shorter period as the Administrator may prescribe) after the promulgation of a national primary ambient air quality standard (or any revision thereof),” and these SIP submissions are to provide for the “implementation, maintenance, and enforcement” of such NAAQS. The statute directly imposes on states the duty to make these SIP submissions, and the requirement to make the submissions is not conditioned upon EPA's taking any action other than promulgating a new or revised NAAQS. Section 110(a)(2) includes a list of specific elements that “each such plan” submission must address.
EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of section 110(a)(1) and (2) as “infrastructure SIP” submissions. Although the term “infrastructure SIP” does not appear in the CAA, EPA uses the term to distinguish this particular type of SIP submission from submissions that are intended to satisfy other SIP requirements under the CAA, such as “nonattainment SIP” or “attainment plan SIP” submissions to address the nonattainment planning requirements of part D of Title I of the CAA, “regional haze SIP” submissions required by EPA rule to address the visibility protection requirements of section 169A of the CAA, and nonattainment new source review permit program submissions to address the permit requirements of CAA, Title I, part D.
Section 110(a)(1) addresses the timing and general requirements for infrastructure SIP submissions and section 110(a)(2) provides more details concerning the required contents of these submissions. The list of required elements provided in section 110(a)(2) contains a wide variety of disparate provisions, some of which pertain to required legal authority, some of which pertain to required substantive program provisions, and some of which pertain to requirements for both authority and substantive program provisions.
The following examples of ambiguities illustrate the need for EPA to interpret some section 110(a)(1) and section 110(a)(2) requirements with respect to infrastructure SIP submissions for a given new or revised NAAQS. One example of ambiguity is that section 110(a)(2) requires that “each” SIP submission must meet the list of requirements therein, while EPA has long noted that this literal reading of the statute is internally inconsistent and would create a conflict with the nonattainment provisions in part D of Title I of the CAA, which specifically address nonattainment SIP requirements.
Another example of ambiguity within section 110(a)(1) and (2) with respect to infrastructure SIPs pertains to whether states must meet all of the infrastructure
Ambiguities within section 110(a)(1) and (2) may also arise with respect to infrastructure SIP submission requirements for different NAAQS. Thus, EPA notes that not every element of section 110(a)(2) would be relevant, or as relevant, or relevant in the same way, for each new or revised NAAQS. The states' attendant infrastructure SIP submissions for each NAAQS therefore could be different. For example, the monitoring requirements that a state might need to meet in its infrastructure SIP submission for purposes of section 110(a)(2)(B) could be very different for different pollutants, because the content and scope of a state's infrastructure SIP submission to meet this element might be very different for an entirely new NAAQS than for a minor revision to an existing NAAQS.
EPA notes that interpretation of section 110(a)(2) is also necessary when EPA reviews other types of SIP submissions required under the CAA. Therefore, as with infrastructure SIP submissions, EPA also has to identify and interpret the relevant elements of section 110(a)(2) that logically apply to these other types of SIP submissions. For example, section 172(c)(7) requires attainment plan SIP submissions required by part D to meet the “applicable requirements” of section 110(a)(2); thus, attainment plan SIP submissions must meet the requirements of section 110(a)(2)(A) regarding enforceable emission limits and control measures and section 110(a)(2)(E)(i) regarding air agency resources and authority. By contrast, it is clear that attainment plan SIP submissions required by part D would not need to meet the portion of section 110(a)(2)(C) that pertains to the PSD program required in part C of Title I of the CAA, because PSD does not apply to a pollutant for which an area is designated nonattainment and thus subject to part D planning requirements. As this example illustrates, each type of SIP submission may implicate some elements of section 110(a)(2) but not others.
Given the potential for ambiguity in some of the statutory language of section 110(a)(1) and section 110(a)(2), EPA believes that it is appropriate to interpret the ambiguous portions of section 110(a)(1) and section 110(a)(2) in the context of acting on a particular SIP submission. In other words, EPA assumes that Congress could not have intended that each and every SIP submission, regardless of the NAAQS in question or the history of SIP development for the relevant pollutant, would meet each of the requirements, or meet each of them in the same way. Therefore, EPA has adopted an approach under which it reviews infrastructure SIP submissions against the list of elements in section 110(a)(2), but only to the extent each element applies for that particular NAAQS.
Historically, EPA has elected to use guidance documents to make recommendations to states for infrastructure SIPs, in some cases conveying needed interpretations on newly arising issues and in some cases conveying interpretations that have already been developed and applied to individual SIP submissions for particular elements.
As an example, section 110(a)(2)(E)(ii) is a required element of section 110(a)(2) for infrastructure SIP submissions. Under this element, a state must meet the substantive requirements of section 128, which pertain to state boards that approve permits or enforcement orders and heads of executive agencies with similar powers. Thus, EPA reviews infrastructure SIP submissions to ensure that the state's SIP appropriately addresses the requirements of section 110(a)(2)(E)(ii) and section 128. The 2013 Guidance explains EPA's interpretation that there
As another example, EPA's review of infrastructure SIP submissions with respect to the PSD program requirements in section 110(a)(2)(C), (D)(i)(II), and (J) focuses upon the structural PSD program requirements contained in part C and EPA's PSD regulations. Structural PSD program requirements include provisions necessary for the PSD program to address all regulated sources and NSR pollutants, including Greenhouse Gases (GHGs). By contrast, structural PSD program requirements do not include provisions that are not required under EPA's regulations at 40 CFR 51.166 but are merely available as an option for the state, such as the option to provide grandfathering of complete permit applications with respect to the PM
For other section 110(a)(2) elements, however, EPA's review of a state's infrastructure SIP submission focuses on assuring that the state's SIP meets basic structural requirements. For example, section 110(a)(2)(C) includes,
With respect to certain other issues, EPA does not believe that an action on a state's infrastructure SIP submission is necessarily the appropriate type of action in which to address possible deficiencies in a state's existing SIP. These issues include: (i) Existing provisions related to excess emissions from sources during periods of startup, shutdown, or malfunction (SSM) that may be contrary to the CAA and EPA's policies addressing such excess emissions;
EPA's approach to review of infrastructure SIP submissions is to identify the CAA requirements that are logically applicable to that submission. EPA believes that this approach to the review of a particular infrastructure SIP submission is appropriate, because it would not be reasonable to read the general requirements of section 110(a)(1) and the list of elements in section 110(a)(2) as requiring review of each and every provision of a state's existing SIP against all requirements in the CAA and EPA regulations merely for purposes of assuring that the state in question has the basic structural elements for a functioning SIP for a new or revised NAAQS. Because SIPs have grown by accretion over the decades as statutory and regulatory requirements under the CAA have evolved, they may include some outmoded provisions and historical artifacts. These provisions, while not fully up to date, nevertheless may not pose a significant problem for the purposes of “implementation, maintenance, and enforcement” of a new or revised NAAQS when EPA evaluates adequacy of the infrastructure SIP submission. EPA believes that a better approach is for states and EPA to focus attention on those elements of section 110(a)(2) of the CAA most likely to warrant a specific SIP revision due to the promulgation of a new or revised NAAQS or other factors.
For example, EPA's 2013 Guidance gives simpler recommendations with respect to carbon monoxide than other NAAQS pollutants to meet the visibility requirements of section 110(a)(2)(D)(i)(II), because carbon monoxide does not affect visibility. As a result, an infrastructure SIP submission for any future new or revised NAAQS for carbon monoxide need only state this fact in order to address the visibility prong of section 110(a)(2)(D)(i)(II).
Finally, EPA believes that its approach with respect to infrastructure SIP requirements is based on a reasonable reading of section 110(a)(1) and (2) because the CAA provides other avenues and mechanisms to address specific substantive deficiencies in existing SIPs. These other statutory tools allow EPA to take appropriately tailored action, depending upon the nature and severity of the alleged SIP deficiency. Section 110(k)(5) authorizes EPA to issue a “SIP call” whenever the Agency determines that a state's SIP is substantially inadequate to attain or maintain the NAAQS, to mitigate interstate transport, or to otherwise comply with the CAA.
Section 110(a)(2)(D)(i)(II) requires a state's SIP to contain provisions prohibiting sources in that state from emitting pollutants in amounts that interfere with any other state's efforts to protect visibility under part C of the CAA (which includes sections 169A and 169B). The 2013 Guidance states that these prong 4 requirements can be satisfied by approved SIP provisions that EPA has found to adequately address any contribution of that state's sources to impacts on visibility program requirements in other states. The 2013 Guidance also states that EPA interprets this prong to be pollutant-specific, such that the infrastructure SIP submission need only address the potential for interference with protection of visibility caused by the pollutant (including precursors) to which the new or revised NAAQS applies.
The 2013 Guidance lays out two ways in which a state's infrastructure SIP may satisfy prong 4. The first way is through an air agency's confirmation in its infrastructure SIP submission that it has an EPA-approved regional haze SIP that fully meets the requirements of 40 CFR 51.308 or 51.309. 40 CFR 51.308 and 51.309 specifically require that a state participating in a regional planning process include all measures needed to achieve its apportionment of emission reduction obligations agreed upon through that process. A fully approved regional haze SIP will ensure that emissions from sources under an air agency's jurisdiction are not interfering with measures required to be included in other air agencies' plans to protect visibility.
Alternatively, in the absence of a fully approved regional haze SIP, a state may meet the requirements of prong 4 through a demonstration in its infrastructure SIP submission that emissions within its jurisdiction do not interfere with other air agencies' plans to protect visibility. Such an infrastructure SIP submission would need to include measures to limit visibility-impairing pollutants and ensure that the reductions conform with any mutually agreed regional haze reasonable progress goals for mandatory Class I areas in other states.
North Carolina's November 2, 2012, 2008 8-hour Ozone submission; August 23, 2013, 2010 1-hour NO
EPA demonstrated that CAIR achieved greater reasonable progress toward the national visibility goal than BART for NO
The United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) initially vacated CAIR in 2008,
Due to CAIR's status as a temporary measure following the D.C. Circuit's 2008 ruling, EPA could not fully approve regional haze SIP revisions to the extent that they relied on CAIR to satisfy the BART requirement and the requirement for a long-term strategy sufficient to achieve the state-adopted reasonable progress goals. On these grounds, EPA finalized a limited disapproval of North Carolina's regional haze SIP on June 7, 2012, triggering the requirement for EPA to promulgate a FIP unless North Carolina submitted and EPA approved a SIP revision that corrected the deficiency.
On October 31, 2014, North Carolina submitted a regional haze SIP revision to correct the deficiencies identified in the June 7, 2012, limited disapproval by replacing reliance on CAIR with reliance on a BART Alternative to
As described above, EPA is proposing to approve the prong 4 portions of North Carolina's November 2, 2012, 2008 8-hour Ozone infrastructure SIP submission; August 23, 2013, 2010 1-hour NO
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations.
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501
• is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
• does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);
• does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);
• is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);
• is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);
• is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and
• does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).
The SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications as specified by Executive Order 13175 (65 FR 67249, November 9, 2000), nor will it impose substantial direct costs on tribal governments or preempt tribal law.
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate Matter, Reporting and recordkeeping requirements, Volatile organic compounds.
42 U.S.C. 7401
United States African Development Foundation.
Notice of meeting.
The US African Development Foundation (USADF) will hold its quarterly meeting of the Board of Directors to discuss the agency's programs and administration.
The meeting date is Monday, April 25, 2016, 12:00 p.m. to 2:00 p.m.
The meeting location is USADF, 1400 I St. NW., Suite 1000, Washington, DC 20005.
Julia Tanton, 202-233-8811.
Public Law 96-533 (22 U.S.C. 290h).
Forest Service, USDA.
Notice of meetings.
The National Advisory Committee for Implementation of the National Forest System Land Management Planning Rule Committee (Committee) will meet in Charleston, South Carolina. Attendees may also participate via webinar and conference call. The Committee operates in compliance with the Federal Advisory Committee Act (FACA) (Pub. L. 92-463). Committee information can be found at the following Web site:
The meeting will be held in-person and via webinar/conference call on the following dates and times:
• Tuesday, May 10, 2016, from 8:30 a.m. to 5:00 p.m. EST.
• Wednesday, May 11, 2016, from 8:30 a.m. to 5:00 p.m. EST.
• Thursday, May 12, 2016, from 8:30 a.m. to 12:00 p.m. EST.
All meetings are subject to cancellation. For updated status of meetings prior to attendance, please contact the person listed under
The meeting will be held at the Holiday Inn Charleston Historic Downtown, 425 Meeting Street, Charleston, South Carolina. For anyone who would like to attend via webinar and/or conference call, please visit the Web site listed above or contact the person listed in the section titled
Jennifer Helwig, Committee Coordinator, by phone at 202-205-0892, or by email at
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.
The purpose of this meeting is to provide:
1. Continued deliberations on formulating advice for the Secretary,
2. Discussion of Committee work group findings,
3. Hearing public comments, and
4. Administrative tasks.
This meeting is open to the public. The agenda will include time for people to make oral comments of three minutes or less. Individuals wishing to make an oral comment should submit a request in writing by May 2, 2016, to be scheduled on the agenda. Anyone who would like to bring related matters to the attention of the Committee may file written statements with the Committee's staff before or after the meeting. Written comments and time requests for oral comments must be sent to Jennifer Helwig, USDA Forest Service, Ecosystem Management Coordination, 201 14th Street SW., Mail Stop 1104, Washington, DC, 20250-1104; or by email at
Forest Service, USDA.
Notice of meeting.
The Black Hills National Forest Advisory Board (Board) will meet in Rapid City, South Dakota. The Board is established consistent with the Federal Advisory Committee Act of 1972 (5 U.S.C. App. II), the Forest and Rangeland Renewable Resources Planning Act of 1974 (16 U.S.C. 1600
The meeting will be held on Wednesday, April 20, 2016, at 1:00 p.m.
All meetings are subject to cancellation. For updated status of meeting prior to attendance, please contact the person listed under
The meeting will be held at the Mystic Ranger District, 8221 South Highway 16, Rapid City, South Dakota.
Written comments may be submitted as described under
Scott Jacobson, Board Coordinator, by phone at 605-440-1409 or by email at
Individuals who use telecommunication devices for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 between 8:00 a.m. and 8:00 p.m., Eastern Standard Time, Monday through Friday.
The purpose of the meeting is to provide:
(1) Over-snow and Non-motorized Working Group Report update;
(2) Elk Management Report;
(3) Heritage and Sacred Site update;
(4) Forest Health Working Group Recommendation for FY 16-18;
(5) Motorized Trails and Permit Fees;
(6) Fire Season 2016 Outlook; and
(7) Election.
The meeting is open to the public. The agenda will include time for people to make oral statements of three minutes or less. Individuals wishing to make an oral statement should submit a request in writing by April 11, 2016, to be scheduled on the agenda. Anyone who would like to bring related matters to the attention of the Board may file written statements with the Board's staff before or after the meeting. Written comments and time requests for oral comments must be sent to Scott Jacobson, Black Hills National Forest Supervisor's Office, 1019 North Fifth Street, Custer, South Dakota 57730; by email to
Rural Business-Cooperative Service, USDA.
Notice.
This Notice announces that the Rural Business-Cooperative Service (Agency) is accepting fiscal year (FY) 2016 applications for the Value-Added Producer Grant (VAPG) program. Approximately $44 million is available to help agricultural producers enter into value-added activities for FY 2016, including approximately $30.25 million available through the Agricultural Act of 2014 (2014 Farm Bill), $10.75 million through the Consolidated Appropriations Act, 2016 and $3 million in carryover funding.
You must submit your application by July 1, 2016 or it will not be considered for funding. Paper applications must be postmarked and mailed, shipped or sent overnight by this date. You may also hand carry your application to one of our field offices, but it must be received by close of business on the deadline date. Electronic applications are permitted via
You should contact your USDA Rural Development State Office if you have questions about eligibility or submission requirements. You are encouraged to contact your State Office well in advance of the application deadline to discuss your project and to ask any questions about the application process. Application materials are available at
If you want to submit an electronic application, follow the instructions for the VAPG funding announcement on
Grants Division, Cooperative Programs, Rural Business-Cooperative Service, United States Department of Agriculture, 1400 Independence Avenue SW., MS 3253, Room 4008-South, Washington, DC 20250-3253, or call 202-690-1374.
In accordance with the Paperwork Reduction Act, the paperwork burden associated with this Notice has been approved by the Office of Management and Budget (OMB) under OMB Control Number 0570-0039.
The VAPG program is authorized under section 231 of the Agriculture Risk Protection Act of 2000 (Pub. L. 106-224), as amended by section 6203 of the Agricultural Act of 2014 (Pub. L. 113-79) (see 7 U.S.C. 1632a). Applicants must adhere to the requirements contained in the program regulation, 7 CFR 4284, subpart J, which is incorporated by reference in this Notice.
The objective of this grant program is to assist viable Independent Producers, Agricultural Producer Groups, Farmer and Rancher Cooperatives, and Majority-Controlled Producer-Based Businesses in starting or expanding value-added activities related to the
Funding priority will be made available to Beginning Farmers and Ranchers, Veteran Farmers and Ranchers, Socially-Disadvantaged Farmers and Ranchers, Operators of Small and Medium-Sized Farms and Ranches structured as Family Farms or Ranches, Farmer or Rancher Cooperatives, and projects proposing to develop a Mid-Tier Value Chain. See 7 CFR 4284.923 for Reserved Funds eligibility and 7 CFR 4284.924 for Priority Scoring eligibility.
The terms you need to understand are defined in 7 CFR 4284.902.
Applicants must comply with the program regulation 7 CFR part 4284 subpart J in order to meet all of the following eligibility requirements. Applications which fail to meet any of these requirements by the application deadline will be deemed ineligible and will not be evaluated further.
You must demonstrate that you meet all the applicant eligibility requirements of 7 CFR 4284.920 and 4284.921. This includes meeting the definition requirements at 7 CFR 4284.902 for one of the following applicant types: Independent Producer, Agricultural Producer Group, Farmer or Rancher Cooperative or Majority-Controlled Producer-Based Business and also meeting the Emerging Market, Citizenship, Legal Authority and Responsibility, Multiple Grants and Active Grants requirements of the section. Required documentation to support eligibility is contained at 7 CFR 4284.931.
Federally-recognized Tribes and tribal entities must demonstrate that they meet the definition requirements for one of the four eligible applicant types. Rural Development State Offices and posted application toolkits will provide additional information on Tribal eligibility.
Per 7 CFR 4284.921, an applicant is ineligible if they have been debarred or suspended or otherwise excluded from or ineligible for participation in Federal assistance programs under Executive Order 12549, “Debarment and Suspension.” In addition, an applicant will be considered ineligible for a grant due to an outstanding judgment obtained by the U.S. in a Federal Court (other than U.S. Tax Court), is delinquent on the payment of Federal income taxes, or is delinquent on Federal debt.
An Applicant may submit only one application in response to a solicitation, and must explicitly direct that it compete in either the general funds competition or in one of the named reserved funds competitions. Multiple applications from separate entities with identical or greater than 75 percent common ownership, or from a parent, subsidiary or affiliated organization (with “affiliation” defined by Small Business Administration regulation 13 CFR 121.103, or successor regulation) are not permitted. Further, Applicants who have already received a Planning Grant for the proposed project cannot receive another Planning Grant for the same project. Applicants who have already received a Working Capital Grant for the proposed project cannot receive any additional grants for that project (Proposals from previous award recipients should be substantially different in terms of products and/or markets and should not merely be extensions of previously funded projects).
There is a matching funds requirement of at least $1 for every $1 in grant funds provided by the Agency (matching funds plus grant funds must equal proposed Total Project Costs). Matching funds may be in the form of cash or eligible in-kind contributions and may be used only for eligible project purposes. Tribal applicants may utilize grants made available under Public Law 93-638, the Indian Self-Determination and Education Assistance Act of 1975, as their matching contribution, and should check with appropriate tribal authorities regarding the availability of such funding.
Matching funds must be available at time of application and must be certified and verified as described in 7 CFR 4284.931(b)(3) and (4). Note that matching funds must also be discussed as part of the scoring criterion Commitments and Support as described in section E.1. (c).
You must demonstrate that you meet all the project eligibility requirements of 7 CFR 4284.922.
(a)
(b)
(i) Planning Grants. A planning grant is used to fund development of a defined program of economic planning activities to determine the viability of a potential value-added venture, and specifically for the purpose of paying for a qualified consultant to conduct and develop a feasibility study, business plan, and/or marketing plan associated with the processing and/or marketing of a value-added agricultural product. Planning grant funds may not be used to fund working capital activities.
(ii) Working Capital Grants. This type of grant provides funds to operate a value-added project, specifically to pay the eligible project expenses related to the processing and/or marketing of the value-added product that are eligible uses of grant funds. Working capital funds may not be used for planning purposes.
(c)
(d)
Priority points will also be awarded during the scoring process to eligible Agricultural Producer Groups, Farmer or Cooperatives, and Majority-Controlled Producer-Based Business Ventures that best contribute to creating or increasing marketing opportunities for Beginning Farmers or Ranchers, Socially-Disadvantaged Farmers or Ranchers, and/or Veteran Farmers or Ranchers. You must meet the eligibility requirements at 7 CFR 4284.923 and 4284.924 and must address the relevant proposal evaluation criterion.
Eligible uses of grant and matching funds are discussed, along with examples, in 7 CFR 4284.923. In general, grant and cost-share matching funds have the same use restrictions and must be used to fund only the costs for eligible purposes as defined at 7 CFR 4284.923 (a) and (b).
Federal procurement standards prohibit transactions that involve a real or apparent Conflict of Interest for owners, employees, officers, agents, or their Immediate Family members having a personal, professional, financial or other interest in the outcome of the project; including organizational conflicts, and conflicts that restrict open and free competition for unrestrained trade. A list (not all inclusive) of ineligible uses of grant and matching funds is found in 7 CFR 4284.926.
The application toolkit, regulation, and official program notification for this funding opportunity can be obtained online at
You may submit your application in paper form or electronically through Grants.gov. Your application must contain all required information.
To submit an application electronically, you must follow the instructions for this funding announcement at
You can locate the Grants.gov downloadable application package for this program by using a keyword, the program name, or the Catalog of Federal Domestic Assistance Number for this program.
When you enter the Grants.gov Web site, you will find information about submitting an application electronically through the site, as well as the hours of operation.
To use Grants.gov, you must already have a DUNS number and you must also be registered and maintain registration in SAM. We strongly recommend that you do not wait until the application deadline date to begin the application process through Grants.gov.
You must submit all of your application documents electronically through Grants.gov.
After electronically submitting an application through Grants.gov, you will receive an automatic acknowledgement from Grants.gov that contains a Grants.gov tracking number.
If you want to submit a paper application, send it to the State Office located in the State where your project will primarily take place. You can find State Office Contact information at:
Your application must contain all of the required forms and proposal elements described in 7 CFR 4284.931, unless otherwise clarified in this Notice. You are encouraged, but not required to utilize the Application Toolkits found at
• Standard Form (SF)-424, “Application for Federal Assistance,” to include your DUNS number and SAM (CAGE) code and expiration date. Because there are no specific fields for a CAGE code and expiration date, you may identify them anywhere you want to on the form. If you do not include the CAGE code and expiration date and the DUNS number in your application, it will not be considered for funding.
• SF-424A, “Budget Information-Non-Construction Programs.” This form must be completed and submitted as part of the application package.
• SF-424B, “Assurances—Non-Construction Programs.” This form must be completed, signed, and submitted as part of the application package.
• Form AD-3030, “Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants,” if you are a corporation. A corporation is any entity that has filed articles of incorporation in one of the 50 States, the District of Columbia, the Federated States of Micronesia, the Republic of Palau, and the Republic of the Marshall Islands, or the various territories of the United States including American Samoa, Guam, Midway Islands, the Commonwealth of the Northern Mariana Islands, Puerto Rico,
• You must certify that there are no current outstanding Federal judgments against your property and that you will not use grant funds to pay for any judgment obtained by the United States. To satisfy the Certification requirement, you should include this statement in your application: “[INSERT NAME OF APPLICANT] certifies that the United States has not obtained an unsatisfied judgment against its property and will not use grant funds to pay any judgments obtained by the United States.” A separate signature is not required.
• Executive Summary and Abstract. A one-page Executive Summary containing the following information: Legal name of applicant entity, application type (planning or working capital), applicant type, amount of grant request, a summary of your project, and whether you are submitting a simplified application, and whether you are requesting Reserved Funds. Also include a separate abstract of up to 100 words briefly describing your project.
• Eligibility discussion.
• Work plan and budget.
• Performance evaluation criteria.
• Proposal evaluation criteria.
• Certification and verification of matching funds.
• Reserved Funds and Priority Point documentation (as applicable).
• Appendices containing required supporting documentation.
In order to be eligible (unless you are accepted under 2 CFR 25.110(b), (c) or (d), you are required to:
(a) Provide a valid DUNS number in your application, which can be obtained at no cost via a toll-free request line at (866) 705-5711;
(b) Register in SAM before submitting your application. You may register in SAM at no cost at
(c) Continue to maintain an active SAM registration with current information at all times during which you have an active Federal award or an application or plan under consideration by a Federal awarding agency.
If you have not fully complied with all applicable DUNS and SAM requirements, the Agency may determine that the applicant is not qualified to receive a Federal award and the Agency may use that determination as a basis for making an award to another applicant. Please refer to Section F. 2. for additional submission requirements that apply to grantees selected for this program.
Electronic applications must be received at
Executive Order (EO) 12372, Intergovernmental Review of Federal Programs, applies to this program. This EO requires that Federal agencies provide opportunities for consultation on proposed assistance with State and local governments. Many States have established a Single Point of Contact (SPOC) to facilitate this consultation. A list of States that maintain a SPOC may be obtained at
Funding limitations and reservations found in the program regulation at 7 CFR 4284.927 will apply, including:
(a) Use of Funds. Grant funds may be used to pay up to 50 percent of the total eligible project costs, subject to the limitations established for maximum total grant amount. Grant funds may not be used to pay any costs of the project incurred prior to the date of grant approval. Grant and matching funds may only be used for eligible purposes. (see examples of eligible and ineligible uses in 7 CFR 4284.923 and 4284.924, respectively).
(b) Grant Term (project period). Your project timeframe or grant period can be a maximum of 36 months in length from the date of award. Your proposed grant period should begin no earlier than the anticipated award announcement date in this notice and should end no later than 36 months following that date. If you receive an award, your grant period will be revised to begin on the actual date of award—the date the grant agreement is executed by the Agency—and your grant period end date will be adjusted accordingly. Your project activities must begin within 90 days of that date of award. The length of your grant period should be based on your project's complexity, as indicated in your application work plan. For example, it is expected that most planning grants can be completed within 12 months.
(c) Program Income. If income (Program Income) is earned during the grant period as a result of the project activities, it is subject to the requirements in 2 CFR 200.80, and must be managed and reported accordingly.
(d) Majority Controlled Producer-Based Business. The aggregate amount of awards to Majority Controlled Producer-Based Businesses in response to this announcement shall not exceed 10 percent of the total funds obligated for the program during the fiscal year.
(e) Reserved Funds. Ten percent of all funds available for FY 2016 will be reserved to fund projects that benefit Beginning Farmers or Ranchers, or Socially-Disadvantaged Farmers or Ranchers. In addition, 10 percent of total funding available will be used to fund projects that propose development of Mid-Tier Value Chains as part of a Local or Regional Supply Chain Network. See related definitions in 7 CFR 4284.902.
(f) Disposition of Reserved Funds Not Obligated. For this announcement, any reserved FY 2015 funds that have not been obligated by June 30, 2016, will be available to the Secretary to make VAPG grants in accordance with 7 CFR 4284.927(d).
This notice has been reviewed in accordance with 7 CFR part 1940,
All grants made under this Notice are subject to title VI of the Civil Rights Act of 1964 as required by the USDA (7 CFR part 15, subpart A) and section 504 of the Rehabilitation Act of 1973.
Applications will be reviewed and processed as described at 7 CFR 4284.940. The Agency will review your application to determine if it is complete and eligible. If at any time, the Agency determines that your application is ineligible, you will be notified in writing as to the reasons it was determined ineligible and you will be informed of your review and appeal rights. Funding of successfully appealed applications will be limited to available FY 2016 funds.
The Agency will only score applications in which the applicant and project are eligible, which are complete and sufficiently responsive to program requirements, and in which the Agency agrees on the likelihood of financial feasibility for working capital requests. We will score your application according to the procedures and criteria specified in 7 CFR 4284.942, and with tiered scoring thresholds as specified below.
For each criterion, you must show how the project has merit and why it is likely to be successful. If you do not address all parts of the criterion, or do not sufficiently communicate relevant project information, you will receive lower scores. VAPG is a competitive program, so you will receive scores based on the quality of your responses. Simply addressing the criteria will not guarantee higher scores. The maximum number of points that can be awarded to your application is 100. For this announcement, the minimum score requirement for funding is 50 points.
The Agency application toolkit provides additional instruction to help you to respond to the criteria below.
(a)
For both planning and working capital grants, you should discuss the technological feasibility of the project, as well as operational efficiency, profitability, and overall economic sustainability resulting from the project. In addition, demonstrate the potential for expanding the customer base for the agricultural commodity or value-added product, and the expected increase in revenue returns to the producer-owners providing the majority of the raw agricultural commodity to the project. You should reference third-party data and other information that specifically supports your value-added project; discuss the value-added process you are proposing; potential markets and distribution channels; the value to be added to the raw commodity through the value-added process; cost and availability of inputs, your experience in marketing the proposed or similar product; business financial statements; and any other relevant information that supports the viability of your project. Working capital applicants should demonstrate that these outcomes will result from the project. Planning grant applicants should describe the expected results, and the reasons supporting those expectations.
Points will be awarded as follows:
(i) 0 points will be awarded if you do not substantively address the criterion.
(ii) 1-5 points will be awarded if you do not address each of the following: technological feasibility, operational efficiency, profitability, and overall economic sustainability.
(iii) 6-13 points will be awarded if you address technological feasibility, operational efficiency, profitability, and overall economic sustainability, but do not reference third-party information that supports the success of your project.
(iv) 14-22 points will be awarded if you address technological feasibility, operational efficiency, profitability, and overall economic sustainability, supported by third-party information demonstrating a reasonable likelihood of success.
(v) 23-30 points will be awarded if all criterion components are well addressed, supported by third-party information, and demonstrate a high likelihood of success.
(b)
You must identify all individuals who will be responsible for completing the proposed tasks in the work plan, including the roles and activities that owners, staff, contractors, consultants or new hires may perform; and show that these individuals have the necessary qualifications and expertise, including those hired to do market or feasibility analyses, or to develop a business operations plan for the value-added venture. You must include the qualifications of those individuals responsible for leading or managing the total project (applicant owners or project managers), as well as those individuals responsible for actually conducting the various individual tasks in the work plan (such as consultants, contractors, staff or new hires). You must discuss the commitment and the availability of any consultants or other professionals to be hired for the project. If staff or consultants have not been selected at the time of application, you must provide specific descriptions of the qualifications required for the positions to be filled. Applications that demonstrate the strong credentials, education, capabilities, experience and availability of project personnel that will contribute to a high likelihood of project success will receive more points than those that demonstrate less potential for success in these areas.
Points will be awarded as follows:
(i) 0 points will be awarded if you do not substantively address the criterion.
(ii) 1-4 points will be awarded if qualifications and experience of all staff is not addressed and/or if necessary qualifications of unfilled positions are not provided.
(iii) 5-9 points will be awarded if all project personnel are identified but do not demonstrate qualifications or experience relevant to the project.
(iv) 10-14 will be awarded if most key personnel demonstrate strong credentials and/or experience, and availability indicating a reasonable likelihood of success.
(v) 15-20 points will be awarded if all personnel demonstrate strong, relevant credentials or experience, and availability indicating a high likelihood of project success.
(c)
Producer commitments to the project will be evaluated based on the number of independent producers currently involved in the project; and the nature, level and quality of their contributions, including matching contributions. End-
Points will be awarded as follows:
(i) 0 points will be awarded if you do not substantively address the criterion.
(ii) 1-3 points will be awarded if you are the only producer participating in the project, AND show real, direct support from at least one end-user or third-party contributor.
(iii) 4-6 points will be awarded if you, as the applicant, are the only producer participating in the project, AND show strong financial commitment in the form of cash matching contributions to the project AND measurable commitment or interest in purchasing the value-added product from at least one end-user; AND commitment or tangible support from at least one other third-party contributor; OR you, as the applicant, demonstrate participation from multiple producers, AND measurable commitment or interest in purchasing the value-added product from at least one end-user; AND commitment or tangible support from at least one third party contributor.
(iv) 7-10 points will be awarded if you, as the applicant, show strong financial commitment to the project in the form of cash matching contributions, AND participation from additional producers, AND measurable commitment or interest from multiple end-users, AND commitment or tangible support from multiple third-party contributors.
(d)
You must submit a comprehensive work plan and budget (for full details, see 7 CFR 4284.922(b)(5)). Your work plan must provide specific and detailed descriptions of the tasks and the key project personnel that will accomplish the project's goals. The budget must present a detailed breakdown of all estimated costs of project activities and allocate those costs among the listed tasks. You must show the source and use of both grant and matching funds for all tasks. Matching funds must be spent at a rate equal to, or in advance of, grant funds. An eligible start and end date for the project and for individual project tasks must be clearly shown and may not exceed Agency specified timeframes for the grant period. Working capital applications must include an estimate of program income expected to be earned during the grant period (see 2 CFR 200.307).
Points will be awarded as follows:
(i) 0 points will be awarded if you do not substantively address the criterion.
(ii) 1-7 points will be awarded if the work plan and budget do not account for all project goals, tasks, costs, timelines, and responsible personnel.
(iii) 8-14 points will be awarded if you provide a clear, comprehensive work plan detailing all project goals, tasks, timelines, costs, and responsible personnel in a logical and realistic manner that demonstrates a reasonable likelihood of success.
(iv) 15-20 points will be awarded if you provide a clear, comprehensive work plan detailing all project goals, tasks, timelines, costs, and responsible personnel in a logical and realistic manner that demonstrates a high likelihood of success.
(e)
It is recommended that you use the Agency application package when applying for priority points and refer to the requirements specified in 7 CFR 4284.924. Priority points may be awarded in both the general funds and Reserved Funds competitions.
(i) 5 points will be awarded if you meets the requirements for one of the following categories and provide the documentation described in 7 CFR 4284.923 and 4284.924 as applicable: Beginning Farmer or Rancher, Socially-Disadvantaged Farmer or Rancher, Veteran Farmer or Rancher, or Operator of a Small or Medium-sized Farm or Ranch that is structured as a Family Farm, Farmer or Rancher Cooperative, or are proposing a Mid-Tier Value Chain project.
(ii) Up to 5 priority points will be awarded if you are an Agricultural Producer Group, Farmer or Rancher Cooperative, or Majority-Controlled Producer-Based Business Venture (referred to below as “applicant group”) whose project “best contributes to creating or increasing marketing opportunities” for Operators of Small- and Medium-sized Farms and Ranches that are structured as Family Farms, Beginning Farmers and Ranchers, Socially-Disadvantaged Farmers and Ranchers, and Veteran Farmers and Ranchers (referred to below as “priority groups”). For each of the priority point levels below, applications must demonstrate how the proposed project will contribute to new or increased marketing opportunities for respective priority groups. Guidance on relevant information required to adequately demonstrate this requirement can be found in program application package.
(A) 2 priority points will be awarded if the existing membership of the applicant group is comprised of either more than 50 percent of any one of the four priority groups or more than 50 percent of any combination of the four priority groups.
(B) 1 priority point will be awarded if the existing membership of the applicant group is comprised of two or more of the priority groups. One point is awarded regardless of whether a group's membership is comprised of two, three, or all four of the priority groups.
(C) 2 priority points will be awarded if the applicant's proposed project will increase the number of priority groups that comprise applicant membership by one or more priority groups. However, if an applicant group's membership is already comprised of all four priority groups, such an applicant would not be eligible for points under this criterion because there is no opportunity to increase the number of priority groups. Note also that this criterion does not consider either the percentage of the existing membership that is comprised of the four priority groups or the number of priority groups currently comprising the applicant group's membership.
(f)
The Administrator of the Agency may choose to award up to 10 points to an application to improve the geographic diversity of awardees in a fiscal year.
The Agency will select applications for award under this Notice in accordance with the provisions specified in 7 CFR 4284.950(a).
If your application is eligible and complete, it will be qualitatively scored by at least two reviewers based on criteria specified in section E.1. of this Notice. One of these reviewers will be an experienced RD employee from your servicing State Office and at least one additional reviewer will be a non-Federal, independent reviewer, who must meet the following qualifications. Independent reviewers must have at least bachelor's degree in one or more of the following fields: Agri-business, agricultural economics, agriculture, animal science, business, marketing, economics or finance; and a minimum of 8 years of experience in an agriculture-related field (
The Administrator of the Agency may choose to award up to 10 Administrator priority points based on criterion (f) in section E.1. of this Notice. These points will be added to the cumulative score for a total possible score of 100.
A final ranking will be obtained based solely on the scores received for criteria (a) through (e). A minimum score of 50 points is required for funding. Applications for Reserved Funds will be funded in rank order until funds are depleted. Unfunded reserve applications will be returned to the general funds where applications will be funded in rank order until the funds are expended. Funding for Majority Controlled Producer-Based Business Ventures is limited to 10 percent of total grant funds expected to be obligated as a result of this Notice. These applications will be funded in rank order until the funding limitation has been reached. Grants to these applicants from Reserved Funds will count against this funding limitation. In the event of tied scores, the Administrator shall have discretion in breaking ties.
If your application is ranked, but not funded, it will not be carried forward into the next competition.
If you are selected for funding, you will receive a signed notice of Federal award by postal mail, containing instructions on requirements necessary to proceed with execution and performance of the award.
If you are not selected for funding, you will be notified in writing via postal mail and informed of any review and appeal rights. Funding of successfully appealed applications will be limited to available FY 2016 funding.
Additional requirements that apply to grantees selected for this program can be found in 7 CFR part 4284, subpart J; the Grants and Agreements regulations of the Department of Agriculture codified in 2 CFR parts 180, 400, 415, 417, 418, 421; 2 CFR parts 25 and 170; and 48 CFR 31.2, and successor regulations to these parts.
In addition, all recipients of Federal financial assistance are required to report information about first-tier sub-awards and executive compensation (see 2 CFR part 170). You will be required to have the necessary processes and systems in place to comply with the Federal Funding Accountability and Transparency Act of 2006 (Pub.L. 109-282) reporting requirements (see 2 CFR 170.200(b), unless you are exempt under 2 CFR 170.110(b)). More information on these requirements can be found at
The following additional requirements apply to grantees selected for this program:
(a) Agency approved Grant Agreement.
(b) Letter of Conditions.
(c) Form RD 1940-1, “Request for Obligation of Funds.”
(d) Form RD 1942-46, “Letter of Intent to Meet Conditions.”
(e) Form AD-1047, “Certification Regarding Debarment, Suspension, and Other Responsibility Matters—Primary Covered Transactions.”
(f) Form AD-1048, “Certification Regarding Debarment, Suspension, Ineligibility and Voluntary Exclusion—Lower Tier Covered Transactions.”
(g) Form AD-1049, “Certification Regarding a Drug-Free Workplace Requirement (Grants).”
(h) Form AD-3031, “Assurance Regarding Felony Conviction or Tax Delinquent Status for Corporate Applicants.” Must be signed by corporate applicants who receive an award under this Notice.
(i) Form RD 400-4, “Assurance Agreement.”
(j) SF LLL, “Disclosure of Lobbying Activities,” if applicable.
(k) Use Form SF 270, “Request for Advance or Reimbursement.”
After grant approval and through grant completion, you will be required to provide the following, as indicated in the Grant Agreement:
(a) A SF-425, “Federal Financial Report,” and a project performance report will be required on a semiannual basis (due 45 working days after end of the semiannual period). For the purposes of this grant, semiannual periods end on March 31st and September 30th. The project performance reports shall include the elements prescribed in the grant agreement.
(b) A final project and financial status report within 90 days after the expiration or termination of the grant.
(c) Provide outcome project performance reports and final deliverables.
If you have questions about this Notice, please contact the State Office as identified in the
The U.S. Department of Agriculture (USDA) prohibits discrimination against its customers, employees, and applicants for employment on the bases of race, color, national origin, age, disability, sex, gender identity, religion, reprisal, and where applicable, political beliefs, marital status, familial or parental status, sexual orientation, or all or part of an individual's income is derived from any public assistance program, or protected genetic information in employment or in any program or activity conducted or funded by the Department. (Not all prohibited bases will apply to all programs and/or employment activities.)
If you wish to file an employment complaint, you must contact your agency's EEO Counselor (PDF) within 45 days of the date of the alleged
If you wish to file a Civil Rights program complaint of discrimination, complete the USDA Program Discrimination Complaint Form (PDF), found online at
Individuals who are deaf, hard of hearing or have speech disabilities and you wish to file either an EEO or program complaint please contact USDA through the Federal Relay Service at (800) 877-8339 or (800) 845-6136 (in Spanish).
Persons with disabilities, who wish to file a program complaint, please see information above on how to contact us by mail directly or by email. If you require alternative means of communication for program information (
Rural Utilities Service, USDA.
Notice of Solicitation of Applications (NOSA).
The Rural Utilities Service (RUS), an agency of the United States Department of Agriculture (USDA), announces that it is accepting applications for fiscal year (FY) 2016 for the Rural Broadband Access Loan and Loan Guarantee program (the Broadband Program).
In addition to announcing the application window, RUS announces the minimum and maximum amounts for broadband loans for FY 2016.
Applications under this NOSA will be accepted immediately and must be submitted through the Agency's online application system
For further information contact Shawn Arner, Deputy Assistant Administrator, Loan Originations and Approval Division, Rural Utilities Service, STOP 1597, 1400 Independence Avenue SW., Washington, DC 20250-1597, Telephone: (202) 720-0800, or email:
The Rural Broadband Access Loan and Loan Guarantee Program (the Broadband Program) is authorized by the Rural Electrification Act (7 U.S.C. 901
During FY 2016, loans will be made available for the construction, improvement, and acquisition of facilities and equipment to provide service at the broadband lending speed for eligible rural areas. Applications must be submitted in accordance with the interim final rule published July 30, 2015.
For questions about the requirements of completing an application please use the RUS contact listed in the
Loans under this authority will not be made for less than $100,000. The maximum loan amount that will be considered for FY 2016 is $10,000,000.
The interim regulation for the Broadband Program requires that certain definitions affecting eligibility be revised and published from time to time by the agency in the
Applications for FY 2016 will be accepted from April 8, 2016 through July 7, 2016. Although review of applications will start when they are submitted, all applications submitted by July 7, 2016, will be evaluated and ranked together on the basis of the number of unserved households in the proposed funded service area. Subject to available funding, eligible applications that propose to serve the most unserved households will receive funding offers before other eligible applications that have been submitted.
Applications will not be accepted after July 7, 2016, until a new funding window has been opened with the publication of an additional NOSA in the
In accordance with the Paperwork Reduction Act of 1995, the information collection requirements associated with Broadband loans, as covered in this NOSA, have been approved by the Office of Management and Budget (OMB) under OMB Control Number 0572-0130.
In accordance with Federal civil rights law and U.S. Department of Agriculture (USDA) civil rights regulations and policies, the USDA, its Agencies, offices, and employees, and institutions participating in or administering USDA programs are prohibited from discriminating based on race, color, national origin, religion, sex, gender identity (including gender expression), sexual orientation, disability, age, marital status, family/
Persons with disabilities who require alternative means of communication for program information (
To file a program discrimination complaint, complete the USDA Program Discrimination Complaint Form, AD-3027, found online at
(1)
(2)
(3)
USDA is an equal opportunity provider, employer, and lender.
Rural Utilities Service, USDA.
Notice and request for comments.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35, as amended), the Rural Utilities Service (RUS) invites comments on this information collection for which approval from the Office of Management and Budget (OMB) will be requested.
Comments on this notice must be received by June 7, 2016.
Thomas P. Dickson, Acting Director, Program Development and Regulatory Analysis, USDA Rural Utilities Service, 1400 Independence Avenue SW., STOP 1522, Room 5164 South Building, Washington, DC 20250-1522. Telephone: (202) 690-4492; Email:
The Office of Management and Budget's (OMB) regulation (5 CFR 1320) implementing provisions of the Paperwork Reduction Act of 1995 (Pub. L. 104-13) requires that interested members of the public and affected agencies have an opportunity to comment on information collection and recordkeeping activities (see 5 CFR 1320.8(d)). This notice identifies an information collection that RUS is submitting to OMB for extension.
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Agency, including whether the information will have practical utility; (b) the accuracy of the Agency's estimate of the burden of the proposed collection of information including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology. Comments may be sent to: Thomas P. Dickson, Acting Director, Program Development and Regulatory Analysis, USDA Rural Utilities Service, 1400 Independence Avenue SW., STOP 1522, Washington, DC 20250-1522. FAX: (202)720-8435, Email:
Copies of this information collection can be obtained from Rebecca Hunt, Program Development and Regulatory Analysis, at (202) 205-3660, FAX: (202) 720-8435, Email:
All responses to this notice will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
U.S. Commission on Civil Rights.
Announcement of public meeting.
Friday, May 6, 2016.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act (FACA) that a meeting of the Texas State Advisory Committee (Committee) to the Commission will be held at 11:00 a.m. (Central Time) Friday, May 6, 2016, for the purpose of discussing plans to hold a briefing meeting assessing the impact of a 2012 study by the Public Policy Research Institute at Texas A&M University and the Council of State Governments Justice Center that found ethnic and racial disparities in school discipline in Texas.
This meeting is available to the public through the following toll-free call-in number: 888-395-3227; when prompted, please provide conference ID number: 4227309. Any interested member of the public may call this number and listen to the meeting. An open comment period will be provided to allow members of the public to make a statement at the end of the meeting.
Persons with hearing impairments may also follow the proceedings by first calling the Federal Relay Service at 1-800-977-8339 and providing the Service with the conference call number and conference ID number. Hearing-impaired persons who will attend the meeting and require the services of a sign language interpreter should contact the Regional Office at least ten (10) working days before the scheduled date of the meeting.
Members of the public may also submit written comments. The comments must be received in the Western Regional Office of the Commission by Monday, June 6, 2016. The address is Western Regional Office, U.S. Commission on Civil Rights, 300 N. Los Angeles Street, Suite 2010, Los Angeles, CA 90012. Persons wishing to email their comments may do so by sending them to Angela French-Bell, Regional Director, Western Regional Office, at
Records and documents discussed during the meeting will be available for public viewing prior to and after the meeting at
Angela French-Bell, DFO, at (213) 894-3437 or
Bureau of the Census, Department of Commerce.
Notice of advisory committee charter renewal.
The Bureau of the Census (Census Bureau) is giving notice that the Secretary of the Department of Commerce has determined that the renewal of an advisory committee of technical advisors is necessary and in the public interest. Accordingly, the Census Bureau has chartered the Census Scientific Advisory Committee (CSAC). The renewed charter can be found on the Census Bureau's Advisory Committee Web site at the following link:
Tara Dunlop, Chief, Advisory Committee Branch, U.S. Census Bureau, Room 8H177, Washington, DC 20233, telephone 301-763-5222,
The CSAC will advise the Census Bureau's Director on the full range of Census Bureau programs and activities. The CSAC will provide scientific and technical expertise from the following disciplines: demography, economics, geography, psychology, statistics, survey methodology, social and behavioral sciences, Information Technology and computing, marketing and other fields of expertise, as appropriate, to address Census Bureau program needs and objectives.
The CSAC will function solely as an advisory body and in compliance with provisions of the Federal Advisory Committee Act. Pursuant to subsection 9(c) of the Federal Advisory Committee Act, 5 U.S.C., App., as amended, copies of this charter were furnished to the Library of Congress and to the following Committees of Congress:
Bureau of the Census, Department of Commerce.
Notice of advisory committee charter renewal.
The Bureau of the Census (Census Bureau) is giving notice that the Secretary of the Department of Commerce has determined that the charter renewal of the National Advisory Committee of Racial, Ethnic, and Other Populations (NAC) is necessary and in the public interest. The renewed charter can be found on the Census Bureau's Advisory Committee Web site at the following link:
Tara Dunlop, Chief, Advisory Committee Branch, Room 8H177, U.S. Census Bureau, Washington, DC 20233, telephone 301-763-5222,
The Census Bureau's National Advisory Committee on Racial, Ethnic, and Other Populations will advise the Director of the Census Bureau on the full range of Census Bureau programs and activities. The NAC will provide race, ethnic, and other population expertise from the following disciplines: economic, housing, demographic, socioeconomic, linguistic, technological, methodological, geographic, behavioral and operational variables affecting the cost, accuracy, and implementation of Census Bureau programs and surveys, including the decennial census.
The NAC will function solely as an advisory body and in compliance with provisions of the Federal Advisory Committee Act. Pursuant to subsection 9(c) of the Federal Advisory Committee Act, 5 U.S.C., App., as amended, copies of this charter were furnished to the Library of Congress and to the following Committees of Congress:
Bureau of the Census, Department of Commerce.
Notice of public virtual meeting.
The Bureau of the Census (Census Bureau) is giving notice of a virtual meeting of the National Advisory Committee (NAC). The Committee will address updates on the 2015 National Content Test and Tribal Enrollment Question Focus Groups. The NAC will meet virtually on Thursday, April 21, 2016. Last minute changes to the schedule are possible, which could prevent giving advance public notice of schedule adjustments. Please visit the Census Advisory Committees Web site for the most current meeting agenda at:
April 21, 2016. The virtual meeting will begin at approximately 2:00 p.m. ET and end at approximately 4:00 p.m. ET.
The meeting will be held via teleconference. To attend, participants should call the following phone number to access the audio portion of the meeting: 1-800-369-1730, passcode: 5198433. The meeting will be available via WebEx, please CLICK HERE for access. The meeting number is 744882915.
Tara Dunlop, Advisory Committee Branch Chief, Customer Liaison and Marketing Services Office,
The NAC was established in March 2012 and operates in accordance with the Federal Advisory Committee Act (Title 5, United States Code, Appendix 2, Section 10). The NAC members are appointed by the Director, Census Bureau, and consider topics such as hard to reach populations, race and ethnicity, language, aging populations, American Indian and Alaska Native tribal considerations, new immigrant populations, populations affected by natural disasters, highly mobile and migrant populations, complex households, rural populations, and population segments with limited access to technology. The Committee also advises on data privacy and confidentiality, among other issues.
All meetings are open to the public. A brief period will be set aside at the meeting for public comment on April 21, 2016. However, individuals with extensive questions or statements must submit them in writing to:
The Greater Mississippi Foreign-Trade Zone, Inc., grantee of FTZ 158, submitted a notification of proposed production activity to the FTZ Board on behalf of Max Home, LLC (Max Home), for its facilities in Iuka and Fulton, Mississippi. The notification conforming to the requirements of the regulations of the FTZ Board (15 CFR 400.22) was received on March 17, 2016.
Max Home previously had authority to conduct cut-and-sew activity using certain foreign micro-denier suede upholstery fabrics to produce upholstered furniture and related parts (upholstery cover sets) on a restricted basis (see Board Order 1744, 76 FR 11425, March 2, 2011). Board Order 1744 authorized the production of upholstered furniture (chairs, seats, sofas, sleep sofas, and sectionals) for a five-year period, with a scope of authority that only provided FTZ savings on a limited quantity (2.23 million square yards per year) of foreign origin, micro-denier suede upholstery fabric finished with a hot caustic soda solution process (
The current request seeks to renew Max Home's previously approved FTZ authority indefinitely (with no increase in the company's annual quantitative limit of 2.23 million square yards) and to add foreign-status leather and certain polyurethane-type fabrics to the scope of authority. Pursuant to 15 CFR 400.14(b), additional FTZ authority would be limited to the specific foreign-status materials and components and specific finished products described in the submitted notification (as described below) and subsequently authorized by the FTZ Board.
Production under FTZ procedures could exempt Max Home from customs duty payments on the foreign-status fabrics used in export production. On its domestic sales, Max Home would be able to apply the finished upholstery cover set (
Authority to admit foreign-status fabrics to Subzone 158F would only involve micro-denier suede upholstery fabrics finished with a hot caustic soda solution process (classified within HTSUS Headings 5407, 5512, 5515, 5516, 5801, and 5903), polyurethane fabrics backed with ground leather (5903.20.2500), wet coagulation process 100 percent polyurethane coated fabrics (5903.20.2500), and upholstery leather (Heading 4107), as detailed in the notification (duty rate ranges from free to 14.9%).
Public comment is invited from interested parties. Submissions shall be addressed to the FTZ Board's Executive Secretary at the address below. The closing period for their receipt is May 18, 2016.
A copy of the notification will be available for public inspection at the Office of the Executive Secretary, Foreign-Trade Zones Board, Room 21013, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230-0002, and in the “Reading Room” section of the FTZ Board's Web site, which is accessible via
For further information, contact Pierre Duy at
Bureau of Industry and Security, Department of Commerce.
Notice; annual reporting requirements.
This notice is to remind the public that U.S. firms are required to report annually to the Department of Commerce (Commerce) information on contracts for the sale of defense articles or defense services to foreign countries or foreign firms that are subject to offsets agreements exceeding $5,000,000 in value. U.S. firms are also required to report annually to Commerce information on offsets transactions completed in performance of existing offsets commitments for which offsets credit of $250,000 or more has been claimed from the foreign representative. This year, such reports must include relevant information from calendar year 2015 and must be submitted to Commerce no later than June 15, 2016.
Submit reports in both hard copy and electronically. Address the hard copy to “Offsets Program Manager, U.S. Department of Commerce, Office of Strategic Industries and Economic Security, Bureau of Industry and Security (BIS), Room 3878, Washington, DC 20230”. Submit electronic copies toy to
Ronald DeMarines, Office of Strategic Industries and Economic Security, Bureau of Industry and Security, U.S. Department of Commerce, telephone: 202-482-3755; fax: 202-482-5650; email:
Section 723(a)(1) of the Defense Production Act of 1950, as amended (DPA) (50 U.S.C. 4568 (2015)) requires the President to submit an annual report to Congress on the impact of offsets on the U.S. defense industrial base. Section 723(a)(2) directs the Secretary of Commerce (Secretary) to prepare the President's report and to develop and administer the regulations necessary to collect offsets data from U.S. defense exporters.
The authorities of the Secretary regarding offsets have been delegated to the Under Secretary of Commerce for Industry and Security. The regulations associated with offsets reporting are set forth in part 701 of title 15 of the Code of Federal Regulations. Offsets are compensation practices required as a condition of purchase in either government-to-government or commercial sales of defense articles and/or defense services, as defined by the Arms Export Control Act (22 U.S.C. 2778) and the International Traffic in Arms Regulations (22 CFR 120-130). Offsets are also applicable to certain items controlled on the Commerce Control list (CCL) and with an Export Control Classification Number (ECCN) including the numeral “6” as its third character. The CCL is found in Supplement No. 1 to part 774 of the Export Administration Regulations.
An example of an offset is as follows: a company that is selling a fleet of military aircraft to a foreign government may agree to offset the cost of the aircraft by providing training assistance to plant managers in the purchasing country. Although this distorts the true price of the aircraft, the foreign government may require this sort of extra compensation as a condition of awarding the contract to purchase the aircraft. As described in the regulations, U.S. firms are required to report information on contracts for the sale of defense articles or defense services to foreign countries or foreign firms that are subject to offsets agreements exceeding $5,000,000 in value. U.S. firms are also required to report annually information on offsets transactions completed in performance of existing offsets commitments for which offsets credit of $250,000 or more has been claimed from the foreign representative.
Commerce's annual report to Congress includes an aggregated summary of the data reported by industry in accordance with the offsets regulation and the DPA (50 U.S.C. 4568 (2015)). As provided by section 723(c) of the DPA, BIS will not publicly disclose individual firm information it receives through offsets reporting unless the firm furnishing the information specifically authorizes public disclosure. The information collected is sorted and organized into an aggregate report of national offsets data, and therefore does not identify company-specific information.
In order to enable BIS to prepare the next annual offset report reflecting calendar year 2015 data, affected U.S. firms must submit required information on offsets agreements and offsets transactions from calendar year 2015 to BIS no later than June 15, 2016.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
On March 3, 2016, the Department of Commerce (the Department) published a notice of initiation and preliminary results of a changed circumstances review of the antidumping duty order on diamond sawblades and parts thereof (diamond sawblades) from the People's Republic of China (the PRC).
Yang Jin Chun AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-5760.
Effective May 4, 2015, Wuhan Wanbang Co. (1) changed its legal status from a limited liability company to a joint-stock limited company and (2) changed its name to Wuhan Wanbang Laser Diamond Tools Co., Ltd.
On March 3, 2016, we initiated this changed circumstances review and preliminarily determined that Wuhan Wanbang Co., Ltd. is the successor-in-interest to Wuhan Wanbang Co.
The products covered by the order are all finished circular sawblades, whether slotted or not, with a working part that is comprised of a diamond segment or segments, and parts thereof, regardless of specification or size, except as specifically excluded below. Within the scope of the order are semifinished diamond sawblades, including diamond sawblade cores and diamond sawblade segments. Diamond sawblade cores are circular steel plates, whether or not attached to non-steel plates, with slots. Diamond sawblade cores are manufactured principally, but not exclusively, from alloy steel. A diamond sawblade segment consists of a mixture of diamonds (whether natural or synthetic, and regardless of the quantity of diamonds) and metal powders (including, but not limited to, iron, cobalt, nickel, tungsten carbide) that are formed together into a solid shape (from generally, but not limited to, a heating and pressing process).
Sawblades with diamonds directly attached to the core with a resin or electroplated bond, which thereby do not contain a diamond segment, are not included within the scope of the order. Diamond sawblades and/or sawblade cores with a thickness of less than 0.025 inches, or with a thickness greater than 1.1 inches, are excluded from the scope of the order. Circular steel plates that have a cutting edge of non-diamond material, such as external teeth that protrude from the outer diameter of the plate, whether or not finished, are excluded from the scope of the order. Diamond sawblade cores with a Rockwell C hardness of less than 25 are excluded from the scope of the order. Diamond sawblades and/or diamond segment(s) with diamonds that predominantly have a mesh size number greater than 240 (such as 250 or 260) are excluded from the scope of the order. Merchandise subject to the order is typically imported under heading 8202.39.00.00 of the Harmonized Tariff Schedule of the United States (HTSUS). When packaged together as a set for retail sale with an item that is separately classified under headings 8202 to 8205 of the HTSUS, diamond sawblades or parts thereof may be imported under heading 8206.00.00.00 of the HTSUS. On October 11, 2011, the Department included the 6804.21.00.00 HTSUS classification number to the customs case reference file, pursuant to a request by U.S. Customs and Border Protection (CBP).
For the reasons stated in the
This notice of final results is in accordance with sections 751(b)(1) and 777(i)(1) and (2) of the Tariff Act of 1930, as amended, and 19 CFR 351.216, and 19 CFR 351.221(c)(3).
Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce.
The U.S. Department of Commerce (the Department) preliminarily determines that countervailable subsidies are being provided to exporters/producers of circular welded carbon-quality steel pipe (circular welded pipe) from Pakistan. The period of investigation (POI) is July 1, 2014, through June 30, 2015.
Effective April 8, 2016.
Kaitlin Wojnar, AD/CVD Operations, Office VII, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-3857.
On the same day that the Department initiated this countervailing duty (CVD) investigation, the Department also initiated an antidumping duty (AD) investigation of circular welded pipe from Pakistan.
The product covered by this investigation is circular welded pipe from Pakistan. Interested parties filed comments regarding the scope of the investigation, which resulted in one clarification to the scope language and are addressed, in detail, in the Department's Preliminary Scope Decision Memorandum.
The Department is conducting this countervailing duty investigation in accordance with section 701 of the Act. We preliminarily determine that, for each of the programs found countervailable, there is a subsidy (
For this preliminary determination, pursuant to section 776(a) of the Act, the Department relied on facts otherwise available because necessary information is not available on the record.
A complete list of topics discussed in the Preliminary Decision Memorandum can be found at Appendix II to this notice.
In accordance with sections 776(a) and (b) of the Act, the Department applied facts otherwise available, with adverse inferences, to determine a countervailable subsidy rate for the non-cooperative mandatory respondent, IIL. With respect to the “all-others” rate, section 705(c)(5)(A)(ii) of the Act provides that, if the countervailable subsidy rates established for all individually-investigated exporters/producers are determined entirely under section 776 of the Act (
We preliminarily determine estimated countervailable subsidy rates as follows:
In accordance with sections 703(d)(1)(B) and (d)(2) of the Act, we are directing U.S. Customs and Border Protection to suspend liquidation of all entries of circular welded pipe from Pakistan, as described in the “Scope of the Investigation,” that are entered, or withdrawn from warehouse, for consumption on or after the date of the publication of this notice in the
Because the Department has reached its conclusions on the basis of adverse facts available, the calculations performed in connection with this preliminary determination are not proprietary in nature and are described in the Preliminary Decision Memorandum. Interested parties may submit case and rebuttal briefs, as well as request a hearing.
In accordance with section 703(f) of the Act, we will notify the U.S. International Trade Commission (ITC) of our determination. In addition, we are making all non-privileged and non-proprietary information relating to this investigation available to the ITC. We will allow the ITC access to all privileged and business proprietary information in our files, provided that the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order, without the written consent of the Assistant Secretary for Enforcement and Compliance.
In accordance with section 705(b)(2) of the Act, if our final determination is affirmative, the ITC will make its final determination no more than 45 days after the Department makes its final determination.
This determination is issued and published pursuant to sections 703(f) and 777(i) of the Act and 19 CFR 351.205(c).
This investigation covers welded carbon-quality steel pipes and tube, of circular cross-section, with an outside diameter (O.D.) not more than nominal 16 inches (406.4 mm), regardless of wall thickness, surface finish (
(a) Iron predominates, by weight, over each of the other contained elements;
(b) the carbon content is 2 percent or less, by weight; and
(c) none of the elements listed below exceeds the quantity, by weight, as indicated:
(i) 1.80 percent of manganese;
(ii) 2.25 percent of silicon;
(iii) 1.00 percent of copper;
(iv) 0.50 percent of aluminum;
(v) 1.25 percent of chromium;
(vi) 0.30 percent of cobalt;
(vii) 0.40 percent of lead;
(viii) 1.25 percent of nickel;
(ix) 0.30 percent of tungsten;
(x) 0.15 percent of molybdenum;
(xi) 0.10 percent of niobium;
(xii) 0.41 percent of titanium;
(xiii) 0.15 percent of vanadium; or
(xiv) 0.15 percent of zirconium.
Covered products are generally made to standard O.D. and wall thickness combinations. Pipe multi-stenciled to a standard and/or structural specification and to other specifications, such as American Petroleum Institute (API) API-5L specification, may also be covered by the scope of these investigations. In particular, such multi-stenciled merchandise is covered when it meets the physical description set forth above, and also has one or more of the following characteristics: is 32 feet in length or less; is less than 2.0 inches (50 mm) in outside diameter; has a galvanized and/or painted (
Standard pipe is ordinarily made to ASTM specifications A53, A135, and A795, but can also be made to other specifications. Structural pipe is made primarily to ASTM specifications A252 and A500. Standard and structural pipe may also be produced to proprietary specifications rather than to industry specifications.
Sprinkler pipe is designed for sprinkler fire suppression systems and may be made to industry specifications such as ASTM A53 or to proprietary specifications.
Fence tubing is included in the scope regardless of certification to a specification listed in the exclusions below, and can also be made to the ASTM A513 specification. Products that meet the physical description set forth above but are made to the following nominal outside diameter and wall thickness combinations, which are recognized by the industry as typical for fence tubing, are included despite being certified to ASTM mechanical tubing specifications:
The scope of this investigation does not include:
(a) Pipe suitable for use in boilers, superheaters, heat exchangers, refining furnaces and feedwater heaters, whether or not cold drawn, which are defined by standards such as ASTM A178 or ASTM A192;
(b) finished electrical conduit,
(c) finished scaffolding,
(d) tube and pipe hollows for redrawing;
(e) oil country tubular goods produced to API specifications;
(f) line pipe produced to only API specifications, such as API 5L, and not multi-stenciled; and
(g) mechanical tubing, whether or not cold-drawn, other than what is included in the above paragraphs.
The products subject to this investigation are currently classifiable in Harmonized Tariff Schedule of the United States (HTSUS) statistical reporting numbers 7306.19.1010, 7306.19.1050, 7306.19.5110, 7306.19.5150, 7306.30.1000, 7306.30.5015, 7306.30.5020, 7306.30.5025, 7306.30.5032, 7306.30.5040, 7306.30.5055, 7306.30.5085, 7306.30.5090, 7306.50.1000, 7306.50.5030, 7306.50.5050, and 7306.50.5070. The HTSUS subheadings above are provided for convenience and U.S. Customs purposes only. The written description of the scope of the investigation is dispositive.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a public meeting.
The Mid-Atlantic Fishery Management Council's (Council) Surfclam and Ocean Quahog Advisory Panel will hold a public meeting.
The meeting will be held on Monday, May 2, 2016, from 1:30 p.m. until 4 p.m.
The meeting will be held via Internet Webinar. Detailed connection details are available at
Christopher M. Moore Ph.D., Executive Director, Mid-Atlantic Fishery Management Council, 800 N. State Street, Suite 201, Dover, DE 19901; telephone: (302) 526-5255.
The purpose of the meeting is to develop a fishery performance report by the Council's Surfclam and Ocean Quahog Advisory Panel. The intent of this report is to facilitate structured input from the Surfclam and Ocean Quahog Advisory Panel members to the Council and its Scientific and Statistical Committee (SSC) on setting catch and landings limits for 2017-18, changes that may be occurring in the fisheries, and other fishery-related issues.
The meeting is physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to M. Jan Saunders at the Mid-Atlantic Council Office, (302) 526-5251, at least 5 days prior to the meeting date.
National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of availability of a Draft NOAA/NESDIS Commercial Space Activities Assessment Process; request for comments.
On January 8, 2016, NOAA released the NOAA Commercial Space Policy. Consistent with that policy, the Draft National Environmental Satellite, Data, and Information Service (NESDIS) Commercial Space Activities Assessment Process identifies the NESDIS process for engagement with the commercial sector by which NESDIS will assess and pursue commercial opportunities to support NOAA's space-based observational information requirements. In order to ensure consideration of a broad range of ideas for optimal methods of engaging with the commercial sector, NESDIS seeks comments on the Draft NESDIS Commercial Space Activities Assessment Process. Through
All comments are welcome. In particular, NOAA would like comments on the following areas:
What contractual or other mechanisms could NOAA use to work with commercial sector data providers beyond traditional acquisition approaches?
What steps should NOAA take to consider the long-term viability of a commercial data provider prior to an operational data purchase?
What are the key aspects of demonstration projects that allow the commercial sector to gain necessary insights?
What are the key aspects of demonstration projects that would allow NOAA to perform the necessary data validation for the continued success of NOAA's public safety mission?
Comments must be received by 5 p.m. on May 9, 2016.
You may submit comments on this document, identified by NOAA-NESDIS-2015-0132, by either of the following methods:
Ms. Kate Becker, NESDIS Office of the Chief of Staff, U.S. Department of Commerce, National Oceanic and Atmospheric Administration, National Environmental Satellite, Data, and Information Service, Room 8229, 1335 East West Highway, Silver Spring, MD 20910. (Phone: 301-713-7049,
NOAA is a science-based services agency charged with understanding and predicting changes in Earth systems in order to provide critical environmental intelligence to the American public, decision makers, and our partners. NOAA's environmental intelligence depends on observations obtained via a variety of systems, including satellites, ships, ground, and in situ networks.
The NOAA Commercial Space Policy and the NESDIS Commercial Space Activities Assessment Process are two steps of NOAA's multi-step approach to engaging the commercial sector to ensure best use of commercial sector capabilities. NOAA has developed these documents as timeless guidance to provide a foundation for a long-term endeavor. Both documents formally establish core principles that will guide NOAA's engagement with the commercial sector. In January, NOAA released the Commercial Space Policy to establish the broad principles for the use of commercial space-based approaches to meet NOAA's observational requirements. Now, to supplement the principles established in the policy, NESDIS has released the draft NESDIS Commercial Space Activities Assessment Process.
The NESDIS Process lays out the phases of the process that NESDIS will follow leading to any potential commercial data acquisition. First, NESDIS will release one or more Requests for Information (RFIs) to gather a sense of commercial capabilities and convey our interest in a new dataset. Based on assessment of the RFI responses, NESDIS will then release one or more Requests for Proposals (RFPs) to acquire and evaluate commercial data, which will include the data specifications we require. Based on RFP responses, NOAA may purchase data from one or more vendors for analysis and evaluation through a demonstration project.
Because specifications are unique to each individual dataset, RFPs are an appropriate vehicle for sharing data specifications rather than through the policy or the process. The RFPs will focus on individual systems and allow for an in-depth, detailed description of requirements.
Following the demonstration project and the pending results, NESDIS may issue one or more RFPs to purchase on-orbit observations from commercial sources for operational use by NOAA.
These steps are formally outlined in the draft NESDIS Commercial Space Activities Assessment Process, which can be found at:
Both the NOAA Commercial Space Policy and the NESDIS Commercial Space Activities Assessment Process firmly establish the principles that will guide NOAA's engagement with the commercial sector and the practices for how NOAA will assess, pursue, and determine the viability of using commercial data. We are actively implementing the activities identified in the two documents toward this end. In the near future, we plan to share more specific information on individual datasets and steps involved in our process. NOAA will use multiple platforms to share important information, including RFIs, RFPs, the Office of Space Commerce Web site, and ongoing engagement events to promote dialogue and transparency.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a public meeting.
The Pacific Fishery Management Council (Pacific Council) and the NOAA's Southwest Fisheries Science Center (SWFSC) will convene a workshop to develop methods for conducting stock assessments of short-lived coastal pelagic species (CPS) on the U.S. West Coast. The meeting is open to the public.
The meeting will be held Monday, May 2, 2016 through Thursday, May 5, 2016. The meeting will begin at 10 a.m. the first day, and at 8 a.m. each subsequent day, Pacific Standard Time. The meeting will conclude at 5 p.m. each day, or when business for the day has been completed.
The meeting will be held at the Southwest Fisheries Science Center Pacific Room, 8901 La Jolla Shores Drive, La Jolla, CA 92037.
Kerry Griffin, Staff Officer; telephone: (503) 820-2409.
The primary purpose of the workshop is to develop methods for conducting stock assessments of short-lived CPS on the U.S. West Coast, with an emphasis on the central subpopulation of northern anchovy. The workshop will include a discussion of how stock assessments and/or single point biomass estimates can be used in management. The intent is to provide recommendations to the SWFSC for use in conducting CPS stock assessments, especially for data-limited stocks.
Note: All foreign nationals must complete the Foreign National Registration form at
Requests for sign language interpretation or other auxiliary aids should be directed to Mr. Dale Sweetnam (858) 546-7170 at least 5 days prior to the meeting date.
Committee for Purchase From People Who Are Blind or Severely Disabled.
Deletions from the Procurement List.
This action deletes products from the Procurement List that were previously furnished by nonprofit agency employing persons who are blind or have other severe disabilities.
Committee for Purchase From People Who Are Blind or Severely Disabled, 1401 S. Clark Street, Suite 715, Arlington, Virginia 22202-4149.
Barry S. Lineback, Telephone: (703) 603-7740, Fax: (703) 603-0655, or email
On 3/4/2016 (81 FR 11520), the Committee for Purchase From People Who Are Blind or Severely Disabled published notice of proposed deletions from the Procurement List.
After consideration of the relevant matter presented, the Committee has determined that the products listed below are no longer suitable for procurement by the Federal Government under 41 U.S.C. 8501-8506 and 41 CFR 51-2.4.
I certify that the following action will not have a significant impact on a substantial number of small entities. The major factors considered for this certification were:
1. The action will not result in additional reporting, recordkeeping or other compliance requirements for small entities.
2. The action may result in authorizing small entities to furnish the products to the Government.
3. There are no known regulatory alternatives which would accomplish the objectives of the Javits-Wagner-O'Day Act (41 U.S.C. 8501-8506) in connection with the products deleted from the Procurement List.
Accordingly, the following products are deleted from the Procurement List:
Committee for Purchase From People Who Are Blind or Severely Disabled.
Proposed Addition to and Deletions from the Procurement List.
The Committee is proposing to add a service to the Procurement List that will be provided by nonprofit agency employing persons who are blind or have other severe disabilities and, deletes products and services previously furnished by such agencies.
Comments must be received on or before: 5/8/2016.
Committee for Purchase From People Who Are Blind or Severely Disabled, 1401 S. Clark Street, Suite 715, Arlington, Virginia 22202-4149.
Barry S. Lineback, Telephone: (703) 603-7740, Fax: (703) 603-0655, or email
This notice is published pursuant to 41 U.S.C. 8503(a)(2) and 41 CFR 51-2.3. Its purpose is to provide interested persons an opportunity to submit comments on the proposed actions.
If the Committee approves the proposed addition, the entities of the Federal Government identified in this notice will be required to provide the service listed below from the nonprofit agency employing persons who are blind or have other severe disabilities.
The following service is proposed for addition to the Procurement List for provision by the nonprofit agency listed:
The following products and services are proposed for deletion from the Procurement List:
Department of Defense (DoD), Office of the Under Secretary of Defense (Acquisition, Technology, and Logistics).
Federal advisory committee meeting notice.
The Department of Defense announces the following closed Federal advisory committee meeting of the Threat Reduction Advisory Committee (TRAC).
Thursday, May 5, 2016, from 8:30 a.m. to 5:00 p.m. and Friday, May 6, 2016, from 8:30 a.m. to 3:00 p.m.
CENTRA Technology Inc., Ballston, VA on May 5, 2016, and CENTRA Technology, Inc. and the Pentagon, Arlington, Virginia on May 6, 2016.
Mr. William Hostyn, DoD, Defense Threat Reduction Agency (DTRA) J2/5/8R-AC, 8725 John J. Kingman Road, MS 6201, Fort Belvoir, VA 22060-6201. Email:
The TRAC will continue to meet on May 6, 2016. The TRAC will receive a classified brief from retired General Carns on Russia and issues related to CWMD based upon his recent trips and meetings with high-level leaders in the region. The briefing will be followed by a closed session led by Hon. Koch and Dr. Reichart on Russian provocations and the relationship to nuclear strategic stability in the region. Hon. Benkert and Dr. Choi will follow suit with a session on China. Amb Lehman will discuss future efforts of the TRAC and the way forward in 2016-2017 based upon the sponsor's guidance and direction. The TRAC will then transition to the Pentagon, where they will provide Under Secretary Kendall with a brief from the previous days meeting. At the conclusion of the discussion, the Chair will adjourn the 37th Plenary.
Email:
Office of the Secretary of Defense (Health Affairs)/TRICARE Management Activity, Department of Defense.
Notice of an extension of the TRICARE demonstration project for the Philippines.
On Wednesday, September 28, 2011, the Department of Defense (DoD) published a notice of the Philippines Demonstration Project (PDP) (76 FR 60007-60008). This notice is to advise interested parties of an extension to a Military Health System demonstration project entitled “TRICARE Demonstration Project for the Philippines.” The purpose of this demonstration is to validate an alternative approach to providing healthcare services for those beneficiaries covered under the TRICARE Standard option in the Philippines, controlling costs, eliminating any balance billing issues, and ensuring that the billing practices comply with regulatory requirements. During the initial two years of the demonstration project, significant reductions in providers under Pre-Payment Review has been observed, resulting in less fraudulent claim investigations. In addition, beneficiaries have been over 93% compliant with utilizing approved network providers in the Philippines demonstration areas. The DHA's intent is to extend the demonstration project for an additional three years in order to determine if the cost savings to the Government in terms of the average cost per paid claim along with the savings on fraudulent claims can exceed the administrative costs related to the project while ensuring Standard beneficiaries are able to access high quality medical care within TRICARE access standards.
Defense Health Agency (DHA), TRICARE Overseas Program Office, 16401 East Centretech Parkway, Aurora, CO 80011.
CAPT Bruno Himmler, Office of the ASD (HA)—DHA, (303) 676-3728.
TRICARE has recognized the unique circumstances existing in the Philippines which made the provision of medical care to TRICARE beneficiaries through the TRICARE Overseas program operated in other overseas locations challenging. TRICARE has experienced dramatic increases in the amount billed for healthcare services rendered in the Philippines from $15 million in 1999 to $59 million in 2009 while the number of beneficiaries has remained constant. Administrative controls such as the validation of providers, implementation of a fee reimbursement schedule, duplicate claims edits and the impact of the cost-shares and deductibles have limited actual TRICARE expenditures to $17 million in 2009 for only approximately 11,000 beneficiaries.
In addition to these administrative controls, fraud and abuse activities in the Philippines have been a growing concern that necessitated prompt investigation and actions to reduce the number of fraudulent or abusive incidences. Measures were taken to prevent or reduce the level of fraud and abuse against TRICARE while concurrent investigations and prosecutions were conducted. In April 2008, seventeen individuals were convicted of defrauding the TRICARE program of more than $100 million.
As a result, prepayment review of claims is conducted to identify excessive charges and aberrant practices. Prepayment review is a tool typically used on a limited basis. Nevertheless, these efforts alone are not expected to control and eliminate the rising costs in the Philippines.
Because of this concern, the purpose of this demonstration is to validate an alternative approach to providing healthcare services for those beneficiaries covered under the TRICARE Standard option in the Philippines, controlling costs, eliminating any balance billing issues, and ensuring that the billing practices comply with regulatory requirements.
Initial results have shown some partial success with the PDP, but additional data needs to be gathered and assessed to be able to determine the long term implications of the PDP. Therefore, DHA proposes, utilizing the new overseas contract as the vehicle, to extend the demonstration for an additional three years in the Philippines to validate that use of a well-certified and limited set of approved providers in the Philippines will result in a significant reduction in the level of claims billing issues, including beneficiaries being liable for balanced billing amounts and fraud by providers, and average cost per claim paid by the Government, while ensuring beneficiaries have sufficient access to high quality care. The demonstration would continue to be conducted under 10 U.S.C. 1092.
During the next three years, the Government will look to expand the demonstration areas to other locations/cities with a significant Standard population. Also, the contractor will be requested to look at including pharmacies as network providers to help control costs related to outpatient prescriptions.
Department of Defense.
Notice of federal advisory committee meeting.
The Defense Science Board will meet in closed session on Thursday, May 19, 2016, from 8:00 a.m. to 5:00 p.m. at the Pentagon, Room 3E863, Washington, DC.
Thursday, May 19, 2016, from 8:00 a.m. to 5:00 p.m.
The Pentagon, Room 3E863, Washington, DC.
Ms. Debra Rose, Executive Officer, Defense Science Board, 3140 Defense Pentagon, Room 3B888A, Washington, DC 20301-3140, via email at
This meeting is being held under the provisions of the Federal Advisory Committee Act of 1972 (5 U.S.C., Appendix, as amended), the Government in the Sunshine Act of 1976 (5 U.S.C. 552b, as amended), and 41 CFR 102-3.150.
The mission of the Defense Science Board is to advise the Secretary of Defense and the Under Secretary of Defense for Acquisition, Technology & Logistics on scientific and technical matters as they affect the perceived needs of the Department of Defense. At this meeting, the Board will discuss interim findings and recommendations resulting from ongoing Task Force activities. The Board will also discuss plans for future consideration of scientific and technical aspects of specific strategies, tactics, and policies as they may affect the U.S. national defense posture and homeland security.
In accordance with section 10(d) of the Federal Advisory Committee Act, Public Law 92-463, as amended (5 U.S.C. App. 2) and 41 CFR 102-3.155, the Department of Defense has determined that the Defense Science Board meeting for May 19, 2016, will be closed to the public. Specifically, the Under Secretary of Defense (Acquisition, Technology, and Logistics), in consultation with the DoD Office of General Counsel, has determined in writing that all sessions of meeting for May 19, 2016, will be closed to the public because it will consider matters covered by 5 U.S.C. 552b(c)(1) and (4).
In accordance with 41 CFR 102-3.140 and section 10(a)(3) of the Federal Advisory Committee Act, interested persons may submit a written statement for consideration by the Defense Science Board. Individuals submitting a written statement must submit their statement to the Designated Federal Official at the address detailed in
Department of the Navy, DoD.
Notice.
The Department of the Navy (DoN), after carefully weighing the strategic, operational, and environmental consequences of the proposed action, announces its decision to continue and enhance training and testing activities as identified in Alternative 2 in the Final Environmental Impact Statement for Military Readiness Activities at the at Naval Weapons Systems Training Facility Boardman, Oregon. This alternative provides for the construction and operation of new range facilities and other enhancements, and increases in training and testing activities. Alternative 2 also includes a proposal to establish new special use airspace in the form of a Military Operations Area (MOA), including the Boardman Low MOA and an extension to the existing Boardman MOA, both to the northeast of NWSTF Boardman. Implementation of Alternative 2 will enable the DoN to achieve the levels of operational readiness required under Section 5062 Title 10 U.S.C. without resulting in significant environmental impacts.
The complete text of the Record of Decision is available at
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
Any person desiring to protest in any of the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5:00 p.m. Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
The Federal Energy Regulatory Commission (Commission) hereby gives notice that members of the Commission's staff may attend the following meetings related to the transmission planning activities of the New York Independent System Operator, Inc.
The above-referenced meeting will be via web conference and teleconference.
The above-referenced meeting is open to stakeholders.
Further information may be found at:
The above-referenced meeting will be via web conference and teleconference.
The above-referenced meeting is open to stakeholders.
Further information may be found at:
The above-referenced meeting will be via web conference and teleconference.
The above-referenced meeting is open to stakeholders.
Further information may be found at:
The above-referenced meeting will be via web conference and teleconference.
The above-referenced meeting is open to stakeholders.
Further information may be found at:
The above-referenced meeting will be via web conference and teleconference.
The above-referenced meeting is open to stakeholders.
Further information may be found at:
The discussions at the meetings described above may address matters at issue in the following proceedings:
For more information, contact James Eason, Office of Energy Market Regulation, Federal Energy Regulatory Commission at (202) 502-8622 or
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
Take notice that the Commission received the following open access transmission tariff filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that during the month of March 2016, the status of the above-captioned entities as Exempt Wholesale Generators became effective by operation of the Commission's regulations. 18 CFR 366.7(a).
The staff of the Federal Energy Regulatory Commission (FERC or Commission) has prepared this environmental assessment for the New York Bay Expansion Project (Project) proposed by Transcontinental Gas Pipe Line Company, LLC (Transco) in the above-referenced docket. Transco requests authorization to construct, replace, and operate natural gas pipeline facilities located in Chester County, Pennsylvania, Richmond County, New York, and Middlesex and Essex Counties, New Jersey. This Project would enable Transco to modify existing facilities and replace existing pipeline to transport an additional 115 million cubic feet of natural gas per day.
The Project would involve the following activities at existing aboveground facilities in the specified towns and municipalities:
• Uprate Compressor Station 200 from 30,860 horsepower (hp) to 33,000 hp (East Whiteland Township, Chester County, Pennsylvania) and uprate a unit of Compressor Station 303 from 25,000 hp to 27,500 hp (Roseland Borough, Essex County, New Jersey);
• Add 11,000 hp of electric-driven compression to Compressor Station 207 (Old Bridge Township, Middlesex County, New Jersey);
• Install various appurtenances and modifications at three meter and regulation (M&R) stations in East Brandywine Township (Chester County,
In addition, Transco proposes to replace three segments of its 42-inch-diameter Lower New York Bay Lateral pipeline, totaling 0.25 mile, and uprate the lateral pipeline's operating pressure from 960 to 1000 pounds per square inch in Middlesex County, New Jersey.
The environmental assessment assesses the potential environmental effects of the construction and operation of the Project in accordance with the National Environmental Policy Act. The FERC staff concludes that approval of the proposed Project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment.
The environmental assessment has been placed in the public files of the FERC and is available for public viewing on the FERC's Web site at
Copies of the environmental assessment have been mailed to federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American tribes; potentially affected landowners and other interested individuals and groups; libraries in the Project area; and parties to this proceeding.
Any person wishing to comment on the environmental assessment may do so. Your comments should focus on the potential environmental effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. The more specific your comments, the more useful they will be. To ensure that your comments are properly recorded and considered prior to a Commission decision on the proposal, it is important that the FERC receives your comments in Washington, DC on or before May 4, 2016.
For your convenience, there are three methods you can use to submit your comments to the Commission. In all instances, please reference the Project docket number (CP15-527-000) with your submission. The Commission encourages electronic filing of comments and has dedicated eFiling expert staff available to assist you at (202) 502-8258 or
(1) You may file your comments electronically by using the eComment feature, which is located on the Commission's Web site at
(2) You may file your comments electronically by using the eFiling feature, which is located on the Commission's Web site at
(3) You may file a paper copy of your comments at the following address: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
Although your comments will be considered by the Commission, simply filing comments will not serve to make the commentor a party to the proceeding. Any person seeking to become a party to the proceeding must file a motion to intervene pursuant to Rule 214 of the Commission's Rules of Practice and Procedures (18 CFR 385.214).
Additional information about the Project is available from the Commission's Office of External Affairs, at (866) 208-FERC, or on the FERC Web site (
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
Take notice that the Commission has received the following Natural Gas Pipline Rate and Refund Report filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified date(s). Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that on April 1, 2016, pursuant to section 206 of the Federal Power Act, 16 U.S.C. 824e and Rule 206 of the Federal Energy Regulatory Commission's (Commission) Rules of Practice and Procedure, 18 CFR 385.206 (2015), Michigan Electric Transmission Company, LLC (Complainant) filed a formal complaint against Midcontinent Independent System Operator, Inc. (MISO or Respondent) requesting a refund effective date of April 1, 2016, as a protective measure in case refunds of certain Michigan Joint Zone revenues are necessary for charges assessed by the MISO in the latter's capacity as agent for Consumers Energy Company, as more fully explained in the complaint.
Complainant certifies that copies of the complaint were served on the contacts for MISO as listed on the Commission's list of Corporate Officials.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. The Respondent's answer and all interventions, or protests must be filed on or before the comment date. The Respondent's answer, motions to intervene, and protests must be served on the Complainants.
The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at
This filing is accessible on-line at
Take notice that the Commission received the following electric corporate filings:
Take notice that the Commission received the following electric rate filings:
Description: § 205(d) Rate Filing: 2016-4-1_PSC-PRPA-LaPorte PPA 174 0.0.0-Filing to be effective 10/15/2010.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
United States Environmental Protection Agency (EPA).
Notice of objections filed and hearing requested; Notice of public hearing.
Notice is hereby given, pursuant to Section 6 of the Federal Insecticide, Fungicide, and Rodenticide Act, 7 U.S.C. 136d, and Section 164.8 of the associated Rules of Practice Governing Hearings set forth at 40 CFR part 164, that objections were filed and a hearing was requested in response to the Notice of Intent to Cancel Pesticide Registrations, published in the
This proceeding has been assigned Docket No. FIFRA-HQ-2016-0001,
The hearing in this matter will be held beginning promptly at 8:30 a.m. on Tuesday, May 10, 2016, and continue as necessary through Friday, May 13, 2016.
EPA Administrative Courtroom, EPA East Building, Room 1152, 1201 Constitution Avenue NW., Washington, DC 20460.
An electronic copy of the case file in this proceeding is publically available online at
Environmental Protection Agency (EPA).
Notice.
EPA is required under the Toxic Substances Control Act (TSCA) to publish in the
Comments identified by the specific case number provided in this document, must be received on or before May 9, 2016.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPPT-2016-2016-0021, and the specific PMN number or TME number for the chemical related to your comment, by one of the following methods:
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Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
This action is directed to the public in general. As such, the Agency has not attempted to describe the specific entities that this action may apply to. Although others may be affected, this action applies directly to the submitters of the actions addressed in this document.
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This document provides receipt and status reports, which cover the period from February 1, 2016 to February 29, 2016, and consists of the PMNs and TMEs both pending and/or expired, and the NOCs to manufacture a new chemical that the Agency has received under TSCA section 5 during this time period.
Under TSCA, 15 U.S.C. 2601
Anyone who plans to manufacture or import a new chemical substance for a non-exempt commercial purpose is required by TSCA section 5 to provide EPA with a PMN, before initiating the activity. Section 5(h)(1) of TSCA authorizes EPA to allow persons, upon application, to manufacture (includes import) or process a new chemical substance, or a chemical substance subject to a significant new use rule (SNUR) issued under TSCA section 5(a), for “test marketing” purposes, which is referred to as a test marketing exemption, or TME. For more information about the requirements applicable to a new chemical go to:
Under TSCA sections 5(d)(2) and 5(d)(3), EPA is required to publish in the
As used in each of the tables in this unit, (S) indicates that the information in the table is the specific information provided by the submitter, and (G) indicates that the information in the table is generic information because the specific information provided by the submitter was claimed as CBI.
For the 37 PMNs received by EPA during this period, Table 1 provides the following information (to the extent that such information is not claimed as CBI): The EPA case number assigned to the PMN; The date the PMN was received by EPA; the projected end date for EPA's review of the PMN; the submitting manufacturer/importer; the potential uses identified by the manufacturer/importer in the PMN; and the chemical identity.
For the 25 NOCs received by EPA during this period, Table 3 provides the following information (to the extent that such information is not claimed as CBI): The EPA Case number assigned to the NOC; the date the NOC was received by EPA; the projected date of commencement provided by the submitter in the NOC; and the chemical identity.
15 U.S.C. 2601
Export-Import Bank of the United States.
New Submission for OMB review and Final comments request.
The Export-Import Bank of the United States (Ex-Im Bank), as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal Agencies to comment on the proposed information collection, as required by the Paperwork Reduction Act of 1995.
Ex-Im Bank's borrowers, financial institution policy holders and guaranteed lenders provide this form to U.S. exporters, who certify to the eligibility of their exports for Ex-Im Bank support. For direct loans and loan guarantees, the completed form is required to be submitted at time of disbursement and held by either the guaranteed lender or Ex-Im Bank. For MT insurance, the completed forms are held by the financial institution, only to be submitted to Ex-Im Bank in the event of a claim filing.
Ex-Im Bank uses the referenced form to obtain exporter certifications regarding the export transaction, content sourcing, and their eligibility to participate in USG programs with respect to co-financed transactions. These details are necessary to determine the value and legitimacy of Ex-Im Bank financing support and claims submitted. It also provides the financial institutions a check on the export transaction's eligibility at the time it is fulfilling a financing request.
The information collection tool can be reviewed at:
Comments must be received on or before May 9, 2016 to be assured of consideration.
Comments may be submitted electronically on
Annual Number of Respondents: 30.
Estimated Time per Respondent: 30 minutes.
Annual Burden Hours: 15 hours.
Frequency of Reporting of Use: As required.
Reviewing time per year: 0.5 hours.
Average Wages per Hour: $42.50.
Average Cost per Year (time*wages): $21.25.
Benefits and Overhead: 20%.
Total Government Cost: $25.5.
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than April 25, 2016.
A. Federal Reserve Bank of Atlanta (Chapelle Davis, Assistant Vice President) 1000 Peachtree Street, NE., Atlanta, Georgia 30309. Comments can
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B. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
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The companies listed in this notice have applied to the Board for approval, pursuant to the Home Owners' Loan Act (12 U.S.C. 1461
The applications listed below, as well as other related filings required by the Board, are available for immediate inspection at the Federal Reserve Bank indicated. The application also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing on the standards enumerated in the HOLA (12 U.S.C. 1467a(e)). If the proposal also involves the acquisition of a nonbanking company, the review also includes whether the acquisition of the nonbanking company complies with the standards in section 10(c)(4)(B) of the HOLA (12 U.S.C. 1467a(c)(4)(B)). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than May 5, 2016.
A. Federal Reserve Bank of Cleveland (Nadine Wallman, Vice President) 1455 East Sixth Street, Cleveland, Ohio 44101-2566. Comments can also be sent electronically to
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General Services Administration (GSA).
Notice of request for an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve an extension of a previously approved information collection requirement regarding the Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery.
Submit comments on or before June 7, 2016.
Submit comments identified by Information Collection 3090-0297, Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery, by any of the following methods:
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Ms. Anahita Reilly, Customer Advocate Executive, Office of Customer Experience, GSA, 202-714-9421, or email
The information collection activity will garner qualitative customer and stakeholder feedback in an efficient, timely manner, in accordance with the Administration's commitment to improving service delivery. By qualitative feedback we mean information that provides useful insights on perceptions and opinions, but are not statistical surveys that yield quantitative results that can be generalized to the population of study.
This feedback will provide insights into customer or stakeholder perceptions, experiences and expectations, provide an early warning of issues with service, or focus attention on areas where communication, training or changes in operations might improve
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance.
Such data uses require more rigorous designs that address: The target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior fielding the study.
Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results. The Digital Government Strategy released by the White House in May, 2012 drives agencies to have a more customer-centric focus. Because of this, GSA anticipates an increase in requests to use this generic clearance, as the plan states that: A customer-centric principle charges us to do several things: Conduct research to understand the customer's business, needs and desires; “make content more broadly available and accessible and present it through multiple channels in a program-and device-agnostic way; make content more accurate and understandable by maintaining plain language and content freshness standards; and offer easy paths for feedback to ensure we continually improve service delivery.
The customer-centric principle holds true whether our customers are internal (
Public comments are particularly invited on: Whether this collection of information is necessary and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected.
Obtaining Copies of Proposals: Requesters may obtain a copy of the information collection documents from the General Services Administration, Regulatory Secretariat Division (MVCB), 1800 F Street NW., Washington, DC 20405, telephone 202-501-4755. Please cite OMB Control No. 3090-0297, Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery, in all correspondence.
Identity, Credential, and Access Management (ICAM) Division, Office of Security, Office of Mission Assurance (OMA), General Services Administration (GSA).
Notice of request for comments regarding an extension to an existing OMB clearance.
Under the provisions of the Paperwork Reduction Act, the Regulatory Secretariat Division will be submitting to the Office of Management and Budget (OMB) a request to review and approve a previously approved information collection requirement, with changes, expanding the coverage of the information collection of the Contractor Information Worksheet; GSA Form 850.
GSA requires OMB approval for this collection to make determinations on granting unescorted physical access to GSA-controlled facilities and/or logical access to GSA-controlled information systems. The approval is critical for GSA to continue following contractor onboarding processes required for working on GSA contracts. An updated System of Record Notice (SORN) was published in the
Submit comments on or before: May 9, 2016.
Submit comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Office of Information and Regulatory Affairs of OMB, Attention: Desk Officer for GSA, Room 10236, NEOB, Washington, DC 20503. Additionally submit a copy to GSA by any of the following methods:
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Mr. Phil Ahn, Deputy Director, OMA Identity Credential and Access Management Division, GSA, telephone 202-501-2447 or via email at
The U.S. Government conducts criminal checks to establish that applicants or incumbents working for the Government under contract may have unescorted access to federally controlled facilities. GSA uses the Contractor Information Worksheet; GSA Form 850, and digitally captured fingerprints to conduct a FBI National Criminal Information Check (NCIC) for each contractor's physical access determination to GSA-controlled facilities and/or logical access to GSA-controlled information systems. Manual fingerprint card SF-87 is used for exception cases such as contractor's significant geographical distance from fingerprint enrollment sites.
The Office of Management and Budget (OMB) Guidance M-05-24 for Homeland Security Presidential Directive (HSPD) 12, authorizes Federal departments and agencies to ensure that contractors have limited/controlled access to facilities and information systems. GSA Directive CIO P 2181.1 Homeland Security Presidential Directive-12, Personal Identity Verification and Credentialing (available at
Contractors' Social Security Number is needed to keep records accurate, because other people may have the same name and birth date. Executive Order 9397, Numbering System for Federal Accounts Relating to Individual Persons, also allows Federal agencies to use this number to help identify individuals in agency records.
Public comments are particularly invited on: Whether this collection of information is necessary and whether it will have practical utility; whether our estimate of the public burden of this collection of information is accurate, and based on valid assumptions and methodology; ways to enhance the quality, utility, and clarity of the information to be collected.
Agency for Healthcare Research and Quality, HHS.
Notice.
This notice announces the intention of the Agency for Healthcare Research and Quality (AHRQ) to request that the Office of Management and Budget (OMB) approve the proposed information collection project:
Comments on this notice must be received by June 7, 2016.
Written comments should be submitted to: Doris Lefkowitz, Reports Clearance Officer, AHRQ, by email at
Copies of the proposed collection plans, data collection instruments, and specific details on the estimated burden can be obtained from the AHRQ Reports Clearance Officer.
Doris Lefkowitz, AHRQ Reports Clearance Officer, (301) 427-1477, or by email at
In 1999, the Institute of Medicine called for health care organizations to develop a “culture of safety” such that their workforce and processes focus on improving the reliability and safety of care for patients (IOM, 1999;
The survey is designed to enable hospitals to assess staff opinions about patient safety issues, medical errors, and error reporting. The survey includes 42 items that measure 12 composites of patient safety culture. AHRQ made the survey publicly available along with a Survey User's Guide and other toolkit materials in November 2004 on the AHRQ Web site (located at
The Hospital SOPS Comparative Database consists of data from the AHRQ Hospital Survey on Patient Safety Culture. Hospitals in the U.S. are asked to voluntarily submit data from the survey to AHRQ, through its contractor, Westat. The Hospital SOPS Database (OMB NO. 0935-0162, last approved on September 26, 2013) was developed by AHRQ in 2006 in response to requests from hospitals interested in knowing how their patient safety culture survey results compare to those of other hospitals in their efforts to improve patient safety.
This database will:
(1) Allow hospitals to compare their patient safety culture survey results with those of other hospitals,
(2) provide data to hospitals to facilitate internal assessment and learning in the patient safety improvement process, and
(3) provide supplemental information to help hospitals identify their strengths and areas with potential for improvement in patient safety culture.
This study is being conducted by AHRQ through its contractor, Westat, pursuant to AHRQ's statutory authority to conduct and support research on health care and on systems for the delivery of such care, including activities with respect to the quality, effectiveness, efficiency, appropriateness and value of health care services and with respect to quality measurement and improvement. 42 U.S.C. 299a(a)(1) and (2).
To achieve the goal of this project the following activities and data collections will be implemented:
(1) Eligibility and Registration Form—The hospital point-of-contact (POC) completes a number of data submission steps and forms, beginning with the completion of an online eligibility and registration form. The purpose of this form is to determine the eligibility status and initiate the registration process for hospitals seeking to voluntarily submit their Hospital SOPS data to the Hospital SOPS Comparative Database.
(2) Data Use Agreement—The purpose of the data use agreement, completed by the hospital POC, is to state how data submitted by hospitals will be used and provides confidentiality assurances.
(3) Hospital Site Information Form—The purpose of the site information form is to obtain basic information about the characteristics of the hospitals submitting their Hospital SOPS data to the Hospital SOPS Comparative Database (
(4) Data Files Submission—The number of submissions to the database is likely to vary each year because hospitals do not administer the survey and submit data every year. Data submission is typically handled by one POC who is either a manager or a survey vendor who contracts with a hospital to collect its data. POCs submit data on behalf of 3 hospitals, on average, because many hospitals are part of a health system that includes many hospitals, or the POC is a vendor that is submitting data for multiple hospitals.
Survey data from the AHRQ Hospital Survey on Patient Safety Culture is used to produce three types of products: (1) A Hospital SOPS Comparative Database Report that is produced periodically and made publicly available on the AHRQ Web site (see
Hospitals are asked to voluntarily submit their Hospital SOPS survey data to the comparative database. The data are then cleaned and aggregated and used to produce a Comparative Database Report that displays averages, standard deviations, and percentile scores on the survey's 42 items and 12 composites of patient safety culture, as well as displaying these results by hospital characteristics (bed size, teaching status, ownership) and respondent characteristics (hospital work area, staff position, and those with direct interaction with patients). In addition, trend data, showing changes in scores over time, are presented from hospitals that have submitted to the database more than once.
Data submitted by hospitals are used to give each hospital its own customized survey feedback report that presents the hospital's results compared to the latest comparative database results. If the hospital submits data in two consecutive database submission years, its survey feedback report also presents trend data, comparing its previous and most recent data.
Hospitals use the Hospital SOPS, Comparative Database Reports and Individual Hospital Survey Feedback Reports for a number of purposes, to:
• Raise staff awareness about patient safety.
• Diagnose and assess the current status of patient safety culture in their hospital.
• Identify strengths and areas for improvement in patient safety culture.
• Examine trends in patient safety culture change over time.
• Evaluate the cultural impact of patient safety initiatives and interventions.
• Facilitate meeting Joint Commission hospital accreditation standards in Leadership that require a regular assessment of hospital patient safety culture.
• Compare patient safety culture survey results with other hospitals in their efforts to improve patient safety and quality.
Exhibit 1 shows the estimated annualized burden hours for the respondents' time to participate in the database. An estimated 304 POCs, each representing an average of 3 individual hospitals each, will complete the database submission steps and forms annually. The POCs typically submit data on behalf of 3 hospitals, on average, because many hospitals are part of a multi-hospital system that is submitting data, or the POC is a vendor that is submitting data for multiple hospitals. Completing the registration form will take about 3 minutes. The Hospital Information Form is completed by all POCs for each of their hospitals (304 × 3 = 912). The total annual burden hours are estimated to be 410.
Exhibit 2 shows the estimated annualized cost burden based on the respondents' time to submit their data. The cost burden is estimated to be $21,801 annually.
In accordance with the Paperwork Reduction Act, comments on AHRQ's information collection are requested with regard to any of the following: (a) Whether the proposed collection of information is necessary for the proper performance of AHRQ health care research and health care information dissemination functions, including whether the information will have practical utility; (b) the accuracy of AHRQ's estimate of burden (including hours and costs) of the proposed collection(s) of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden of the collection of information upon the respondents, including the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and included in the Agency's subsequent request for OMB approval of the proposed information collection. All comments will become a matter of public record.
Agency for Healthcare Research and Quality (AHRQ), Department of Health and Human Services (HHS).
Notice of availability—new common formats.
As authorized by the Secretary of HHS, AHRQ coordinates the development of sets of common definitions and reporting formats (Common Formats) for reporting on health care quality and patient safety. The purpose of this notice is to announce the availability of new formats for public review and comment, Common Formats for Event Reporting for Hospitals Version 2.0.
May 9, 2016.
The Common Formats for Event Reporting for Hospitals Version 2.0, and the remaining Common Formats, can be accessed electronically at the following HHS Web site:
Cathryn Bach
The Patient Safety and Quality Improvement Act of 2005, 42 U.S.C. 299b-21 to b-26, (Patient Safety Act) and the related Patient Safety and Quality Improvement Final Rule, 42 CFR part 3 (Patient Safety Rule), published in the
The Patient Safety Act and Patient Safety Rule establish a framework by which doctors, hospitals, skilled nursing facilities, and other health care providers may assemble information regarding patient safety events and quality of care. Information that is assembled and developed by providers for reporting to PSOs and the information received and analyzed by PSOs—called “patient safety work product”—is privileged and confidential. Patient safety work product is used to conduct patient safety activities, which may include identifying events, patterns of care, and unsafe conditions that increase risks and hazards to patients. Definitions and other details about PSOs and patient safety work product are included in the Patient Safety Act and Patient Safety Rule which can be accessed electronically at:
The term “Common Formats” refers to the common definitions and reporting formats, specified by AHRQ, that allow health care providers to collect and submit standardized information regarding patient quality and safety to PSOs and other entities. The formats are not intended to replace any current mandatory reporting system, collaborative/voluntary reporting system, research-related reporting system, or other reporting/recording system; rather the formats are intended to enhance the ability of health care providers to report information that is standardized both clinically and electronically.
In collaboration with the interagency Federal Patient Safety Workgroup (PSWG), the National Quality Forum (NQF), and the public, AHRQ has developed Common Formats for three settings of care—acute care hospitals, nursing homes, and retail pharmacies—in order to facilitate standardized data collection and analysis. The scope of the formats applies to all patient safety concerns including: Incidents—patient safety events that reached the patient, whether or not there was harm; near misses or close calls—patient safety events that did not reach the patient; and unsafe conditions—circumstances
AHRQ's Common Formats for patient safety event reporting include:
• Event descriptions (definitions of patient safety events, near misses, and unsafe conditions to be reported);
• Specifications for patient safety aggregate reports and individual event summaries that derive from event descriptions;
• Delineation of data elements and algorithms to be used for collection of adverse event data to populate the reports; and
• Technical specifications for electronic data collection and reporting.
The technical specifications promote standardization of collected patient safety event information by specifying rules for data collection and submission, as well as by providing guidance for how and when to create data elements, their valid values, conditional and go-to logic, and reports. These specifications will ensure that data collected by PSOs and other entities have comparable clinical meaning. They also provide direction to software developers, so that the formats can be implemented electronically, and to PSOs, so that the Common Formats can be submitted electronically to the PSO Privacy Protection Center (PSOPPC) for data de-identification and transmission to the Network of Patient Safety Databases (NPSD).
In anticipation of the need for Common Formats, AHRQ began their development by creating an inventory of functioning private and public sector patient safety reporting systems. This inventory provided an evidence base to inform construction of the Common Formats. The inventory included many systems from the private sector, including prominent academic settings, hospital systems, and international reporting systems (
Since February 2005, AHRQ has convened the PSWG to assist AHRQ with developing and maintaining the Common Formats. The PSWG includes major health agencies within HHS—CDC, Centers for Medicare & Medicaid Services, FDA, Health Resources and Services Administration, Indian Health Service, National Institutes of Health, National Library of Medicine, Office of the National Coordinator for Health Information Technology, Office of Public Health and Science, and Substance Abuse and Mental Health Services Administration—as well as the DoD and VA.
When developing Common Formats, AHRQ first reviews existing patient safety practices and event reporting systems. In collaboration with the PSWG and Federal subject matter experts, AHRQ drafts and releases beta versions and updates to current versions of the Common Formats for public review and comment. The prior version of Common Formats for Event Reporting for Hospitals, Version 1.2, was released in April 2013. The PSWG assists AHRQ with assuring the consistency of definitions/formats with those of relevant government agencies as refinement of the Common Formats continues.
Since the initial release of the Common Formats in August 2008, AHRQ has regularly revised the formats based upon public comment. AHRQ solicits feedback on beta, and subsequent, versions of Common Formats from private sector organizations and individuals. Based upon the feedback received, AHRQ further revises the formats. To the extent practicable, the Common Formats are also aligned with World Health Organization (WHO) concepts, frameworks, and definitions.
Participation by the private sector in the development and subsequent revision of the Common Formats is achieved through working with the NQF. The Agency engages the NQF, a non-profit organization focused on health care quality, to solicit comments and advice regarding proposed versions of the Common Formats. AHRQ began this process with the NQF in 2008, receiving feedback on AHRQ's 0.1 Beta release of the Common Formats for Event Reporting—Hospital. After receiving public comment, the NQF solicits the review and advice of its Common Formats Expert Panel and subsequently provides feedback to AHRQ. The Agency then revises and refines the Common Formats and issues them as a production version. AHRQ has continued to employ this process for all subsequent versions of the formats.
AHRQ used a tiered approach to develop Hospital Version 2.0. This approach was done in response to feedback from PSOs and the public to decrease the number of questions for each module of the formats in order to reduce the burden on health care providers and to facilitate data transmission. These formats have two tiers, or data sets. The first tier, or national data set, contains elements that are collected for submission to the PSOPPC. The second tier, or local data set, is optional and is designed for use at the local level for additional analyses. This local data set is not meant for transmission to the PSOPPC.
The Agency is specifically interested in obtaining feedback from both the private and public sectors on the updated Common Formats for Event Reporting—Hospitals Version 2.0. At this time, only the event descriptions—which define adverse events of interest in the inpatient hospital setting—are available. Other elements of the Common Formats, including aggregate reports and technical specifications, will be developed following revision of the Common Formats for Hospital Version 2.0 based on public comment and NQF advice. Information on how to comment and provide feedback on the Common Formats for Hospital Version 2.0 is available at the NQF Web site:
AHRQ appreciates the time and effort individuals invest in providing comments. The Agency will review and consider all feedback received to help guide the development of a revised version. The process for updating and refining the formats will continue to be an iterative one.
Further information on the Common Formats can be obtained through AHRQ's PSO Web site:
Centers for Medicare & Medicaid Services.
Notice.
The Centers for Medicare & Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the Paperwork Reduction Act of 1995 (the PRA), federal agencies are required to publish notice in the
Comments must be received by
When commenting, please reference the document identifier or OMB control number. To be assured consideration, comments and recommendations must be submitted in any one of the following ways:
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To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, you may make your request using one of following:
1. Access CMS' Web site address at
2. Email your request, including your address, phone number, OMB number, and CMS document identifier, to
3. Call the Reports Clearance Office at (410) 786-1326.
Reports Clearance Office at (410) 786-1326.
This notice sets out a summary of the use and burden associated with the following information collections. More detailed information can be found in each collection's supporting statement and associated materials (see
Under the PRA (44 U.S.C. 3501-3520), federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA requires federal agencies to publish a 60-day notice in the
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In compliance with the requirements of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, the Administration for Children and Families is soliciting public comment on the specific aspects of the information collection described above.
Copies of the proposed collection of information can be obtained and comments may be forwarded by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 330 C Street SW., Washington, DC 20201, Attn: OPRE Reports Clearance Officer. Email address:
The Department specifically requests comments on (a) whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the
This request is to create an AFI program specific Performance Progress Report (PPR) to replace the semiannual standard form performance progress report (SF-PPR) and the annual data report. The AFI PPR will collect data on project activities and attributes similar to the reports that it is replacing. The Office of Community Services (OCS) in the Administration for Children and Families (ACF) will use the data collected in the AFI PPR to prepare the annual AFI Report to Congress, to evaluate and monitor the performance of the AFI program overall and of individual projects, and to inform and support technical assistance efforts. The AFI PPR would fulfill AFI Act reporting requirements and program purposes.
The AFI PPR will be submitted quarterly: three times per year using an abbreviated short form and one time using a long form. Both draft data collection instruments are available for review online at
Respondents: Assets for Independence (AFI) program grantees.
Annual Burden Estimates:
Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 370 L'Enfant Promenade SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. All requests should be identified by the title of the information collection. Email address:
OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA, we) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either electronic or written comments on the collection of information by June 7, 2016.
You may submit comments as follows:
Submit electronic comments in the following way:
• Federal eRulemaking Portal:
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).
Submit written/paper submissions as follows:
• Mail/Hand delivery/Courier (for written/paper submissions): Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.” The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
Under the PRA (44 U.S.C. 3501-3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
We accept certain types of submissions electronically with no requirement for a paper copy. These types of documents are listed in public docket 97S-0251 as required by 21 CFR 11.2. Our ability to receive and process information submitted electronically is limited by our current information technology capabilities and the requirements of the Electronic Records; Electronic Signatures final regulation. Our guidance entitled “Guidance for Industry #108: How to Submit Information in Electronic Format to CVM Using the FDA Electronic Submission Gateway” outlines general standards to be used for the submission of any electronic information to CVM using the FDA ESG. The likely respondents are sponsors for new animal drug applications.
FDA estimates the burden of this collection of information as follows:
We base our estimates on our experience with the submission of electronic information to us using the FDA ESG and the number of electronic registration or change requests received between January 1, 2014, and December 31, 2014.
Health Resources and Services Administration, HHS.
Notice.
In compliance with Section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the Health Resources and Services Administration (HRSA) has submitted an Information Collection Request (ICR) to the Office of Management and Budget (OMB) for review and approval. Comments submitted during the first public review of this ICR will be provided to OMB. OMB will accept further comments from the public during the review and approval period.
Comments on this ICR should be received no later than May 9, 2016.
Submit your comments, including the Information Collection Request Title, to the desk officer for HRSA, either by email to
To request a copy of the clearance requests submitted to OMB for review, email the HRSA Information Collection Clearance Officer at
The purpose of this revision is to include an addendum to the PPA to incorporate the administrative requirement for manufacturer integrity provisions directly addressed in the Affordable Care Act.
I. “Each such agreement shall require that the manufacturer furnish the Secretary with reports, on a quarterly basis, of the price for each covered outpatient drug subject to the agreement that, according to the manufacturer, represents the maximum price that covered entities may permissibly be required to pay for the drug . . .” and
II. “. . . shall require that the manufacturer offer each covered entity covered outpatient drugs for purchase at or below the applicable ceiling price if such drug is made available to any other purchaser at any price.”
These requirements shall be included in the PPA addendum to be signed by manufacturers participating in the 340B Program to ensure that the provisions of the 340B statute requiring inclusion in the PPA are satisfied. The execution of the addendum by manufacturers will fulfill the administrative requirement of the statute that these provisions be included in the PPA. The burden imposed on manufacturers by the proposed requirement of the PPA is minimal because the addendum does not impose requirements beyond review and a signature by the manufacturer.
HRSA specifically requests comments on (1) the necessity and utility of the proposed information collection for the proper performance of the agency's functions, (2) the accuracy of the estimated burden, (3) ways to enhance the quality, utility, and clarity of the information to be collected, and (4) the use of automated collection techniques or other forms of information technology to minimize the information collection burden.
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), notice is hereby given of the following meeting:
Further information regarding NACNEP, including the roster of members, reports to Congress, and minutes from previous meetings, is available at the NACNEP Web site. Members of the public and interested parties may request to attend the meeting by contacting Staff Assistant, Jeanne Brown, at
Please be advised that council members are given copies of all written statements submitted by the public prior to the meeting. Any further public participation will be at the discretion of the Chair, with approval of the Designated Federal Official in attendance. Any member of the public who wishes to have printed materials distributed to NACNEP should submit materials to the National Advisory Council on Nurse Education and Practice mailbox at
For additional information regarding NACNEP, please contact Jeanne Brown, Staff Assistant, National Advisory Council on Nurse Education and Practice, 5600 Fishers Lane, Rockville, Maryland 20857. The telephone number is: (301) 443-5688. The email is:
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), the President's Advisory Council on Faith-based and Neighborhood Partnerships announces the following meetings:
The meeting will be available to the public through a conference call line. Register to participate in the conference call on Monday, April 25th at the Web site
Office of the National Coordinator for Health IT (ONC), HHS.
Request for information.
In section 106(b)(1) of the Medicare Access and CHIP Reauthorization Act of 2015 (MACRA) (Pub. L. 114-10, enacted April 16, 2015), Congress declares it a national objective to achieve widespread exchange of health information through interoperable certified electronic health record (EHR) technology nationwide by December 31, 2018. Section 106(b)(1)(C) of the MACRA provides that by July 1, 2016, and in consultation with stakeholders, the Secretary of Health and Human Services (HHS) shall establish metrics to be used to determine if and to the extent this objective has been met.
ONC intends to consider metrics that address the specific populations and aspects of interoperable health information described in section 106(b)(1)(B) of the MACRA. ONC is issuing this RFI is to solicit input on the following three topics: (1) Measurement population and key components of interoperability that should be measured; (2) current data sources and potential metrics that address section 106(b)(1) of the MACRA; and (3) other data sources and metrics ONC should consider with respect to section 106(b)(1) of the MACRA or interoperability measurement more broadly.
To be assured consideration, written or electronic comments must be received at one of the addresses provided below, no later than 5 p.m. on June 3, 2016.
In commenting, refer to file code ONC xxxx. Because of staff and resource limitations, ONC cannot accept comments by facsimile (FAX) transmission. You may submit comments in one of four ways (please choose only one of the ways listed):
1.
2.
3.
4.
If you intend to deliver your comments to this address, contact 202-205-8417 in advance to schedule your arrival with one of our staff members.
Talisha Searcy, Office of Policy, Evaluation & Analysis, ONC, 202-205-8417,
Comments received timely will also be available for public inspection, generally beginning approximately 3 weeks after publication of a document at Office of the National Coordinator for Health Information Technology, 330 C Street SW., Room 7025A, Washington, DC 20201. Contact Talisha Searcy, listed above, to arrange for inspection.
In section 106(b)(1) of the Medicare Access and CHIP Reauthorization Act of 2015 (MACRA) (Pub. L. 114-10, enacted April 16, 2015), Congress declares it a national objective to achieve widespread exchange of health information through interoperable certified electronic health record (EHR) technology nationwide by December 31, 2018. Section 106(b)(1)(C) of the MACRA provides that by July 1, 2016, and in consultation with stakeholders, the Secretary of Health and Human Services (HHS) shall establish metrics to be used to determine if and to the extent this objective has been met. Section 106(b)(1)(D) of the MACRA provides that if the Secretary determines that this objective has not been achieved by December 31, 2018, then by December 31, 2019 the Secretary shall submit a report to Congress that identifies barriers to this objective and recommends actions that the Federal Government can take to achieve it.
The Secretary of HHS will delegate authority to carry out the provisions of section 106(b)(1) of the MACRA to the Office of the National Coordinator for Health Information Technology (ONC). ONC is committed to advancing interoperability of health information and has developed a roadmap with stakeholder input, entitled
ONC is issuing this RFI is to solicit input on the following three topics, which are described in the comments section (Section II) of the RFI:
(1) Measurement population and key components of interoperability that should be measured;
(2) Current data sources and potential metrics that address section 106(b)(1) of the MACRA; and
(3) Other data sources and metrics ONC should consider with respect to section 106(b)(1) of the MACRA or interoperability measurement more broadly.
In order to establish metrics that will assess whether, and the extent to which, widespread exchange of health information through interoperable certified EHR technology nationwide has occurred, ONC needs to first define the scope of measurement.
Section 106(b)(1)(B) of the MACRA describes key components of interoperability that should be measured and the population that should be the focus of measurement. Section 106(b)(1)(B)(ii) of the MACRA defines interoperability as the ability of two or more health information systems or components to: (1) Exchange clinical and other information and (2) use the information that has been exchanged using common standards to provide access to longitudinal information for health care providers in order to facilitate coordinated care and improve patient outcomes. We believe appropriate metrics should address both of these aspects of interoperability. Section 106(b)(1)(B)(i) of the MACRA defines “widespread interoperability” as interoperability between certified EHR technology systems employed by meaningful EHR users under the Medicare and Medicaid EHR Incentive Programs and other clinicians and health care providers on a nationwide basis.
ONC intends to consider metrics that address the specific populations and aspects of interoperable health information as described above and in section 106(b)(1)(B) of the MACRA. Thus, ONC plans to assess interoperability among “meaningful EHR users” and clinicians and health care providers with whom they exchange clinical and other information—their exchange partners. Note that the exchange partners do not have to be “meaningful EHR users” themselves. Additionally, ONC plans to measure interoperability by identifying measures that relate to both exchange of health information as well as use of information that has been exchanged using common standards. More specifically, ONC seeks to measure the interoperable exchange and use of information by examining the following:
ONC expects that the scope of the metrics established pursuant to section 106(b)(1)(C) of the MACRA will support overarching interoperability measurement. However, ONC recognizes the need to measure interoperability across populations and settings beyond those specified by section 106(b)(1)(B) of the MACRA. The last chapter of the Interoperability Roadmap details ONC's plans for measuring interoperability across a variety of populations and settings, including proposed measures and accompanying timeframes.
In summary, under section 106(b)(1)(B)(i) of the MACRA, ONC believes the scope of the measurement should be limited to “meaningful EHR users” and their exchange partners. ONC believes this should include eligible professionals, eligible hospitals, and critical access hospitals (CAHs) that attest to meaningful use of certified EHR technology under CMS' Medicare and Medicaid EHR Incentive Programs. ONC would measure interoperability for section 106(b)(1)(B) of the MACRA by assessing the extent to which “meaningful EHR users” are electronically sending, receiving, finding, integrating information that has been received within an EHR, and subsequently using information they receive electronically from outside sources. Thus, this RFI focuses on obtaining input on measures that address these aspects of interoperability for the specified populations. Although this RFI seeks to obtain input on proposed measures that address section 106(b)(1)(B) of the MACRA, ONC also plans to measure interoperability across a variety of settings and populations, as well as barriers to interoperability in order to evaluate progress for the Interoperability Roadmap. ONC is requesting input regarding the provisions of section 106(b)(1) of the MACRA. Below are a specific set of questions related to those provisions.
Questions: We would appreciate comments you may have in response to some or all of the questions below. We also welcome any additional comments related to Section 106(b)(1) of the MACRA that you may want us to consider.
• Should the focus of measurement be limited to “meaningful EHR users,” as defined in this section (
• How should eligible professionals under the Merit-Based Incentive Payment System (MIPS) and eligible professionals who participate in the alternative payment models (APMs) be addressed? Section 1848(q) of the Social Security Act, as added by section 101(c) of the MACRA, requires the establishment of a Merit-Based Incentive Payment System for MIPS eligible professionals (MIPS eligible professionals).
• ONC seeks to measure various aspects of interoperability (electronically sending, receiving, finding and integrating data from outside sources, and subsequent use of information electronically received from outside sources). Do these aspects of interoperability adequately address both the exchange and use components of section 106(b)(1) of the MACRA?
• Should the focus of measurement be limited to use of certified EHR technology? Alternatively, should we consider measurement of exchange and use outside of certified EHR technology?
ONC is considering using a combination of the data sources to evaluate interoperability from two different perspectives: (1) By provider, based upon the proportion of “meaningful EHR users” exchanging information with other clinicians and health care providers and subsequently using electronic health information that has been exchanged; and (2) by transactions (
ONC recognizes that its currently available data sources might not be sufficient to fully measure and determine whether the goal of widespread exchange of health information through interoperable certified EHR technology has been achieved. ONC's currently available data sources are largely limited to eligible professionals, eligible hospitals, and CAHs as defined under the current Medicare and Medicaid EHR Incentive Programs. Therefore, ONC is requesting input on these measures and data sources, and is requesting feedback on additional national data sources which may be available for this purpose.
ONC is considering using nationally representative surveys of hospitals and office-based physicians to evaluate progress related to the interoperable exchange of health information from the health care provider perspective. ONC collaborates with the American Hospital Association (AHA) to conduct the AHA Health IT Supplement Survey and with the National Center for Health Statistics (NCHS) to conduct the National Electronic Health Record Survey of office-based physicians. Both surveys have relatively high response rates and convey health care providers' perspectives on exchange and interoperability (
Using these national survey data, ONC is considering the following measures below for both hospitals and office-based physicians.
• Proportion of health care providers who are electronically sending, receiving, finding, and easily integrating key health information, such as summary of care records. This can be a
• Proportion of health care providers who use the information that they electronically receive from outside providers and sources for clinical decision-making.
• Proportion of health care providers who electronically perform reconciliation of clinical information (
Based upon data collected in 2014, approximately one-fifth of non-federal acute care hospitals electronically sent, received, found (queried) and were able to easily integrate summary of care records into their EHRs.
ONC could also use data from national surveys to evaluate whether hospitals and office-based physicians are unable to widely share and use health information, and to identify what barriers to interoperable exchange exist. This would provide contextual information regarding whether interoperability is progressing as expected. For example, in 2014, hospitals reported a number of barriers they faced in exchanging and using interoperable health information.
• Do the survey-based measures described in this section, which focus on measurement from a health care provider perspective (as opposed to transaction-based approach) adequately address the two components of interoperability (exchange and use) as described in section 106(b)(1) of the MACRA?
• Could office-based physicians serve as adequate proxies for eligible professionals who are “meaningful EHR users” under the Medicare and Medicaid EHR Incentive Programs (
• Do national surveys provide the necessary information to determine why electronic health information may not be widely exchanged? Are there other recommended methods that ONC could use to obtain this information?
CMS Medicare and Medicaid EHR Incentive Program data could potentially be a useful data source as it consists of the population and measures aspects of interoperability as described in section 106(b)(1)(B) of the MACRA. However, there are limitations associated with these data for addressing both the exchange and use components of section 106(b)(1) of the MACRA. One primary limitation is that differences exist in how CMS currently receives performance data from each of the Medicare and Medicaid EHR Incentive Programs. Currently, Medicare collects and reports on performance data for each individual eligible professional, eligible hospital, and CAH. However, performance data is not available for each individual Medicaid eligible professional, eligible hospital, or CAH as the Medicaid EHR Incentive Program is operated by the states. Thus, ONC would not be able to evaluate interoperability across individual health care providers or transactions for the Medicaid EHR Incentive Program, unless it obtained these data from each state individually.
Additionally, not all aspects of health information exchange can be measured using the CMS EHR Incentive Programs data. The purpose of this meaningful use objective is to ensure a summary of care record is
Based upon CMS EHR Incentive Programs data, ONC is considering the following measures listed below.
• Proportion of transitions of care or referrals where a summary of care record was created using certified EHR technology and exchanged or transmitted electronically.
• For 2017 and subsequent years, the proportion of transitions or referrals and patient encounters in which the health care provider is the recipient of a transition or referral or has never before encountered the patient, and where the health care provider (
• Proportion of transitions of care where medication reconciliation is performed.
• For 2017 and subsequent years, the proportion of transitions or referrals received and patient encounters in which the health care provider is the recipient of a transition or referral or has never before encountered the patient, and the health care provider performs clinical information reconciliation for medications, medication allergies, and problem lists.
Reconciliation may include both automated and manual processes to allow the receiving provider to work with both electronic data and with the patient to reconcile their health information. The assumption underlying including this measure is that although some portion of the medication reconciliation processes may be occurring manually, it should be facilitated by the electronic exchange of clinical data, and therefore may serve as an adequate proxy for assessing use of information that is exchanged.
• Given some of the limitations described above, do these potential measures adequately address the “exchange” component of interoperability required by section 106(b)(1) of the MACRA?
• Do the reconciliation-related measures serve as adequate proxies to assess the subsequent use of exchanged information? What alternative, national-level measures (
• Can state Medicaid agencies share health care provider-level data with CMS similar to how Medicare currently collects and reports on these data in order to report on progress toward widespread health information exchange and use? If not, what are the barriers to doing so? What are some alternatives?
• These proposed measures evaluate interoperability by examining the exchange and subsequent use of that information across encounters or transitions of care rather than across health care providers. Would it also be valuable to develop measures to evaluate progress related to interoperability across health care providers, even if this data source may only available for eligible professionals under the Medicare EHR Incentive Program?
ONC acknowledges that other data sources might exist that could aid in the measurement of interoperability. For example, other potential data sources are Medicare Fee-For-Service (FFS) claims data as well as performance data from other programs. Section 1848(q)(2)(B) of the Social Security Act, as added by section 101(c) of the MACRA, describes the measures and activities for each of the four performance categories under the Merit-Based Incentive Payment System (MIPS), which includes meaningful use of certified EHR technology. These measures may also serve as a potential data source for assessing progress related to interoperability for MIPS eligible professionals. As the MIPS Program is implemented, ONC will be assessing whether any measures could be used for this purpose. Additionally, some of the information used to evaluate the performance of eligible professionals who participate in the alternative payment models (APMs) may also help inform progress related to interoperability.
Additionally, ONC is considering use of electronically-generated data from certified EHR technology or other systems, such as log-audit data, or leveraging surveys of entities that enable exchange to evaluate progress related to widespread electronic information exchange and use. ONC recognizes this will require collaboration and coordination with federal entities and stakeholders across the ecosystem including entities that enable exchange and interoperable health information use, such as technology developers, Health Information Organizations (HIOs) and Health Information Service Providers (HISPs).
• Should ONC select measures from a single data source for consistency, or should ONC leverage a variety of data sources? If the latter, would a combination of measures from CMS EHR Incentive Programs and national survey data of hospitals and physicians be appropriate?
• What, if any, other measures should ONC consider that are based upon the data sources that have been described in this RFI?
• Are there Medicare claims based measures that have the potential to add unique information that is not available from the combination of the CMS EHR Incentive Programs data and survey data?
• If ONC seeks to limit the number of measures selected, which are the highest priority measures to include?
• What, if any, other national-level data sources should ONC consider? Do technology developers, HISPs, HIOs and other entities that enable exchange have suggestions for national-level data sources that can be leveraged to evaluate interoperability for purposes of section 106(b)(1) of the MACRA (keeping in mind the December 31, 2018 deadline) or for interoperability measurement more broadly?
• How should ONC define “widespread” in quantifiable terms across these measures? Would this be a simple majority, over 50%, or should the threshold be set higher across these measures to be considered “widespread”?
This document does not impose information collection requirements, that is, reporting, recordkeeping or third-party disclosure requirements. Consequently, there is no need for review by the Office of Management and Budget under the authority of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
ONC typically receives a large public response to its published
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. Appendix 2), notice is hereby given of the meeting of the Council of Councils.
The meeting will be open to the public as indicated below, with attendance limited to space available. Individuals who plan to attend and need special assistance, such as sign language interpretation or other reasonable accommodations, should notify the Contact Person listed below in advance of the meeting. The open session will be videocast and can be accessed from the NIH Videocasting and Podcasting Web site (
A portion of the meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4), and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Any interested person may file written comments with the committee by forwarding the statement to the Contact Person listed on this notice. The statement should include the name, address, telephone number and when applicable, the business or professional affiliation of the interested person.
In the interest of security, NIH has instituted stringent procedures for entrance onto the NIH campus. All visitor vehicles, including taxicabs, hotel, and airport shuttles will be inspected before being allowed on campus. Visitors will be asked to show one form of identification (for example, a government-issued photo ID, driver's license, or passport) and to state the purpose of their visit.
Information is also available on the Council of Council's home page at
In accordance with Title 41 of the U.S. Code of Federal Regulations, Section 102-3.65(a), notice is hereby given that the Charter for the National Science Advisory Board for Biosecurity was renewed for an additional two-year period on April 7, 2016.
It is determined that the National Science Advisory Board for Biosecurity is in the public interest in connection with the performance of duties imposed on the National Institutes of Health by law, and that these duties can best be performed through the advice and counsel of this group.
Inquiries may be directed to Jennifer Spaeth, Director, Office of Federal Advisory Committee Policy, Office of the Director, National Institutes of Health, 6701 Democracy Boulevard, Suite 1000, Bethesda, Maryland 20892 (Mail code 4875), Telephone (301) 496-2123, or
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App), notice is hereby given of the meetings.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable materials, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
National Institutes of Health, HHS.
Notice.
This is notice, in accordance with 35 U.S.C. 209 and 37 CFR part 404, that the National Institute of Neurological Disorders and Stroke (NINDS), National Institutes of Health (NIH), Department of Health and Human Services, is contemplating the grant of a start-up exclusive license to AestasRx Inc., which is located in North Carolina, to practice the inventions embodied in the following patents: U.S. Patent 8,597,660, issued December 3, 2013 (HHS reference E-144-2010/0-US-02).
The patent rights in these inventions have been assigned to the United States of America. The prospective start-up exclusive license territory may be worldwide and the field of use may be limited to therapeutics (including small-molecule TFP5 mimetics) and PMA-approved diagnostics for Alzheimer's disease (intranasal delivery only), Parkinson's Disease, neuropathy, neuropathic pain, peripheral neuropathy, diabetic neuropathy, neurapraxia, axonotmesis and neurotmesis.
Only written comments and/or applications for a license which are received by NINDS Technology Transfer on or before April 25, 2016 will be considered.
Requests for copies of the patent application, inquiries, comments, and other materials relating to the contemplated start-up exclusive license should be directed to: Susan Ano, Ph.D., NINDS Technology Transfer, 31 Center Drive, Suite 8A52, MSC2540, Bethesda, MD 20892; Telephone: (301) 435-5515; Email:
This invention discloses treating neurodegenerative diseases by administering cyclin dependent kinase 5 (Cdk5) inhibitory peptides derived from P35, the activator of Cdk5. Abnormally hyperactive Cdk5 has been shown to be associated with a variety of neurodegenerative disorders. This invention describes isolated peptide fragments, pharmaceutical compositions and methods for use of such for treating subjects with a neurodegenerative disease, such as Alzheimer's disease (AD), Amyotrophic Lateral Sclerosis (ALS) and Parkinson's disease (PD). An inhibitory fragment, TFP5, disclosed in this invention, has been shown to ameliorate symptoms of AD in disease animal models without any evidence of toxicity. In particular, TFP5 treatment of rat cortical neurons reduced hyperactivation of Cdk5 upon neuronal stress and insults. Following intraperitoneal (ip) injection, TFP5 was capable of crossing the blood-brain barrier and localizing within the brain where it was found to rescue memory deficits and pathology in a double transgenic mouse (APP/PS1) AD model.
The prospective start-up exclusive license may be granted unless within fifteen (15) days from the date of this published notice, the NIH receives written evidence and argument that establishes that the grant of the license would not be consistent with the requirements of 35 U.S.C. 209 and 37 CFR part 404.
Complete applications for a license in the field of use filed in response to this notice will be treated as objections to the grant of the contemplated start-up exclusive license. Comments and objections submitted to this notice will not be made available for public inspection and, to the extent permitted by law, will not be released under the Freedom of Information Act, 5 U.S.C. 552.
Notice.
The National Institute of Allergy and Infectious Diseases (NIAID), a component of the National Institutes of Health (NIH), Department of Health and Human Services (HHS) seeks to enter into a CRADA with a commercial partner to collaborate on the development and commercialization of an assay to detect a genetic variation related to mast cell activation disorders.
Interested CRADA collaborators must submit a confidential proposal summary to the NIAID (attention Amy F. Petrik at the address below) on or before 8 June 2016 for consideration. Guidelines for preparing full CRADA proposals will be communicated shortly thereafter to all respondents with whom initial confidential discussions will have established sufficient mutual interest. CRADA proposals submitted thereafter may be considered if a suitable CRADA collaborator has not been selected.
Questions should be addressed to Amy F. Petrik, Ph.D., Technology Transfer and Intellectual Property Office, National Institute of Allergy and Infectious Diseases, 5601 Fishers Lane, Suite 6D, Rockville, MD 20892-9804, Tel: (240) 627-3721 or email:
Approximately 4-6% of the general Western population exhibit elevated basal levels of serum tryptase. As a mast cell mediator, tryptase is expected to be transiently elevated following allergic stimuli. Sustained elevation of serum tryptase levels can be associated with symptoms of mast cell mediator release (such as flushing, itching and swelling), neuropsychiatric symptoms (such as chronic pain, anxiety and dysautonomia) and gastrointestinal (GI) symptoms (including functional GI disorders like irritable bowel syndrome as well as eosinophilic GI disease) as well as an increased risk for systemic anaphylaxis.
The NIAID Investigators have recently reported that these symptomatic tryptase elevations can be inherited in an autosomal dominant fashion and are associated with the phenotype described above (Lyons, J.J., et al. J Allergy Clin Immunol, 133 (2014), pp. 1471-1474). Through next generation sequencing and linkage analysis the NIAID Investigators identified a structural variant cosegregating with disease. They then developed an assay, based on digital droplet PCR, to identify individuals with this variant, and estimate that 5-8% of Caucasians may have it, and be at risk for being symptomatic.
Under the CRADA, the assay will be developed toward licensure. Due to the relatively high prevalence of serum tryptase elevation, NIAID Investigators
A Cooperative Research and Development Agreement (CRADA) is the anticipated collaborative agreement to be entered into with NIAID pursuant to the Federal Technology Transfer Act of 1986, codified as 15 U.S.C. 3710a, and Executive Order 12591 of April 10, 1987, as amended. A CRADA is an agreement designed to enable certain collaborations between Government laboratories and non-Government laboratories. A CRADA is not a grant, and it is not a contract for the procurement of goods/services. The NIAID is prohibited from transferring funds to a CRADA collaborator. Under a CRADA, NIAID can contribute facilities, staff, materials, and expertise. The CRADA collaborator can contribute facilities, staff, materials, expertise, and funds. The CRADA collaborator will also have an option to negotiate the terms of an exclusive or non-exclusive commercialization license to subject inventions arising under the CRADA. The goals of the CRADA include the rapid publication of research results and timely commercialization of products, diagnostics, and treatments that result from the research.
The expected duration of the CRADA with be two (2) to three (3) years.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The contract proposals and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the contract proposals, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Under the provisions of Section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the National Institutes of Health (NIH) has submitted to the Office of Management and Budget (OMB) a request for review and approval of the information collection listed below. This proposed information collection was previously published in the
To obtain a copy of the data collection plans and instruments, submit comments in writing, or request more information on the proposed project, contact: Ms. Deshiree Belis, National Heart, Lung, and Blood Institute, National Institutes of Health, 6705 Rockledge Dr., Suite 6185A, Bethesda, MD 20892, or call non-toll-free number 301-435-1032, or Email your request, including your address to
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 8,382.
Federal Emergency Management Agency, DHS.
Final notice.
Flood hazard determinations, which may include additions or modifications of Base Flood Elevations (BFEs), base flood depths, Special Flood Hazard Area (SFHA) boundaries or zone designations, or regulatory floodways on the Flood Insurance Rate Maps (FIRMs) and where applicable, in the supporting Flood Insurance Study (FIS) reports have been made final for the communities listed in the table below.
The FIRM and FIS report are the basis of the floodplain management measures that a community is required either to adopt or to show evidence of having in effect in order to qualify or remain qualified for participation in the Federal Emergency Management Agency's (FEMA's) National Flood Insurance Program (NFIP). In addition, the FIRM and FIS report are used by insurance agents and others to calculate appropriate flood insurance premium rates for buildings and the contents of those buildings.
The effective date of July 6, 2016 which has been established for the FIRM and, where applicable, the supporting FIS report showing the new or modified flood hazard information for each community.
The FIRM, and if applicable, the FIS report containing the final flood hazard information for each community is available for inspection at the respective Community Map Repository address listed in the tables below and will be available online through the FEMA Map Service Center at
Luis Rodriguez, Chief, Engineering Management Branch, Federal Insurance and Mitigation Administration, FEMA, 500 C Street SW., Washington, DC 20472, (202) 646-4064, or (email)
The Federal Emergency Management Agency (FEMA) makes the final determinations listed below for the new or modified flood hazard information for each community listed. Notification of these changes has been published in newspapers of local circulation and 90 days have elapsed since that publication. The Deputy Associate Administrator for Mitigation has resolved any appeals resulting from this notification.
This final notice is issued in accordance with section 110 of the Flood Disaster Protection Act of 1973, 42 U.S.C. 4104, and 44 CFR part 67.
Interested lessees and owners of real property are encouraged to review the new or revised FIRM and FIS report available at the address cited below for each community or online through the FEMA Map Service Center at
The flood hazard determinations are made final in the watersheds and/or communities listed in the table below.
Office of the Assistant Secretary for Community Planning and Development, HUD.
Notice.
This Notice identifies unutilized, underutilized, excess, and surplus Federal property reviewed by HUD for suitability for use to assist the homeless.
Juanita Perry, Department of Housing and Urban Development, 451 Seventh Street SW., Room 7266, Washington, DC 20410; telephone (202) 402-3970; TTY number for the hearing- and speech-impaired (202) 708-2565 (these telephone numbers are not toll-free), or call the toll-free Title V information line at 800-927-7588.
In accordance with 24 CFR part 581 and section 501 of the Stewart B. McKinney Homeless Assistance Act (42 U.S.C. 11411), as amended, HUD is publishing this Notice to identify Federal buildings and other real property that HUD has reviewed for suitability for use to assist the homeless. The properties were reviewed using information provided to HUD by Federal landholding agencies regarding unutilized and underutilized buildings and real property controlled by such agencies or by GSA regarding its inventory of excess or surplus Federal property. This Notice is also published in order to comply with the December 12, 1988 Court Order in
Properties reviewed are listed in this Notice according to the following categories: Suitable/available, suitable/unavailable, and suitable/to be excess, and unsuitable. The properties listed in the three suitable categories have been reviewed by the landholding agencies, and each agency has transmitted to HUD: (1) Its intention to make the property available for use to assist the homeless, (2) its intention to declare the property excess to the agency's needs, or (3) a statement of the reasons that the property cannot be declared excess or made available for use as facilities to assist the homeless.
Properties listed as suitable/available will be available exclusively for homeless use for a period of 60 days from the date of this Notice. Where property is described as for “off-site use only” recipients of the property will be required to relocate the building to their own site at their own expense. Homeless assistance providers interested in any such property should send a written expression of interest to HHS, addressed to: Ms. Theresa M. Ritta, Chief Real Property Branch, the Department of Health and Human Services, Room 5B-17, Parklawn Building, 5600 Fishers Lane, Rockville, MD 20857, (301)-443-2265 (This is not a toll-free number.) HHS will mail to the interested provider an application packet, which will include instructions for completing the application. In order to maximize the opportunity to utilize a suitable property, providers should submit their written expressions of interest as soon as possible. For complete details concerning the processing of applications, the reader is encouraged to refer to the interim rule governing this program, 24 CFR part 581.
For properties listed as suitable/to be excess, that property may, if subsequently accepted as excess by GSA, be made available for use by the homeless in accordance with applicable law, subject to screening for other Federal use. At the appropriate time, HUD will publish the property in a Notice showing it as either suitable/available or suitable/unavailable.
For properties listed as suitable/unavailable, the landholding agency has decided that the property cannot be declared excess or made available for use to assist the homeless, and the property will not be available.
Properties listed as unsuitable will not be made available for any other purpose for 20 days from the date of this Notice. Homeless assistance providers interested in a review by HUD of the determination of unsuitability should call the toll free information line at 1-800-927-7588 for detailed instructions or write a letter to Ann Marie Oliva at the address listed at the beginning of this Notice. Included in the request for review should be the property address (including zip code), the date of publication in the
For more information regarding particular properties identified in this Notice (
Fish and Wildlife Service, Interior.
Notice of receipt of applications for permit.
We, the U.S. Fish and Wildlife Service, invite the public to comment on the following applications to conduct certain activities with endangered species. With some exceptions, the Endangered Species Act (ESA) prohibits activities with listed species unless Federal authorization is acquired that allows such activities.
We must receive comments or requests for documents on or before May 9, 2016.
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•
When submitting comments, please indicate the name of the applicant and the PRT# you are commenting on. We will post all comments on
Brenda Tapia, (703) 358-2104 (telephone); (703) 358-2281 (fax);
Send your request for copies of applications or comments and materials concerning any of the applications to the contact listed under
Please make your requests or comments as specific as possible. Please confine your comments to issues for which we seek comments in this notice, and explain the basis for your comments. Include sufficient information with your comments to allow us to authenticate any scientific or commercial data you include.
The comments and recommendations that will be most useful and likely to influence agency decisions are: (1) Those supported by quantitative information or studies; and (2) Those that include citations to, and analyses of, the applicable laws and regulations. We will not consider or include in our administrative record comments we receive after the close of the comment period (see
Comments, including names and street addresses of respondents, will be available for public review at the street address listed under
To help us carry out our conservation responsibilities for affected species, and in consideration of section 10(a)(1)(A) of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
On September 30, 2015, we published a
The applicant requests a permit to import biological samples from black rhinoceros (
The applicant requests renewal of a permit to import captive-bred/captive-hatched and wild live specimens, captive-bred/wild-collected viable eggs, biological samples, and salvaged materials from captive-bred/wild specimens of whooping cranes (
The applicant requests amendment of their captive-bred wildlife registration under 50 CFR 17.21(g) for the following species: Spotted pond turtle (
The applicant requests a captive-bred wildlife registration under 50 CFR 17.21(g) for the following species to enhance species propagation or survival: Lar gibbon (
The following applicants each request a permit to import the sport-hunted trophy of one male bontebok (
Bureau of Land Management, Interior.
Notice.
The Bureau of Land Management (BLM) has examined and found suitable for classification for lease and subsequent conveyance under the provisions of the Taylor Grazing Act and the Recreation and Public Purposes (R&PP) Act, as amended, approximately 15 acres of public land in the Las Vegas Valley, Clark County, Nevada. Clark County proposes to use the land for a community park. The 15-acre park will help meet future expanding needs in the southwestern part of Las Vegas Valley.
Interested parties may submit written comments regarding the proposed classification for lease and conveyance of the land until May 23, 2016.
Mail written comments to the BLM Field Manager, Las Vegas Field Office, 4701 N. Torrey Pines Drive, Las Vegas, Nevada 89130.
Luis Rodriguez, (702) 515-5069, email:
The parcel of land is located southwest of the intersection of Wigwam Avenue and Torrey Pines Drive and is legally described as:
The area described contains 15 acres, more or less, in Clark County.
In accordance with the R&PP Act, Clark County has filed an application to develop the above-described land as a community park with covered play structures, restrooms, parking, picnic pavilions, open turf areas, walking path, basketball courts, landscaping, lighting signage, and other ancillary amenities. Additional detailed information pertaining to this application, plan of development, and site plan is located in case file N-94234, which is available for review at the BLM Las Vegas Field Office at the above address.
Clark County is a political subdivision of the State of Nevada; and is therefore, a qualified applicant under the R&PP Act.
Subject to limitations prescribed by law and regulation, prior to patent issuance, the holder of any right-of-way grant within the lease area may be given the opportunity to amend the right-of-way grant for conversion to a new term, including perpetuity, if applicable.
The land identified is not needed for any Federal purpose. The lease and/or conveyance is consistent with the BLM Las Vegas Resource Management Plan dated October 5, 1998, and would be in the public interest. Clark County has not applied for more than the 640-acre limitation for public purpose uses in a year and has submitted a statement in compliance with the regulations at 43 CFR 2741.4(b).
The lease and conveyance, when issued, will be subject to the provisions of the R&PP Act and applicable regulations of the Secretary of the Interior, and will contain the following reservations to the United States:
1. A right-of-way thereon for ditches or canals constructed by the authority of the United States, Act of August 30, 1890 (43 U.S.C. 945); and
2. All minerals shall be reserved to the United States, together with the right to prospect for, mine, and remove such deposits from the same under applicable law and such regulations as the Secretary of the Interior may prescribe.
Any lease and conveyance will also be subject to valid existing rights, will contain any terms or conditions required by law (including, but not limited to, any terms or conditions required by 43 CFR 2741.4), and will contain an appropriate indemnification clause protecting the United States from claims arising out of the lessee's/patentee's use, occupancy, or operations on the leased/patented lands. It will also contain any other terms and conditions deemed necessary and appropriate by the Authorized Officer.
Any lease and conveyance will also be subject to all valid and existing rights.
Upon publication of this notice in the
Interested parties may submit written comments on the suitability of the land for a public park in the Enterprise area. Comments on the classification are restricted to whether the land is physically suited for the proposal, whether the use will maximize the future use or uses of the land, whether the use is consistent with local planning and zoning, or if the use is consistent with State and Federal programs. Interested parties may also submit written comments regarding the specific use proposed in the application and plan of development, and whether the BLM followed proper administrative procedures in reaching the decision to lease and convey under the R&PP Act.
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so. Only written comments submitted to the Field Manager, BLM Las Vegas Field Office, will be considered properly filed. Any adverse comments will be reviewed by the BLM Nevada State Director, who may sustain, vacate, or modify this realty action.
In the absence of any adverse comments, the decision will become effective on June 7, 2016. The lands will not be available for lease and conveyance until after the decision becomes effective.
43 CFR 2741.5.
Bureau of Land Management, Interior.
Notice of Intent.
In compliance with the National Environmental Policy Act of 1969, as amended (NEPA), and the Federal Land Policy and Management Act of 1976, as amended, the Bureau of Land Management (BLM), Vernal Field Office, Vernal, Utah, intends to prepare an Environmental Impact Statement (EIS) for the Utah Federal-Tribal Well Development proposal submitted by Crescent Point Energy. By this notice the BLM is also announcing the beginning of the scoping process and is soliciting public comments on the issues to be analyzed in the EIS.
This notice initiates a public scoping process for the EIS. Comments on issues may be submitted in writing for 30 days following the publication of this notice. The date(s) and location(s) of any public scoping meetings will be announced at least 15 days in advance through local news media, a project newsletter, and the BLM Web site at:
Comments on issues related to the Crescent Point Energy Utah Federal-Tribal Well Development Project may be submitted by any of the following methods:
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Documents pertinent to this proposal may be examined at the Vernal Field Office.
Stephanie Howard, BLM Project Manager; telephone at 435-781-4469; email
The applicant, Crescent Point Energy U.S. Corp, has filed a plan of development for their Federal, State, private, and tribal trust leases. Crescent Point proposes to drill up to 3,925 new oil and gas wells and build 863 miles of roads; 693 miles of pipelines co-located with the proposed roads; 170 miles of cross-country pipelines; 400 miles of trunk pipelines; 5 salt water disposal wells; 5 produced water treatment facilities; 20 central tank batteries; 4 gas processing plants; 8 oil storage areas; and, 4 equipment storage areas. These activities would occur on Federal-, tribal trust-, allottee-, State-, and privately-owned or administered lands. The project area is located within Duchesne and Uintah counties. It encompasses lands from 1 mile east of Myton, Utah, to 1 mile west of Highway 45. It is directly south of Roosevelt and Ballard cities, Utah, and north of the Ouray Wildlife Refuge. It encompasses:
The purpose of the public scoping process is to determine relevant issues that will influence the scope of the environmental analysis, including alternatives and mitigation, and to guide the process for developing the EIS. At present, the BLM has identified the following resources as potentially being impacted by the project: Air quality and air-related values; surface water and groundwater resources including floodplains, wetlands, the Dry Gulch Creek, Pelican Lake, and the Green, Uinta, and Duchesne Rivers; cultural and paleontological resources; soils; special status plant and animal species; greater sage-grouse habitat; livestock grazing; recreation; the Pelican Lake Special Recreation Management Area; residences and residential areas; local
Alternatives identified at this time include the proposed action and the no action alternatives. Additional alternatives and mitigation will be developed as a result of issues and concerns identified through the scoping process. The BLM will identify and analyze impacts to resources that could be expected to occur from the approval of this project, and the BLM will consider potential mitigation measures to address those impacts, where available. Mitigation may include avoidance, minimization, rectification, reduction or elimination over time, and compensatory mitigation; and may be considered at multiple scales, including the landscape scale.
The BLM-Vernal Field Office Record of Decision and Approved Resource Management Plan (RMP) (October 2008), as amended (September 2015), directs management of the BLM-administered public lands within the project area. The RMP provides for development of valid existing oil and gas leases. An amendment of the RMP is not required in connection with this project.
The BLM is the designated lead Federal agency for preparation of the EIS as defined in 40 CFR 1501.5. Agencies with legal jurisdiction or special expertise have been invited to participate as cooperating agencies in preparation of the EIS. These include: Ballard City; Myton City; Roosevelt City; Duchesne County; Uintah County; Utah School and Institutional Trust Lands Administration; Utah Public Lands Policy and Coordination Office; Ute Indian Tribe; United States (U.S.) Environmental Protection Agency Region 8; U.S. Fish and Wildlife Service Utah Field Office; U.S. Army Corps of Engineers Utah/Nevada Regulatory Office; Bureau of Reclamation Provo Area Office; Bureau of Indian Affairs Uintah and Ouray Agency; Utah Reclamation Mitigation and Conservation Commission; and, the Ouray Wildlife Refuge.
The BLM will use and coordinate the NEPA commenting process to satisfy the public involvement process for Section 106 of the National Historic Preservation Act (16 U.S.C. 470f) as provided for in 36 CFR 800.2(d)(3). The BLM will consult with Indian tribes on a government-to-government basis in accordance with Executive Order 13175 and other policies. Tribal concerns, including impacts on Indian trust assets and potential impacts to cultural resources, will be given due consideration.
Comments regarding issues, alternatives, scope, mitigation, or other concerns or ideas may be submitted in writing to the BLM at any public scoping meeting, or you may submit them to the BLM using one of the methods listed in the
40 CFR 1501.7
Bureau of Land Management, Interior.
Notice.
The Bureau of Land Management (BLM) has examined and found suitable for classification for conveyance under the provisions of the Recreation and Public Purposes Act (R&PP), as amended, approximately 10 acres of public land in Uinta County, Wyoming. Uinta County, Wyoming, proposes to use the land for an expansion of the Bridger Valley Landfill for a municipal solid waste transfer station.
Interested parties may submit comments regarding the proposed conveyance or classification of the lands until May 23, 2016.
You may submit comments by any of the following methods:
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Documents pertinent to this proposal may be examined at the Kemmerer Field Office at the above address.
Kelly Lamborn, Realty Specialist, BLM Kemmerer Field Office, 430 North Highway 189, Kemmerer, WY 83101; telephone 307-828-4505; email
In accordance with Section 7 of the Taylor Grazing Act (43 U.S.C. 3150), and Executive Order No. 6910, the following described public land in Uinta County, Wyoming, has been examined and found suitable for classification for conveyance under the provisions of the R&PP, as amended (43 U.S.C. 869
The land described contains 10 acres in Uinta County, Wyoming, according to the official plat of the survey of the said land, on file with the BLM.
In accordance with the R&PP, Uinta County filed an application to purchase the above described 10 acres of public land to be developed as a municipal solid waste transfer station, as an expansion of the existing Bridger Valley Landfill. Additional detailed information pertaining to this application, plan of development, and site plan is in case file WYW-171474, located in the BLM Kemmerer Field Office at the above address.
The conveyance is consistent with the Kemmerer Resource Management Plan (RMP) dated May 2010, as amended by the Approved RMP Amendments for the Rocky Mountain Region (ARMPA) approved September 22, 2015. The proposal is consistent with the objectives, goals, and decision of the 2010 BLM Kemmerer RMP, and would be in the public interest. The ARMPA Management Decision, LR 7, allows for lands within general habitat management areas to be disposed of, as long as the action is consistent with the goals and objectives of the plan, including, but not limited to, the RMP
The parcel of land is not required for any other Federal purposes and does not contain other known public values. The patent will include an appropriate indemnification claim protecting the United States from claims arising out of the patentee's use occupancy or occupations on the patented lands. The BLM will retain all mineral rights.
Upon publication of this notice in the
The patent, if issued, will be subject to the provisions of the R&PP and applicable regulations of the Secretary of the Interior, and will contain the following reservations to the United States:
1. All minerals, together with the right to prospect for, mine, and remove such deposits from the same under applicable law and such regulations as the Secretary of the Interior may prescribe;
2. A right-of-way thereon for ditches or canals constructed by the authority of the United States pursuant to the Act of August 30, 1890, (43 U.S.C. 945); and
3. All valid existing rights of record, including those documented on the official public land records at the time of patent issuance.
4. An appropriate indemnification clause protecting the United States from claims arising out of the patentee's use, occupancy, or operations on the patented lands.
5. No portion of the land shall under any circumstance revert to the United States if any such portion has been used for solid waste disposal or for any other purpose which may result in the disposal, placement, or release of any hazardous substance.
Detailed information concerning these actions is available for review at the address above during normal business hours, 7:45 a.m. to 4:30 p.m., Monday through Friday, excluding Federal holidays.
Interested parties may submit comments involving the suitability of the lands for a municipal solid waste transfer station. Classification comments are restricted to whether the land is physically suitable for the proposal, whether the use will maximize the future use or uses of the land, whether the use is consistent with local planning and zoning, or if the use is consistent with State and Federal programs.
Interested parties may submit comments regarding the conveyance and specific uses proposed in the application and plan of development, whether the BLM followed proper administrative procedures in reaching the decision to convey under the R&PP, or any other factor not directly related to the suitability of the land for R&PP use.
Interested parties may submit written comments to the BLM Kemmerer Field Manager at the address above. Comments, including names and street addresses of respondents, will be available for public review at the BLM Kemmerer Field Office during regular business hours.
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
Any adverse comments will be reviewed by the State Director, who may sustain, vacate, or modify this realty action. In the absence of timely filed objections, the classification of the land described in this notice will become effective June 7, 2016. The lands will not be available for conveyance until after the classification becomes effective.
43 CFR 2741.5(h).
Bureau of Land Management, Interior.
Notice.
Pursuant to the National Environmental Policy Act of 1969, the BLM is making available for public review and comment the Final National Programmatic Environmental Impact Statement (EIS) on vegetation treatments involving the use of aminopyralid, fluroxypyr, and rimsulfuron herbicides on public lands administered by 11 BLM state offices in 17 western states, including Alaska. The BLM is the lead Federal agency for the preparation of this final Programmatic EIS in compliance with the requirements of NEPA. If a Record of Decision is approved, the BLM would be permitted to use three new herbicide formulations on public lands.
The BLM will not issue a final decision on the proposal for a minimum of 30 days after the date that the Environmental Protection Agency publishes its Notice of Availability in the
The Final Programmatic EIS and associated documents will be available for review in either hard copy or on compact disks at all BLM State, District, and Field Office public rooms. You can also review or download the document from the BLM Web site:
Gina Ramos, Senior Weeds Specialist, telephone 202-912-7226, or Stuart Paulus, Project Manager, telephone 206-403-4287. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 1-800-877-8339 to contact the referenced individuals during normal business hours. The FIRS is available 24 hours a day, 7 days a week, to leave a message or question with the above individuals. You will receive a reply during normal business hours.
The Final National Programmatic EIS proposes to add aminopyralid, fluroxypyr, and rimsulfuron to the BLM's approved list of herbicides for: (1) Controlling noxious weeds and other invasive species; and (2) Conserving and restoring native vegetation, watersheds, and fish and wildlife habitat. The Programmatic EIS evaluated the use of the three new herbicides as part of the BLM's vegetation treatment programs on public lands in 17 Western States. This action would increase the number of active ingredients approved for use, and would give the BLM increased flexibility and options when designing herbicide treatments. The Programmatic EIS is neither a land-use plan nor a
The BLM issued a Notice of Availability of the Draft Programmatic Environmental Impact Statement Using Aminopyralid, Fluroxypyr, and Rimsulfuron on June 19, 2015 (80 FR 35394). The BLM responded to public comments during the Draft Programmatic EIS public review period. Comment responses and the subsequent changes in the impact analysis as a result of public comments are documented in this Final Programmatic EIS per requirements under 40 CFR 1503.4. The BLM will prepare a Record of Decision for the Final Programmatic EIS after the 30-day period following publication of this notice.
Bureau of Land Management, Interior.
Notice of availability.
In accordance with the National Environmental Policy Act of 1969, as amended (NEPA), and the Federal Land Policy and Management Act (FLPMA) of 1976, as amended, the Bureau of Land Management (BLM) has prepared a Draft Environmental Impact Statement (EIS) for the Enefit American Oil Utility Corridor Project. Through this Notice, the BLM is announcing a 60-day public comment period on the draft.
To ensure comments will be considered, the BLM must receive written comments on the Enefit American Oil Utility Corridor Project Draft EIS within 60 days following the date on which the Environmental Protection Agency publishes its Notice of Availability of the Draft EIS in the
Copies of the Enefit American Oil Utility Corridor Project Draft EIS are available for public inspection in the BLM Vernal Field Office, 170 South 500 East, Vernal, Utah 84078. Interested persons may also review the Draft EIS on the Internet at:
Stephanie Howard, NEPA Coordinator; telephone 435-781-4469; address 170 South 500 East, Vernal, Utah 84078; email
Enefit American Oil (Enefit) submitted five rights-of-way (ROW) applications under Title V of FLPMA. Collectively, these ROW applications are known as the Enefit American Oil Utility Corridor Project. The Project involves three pipeline ROWs, a ROW for a 138-kV power line, and a ROW grant to widen an existing road. The project area is located in the southern portion of Townships 8-10 South, Ranges 24-25 East, Salt Lake Meridian, in Uintah County, Utah, approximately 12 miles southeast of Bonanza Utah.
The BLM is the lead Federal agency for this Draft EIS. Cooperating agencies include the Environmental Protection Agency Region 8, Corps of Engineers Utah Regulatory Office, Fish and Wildlife Service Utah Field Office, Utah's Public Lands Policy and Coordination Office, and Uintah County.
The BLM published a Notice of Intent (NOI) to prepare an EIS for this project in the
The Draft EIS describes and analyzes the impacts of the Utility Corridor Project and the No Action Alternative. The following is a summary of the alternatives:
1.
2.
Enefit has applied for the ROW across public land to facilitate utilities access to and transport finished product from its South Project. The South Project is located entirely on private land and involves accessing privately-owned oil shale mineral resources. The South Project will include development of a 7,000-9,000-acre commercial oil shale mining, retorting, and upgrading operation in Uintah County. The South Project is anticipated to produce 50,000 barrels of oil per day at full build out for a period of up to 30 years utilizing oil shale ore rock mined from Enefit's private property holdings.
Because of its location on fee surface and fee minerals, the South Project is outside of the jurisdiction of the BLM. As explained in the Draft EIS, it is expected to reach full build out regardless of whether or not the BLM approves the Proposed Action.
Because of the relationship between the South Project and the Proposed Action, the Draft EIS evaluates the environmental impacts of the South Project as indirect effects of the Proposed Action. Based on the impact analysis, on-site, landscape, and compensatory conservation and
Before including your address, phone number, email address, or other personal identifying information in your comment, you should be aware that your entire comment—including your personal identifying information—may be made publicly available at any time. While you can ask us in your comment to withhold your personal identifying information from public review, we cannot guarantee that we will be able to do so.
40 CFR 1506.6, 40 CFR 1506.10
Bureau of Ocean Energy Management (BOEM), Interior.
Rescheduling of public meetings.
BOEM is announcing the dates, locations, and times of rescheduled meetings in Washington, DC; Houston, TX; and New Orleans, LA, to elicit comments on the OCS Oil and Gas Leasing Program 2017-2022 Draft Programmatic Environmental Impact Statement (Draft Programmatic EIS), which has been prepared by BOEM to support the Proposed OCS Oil and Gas Leasing Program for 2017-2022 (2017-2022 Program).
Jill Lewandowski, Ph.D., Bureau of Ocean Energy Management, 45600 Woodland Road VAM-OEP, Sterling, VA 20166; Dr. Lewandowski may also be reached by telephone at (703) 787-1703.
• April 18, 2016, DoubleTree by Hilton New Orleans Airport, 2150 Veterans Memorial Blvd., Kenner, LA 70062; 2-6 p.m.; parking available at garage adjacent to hotel at a discounted rate. Validation tickets will be provided to guests upon request at the hotel's registration desk.
• April 20, 2016, Hyatt Regency Houston, 1200 Louisiana Street, Houston, TX 77002; 3-7 p.m.; validated valet parking at hotel.
• April 26, 2016, Marriott Metro Center, 775 12th Street NW., Washington, DC 20005; 3-7 p.m.; valet parking at no charge to meeting attendees up to 8 hours.
All other public meetings were held on the dates and at the locations previously announced, with the exception of the public meeting in Kotzebue, Alaska. The meeting in Kotzebue, Alaska was rescheduled from March 29, 2016, and held on April 1, 2016, because of hazardous travel conditions due to the eruption of the Pavlof Volcano in Alaska.
United States International Trade Commission.
April 15, 2016 at 11:00 a.m.
Room 101, 500 E Street SW., Washington, DC 20436, Telephone: (202) 205-2000.
Open to the public.
In accordance with Commission policy, subject matter listed above, not disposed of at the scheduled meeting, may be carried over to the agenda of the following meeting.
By order of the Commission.
U.S. International Trade Commission.
Notice.
Notice is hereby given that the U.S. International Trade Commission has determined not to review the presiding administrative law judge's (“ALJ”) initial determination (“ID”) (Order No. 4), granting a joint motion to terminate the investigation based on a consent order stipulation and proposed consent order in the above-captioned investigation. The consent order is issued and the investigation is terminated.
Megan M. Valentine, Office of the General Counsel, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202)
The Commission instituted this investigation on February 16, 2016, based on a complaint filed by Covidien LP of Mansfield, Massachusetts (“Covidien”). 81 FR 7830-31 (Feb. 16, 2016). The complaint alleged violations of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. 1337), in the importation into the United States, the sale for importation, or the sale within the United States after importation of surgical stapler devices and components thereof, by reason of infringement of certain claims of U.S. Patent Nos. 6,669,073; 8,342,377; and 6,079,606. The notice of investigation named Chongqing QMI Surgical Co., Ltd. of Chongqing, China (“QMI”) as respondent. The Office of Unfair Import Investigations was also named as a party.
On March 1, 2016, Covidien and QMI jointly moved for termination of the investigation in its entirety based on a consent order stipulation and proposed consent order.
On March 10, 2016, the ALJ issued the subject ID, granting the joint motion. The ID finds that the consent order stipulation and proposed consent order comply with Commission rules,
No petitions for review of the ID were filed.
The Commission has determined not to review the ID and to issue the consent order.
The authority for the Commission's determination is contained in section 337 of the Tariff Act of 1930, as amended (19 U.S.C. 1337), and in Part 210 of the Commission's Rules of Practice and Procedure (19 CFR part 210).
By order of the Commission.
On the basis of the record
The Commission, pursuant to section 751(c) of the Tariff Act of 1930 (19 U.S.C. 1675(c)), instituted this review on March 2, 2015 (80 FR 11224) and determined on June 5, 2015 that it would conduct a full review (80 FR 34458, June 16, 2015). Notice of the scheduling of the Commission's review and of a public hearing to be held in connection therewith was given by posting copies of the notice in the Office of the Secretary, U.S. International Trade Commission, Washington, DC, and by publishing the notice in the
The Commission made this determination pursuant to section 751(c) of the Tariff Act of 1930 (19 U.S.C. 1675(c)). It completed and filed its determination in this review on April 4, 2016. The views of the Commission are contained in USITC Publication 4602 (April 2016), entitled
By order of the Commission.
Office on Violence Against Women, Department of Justice.
30-Day Notice.
The Department of Justice (DOJ), Office on Violence Against Women, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection was previously published in the
Comments are encouraged and will be accepted for 30 days until May 9, 2016.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Cathy Poston, Attorney Advisor, Office on Violence Against Women, 145 N Street NE., Washington, DC 20530 (phone: 202-514-5430). Written comments and/or suggestions can also be directed to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention Department of Justice Desk Officer, Washington, DC 20530 or sent to
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
(5)
(6)
On April 1, 2016, the Department of Justice lodged a proposed Consent Decree Second Modification with the United States District Court for the District of New Hampshire in the lawsuit entitled
The Consent Decree Second Modification is a modification to the 2009 Clean Water Act Consent Decree that was entered into by the United States, State of New Hampshire, and the City. This Consent Decree Second Modification, signed by the original parties and intervenor-plaintiff Conservation Law Foundation, revises Portsmouth's schedule for constructing secondary wastewater treatment facilities that had been set forth in a 2013 Consent Decree Modification. The Consent Decree Second Modification also establishes enhanced reporting obligations and mitigation requirements designed to counter the harm to the Piscataqua River and Great Bay estuary caused by delayed implementation of secondary treatment.
The publication of this notice opens a period for public comment on the Consent Decree Second Modification. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the Consent Decree Second Modification may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $4.00 (25 cents per page reproduction cost) payable to the United States Treasury.
September 11th Victim Compensation Fund, Department of Justice.
30-day notice.
The Department of Justice (DOJ), Civil Division, September 11th Victim Compensation Fund, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. This proposed information collection was previously published in the
Comments are encouraged and will be accepted for an additional 30 days until May 9, 2016.
If you have additional comments on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information please call
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
(1)
(2)
(3)
(4)
The information collected from the VCF Claim Form will be used to determine whether claimants will be eligible for compensation from the Fund, and if so, the amount of compensation they will be awarded. The Form consists primarily of two main sections: Eligibility and Compensation.
The Eligibility section seeks the information required by the Zadroga Act to determine whether a claimant is eligible for the Fund, including information related to: Participation in lawsuits related to September 11, 2001; presence at a 9/11 crash site between September 11, 2001 and May 30, 2002; and physical harm suffered as a result of the air crashes and/or debris removal.
The Compensation section seeks the information required by the Zadroga Act to determine the amount of compensation for which the claimant is eligible. Specifically, the section seeks information regarding the out-of-pocket losses (including medical expenses) incurred by the claimant that are attributable to the 9/11 air crashes or debris removal; the claimant's loss of earnings or replacement services that are attributable to the 9/11 air crashes or debris removal; and any collateral source payments (such as insurance payments) that the claimant received as a result of the terrorist-related aircraft crashes of September 11, 2001 or debris removal efforts.
(5)
(6)
If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., 3E.405B, Washington, DC 20530.
Department of Justice.
Notice.
This notice announces the opening of the public comment period on the presentation of the Forensic Science Discipline Review (FSDR) framework.
Written public comment regarding the presentation should be submitted through
The Office of Legal Policy, 950 Pennsylvania Avenue NW., Washington, DC 20530, by phone at 202-514-4601 or via email at
At the 2016 American Academy of Forensic Sciences (AAFS) Meeting, Deputy Attorney General Sally Yates announced that the Department of Justice (DOJ) would undertake a “quality assurance review” of certain forensic disciplines practiced by the Federal Bureau of Investigation (FBI), and that the DOJ would seek input from the National Commission on Forensic Science (NCFS) in developing this review. Jonathan J. Wroblewski, Office of Legal Policy, Principal Deputy Assistant Attorney General, presented the draft framework for the FSDR to the NCFS on March 21, 2016. The proposed FSDR would advance the practice of forensic science by ensuring DOJ forensic examiners have testified as appropriate in legal proceedings. The presentation is available online at
Posting of Public Comments: To ensure proper handling of comments, please reference “Docket No. OLP 156” on all electronic and written correspondence. The Department encourages all comments on this framework be submitted electronically through
In accordance with the Federal Records Act, please note that all comments received are considered part of the public record, and shall be made available for public inspection online at
DOJ will post all comments received on
Office on Violence Against Women, Department of Justice.
30-day notice.
The Department of Justice (DOJ), Office on Violence Against Women, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection was previously published in the
Comments are encouraged and will be accepted for an additional 30 days until May 9, 2016.
If you have comments especially on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact Cathy Poston, Attorney Advisor, Office on Violence Against Women, 145 N Street NE., Washington, DC 20530 (phone: 202-514-5430). Written comments and/or suggestions can also be directed to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attention Department of Justice Desk Officer, Washington, DC 20530 or sent to
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
Overview of this information collection:
(1)
(2)
(3)
(4)
(5)
(6)
If additional information is required contact: Jerri Murray, Department, Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., Room 3E.405B, Washington, DC 20530.
Office of Justice Programs, U.S. Department of Justice
30-Day notice.
The Department of Justice (DOJ), Office of Justice Programs (OJP), will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The proposed information collection was previously published in the
Comments are encouraged and will be accepted for an additional 30 days until May 9, 2016.
If you have additional comments on the estimated public burden or associated response time, suggestions, or need a copy of the proposed information collection instrument with instructions or additional information, please contact: Maria Swineford, (202) 616-0109, Office of Audit, Assessment, and Management, Office of Justice Programs, U.S. Department of Justice, 810 Seventh Street NW., Washington, DC 20531 or
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address one or more of the following four points:
Overview of this information:
(1)
(2)
(3) The Agency Form Number, if any, and the Applicable Component of the Department Sponsoring the Collection:
(4) Affected Public Who Will be Asked or Required to Respond, as well as a Brief Abstract:
(5)
(6)
If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., 3E.405B, Washington, DC 20530.
The Bureau of Labor Statistics Data Users Advisory Committee will meet on Thursday, May 12, 2016. The meeting will be held in the Postal Square Building, 2 Massachusetts Avenue NE., Washington, DC.
The Committee provides advice to the Bureau of Labor Statistics from the points of view of data users from various sectors of the U.S. economy, including the labor, business, research, academic, and government communities, on technical matters related to the collection, analysis, dissemination, and use of the Bureau's statistics, on its published reports, and on the broader aspects of its overall mission and function.
The meeting will be held in Meeting Rooms 1, 2, and 3 of the Janet Norwood Conference and Training Center. The schedule and agenda for the meeting are as follows:
The meeting is open to the public. Any questions concerning the meeting should be directed to Kathy Mele, Data Users Advisory Committee, on 202.691.6102. Individuals who require special accommodations should contact Ms. Mele at least two days prior to the meeting date.
Occupational Safety and Health Administration (OSHA), Department of Labor.
Notice.
With this notice, the Occupational Safety and Health Administration (“OSHA” or “the Agency”) is making a technical amendment to an existing permanent variance, and revoking two others. The technical amendment involves updating the name of one employer granted a variance whose name has changed. The technical amendment and revocations result from an OSHA review to identify variances that are outdated, unnecessary, or otherwise defective.
The effective date of the technical correction and revocation of the permanent variances is April 8, 2016.
OSHA recently reviewed variances currently in effect to identify those that are outdated, unnecessary, or otherwise defective. As part of this review, OSHA contacted by telephone, every employer with an active OSHA variance to determine if they still needed the variance. As a result of this review, OSHA found that one employer identified in a variance had a new name, and two additional employers no longer needed the variances because conditions at their worksite addressed by the variance no longer exist.
With this notice, the Agency is correcting these technical deficiencies and is announcing the following: (1) Revocation of a permanent variance granted to Rollins College in 1974 from 29 CFR 1910.37(i) [39 FR 11481]; (2) revocation of a permanent variance granted to AmerenUE (formerly Union Electric Company) in 1974 from 29 CFR 1910.28(g)(1) [39 FR 37278]; and (3) renaming CBS Outdoor Systems, Inc. (formerly Gannett Outdoor Companies, operating as Outdoor Systems, Inc.) granted a permanent variance in 1991 from 29 CFR 1910.27(d)(l)(ii), (d)(2), and (d)(5) [56 FR 8801] to Outfront Media, LLC.
Rollins College and AmerenUE representatives confirmed by letter that they no longer needed the variances because conditions which prompted them to seek the variances no longer exist; and they now can comply with the standard from which OSHA granted the variances. Company representatives requested that OSHA revoke their respective variances. Additionally, an Outfront Media, LLC management representative requested the corporate name change and provided documentation supporting the request.
Further, OSHA believes that with this notice it will be able to: (1) Accurately and expeditiously determine the employers covered by a variance; (2) enhance enforcement of the variance; (3) ensure that a variance identifies and covers the appropriate worksites; (4) inform employers and employees that the revoked variances no longer cover the employers, and therefore, the employers must comply with the applicable OSHA standards; and (5) inform employees that the applicable OSHA standards replacing the revoked variances will provide them with the necessary protection.
The corporate name change implemented by this notice maintains the employer's regulatory obligations and does not alter the substantive requirements specified in the original variance. The variance continues to remain in effect and to provide employees with the safety and health protection afforded to them by the original variance.
A list of variances that remain in effect by this notice is available on
As previously indicated, with this notice, the Agency is making only a technical correction to an existing variance, and revoking variances that employers no longer need for employee protection. Accordingly, this notice will not have a substantive effect on employers or employees; OSHA, therefore, finds that public notice-and-comment procedures specified under Section 6(d) of the Occupational Safety and Health Act of 1970 (29 U.S.C. 655), and by 29 CFR 1905.11 or 1905.13, are unnecessary.
The following table provides details about the variances addressed by this notice:
OSHA initially granted a permanent variance to the Gannett Outdoor Companies operating as Outdoor Systems, Inc. on March 1, 1991, (56 FR 8801). Subsequently, on December 9, 2008, OSHA granted Gannett Outdoor Companies operating as Outdoor Systems, Inc. a name change to CBS Outdoor Systems, Inc. (73 FR 74754). Further, on November 11, 2015, a management representative of CBS Outdoor Systems, Inc. sent a letter and supporting documentation to OSHA stating that the former company and associated variance names were no longer valid, and requested the Agency to correct the variance using the new successor company's name (Exhibit OSHA-2015-0017-0004).
CBS Outdoor Systems, Inc. notified the Agency (via letter dated November 11, 2014) that the company changed its name from CBS Outdoor, Inc. (formerly Gannett Outdoor Companies, operating as Outdoor Systems, Inc. for whom the initial variance was granted) to the successor company, Outfront Media, LLC. As, was the case with the December 9, 2008 name change (73 FR 74754), Outfront Media, LLC will continue to follow the conditions specified by the variance.
Additionally, CBS Outdoor Systems, Inc. provided supporting documentation including: (1) A series of documents from the State of Delaware (having jurisdiction where the corporation first formed), each acknowledging a sequential name change for the entity beginning in 1997 as Outdoor Systems, Inc. to November of 2014, when Outdoor Systems, Inc. became Outfront Media, LLC (Exhibit OSHA-2015-0017-0004, attachment 1); and (2) an updated listing of locations (places of employment) potentially affected by the Outfront Media, LLC variance (
On March 28, 1974, OSHA granted Rollins College a variance from 29 CFR 1910.37(i), which governed ceiling height for means of egress (39 FR 11481). The Agency renumbered this provision (to 29 CFR 1910.36(g)(1)) in a subsequent rulemaking that revised its means-of-egress standards to improve the clarity and comprehensibility of these standards (67 FR 67962; November 7, 2002). While this rulemaking renumbered 29 CFR 1910.37(i) as 29 CFR 1910.36(g)(1), it did not revise the substantive requirements of the provision. On July 6, 2012, OSHA published a
Subsequently, in a letter dated July 7, 2015, Rollins College, indicated that the college no longer requires or uses the variance. Further, the college's letter indicated that the ceiling height of the buildings where the variance was used in the past has been renovated and the means of egress are now in compliance with the applicable OSHA standards. As a result, the variance is no longer needed or used and should be revoked (Exhibit OSHA-2015-0017-0002).
On October 18, 1974, OSHA granted Union Electric Company a variance from 29 CFR 1910.28(g)(1), which required that two-point suspension scaffolds be a minimum of 20 inches in width (39 FR 37278). On December 9, 2008, the Agency found that Union Electric Company had a new name and operated as AmerenUE. On that same date, the Agency responded to a request from a company officer to correct Union Electric Company's variance by using the company's new name. OSHA published a
Subsequently, in a letter dated September 18, 2015, Ameren Missouri [(formerly Union Electric Company, then AmerenUE) (Exhibit OSHA-2015-0017-0003)], indicated that the company no longer requires or uses the variance and requested OSHA to revoke it.
Based on the information described herein, the Agency is taking the following actions:
A. Revising the name of CBS Outdoor, Inc. (formerly Gannett Outdoor Companies, operating as Outdoor Systems, Inc. for whom the initial variance was granted) to the successor company, Outfront Media, LLC.
B. Revoking the variances granted to Rollins College and AmerenUE (formerly Union Electric Company).
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, U.S. Department of Labor, 200 Constitution Ave. NW., Washington, DC, authorized the preparation of this notice. OSHA is issuing this notice under the authority specified by Section 6(d) of the Occupational Safety and Health Act of 1970 (29 U.S.C. 655), Secretary of Labor's Order No. 1-2012 (76 FR 3912), and 29 CFR part 1905.
Occupational Safety and Health Administration (OSHA), Labor.
Notice.
In this notice, OSHA grants a permanent variance to Nucor Steel Connecticut Incorporated from the provisions of OSHA standards that regulate the control of hazardous energy (lockout/tagout).
The permanent variance specified by this notice, becomes effective on April 8, 2016 and shall remain in effect until it is modified or revoked.
Information regarding this notice is available from the following sources:
Electronic copies of this
On September 22, 2014, Nucor Steel Connecticut Incorporated (hereafter, “NSCI” or “the applicant”) 35 Toelles Road, Wallingford, CT 06492, submitted under Section 6(d) of the Occupational Safety and Health Act of 1970 (“OSH Act”; 29 U.S.C. 655) and 29 CFR 1905.11 (“Variances and other relief under section 6(d)”) an application for a permanent variance from several provisions of the OSHA standard that regulates the control of hazardous energy (“lockout/tagout” or “LOTO”), as well as a request for an interim order pending OSHA's decision on the application for variance (Ex. OSHA-2014-0022-0003) at its Wallingford, CT facility. Specifically, NSCI was seeking a variance from the provisions of the standard that require: (1) Lockout or tagout devices be affixed to each energy isolating device by authorized employees (29 CFR 1910.147(d)(4)(i)); and (2) lockout devices, where used, be affixed in a manner that holds the energy isolating devices in a “safe” or “off” position (29 CFR 1910.147(d)(4)(ii)). Also, NSCI requested an interim order pending OSHA's decision on the application for variance.
According to its application, NSCI manufactures steel wire rod and coiled rebar from billets of steel by using rolling and forming processes. Further, NSCI's description of its operation indicated that the hot steel billets are shaped and formed into steel wire rod and coiled rebar by running them through a series of rolls. The rolls shape and form the steel as it moves from one stand to the next. Each roll has several passes (or grooves), only one of which is used at a time. The pass is designed to shape the bar to a certain size as it goes through the mill by compressing, squeezing, and stretching the bar. Rolls are designed with passes to bring a bar down through roughing, intermediate and finish mills to a finished size.
As with any shaping tool, the passes wear during use and from time to time need to be changed. As the pass wears, the shape of the bar and the appearance of the bar are affected. When new rolls are brought into production, every pass is prepared with a spray that provides friction which allows the rolls to bite the bar between the rolls. Once rolls are in operation, roll grinding is regularly required, because during the operation of the mill stands water is used to cool the rolls to prevent fracturing and damage to the rolls. The water protects the pass while in use, but it also creates rust in the other passes. The rust can affect the final quality of the bar being processed, so steps are taken to remove the rust prior to restarting the operations. Rust is removed from the passes using a common 4-inch hand grinder. Since January 2012, the rolls have been ground with the rolls stopped and locked out.
NSCI asserted that grinding the rolls requires access to the Motor Control Room (MCR), in order to operate the energy isolation disconnects for the roll mills. Employees who perform the particular task of grinding the passes are exposed to potentially serious arc flash hazards if they accessed the MCR in order to perform energy isolation functions. To control exposure to the arc flash hazards, NSCI instituted safe work rules that: (1) Designate the MCR as a restricted entry work area; (2) restrict MCR access to qualified electricians only; and (3) prohibit employees who perform pass grinding from entering the MCR because they are not qualified electrical employees trained in recognition and mitigation of electrical hazards. Further, NSCI asserted that as a consequence of following these safe work rules the employees performing pass grinding cannot lockout the energy isolation disconnects located in the MCR or personally verify that a lockout has been performed.
OSHA initiated a technical review of NSCI's variance application and developed a set of follow-up questions regarding the assertions of equivalent worker protection included in the application. On November 26, 2014, OSHA sent NSCI a letter containing a set of follow-up questions (Ex. OSHA-2014-0022-0006). On December 19, 2014, NSCI provided its responses to the follow-up questions (Ex. OSHA-2014-0022-0007). Based on these responses to the follow-up questions and the alternate safety measures proposed in NSCI's application, on May 22, 2015, the Agency sent NSCI a letter (Ex. OSHA-2014-0022-0009) describing its findings on the technical merits of the application. OSHA's letter also included a set of proposed conditions for the grant of an interim order and permanent variance and a request for NSCI's comments on these proposed conditions. On July 10, 2015, NSCI provided its response (Ex. OSHA-2014-0022-0010) indicating acceptance of the proposed conditions and including a few recommended changes. OSHA carefully reviewed NSCI's recommended changes and incorporated the majority of the changes into the conditions of the variance.
Following this review, OSHA determined that the applicant proposed an alternative that provides a workplace as safe and healthful as that provided by the standard. On December 2, 2015, OSHA published a preliminary
The comment period closed on January 4, 2016, and OSHA received one comment (Ex. OSHA-2014-0022-0012) from the Association for Packaging and Processing Technologies in support of granting NSCI the variance.
NSCI's variance application and the responses to OSHA's follow-up questions included the following: Detailed descriptions of the manufacturing process; the equipment used; the proposed alternative to lockout/tagout (LOTO) devices and procedures implemented during servicing and maintenance of specific equipment (
According to the information included in its application, performing lockout on the roll mill stands requires access to the MCR, an area restricted to qualified electricians. Because NSCI employees who perform the particular task of grinding the passes are not qualified electrical employees trained in recognition and mitigation of electrical hazards, they may not access the MCR. Therefore, they cannot use the EID in that location to isolate the hazardous electrical energy or personally verify that energy isolation has been achieved if the EID is operated by a qualified employee.
To address these issues, NSCI developed an alternative method of preventing the unexpected startup or energization of the roll mill passes located in the roll mill stands. NSCI proposes to use a comprehensive engineered system and appropriate administrative procedures to meet the energy isolation requirements. The engineered system uses a “trapped key” concept and monitored safety-rated power relays in combination with administrative procedures. The trapped key system is designed to: Replace a locked out energy isolating device; and function similarly (to a lockout device), in that only the employee in possession of the key can restart the machine undergoing maintenance. The single key is controlled through administrative group lockout procedures that NSCI believes match the requirements of 29 CFR 1910.147.
Further, NSCI asserted that its proposed trapped key energy control system has been evaluated
The applicant contended that the alternative safety measures included in its application provide its workers with a place of employment that is at least as safe and healthful as they would obtain under the existing provisions of OSHA's control of hazardous energy (lockout/tagout) standard. The applicant certified that it provided employee representatives with a copy of the variance application. The applicant also certified that it notified its workers of the variance application by posting, at prominent locations where it normally posts workplace notices, a summary of the application and information specifying where the workers can examine a copy of the application. In addition, the applicant informed its workers of their rights to petition the Assistant Secretary of Labor for Occupational Safety and Health for a hearing on the variance application.
As an alternative means of compliance to the requirements of 1910.147(d)(4(i) and (ii), NSCI proposed to use a comprehensive engineered system and appropriate administrative procedures to meet these requirements. The engineered system uses a “trapped key” concept and monitored safety-rated power relays in combination with administrative procedures. The trapped key system is designed to: Replace a locked out energy isolating device; and function similarly (to a lockout device), in that only the employee in possession of the key can restart the machine undergoing maintenance. The single key is controlled through administrative group lockout procedures identical to those required by 29 CFR 1910.147. Although the trapped key prevents normal intended startup of the equipment being serviced, it is not being used on an EID, as required by OSHA's standards. To meet this requirement, NSCI proposed to use a monitored safety-relay system that uses approved components, redundant systems, and control-reliable circuitry. Use of the trapped key system in combination with detailed administrative energy control policies and procedures, as well as providing effective training allows NSCI's authorized and affected employees to complete the required grinding of its stationary rolls in a manner that provides equivalency in energy isolation to compliance with the applicable provisions of the LOTO standard. The trapped key system is based on use of an Allen Bradley
The applicant maintains that use of the trapped key system provides equivalent safety with what can be achieved by strict compliance with the 1910.147(d)(4)(i) and (ii) requirements. According to NSCI's variance application, equivalent safety is achieved by prohibiting roll movement during de-energization while grinding is being performed, as well as prohibiting mistaken intentional re-energization and re-energization due to fault conditions, without exposing employees to hazards within the MCR. To protect against system faults causing re-energization, the trapped key system meets the requirements for control reliability as stated in ANSI B11.19 (2010)
Further, the applicant asserted that the trapped key system uses well tried components, which is a key factor in the reliability of a control system. The system is based on an Allen Bradley
OSHA conducted a review of NSCI's application and the supporting technical documentation. After completing the review of the application
1. Modified the electrical controls at the pulpit (central control station located on the roll mill floor for the 15 roll mill stands), to prevent employee exposure to hazards associated with movement of the roll mill while performing the task of grinding roll mill passes located in the roll mill stands;
2. Installed a trapped key control system and implemented administrative energy control procedures that prevent employee exposure to hazards associated with energy while grinding on the roll mill passes;
3. Utilizing qualified engineering safety experts, performed a job hazard analysis for roll grinding associated tasks, conducted and documented an electrical isolation analysis, system and functional safety reviews, and control reliability analysis to verify that the use of the trapped key system and administrative energy control procedures prevent the movement of roll mill passes; prevent mistaken or intentional re-energization; and maintain immobility in the event of fault conditions;
4. Developed a two-tiered system of securing the trapped key as follows:
a. Stopping the operation and energization of the roll mill passes by removing the trapped key from the system, and securing the key within a lock box inside the pulpit area (central control station located on the roll mill floor for the 15 roll mill stands); and
b. Locking the key to the lock box in the pulpit area inside a secondary group lock box installed on the roll mill floor, with each employee performing roll mill grinding applying their personal lock to the lock box;
5. Developed detailed administrative energy control procedures for use of the trapped key system;
6. Implemented detailed administrative energy control procedures designed to ensure that each authorized employee applies a personal lock to the secondary group lock box;
7. Procured and provided appropriate equipment and supplies;
8. Made the administrative energy control policies and procedures available in English and Spanish;
9. Trained authorized and affected employees on the application of the trapped key system and associated administrative energy control policies and procedures;
10. Ensured that grinding on the passes is conducted only while using the administrative energy control procedures based on the trapped key system;
11. Installed guarding on the entry/infeed and exit/outfeed sides of each roll mill stand to prevent employees from standing between turning mills and being exposed to the crushing hazards of in-running nip points;
12. Developed additional administrative controls and procedures to minimize the potential for authorized and affected employees to enter between the mill stands when harm could occur; and
13. Designated and posted the areas as “No Entry” unless the procedures (1-12 above) are followed.
As previously indicated in this notice, OSHA conducted a review of NSCI's application and the supporting technical documentation. After completing the review of the application and supporting documentation, OSHA determined that NSCI developed, and proposed to implement, effective alternative means of protection that protect its employees as effectively as paragraphs 1910.147(d)(4)(i) and (ii) of OSHA's LOTO standard during the servicing and maintenance task of grinding roll mill passes located in the roll mill stands. Therefore, on December 2, 2015, OSHA published a preliminary
During the period starting with the December 2, 2015, publication of the preliminary
This section describes the conditions that comprise the alternative means of compliance with 29 CFR 1910.147(d)(4)(i) and (d)(4)(ii). Also, these conditions provide additional detail regarding the conditions that form the basis of the permanent variance OSHA is granting to NSCI.
The scope of the permanent variance limits coverage of the conditions of the permanent variance to the work situations specified under this condition. Clearly defining the scope of the permanent variance provides NSCI, NSCI's employees, other stakeholders, the public, and OSHA with necessary information regarding the work situations in which the permanent variance applies and does not apply. For example, condition A limits coverage of the permanent variance only to the task of grinding roll mill passes located in the roll mill stands. The condition clarifies that no other maintenance work, including electrical maintenance, can be performed on the roll mill passes, the roll mill motors, other residual or stored energy sources, or electric circuits connected to the trapped key system or roll mill stands using the trapped key system to control hazardous energy.
According to 29 CFR 1905.11, an employer or class or group of employers
Condition B defines a series of terms, mostly technical terms, used in the permanent variance to standardize and clarify their meaning. Defining these terms serves to enhance the applicant's and its employees' understanding of the conditions specified by the permanent variance.
Condition C requires the applicant to: (1) Modify certain controls at the pulpit by installing and operating a trapped key system designed to replace an energy isolating device; (2) develop and implement certain trapped key system-related alternate energy control policies and procedures; and (3) develop and implement a series of trapped key
Condition D requires the applicant to develop and implement a detailed procedure for de-energizing the roll mill passes located in the roll mill stands in order to perform the grinding task. The procedure for de-energizing the roll mill passes includes a series of steps to ensure that all authorized and effected employees are notified that: The roll mill passes are effectively de-energized; the task of grinding the roll mill passes is ready to begin; and no other servicing or maintenance is to be performed on the roll mill stands while grinding is taking place.
Condition E requires the applicant to develop and implement a detailed procedure for re-energizing and intentionally starting motion in the roll mill passes located in the roll mill stands in order to resume normal operations at the conclusion of the grinding task. The procedure for re-energizing the roll mill passes includes a series of steps to ensure that all authorized and effected employees are notified that the task of grinding the roll mill passes is complete and that the roll mill passes are ready for use.
Condition F requires the applicant to develop and implement an effective hazardous energy control qualification and training program for authorized employees involved in using the trapped key system while grinding roll mill passes. The condition specifies the factors that an employee must know following completion of the training program. Elements to be included in the training program encompass, among others: The program to be presented in language that the employees can understand; the instruction be reviewed periodically to accommodate changes in the energy control program; the contents and conditions included in the variance; the preparation of a job hazard analysis (JHA) describing the application of the trapped key system, the identification of associated hazards and safe use of the associated energy control procedures; and instruction regarding the safe use of the associated energy control procedures. Additionally, condition F also requires the applicant to train each affected employee in the purpose and use of the alternative energy control procedures using the trapped key system.
Condition G requires the applicant to develop, implement and operate an effective program for completing inspections, tests, program evaluations, and accident prevention measures for the use of the trapped key system and safe application of the hazardous energy control procedures in the roll mill stands and associated work areas. This condition serves to ensure the safe operation and physical integrity of the equipment and work area. Use of the trapped key system while conducting roll mill grinding operations enhances worker safety by reducing the risk of unexpected energization of the equipment.
This condition also requires the applicant to document tests, inspections, corrective actions and repairs involving the use of the trapped key system, and maintain these documents. Further, this requirement provides the applicant with information needed to schedule tests and inspections to ensure the continued safe operation of the equipment and systems, and to determine that the actions taken to correct defects are appropriate.
Condition H requires the applicant to maintain records of specific factors associated with use of the trapped key system implemented to prevent the unexpected energization of the equipment while grinding roll mill passes. The information gathered and recorded under this provision, in concert with the information provided under condition I (Notifications, for using the OSHA 301 Incident Report form to investigate and record energy isolation failure-related injuries as defined by 29 CFR 1904.4, 1904.7, 1904.8 through 1904.12), enables the applicant and OSHA to determine the effectiveness of the permanent variance in preventing recordable injuries.
Condition I requires the applicant, within specified periods to: (1) Notify OSHA (
This condition for completing and submitting the variance conditions-related (recordable) preliminary incident investigation report (OSHA 301 form) is more restrictive than the current recordkeeping requirement of completing the OSHA 301 form within 7 calendar days of the incident (1904.29(b)(3)). Submittal of the preliminary incident investigation report is to be followed by submittal of the full incident investigation report within 7 calendar days. This modified and more stringent incident investigation and reporting requirement is restricted to variance conditions-related (recordable) incidents only. Providing this notification is essential because time is a critical element in OSHA's ability to determine the continued effectiveness of the variance conditions in preventing recordable incidents as well as the employer's identification of appropriate hazard control measures and implementation of corrective and preventive actions. Further, these notification requirements enable the applicant, its employees, and OSHA to determine the effectiveness of the permanent variance in providing the requisite level of safety to the employer's workers and, based on this determination, whether to revise or revoke the conditions of the permanent variance. Timely notification permits OSHA to take whatever action is necessary and appropriate to prevent further variance conditions-related recordable injuries and illnesses. Providing notification to employees informs them of the precautions taken by the employer to prevent similar incidents in the future. Additionally, these notification requirements allow OSHA to: Communicate effectively, expedite administration, and enforce the conditions of the permanent variance.
Additionally, this condition requires the applicant to notify OSHA if it ceases to do business, has a new address or location for its main office, or transfers the operations covered by the permanent variance to a successor company. In addition, the condition specifies that OSHA must approve the transfer of the permanent variance to a successor company. These requirements allow OSHA to communicate effectively with the applicant regarding the status of the permanent variance, and expedite the Agency's administration and enforcement. Stipulating that an applicant is required to have OSHA's approval to transfer a variance to a successor company provides assurance that the successor company has knowledge of, and will comply with, the conditions specified by the permanent variance. Also, seeking OSHA's approval to transfer a variance to a successor company serves to further ensure the safety of workers involved in performing the operations covered by the variance.
As described earlier in this notice, after reviewing the proposed alternatives OSHA determined that NSCI developed, and proposed to implement, effective alternative means of protection that protect its employees as effectively as paragraphs 1910.147(d)(4)(i) and (ii) of OSHA's LOTO standard during the servicing and maintenance task of grinding roll mill passes located in the roll mill stands. Further, under section 6(d) of the Occupational safety and Health Act of 1970 (29 U.S.C. 655(d)), and based on the record discussed above, the Agency finds that when the employer complies with the conditions of the variance, the working conditions of the employers' workers are at least as safe and healthful as if the employers complied with the working conditions specified by paragraph 1910.147(d)(4)(i) and (ii) of OSHA's LOTO standard. Therefore, under the terms of this variance NSCI must: (1) Comply with the conditions listed below under section V of this notice (“Order”) for the period between the date of this notice and until the Agency modifies or revokes this final order in accordance with 29 CFR 1905.13; (2) comply fully with all other applicable provisions of 29 CFR part 1910; and (3) provide a copy of this
As of the effective date of this final order, OSHA is revoking the interim order granted to the employer on December 2, 2015 (80 FR 75472).
OSHA issues this final order authorizing Nucor Steel Connecticut Incorporated (“NSCI” or “the applicant”) to comply with the following conditions instead of complying with the requirements of paragraphs 29 CFR 1910.147(d)(4)(i) and (ii) of OSHA's LOTO standard during the servicing and maintenance task of grinding roll mill passes located in the roll mill stands. This final order applies to all NSCI employees located at the 35 Toelles Road, Wallingford, CT 06492 establishment during the servicing and maintenance task of grinding roll mill passes located in the roll mill stands. These conditions are:
1. This permanent variance applies only to the task of grinding roll mill passes located in the roll mill stands of NSCI's Wallingford, CT establishment. This work is to be performed by authorized employees under alternative energy control procedures using a trapped key system and lock boxes.
2. No other maintenance work, including electrical maintenance (such as troubleshooting or maintenance covered under 29 CFR 1910.333), may be performed on the roll mill passes, the roll mill motors, or electric circuits connected to the trapped key system or roll mill stands using the trapped key system to control hazardous energy.
3. If any other maintenance or servicing work is performed, even if that work is performed at the same time as grinding roll mill passes, all of the maintenance work at that time must be performed under full lockout as required by 29 CFR 1910.147.
4. Except for the requirements specified by 29 CFR 1910.147(d)(4)(i) and (ii), NSCI must comply fully with all other applicable provisions of 29 CFR 1910.147 during servicing and maintenance of roll mills during the task of grinding roll mill passes.
5. The interim order granted to the employer on December 2, 2015 (80 FR 75472) is hereby revoked.
The following definitions apply to this permanent variance:
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1. NSCI shall modify the electrical controls at the pulpit (central control station located on the roll mill floor for the 15 roll mill stands), to prevent employee exposure to hazards associated with movement of the roll mill during the task of grinding roll mill passes;
2. NSCI shall install a trapped key system;
3. NSCI shall install a pulpit designated lock box for the trapped key in the pulpit area;
4. NSCI shall install a secondary group lock box in the roll mills floor area for securing the pulpit designated lock box key;
5. NSCI shall develop administrative energy control procedures for use of the trapped key system as described below;
6. NSCI shall implement detailed energy control procedures designed to ensure that each authorized employee applies a personal lock to the secondary group lock box, and has the ability to personally verify de-energization of the system, as described below;
7. NSCI shall make the energy control policies and procedures available to authorized and affected employees in English and Spanish;
8. NSCI shall ensure that grinding on the passes is conducted only while using the administrative energy control procedures based on the trapped key system, or using full lockout procedures that comply with 29 CFR 1910.147 when the roll stands must be de-energized so that other maintenance operations can be performed simultaneously with roll grinding;
9. NSCI shall install guarding on the entry/infeed and exit/outfeed sides of each roll mill stand to prevent employees from standing between turning mills and being exposed to the crushing hazards of in-running nip points;
10. NSCI shall develop additional administrative controls and procedures to minimize the potential for authorized and affected employees to enter between the mill stands when harm could occur; and
11. NSCI shall designate and post the areas as “No Entry” unless the procedures (1-10) are followed.
12. NSCI shall ensure that the trapped key system and its components are properly installed, inspected, maintained, and used so that it works as designed. NSCI shall strictly follow, where applicable, manufacturers'
13. NSCI shall ensure that the trapped key system is only altered or modified for uses specified and approved by a qualified person by following good engineering practices. Where available, such alterations and modifications shall strictly follow the manufacturers' specifications, instructions, and written authorization. No changes or modifications may be made to the trapped key system or its components that diminish the protection provided to affected employees.
14. NSCI shall ensure that alteration or modification of the trapped key system is fully justified and documented when the manufacturers' specifications, instructions, and written authorization are lacking.
15. NCSI shall implement a procedure to ensure that no other maintenance will be performed on the roll mill stands while grinding is taking place, unless full lockout is used for all maintenance tasks being performed at that time.
NSCI shall develop and implement a detailed procedure for de-energizing the roll mill passes located in the roll mill stands in order to perform the grinding task. The procedure for de-energizing the roll mill passes shall include the following steps:
1. The authorized employee de-energizing the roll mill passes shall notify all affected employees that the equipment will be shut down and locked out to perform grinding of the passes;
2. The pulpit operator shall turn off the control leveler on the control panel;
3. The pulpit operator shall activate the E-stop;
4. The pulpit operator verifies that the red “system functional” indicator is illuminated, then turns the trapped lockout key 90º to OFF position, and removes the trapped key from the panel. The operator verifies that the green “safe to work indicator” illuminates, and that the red “system functional” indicator goes out;
5. The pulpit operator:
a. Places the trapped key in the pulpit designated lock box and applies his or her personal lock to the pulpit designated lock box; and
b. Applies the equipment lock box lock designated for this energy control procedure;
6. The pulpit operator hands the equipment lock box lock key to the roll mill operator and/or lead;
7. The roll mill operator and/or lead takes the equipment lock box lock key to the secondary group lock box;
8. The roll mill operator and/or lead places the equipment lock box lock key in the secondary group lock box and attaches his or her personal lock;
9. Authorized employees (team members) place their personal locks on the secondary group lock box;
10. The roll mill operator and/or lead verifies that the equipment is de-energized and locked out by trying to operate the equipment (using the start button);
11. The roll mill operator and/or lead ensures that there are no additional sources of energy that could lead to the unexpected energization of the roll mill passes;
12. Authorized employees who placed their personal trapped key system locks on the secondary group lockout box shall also confirm that the equipment is fully de-energized;
13. Authorized employees who placed their personal locks on the secondary group lock box shall maintain their personal key in their possession while performing grinding of the roll mill passes; and
14. Authorized employees shall perform the task of grinding the passes only while these procedures are used.
NSCI shall develop and implement a detailed procedure for re-energizing and intentionally starting motion in the roll mill passes located in the roll mill stands in order to resume normal operations at the conclusion of the grinding task. The procedure for re-energizing the roll mill passes shall include the following steps:
1. The roll mill operator and/or lead shall check the equipment and the immediate area around the equipment to ensure that necessary items have been removed and that the equipment components are operationally intact;
2. The roll mill operator and/or lead shall check the work area to ensure that all affected employees have been safely positioned or removed from the area;
3. The roll mill operator and/or lead shall check that all controls are in the neutral or off position;
4. Authorized employees shall remove their personal trapped key system locks from the secondary group lock box;
5. The roll mill operator and/or lead shall remove the equipment lock box lock key from the secondary group lock box and take it to the pulpit;
6. The roll mill operator and/or lead shall hand the equipment lock box lock key to the pulpit operator;
7. The pulpit operator shall verify that all personnel are clear of the equipment before starting to re-energize the roll mill passes;
8. The pulpit operator shall remove his or her trapped key system personal lock from the pulpit designated lock box;
9. Using the equipment lock box lock key, the pulpit operator shall remove the equipment lock box lock;
10. The pulpit operator shall remove the trapped key from the pulpit designated lock box and shall insert the key into the rotary switch and turn it 90° to the ON position;
11. The pulpit operator shall press the reset button to re-energize the roll mill passes;
12. The pulpit operator shall confirm that the green light clears and the red light activates indicating that the system is powered and that the trapped key system no longer prevents roll mill motion; and
13. The pulpit operator shall notify affected employees that the task of grinding the roll mill passes is complete and that the roll mill passes are ready for use.
NSCI shall develop and implement a detailed worker qualifications and training program. NSCI must:
1. Develop an energy control training program and train each authorized employee, pulpit operator, roll mill designated person, and their supervisors on the trapped key system, and the procedures each must perform under it. The training program shall be provided in a language that the employees can understand;
2. Develop a training program and train each affected employee in the purpose and use of the alternative energy control procedures using the trapped key system before commencing operations under this variance, and document this instruction. The training program shall be provided in a language that the employees can understand;
3. Repeat the instruction specified in paragraph (1) of this condition periodically and as necessary (
4. Ensure that each authorized and affected employee, designated pulpit operator, roll mill designated person, and each of their supervisors have effective and documented training in the contents and conditions covered by this proposed variance;
5. Ensure that only trained and authorized employees, designated pulpit operators, and roll mill designated persons, perform energy control procedures for the task of grinding roll mill passes;
6. Prepare a JHA for the safe application of energy control procedures; and
7. Review periodically and as necessary (
NSCI shall develop and implement a detailed program for completing inspections, tests, program evaluations and incident prevention. NSCI must:
1. Initiate and maintain a program of frequent and regular inspections of the trapped key system and associated work areas by:
a. Ensuring that a competent person (authorized employee) conducts daily visual checks and quarterly inspections and functionality tests of the trapped key system components and configuration or operation and energy control procedures that affect the grinding of roll mill passes located in the roll mill stands to ensure that the procedure and the conditions of this variance are being followed;
b. Ensuring that a competent person conducts weekly inspections of the work areas associated with the grinding of roll mill passes located in the roll mill stands; and
c. Developing a set of checklists to be used by a competent person in conducting the weekly inspections of the work areas associated with the grinding of roll mill passes located in the roll mill stands and the quarterly inspections and functionality tests of the trapped key system components and configuration or operation and energy control procedures that affect the grinding of roll mill passes.
2. Remove the equipment from service if the competent person determines that the equipment constitutes a safety hazard. NSCI must not return the equipment to service until the hazardous condition is corrected and the correction has been approved by a qualified person.
3. All maintenance, servicing, and installation of replacement parts must be performed in strict accordance with good engineering practices. Where available, the maintenance, servicing and installation of replacement parts must strictly follow the manufacturers' specifications, instructions, and limitations.
1. NSCI must maintain a record of any recordable injury, illness, in-patient hospitalizations, amputations, loss of an eye or fatality (using the OSHA 301 Incident Report form to investigate and record energy control-related recordable injuries as defined by 29 CFR 1904.4, 1904.7, 1904.8 through 1904.12
2. NSCI must maintain records of all tests and inspections of the component configuration or operation, and energy control procedures, as well as associated hazardous condition corrective actions and repairs.
To assist OSHA in administering the conditions specified herein, NSCI shall:
1. Notify the OTPCA and the Bridgeport, CT, Area Office of any recordable injuries, illnesses, in-patient hospitalizations, amputations, loss of an eye or fatality (by submitting the completed OSHA 301 Incident Report form) resulting from implementing the alternative energy control procedures of the proposed variance conditions while completing the task of grinding roll mill passes located in the roll mill stands. The notification must be made within 8 hours of the incident or 8 hours after becoming aware of a recordable injury, illness, in-patient hospitalizations, amputations, loss of an eye, or fatality.
2. Submit a copy of the preliminary incident investigation (OSHA form 301) to the OTPCA and the Bridgeport, CT, Area Office within 24 hours of the incident or 24 hours after becoming aware of a recordable case and submit a copy of the full incident investigation within 7 calendar days of the incident or 7 calendar days after becoming aware of the case. In addition to the information required by the OSHA form 301, the incident-investigation report must include a root-cause determination, and the preventive and corrective actions identified and implemented.
3. Provide certification within 15 working days of the incident that NSCI informed affected workers of the incident and the results of the incident investigation (including the root-cause determination and preventive and corrective actions identified and implemented).
4. Notify the OTPCA and the Bridgeport, CT, Area Office in writing and 15 working days prior to any proposed change in the energy control operations (including changes addressed by condition C-13) that affects NSCI's ability to comply with the conditions specified herein.
5. Obtain OSHA's approval prior to implementing the proposed change in the energy control operations that affects NSCI's ability to comply with the conditions specified herein.
6. Provide a written evaluation report, by January 31st at the beginning of each calendar year, with a report covering the year just ended, to the OTPCA and the Bridgeport, CT, Area Office summarizing the quarterly inspections and functionality tests of the trapped key system components and configuration or operation and energy control procedures that affect the grinding of roll mill passes located in the roll mill stands, to ensure that the energy control procedure and the conditions of this variance are being followed.
The evaluation report is to contain summaries of: (1) The number of variance-related incidents (as recorded on OSHA 301 forms); and (2) root causes of any incidents, and preventive and corrective actions identified and implemented.
7. Inform the OTPCA and the Bridgeport, CT, Area Office as soon as possible after it has knowledge that it will:
a. Cease to do business;
b. change the location and address of the main office for managing the
alternative energy control procedures specified herein; or
c. transfer the operations specified herein to a successor company.
8. Notify all affected employees of this permanent variance by the same means required to inform them of its application for a variance.
9. Request approval from OSHA for the transfer of the permanent variance to a successor company.
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, 200 Constitution Avenue NW., Washington, DC 20210, authorized the preparation of this notice. Accordingly, the Agency is issuing this notice pursuant to Section 29 U.S.C. 655(6)(d), Secretary of Labor's Order No. 1-2012 (77 FR 3912, Jan. 25, 2012), and 29 CFR 1905.11.
National Science Foundation.
Notice and request for comments.
The National Science Foundation (NSF) is announcing plans to request renewal of this collection. In accordance with the requirement of section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995 (Pub. L. 104-13), we are providing opportunity for public comment on this action. After obtaining and considering public comment, NSF will prepare the submission requesting that OMB approve clearance of this collection for three years.
Written comments on this notice must be received by June 7, 2016 to be assured of consideration. Comments received after that date will be considered to the extent practicable.
“(1) collect, acquire, analyze, report, and disseminate statistical data related to the science and engineering enterprise in the U.S. and other nations that is relevant and useful to practitioners, researchers, policymakers, and the public, including statistical data on
(A) research and development trends;
(B) the science and engineering workforce;
(C) U.S. competitiveness in science, engineering, technology, and research and development . . .”
Data are published in NSF's annual publication series
The average burden estimate is 54 hours for the approximately 650 institutions reporting over $1 million in R&D expenditures, 8 hours for the approximately 280 institutions reporting less than $1 million, and 11 hours for the 42 organizations completing the FFRDC survey. The total calculated burden across all forms is 37,802 hours.
Nuclear Regulatory Commission.
Exemption and combined license amendment; issuance.
The U.S. Nuclear Regulatory Commission (NRC) is granting an
Please refer to Docket ID NRC-2008-0441 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
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•
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Paul Kallan, Office of New Reactors, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-2809; email:
The NRC is granting an exemption from paragraph B of Section III, “Scope and Contents,” of appendix D, “Design Certification Rule for the AP1000,” to part 52 of title 10 of the
Part of the justification for granting the exemption was provided by the review of the amendment. Because the exemption is necessary in order to issue the requested license amendment, the NRC granted the exemption and issued the amendment concurrently, rather than in sequence. This included issuing a combined safety evaluation containing the NRC staff's review of both the exemption request and the license amendment. The exemption met all applicable regulatory criteria set forth in 10 CFR 50.12, 10 CFR 52.7, and Section VIII.A.4 of appendix D to 10 CFR part 52. The license amendment was found to be acceptable as well. The combined safety evaluation is available in ADAMS under Accession No. ML15135A211.
Identical exemption documents (except for referenced unit numbers and license numbers) were issued to the licensee for VCSNS Units 2 and 3 (COLs NPF-93 and NPF-94). The exemption documents for VCSNS Units 2 and 3 can be found in ADAMS under Accession Nos. ML15135A160 and ML15135A170, respectively. The exemption is reproduced (with the exception of abbreviated titles and additional citations) in Section II of this document. The amendment documents for COLs NPF-93 and NPF-94 are available in ADAMS under Accession Nos. ML15135A145 and ML15135A156, respectively. A summary of the amendment documents is provided in Section III of this document.
Reproduced below is the exemption document issued to Summer Units 2 and Unit 3. It makes reference to the combined safety evaluation that provides the reasoning for the findings made by the NRC (and listed under Item 1) in order to grant the exemption:
1. In a letter dated October 30, 2014, the licensee requested from the Commission an exemption from the provisions of 10 CFR part 52, appendix D, Section III.B, as part of license amendment request 13-27, “Control Rod Mechanism Motor Generator Set Field Relay Change (LAR-13-27).”
For the reasons set forth in Section 3.1, “Evaluation of Exemption,” of the NRC staff's Safety Evaluation, which can be found in ADAMS under Accession No. ML15135A211, the Commission finds that:
A. The exemption is authorized by law;
B. the exemption presents no undue risk to public health and safety;
C. the exemption is consistent with the common defense and security;
D. special circumstances are present in that the application of the rule in this circumstance is not necessary to serve the underlying purpose of the rule;
E. the special circumstances outweigh any decrease in safety that may result from the reduction in standardization caused by the exemption; and
F. the exemption will not result in a significant decrease in the level of safety otherwise provided by the design.
2. Accordingly, the licensee is granted an exemption from the certified DCD Tier 1, COL appendix C, Table 2.5.1-4, and Table 3.7-1, as described in the licensee's request dated October 30, 2014. This exemption is related to, and necessary for the granting of License Amendment No. 27, which is being issued concurrently with this exemption.
3. As explained in Section 5.0, “Environmental Consideration,” of the NRC staff's Safety Evaluation (ADAMS Accession No. ML15135A211), this exemption meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment needs to be prepared in connection with the issuance of the exemption.
4. This exemption is effective as of June 10, 2015.
By letter dated October 30, 2014, the licensee requested that the NRC amend the COLs for VCSNS, Units 2 and 3, COLs NPF-93 and NPF-94. The proposed amendment is described in Section I of this document.
The Commission has determined for these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
A notice of consideration of issuance of amendment to facility operating license or combined license, as applicable, proposed no significant hazards consideration determination, and opportunity for a hearing in connection with these actions, was published in the
The Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments.
Using the reasons set forth in the combined safety evaluation, the staff granted the exemption and issued the amendment that the licensee requested on October 30, 2014. The exemption and amendment were issued on June 10, 2015 as part of a combined package to the licensee (ADAMS Accession No. ML15135A140).
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Exemption; issuance.
Southern Nuclear Operating Company, Inc. (SNC); Georgia Power Company, Oglethorpe Power Corporation, MEAG Power SPVM, LLC., MEAG Power SPVJ, LLC., MEAG Power SPVP, LLC., and the City of Dalton, Georgia (together, the “VEGP Owners”) are the holders of Combined License (COL) Nos. NPF-91 and NPF-92, which authorize the construction and operation of Vogtle Electric Generating Plant, Units 3 and 4 (VEGP 3 & 4), respectively.
This exemption is effective as of April 8, 2016.
Please refer to Docket ID NRC-2008-0252 when contacting the NRC about the availability of information regarding this document. You may obtain publicly available information related to this document using any of the following methods:
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•
•
Paul Kallan, Office of New Reactors, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-2809; email:
Vogtle Electric Generating Plant, Units 3 and 4 (VEGP 3 & 4) are Westinghouse AP1000 pressurized-water reactors under construction in Burke County, Georgia. They are co-located with Vogtle Electric Generating Plant, Units 1 and 2, which are two operating Westinghouse four-loop pressurized-water reactors.
The simulation facility for VEGP 3 & 4 comprises two AP1000 full scope simulators, which are designated “3A” and “3B.” Both simulators are referenced to Vogtle Unit 3 and are intended to be maintained functionally identical. The simulators are licensed to conform to the requirements of ANSI/ANS-3.5-1998, “Nuclear Power Plant Simulation Facilities for Use in Operator Training and License Examination” (ANS 3.5), as endorsed by Revision 3 of NRC Regulatory Guide 1.149, “Nuclear Power Plant Simulation Facilities for Use in Operator Training and License Examinations.”
On March 29, 2016, the Commission approved the simulation facility under § 55.46(b) of title 10 of the
Section 55.31(a)(5) states that to apply for an operator or senior operator license the applicant shall provide evidence that the applicant, as a trainee, has successfully manipulated the controls of either the facility for which a license is sought or a PRS that meets the requirements of 10 CFR 55.46(c). However, the VEGP 3 & 4 simulators have not yet been found to meet the NRC's requirements for plant-referenced simulators at 10 CFR 55.46(c) because the design activities required by the AP1000 design certification to establish the human factors engineering design for the main control room are incomplete.
Southern Nuclear Operating Company, Inc. (SNC) has not requested an exemption. The Commission, on its own initiative, has determined that an exemption is warranted from the requirement in 10 CFR 55.31(a)(5) that the applicant for a VEGP 3 & 4 operator license use a PRS or the facility to provide evidence of having successfully manipulated the controls of the facility. In lieu of that requirement, the Commission will accept evidence that the applicant, as a trainee, has successfully manipulated the controls of the VEGP 3 & 4 Commission-approved simulation facility meeting the requirements of 10 CFR 55.46(b).
The staff's evaluation of this action follows.
Pursuant to 10 CFR 55.11, the Commission may, upon application by an interested person, or upon its own initiative, grant exemptions from the requirements of 10 CFR part 55 as it determines are (1) authorized by law and (2) will not endanger life or property and (3) are otherwise in the public interest.
Exemptions are authorized by law where they are not expressly prohibited by statute or regulation. A proposed exemption is implicitly “authorized by law” if all of the conditions listed therein are met (
The regulations in 10 CFR part 55 implement Section 107 of the Atomic Energy Act of 1954, as amended (AEA), which sets requirements upon the Commission concerning operators' licenses and states, in part, that the Commission shall (1) “prescribe uniform conditions for licensing individuals as operators of any of the various classes of . . . utilization facilities licensed” by the NRC and (2) “determine the qualifications of such individuals.”
These requirements in the AEA do not expressly prohibit exemptions to the portion of 10 CFR 55.31(a)(5) that requires the use of a PRS or the facility for control manipulations. Further, as explained below, the exemption has little impact on the uniformity of licensing conditions, and little impact on the determinations of qualifications.
In a letter from Ms. Karen Fili, Vice President, VEGP 3 & 4 Operational Readiness, to the NRC dated September 18, 2015 (ADAMS Accession No. ML15265A107), the facility licensee requested Commission approval of the simulation facility for VEGP 3 & 4 to support the administration of operator licensing examinations.
The staff's evaluation of the simulation facility for VEGP 3 & 4 concluded that the simulation facility for VEGP 3 & 4 provides the necessary reactor physics, thermal hydraulic, and integrated system modeling of the reference plant (
The staff's evaluation of the simulation facility for VEGP 3 & 4 concluded that the simulation facility for VEGP 3 & 4 is capable of providing a wide range of scenarios that address the 13 items in 10 CFR 55.45(a) without procedural exceptions, simulator performance exceptions, or deviation from the approved examination scenario sequence. Control manipulations are a subset of actions included in these scenarios and have a defined scope that is significantly less than an exam scenario. Because of the reduced scope, the presence of existing simulator discrepancies in any training scenarios that provide applicants with the opportunity to provide the required control manipulations is even less likely as compared to operating tests. Therefore, there exists a large variety of control manipulations that can be completed without procedural exceptions, simulator performance exceptions, or deviation from the approved training scenario sequence.
Further, the conditions under which the applicants are licensed will be essentially unchanged, and the usage of the VEGP 3 & 4 CAS in place of a PRS will not significantly change how the Commission determines the qualifications of applicants. Under the exemption, 10 CFR 55.31(a)(5) will continue to require the applicant to perform, at a minimum, five significant control manipulations that affect reactivity or power level.
For purposes of control manipulations, the staff has already determined in its safety evaluation documenting Commission-approval of the simulation facility for VEGP 3 & 4 (ADAMS Accession No. ML16070A301) that the facility sufficiently models the systems of the reference plant, including the operating consoles, and permits use of the reference plant's procedures. Facility licensees that propose to use a PRS to meet the control manipulation requirements in 10 CFR 55.31(a)(5) must ensure that:
(i) The plant-referenced simulator utilizes models relating to nuclear and thermal-hydraulic characteristics that replicate the most recent core load in the nuclear power reference plant for which a license is being sought; and
(ii) Simulator fidelity has been demonstrated so that significant control manipulations are completed without procedural exceptions, simulator performance exceptions, or deviation from the approved training scenario sequence.
In its safety evaluation documenting Commission-approval of the simulation facility for VEGP 3 & 4, the staff found that the VEGP 3 & 4 Commission-approved simulation facility meets these criteria and, therefore, is equivalent to a PRS with respect to performing control
Accordingly, because a PRS and the Commission-approved simulation facility for VEGP 3 & 4 are essentially the same with respect to control manipulations, an exemption from 10 CFR 55.31(a)(5) allowing the use of the Commission-approved simulation facility for VEGP 3 & 4 in lieu of a PRS or the facility for control manipulations will still satisfy the applicable statutory requirements of the AEA that the Commission prescribe uniform conditions for licensing individuals as operators and determine the qualifications of operators.
The acceptability of the simulation facility for VEGP 3 & 4 with respect to the significant control manipulations required by 10 CFR 55.31(a)(5) is additionally assured by the fact that SNC performs scenario-based testing (SBT) for scenarios used to satisfy the control manipulation requirement. To ensure that simulator discrepancies and/or procedure issues do not affect control manipulations, SNC, as a standard practice in accordance with its licensing basis, implements SBT in accordance with Revision 1 of NEI 09-09, “Nuclear Power Plant-Referenced Simulator Scenario Based Testing Methodology.”
Key to the SBT Methodology is parallel testing and evaluation of simulator performance while instructors validate simulator training and evaluation scenarios. As instructors validate satisfactory completion of training or evaluation objectives, procedure steps and scenario content, they are also ensuring satisfactory simulator performance in parallel, not series, making the process an “online” method of evaluating simulator performance. Also critical is the assembly of the SBT package—the collection of a marked-up scenario, appropriate procedures, monitored parameters, an alarm summary and an affirmation checklist that serves as the proof of the robust nature of this method of performance testing. Proper conduct of the SBT Methodology is intended to alleviate the need for post-scenario evaluation of simulator performance since the performance of the simulator is being evaluated (
Therefore, since the Commission-approved simulation facility for VEGP 3 & 4 conforms to the same control manipulation requirements as a PRS, the NRC staff will continue to comply with its requirements governing uniformity and operator qualifications.
Accordingly, for the reasons above, and in light of the reasons discussed in Sections 2 and 3 below, the Commission concludes that the exemption is authorized by law.
As discussed above, as part of its review and approval of SNC's request for a Commission-approved simulation facility for VEGP 3 & 4, the staff found that the simulator demonstrates expected plant response to operator input and to normal, transient, and accident conditions to which the simulator has been designed to respond. Further, the staff found that the simulator is designed and implemented so that (i) it is sufficient in scope and fidelity to allow conduct of the evolutions listed in 10 CFR 55.45(a)(1) through (13), and 10 CFR 55.59(c)(3)(i)(A) through (AA), as applicable to the design of the reference plant and (ii) it allows for the completion of control manipulations for operator license applicants. Accordingly, the staff concludes that the simulation facility for VEGP 3 & 4 will replicate reference plant performance for the significant control manipulations required by 10 CFR 55.31(a)(5).
Because the Commission-approved simulation facility for VEGP 3 & 4 matches the criteria of a PRS with respect to control manipulations, the staff concludes that there is no basis to find endangerment of life or property as a consequence of the exemption.
The Commission's values guide the NRC in maintaining certain principles as it carries out regulatory activities in furtherance of its safety and security mission. These principles focus the NRC on ensuring safety and security while appropriately considering the interests of the NRC's stakeholders, including the public and licensees. These principles include Independence, Openness, Efficiency, Clarity, and Reliability. Whether the grant of an exemption to the requirement to use a PRS or the facility rather than the Commission-approved simulation facility for VEGP 3 & 4 would be in the public interest depends on the consideration and balancing of the foregoing factors.
Concerning Efficiency, the public has an interest in the best possible management and administration of regulatory activities. Regulatory activities should be consistent with the degree of risk reduction they achieve. Where several effective alternatives are available, the option which minimizes the use of resources should be adopted. Regulatory decisions should be made without undue delay. As applied to using a CAS rather than a PRS or the facility, in light of the Commission's findings that the capabilities of the VEGP 3 & 4 CAS are equivalent to those of a PRS for control manipulations, the usage of the VEGP 3 & 4 CAS provides both an effective and an efficient alternative for the VEGP 3 & 4 operator license applicant to gain the required experience.
Concerning Reliability, once established, regulations should be perceived to be reliable and not unjustifiably in a state of transition. Regulatory actions should always be fully consistent with written regulations and should be promptly, fairly, and decisively administered so as to lend stability to the nuclear operational and planning processes. Here, where the staff has already found that the VEGP 3 & 4 CAS is equivalent to a PRS with respect to control manipulations, the substantive requirements upon the operator license applicant are unchanged with the granting of the exemption. Further, the public has an interest in reliability in terms of the stability of the nuclear planning process. This exemption aids planning by allowing operator license applicants to complete their applications sooner, with the underlying requirements essentially unchanged, and could result in licensing decisions being made earlier than would be possible if the applicants had to wait for a PRS to be available.
Concerning Clarity, there should be a clear nexus between regulations and agency goals and objectives whether explicitly or implicitly stated. Agency positions should be readily understood and easily applied. For the reasons explained in the NRC's evaluation of the VEGP 3 & 4 CAS, the CAS is sufficient for administering operating tests, and is able to meet the requirements of a PRS with respect to control manipulations. The exemption accordingly recognizes that the capabilities of the VEGP 3 & 4 CAS are suitable to accomplish the regulatory purpose underlying the requirements of 10 CFR 55.31(a)(5).
The exemption is also consistent with the principles of Independence and Openness; the Commission has independently and objectively considered the regulatory interests involved and has explicitly documented its reasons for issuing the exemption.
Accordingly, on balance the Commission concludes that the exemption is in the public interest.
The Commission concludes that the exemption is (1) authorized by law and (2) will not endanger life or property and (3) is otherwise in the public interest. Therefore, in lieu of the requirements of 10 CFR 55.31(a)(5), the Commission will accept evidence that the applicant for a VEGP 3 & 4 operator license has completed the required manipulations on the VEGP 3 & 4 Commission-approved simulation facility that meets the requirements of 10 CFR 55.46(b), rather than on a PRS or the facility.
This exemption will expire when a VEGP 3 & 4 plant-referenced simulator that meets the requirements in 10 CFR 55.46(c) is available. Furthermore, this exemption is subject to the condition that the Commission-approved simulation facility for VEGP 3 & 4 continues to model the reference plant with sufficient scope and fidelity, in accordance with 10 CFR 55.46(c) and (d).
This exemption allows the five significant control manipulations required by 10 CFR 55.31(a)(5) to be performed on the VEGP 3 & 4 CAS that has been approved for the administration of operating tests instead of on the VEGP 3 & 4 facility or a PRS.
For the following reasons, this exemption meets the eligibility criteria of 10 CFR 51.22(c)(25) for a categorical exclusion. There is no significant hazards consideration related to this exemption. The staff has also determined that the exemption involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite; that there is no significant increase in individual or cumulative public or occupational radiation exposure; that there is no significant construction impact; and that there is no significant increase in the potential for or consequences from radiological accidents. Finally, the requirements to which the exemption applies involve qualification requirements. Accordingly, the exemption meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(25). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the exemption.
Accordingly, the Commission has determined that, pursuant to 10 CFR 55.11, issuing this exemption from the requirements in 10 CFR 55.31(a)(5) is authorized by law and will not endanger life or property and is otherwise in the public interest. The Commission will accept evidence of control manipulations performed on the VEGP 3 & 4 Commission-approved simulation facility instead of on the VEGP 3 & 4 facility or a PRS.
For the Nuclear Regulatory Commission.
Overseas Private Investment Corporation (OPIC).
Notice and request for comments.
Under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35), agencies are required to publish a Notice in the
The proposed change to OPIC-162 clarifies existing questions, incorporates sector-specific development impact questions and eliminates ineffective questions in an effort to harmonize development impact indicators with other Development Finance Institutions (“DFIs”). OPIC is a signatory to a “Memorandum of Understanding” with 25 partnering DFIs to harmonize development impact metrics where possible. The goal of this effort is to reduce the reporting burden on clients that receive financing from multiple DFIs and to instill best practices in the collection and the reporting on OPIC's developmental impacts. To minimize the reporting burden on respondents. OPIC has designed OPIC-162 as an electronic form with questions populating if they relate to the project.
Comments must be received within thirty (30) calendar days of publication of this Notice.
Mail all comments and requests for copies of the subject form to OPIC's Agency Submitting Officer: James Bobbitt, Overseas Private Investment Corporation, 1100 New York Avenue NW., Washington, DC 20527. See
OPIC Agency Submitting Officer: James Bobbitt, (202) 336-8558.
OPIC received no comments in response to the sixty (60) day notice published in
U.S. Office of Personnel Management (OPM).
Notice.
This notice identifies Schedule A, B, and C appointing authorities applicable to a single agency that were established or revoked from December 1, 2015, to December 31, 2015.
Senior Executive Resources Services, Senior Executive Services and Performance Management, Employee Services, 202-606-2246.
In accordance with 5 CFR 213.103, Schedule A, B, and C appointing authorities available for use by all agencies are codified in the Code of Federal Regulations (CFR). Schedule A, B, and C appointing authorities applicable to a single agency are not codified in the CFR, but the Office of Personnel Management (OPM) publishes a notice of agency-specific authorities established or revoked each month in the
(2) Not to Exceed 85 positions that require unique technical skills needed for the re-designing and re-building of digital interfaces between citizens, businesses, and government as a part of Smarter Information Technology Delivery Initiative. This authority may be used to make permanent, time-limited and temporary appointments to Digital Services Expert positions (GS-301) directly related to the implementation of the Smarter Information Technology Delivery Initiative at the GS-14 to 15 level. No new appointments may be made under this authority after September 30, 2017.
(11) Not to exceed 3,000 positions that require unique cyber security skills and knowledge to perform cyber risk and strategic analysis, incident handling and malware/vulnerability analysis, program management, distributed control systems security, cyber incident response, cyber exercise facilitation and management, cyber vulnerability detection and assessment, network and systems engineering, enterprise architecture, investigation, investigative analysis and cyber-related infrastructure inter-dependency analysis. This authority may be used to make permanent, time-limited and temporary appointments in the following occupational series: Security (GS-0080), computer engineers (GS-0854), electronic engineers (GS-0855), computer scientists (GS-1550), operations research (GS-1515), criminal investigators (GS-1811), telecommunications (GS-0391), and IT specialists (GS-2210). Within the scope of this authority, the U.S. Cyber Command, Army Cyber Command, Fleet [Navy] Cyber Command, Air Force Cyber Command, and Marine Forces Cyber.
No Schedule B Authorities to report during December 2015.
The following Schedule C appointing authorities were approved during December 2015.
The following Schedule C appointing authorities were revoked during December 2015.
5 U.S.C. 3301 and 3302; E.O. 10577, 3 CFR, 1954-1958 Comp., p. 218.
Office of Personnel Management.
60-Day notice and request for comments.
The Retirement Services, Office of Personnel Management (OPM) offers the general public and other federal agencies the opportunity to comment an extension without change of a currently approved information collection (ICR) 3206-0128, Application For Refund of Retirement Deductions Civil Service Retirement System and Current/Former Spouse's Notification of Application for Refund of Retirement Deductions Under the Civil Service Retirement System. As required by the Paperwork Reduction Act of 1995, (Pub. L. 104-13, 44 U.S.C. chapter 35) as amended by the Clinger-Cohen Act (Pub. L. 104-106), OPM is soliciting comments for this collection.
Comments are encouraged and will be accepted until June 7, 2016. This process is conducted in accordance with 5 CFR 1320.1.
Interested persons are invited to submit written comments on the proposed information collection to the U.S. Office of Personnel Management 1900 E Street NW., Washington, DC 20415, Attention: Alberta Butler, Room 2347-E, or sent via electronic mail to
A copy of this ICR with applicable supporting documentation, may be obtained by contacting the Retirement Services Publications Team, U.S. Office of Personnel Management, 1900 E Street NW., Room 3316-L, Washington, DC 20415, Attention: Cyrus S. Benson, or sent via electronic mail to
The Office of Management and Budget is particularly interested in comments that:
1. Evaluate whether the proposed collection of information is necessary for the proper performance of functions of the agency, including whether the information will have practical utility;
2. Evaluate the accuracy of the agency's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used;
3. Enhance the quality, utility, and clarity of the information to be collected; and
4. Minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology,
SF 2802 is used to support the payment of monies from the Retirement Fund. It identifies the applicant for refund of retirement deductions. SF 2802A is used to comply with the legal requirement that any spouse or former spouse of the applicant has been notified that the former employee is applying for a refund.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The text of the proposed rule change is available on the Exchange's Web site (
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend Rule 6.74A (Automated Improvement Mechanism (“AIM”)) to clarify how orders submitted for electronic crossing into the AIM auction are treated if an auction cannot occur, to adopt Interpretation and Policy .09 to Rule 6.74A (AIM Retained Order Functionality) to describe the Exchange's AIM Retained Order (“A:AIR”) functionality in the Rules, and make minor edits to Interpretation and Policy .08 to Rule 6.53C (Price Check Parameters) relating to the treatment of complex AIM orders marked A:AIR and correct certain typographical errors.
Under Rule 6.74A (Automated Improvement Mechanism (“AIM”)), a Trading Permit Holder (“TPH”) that represents agency orders may electronically execute an order it represents as agent (“Agency Order”) against principal interest or against a solicited order provided it submits the Agency Order for electronic execution into the AIM auction (“Auction”) for processing. Matched Agency Orders may be processed via AIM subject to certain eligibility requirements contained in Rule 6.74A(a). Specifically, to be eligible for processing via AIM, the Agency Order must be: (1) In a class designated as eligible for Auctions and within the designated eligibility size parameters as determined by the Exchange; (2) stopped with a principal or solicited order priced at the national best bid or offer (“NBBO”) (if 50 standard option contracts or 500 mini-option contracts or greater) or one cent/one minimum increment better than the NBBO (if less than 50 standard option contracts or 500 mini-option contracts); and (3) submitted in a series in which at least three Market-Makers are quoting if submitted during regular trading hours.
A:AIR functionality is an enhancement to AIM that allows TPHs the flexibility to choose, on an order-by-order basis, whether an Agency Order should continue into the Hybrid Trading System
The Exchange notes that A:AIR functionality is currently available for use on the Exchange and is referred to in the Rules (although not using that term)
Furthermore, to ensure that A:AIR orders are properly priced to allow the Exchange to book the Agency Order in the event an Auction cannot occur, proposed Interpretation and Policy .09 to Rule 6.74A would provide that orders marked “A:AIR” with Agency Orders that are not priced at the market or that are priced with a limit price not in the standard increment for the option series in which they are entered would be cancelled. For example, if a TPH were to submit a matched Agency Order into AIM for processing in a class with a minimum increment of a nickel, which was stopped with a contra order at $0.07, both the Agency Order and the contra order would be cancelled because the order, which is not priced in the minimum increment for the class, would not be eligible for AIM processing and because the System would not be able to book an order at $0.07 in a class with a minimum increment of a nickel. Notably, this provision of proposed Interpretation and Policy .09 to Rule 6.74A is consistent with previous descriptions of A:AIR functionality by the Exchange and Exchange rules that only permit orders at the standard increment to enter the book.
The Exchange also notes that although orders submitted into AIM, which are not marked A:AIR and are ineligible for Auction processing will result in both the Agency Order and the matching contra order(s) being cancelled, the Rules do not explicitly provide as much. Accordingly, the Exchange proposes to add language to Rule 6.74A(a) to provide that in the event that a Trading Permit Holder submits a matched Agency Order for electronic execution into the Auction that is ineligible for processing because it does not meet the conditions described in paragraph (a), both the Agency Order and any solicited contra orders will be cancelled unless marked as an AIM Retained order pursuant to proposed Interpretation and Policy .09 to Rule 6.74A.
The Exchange also proposes to make minor changes to Interpretation and Policy .08 to Rule 6.53C regarding price reasonability checks on complex orders to harmonize references to A:AIR functionality in Rule 6.53C with the language in proposed Interpretation and Policy .09 to Rule 6.74A. Specifically, the Exchange proposes to modify Interpretation and Policy .08(c)(5), (d), (f)(2), and (g)(4) to Rule 6.53C (Price Check Parameters) to change references to AIM orders that instruct the System to process the Agency Order as an unpaired order if an AIM auction cannot be initiated, to instead refer to AIM Retained (“A:AIR”) orders as defined in proposed Interpretation and Policy .09 to Rule 6.74A. These changes are non-substantive and intended only to harmonize existing references to A:AIR functionality currently in the Rules with the definition of A:AIR orders set forth in proposed Interpretation and Policy .09 to Rule 6.74A. The proposed rule change also makes non-substantive changes in these paragraphs to capitalize the defined term Agency Order, consistent with Rule 6.74A.
The Exchange believes the proposed rule change is consistent with the Act and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
The proposed rule change seeks to provide additional clarity and completeness in the Rules regarding functionalities in use at the Exchange. The Exchange is continuously updating the Rules to provide additional detail, clarity, and transparency regarding its operations and trading systems. The Exchange believes that the adoption of detailed, clear, and transparent rules reduces burdens on competition and promotes just and equitable principles of trade. The Exchange also believes that A:AIR functionality is valuable enhancement to AIM, which provides the opportunity for execution of customer orders that a TPH submitted for crossing via AIM but cannot be executed via AIM and helps prevent inadvertent mishandling of Agency Orders (
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The Exchange notes that price improvement mechanisms are widely used across the national options exchanges. The exchanges have developed these mechanisms in order to provide market participants diverse opportunities to seek valuable price improvement and as a means to compete with one another for order flow. Such price improvement mechanisms not only promote intermarket competition for order flow between the exchanges, but also intramarket competition between market participants competing for orders directly through the auction process. Accordingly, the exchanges are continuously making enhancements and adding functionalities to their price improvement mechanisms in order to provide more competitive marketplaces for market participants and better compete with one another. A:AIR functionality is simply one of many enhancements that the Exchange has made to AIM for this purpose.
The Exchange neither solicited nor received written comments on the proposed rule change.
Within 45 days of the date of publication of this notice in the
A. By order approve or disapprove such proposed rule change, or
B. institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change, as modified by Amendment No. 2, is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Securities and Exchange Commission (“Commission”).
Notice of an application for an order under section 6(c) of the Investment Company Act of 1940 (the “Act”) for an exemption from sections 2(a)(32), 5(a)(1), 22(d), and 22(e) of the Act and rule 22c-1 under the Act, under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and 17(a)(2) of the Act, and under section 12(d)(1)(J) for an exemption from
Applicants request an order that would permit (a) series of certain open-end management investment companies to issue shares (“Shares”) redeemable in large aggregations only (“Creation Units”); (b) secondary market transactions in Shares to occur at negotiated market prices rather than at net asset value (“NAV”); (c) certain series to pay redemption proceeds, under certain circumstances, more than seven days after the tender of Shares for redemption; (d) certain affiliated persons of the series to deposit securities into, and receive securities from, the series in connection with the purchase and redemption of Creation Units; (e) certain registered management investment companies and unit investment trusts outside of the same group of investment companies as the series to acquire Shares; and (f) certain series to perform creations and redemptions of Creation Units in-kind in a master-feeder structure.
Madison ETF Trust (“Trust”) and Madison ETF Advisers, LLC (“Initial Adviser”).
The application was filed on August 4, 2015, and amended on December 11, 2015.
An order granting the requested relief will be issued unless the Commission orders a hearing. Interested persons may request a hearing by writing to the Commission's Secretary and serving applicants with a copy of the request, personally or by mail. Hearing requests should be received by the Commission by 5:30 p.m. on April 29, 2016, and should be accompanied by proof of service on applicants, in the form of an affidavit, or for lawyers, a certificate of service. Pursuant to rule 0-5 under the Act, hearing requests should state the nature of the writer's interest, any facts bearing upon the desirability of a hearing on the matter, the reason for the request, and the issues contested. Persons who wish to be notified of a hearing may request notification by writing to the Commission's Secretary.
Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090; Applicants: 1209 Orange Street, Wilmington, DE 19801.
Courtney S. Thornton, Senior Counsel, at (202) 551-6812, or Mary Kay Frech, Branch Chief, at (202) 551-6821 (Division of Investment Management, Chief Counsel's Office).
The following is a summary of the application. The complete application may be obtained via the Commission's Web site by searching for the file number, or for an applicant using the Company name box, at
1. The Trust is a Delaware statutory trust that will register under the Act as a series open-end management investment company. The Trust will offer a number of Funds (as defined below), each tracking a particular index and utilizing either a replication or representative sampling strategy. Applicants currently expect that the Trust's initial series will be the Madison Gold Miners ETF (the “Initial Fund”). The Underlying Index (as defined below) for the Initial Fund is currently expected to be the Solactive Global Pure Gold Miners Index. Each Fund will operate as an exchange traded fund (“ETF”).
2. The Initial Adviser, a Delaware limited liability company, will be the investment adviser to the Initial Fund. The Initial Adviser is, and any other Adviser (as defined below) will be, registered as an investment adviser under the Investment Advisers Act of 1940 (“Advisers Act”). The Adviser may enter into sub-advisory agreements with one or more investment advisers to act as sub-advisers (each, a “Sub-Adviser”) to particular Funds, or their respective Master Fund (as defined below). Any Sub-Adviser will either be registered under the Advisers Act or will not be required to register thereunder.
3. The Trust will enter into a distribution agreement with one or more distributors. Each distributor will be a broker-dealer (“Broker”) registered under the Securities Exchange Act of 1934 (“Exchange Act”) and will act as distributor and principal underwriter (“Distributor”) of one or more of the Funds. No Distributor will be affiliated with any Exchange (as defined below), and each Distributor will comply with the terms and conditions of the application. The Distributor of a Fund may be an affiliated person or an affiliated person of an affiliated person of that Fund's Adviser and/or Sub-Advisers.
4. Applicants request that the order apply to the Initial Fund and any additional series of the Trust and any other existing or future open-end management investment company or existing or future series thereof (“Future Fund” and together with the Initial Fund, “Funds”), that operate as ETFs, and their respective existing or future Master Funds, and will track a specified index comprised of domestic or foreign equity and/or fixed income securities (each, an “Underlying Index”). Each Fund will (a) be advised by the Initial Adviser or an entity controlling, controlled by, or under common control with the Initial Adviser (each, an “Adviser”) and (b) comply with the terms and conditions of the application.
5. Applicants state that a Fund may operate as a feeder fund (“Feeder Fund”) in a master-feeder structure. Applicants request that the order permit a Feeder Fund to acquire shares of a master fund (“Master Fund”), which will be another registered investment company in the same group of investment companies having substantially the same investment objectives as the Feeder Fund, beyond the limitations in section 12(d)(1)(A) of the Act and permit the Master Fund, and any principal underwriter for the Master Fund, to sell shares of the Master Fund to the Feeder Fund beyond the limitations in section 12(d)(1)(B) of the Act (“Master-Feeder Relief”). Applicants may structure certain Feeder Funds to generate economies of scale and incur lower overhead costs.
6. Each Fund, or its respective Master Fund, will hold certain securities, assets or other positions (“Portfolio Holdings”) selected to correspond generally to the performance of its Underlying Index. Certain Funds will be based on Underlying Indexes comprised solely of equity and/or fixed income securities issued by one or more of the following categories of issuers: (i) Domestic issuers and (ii) non-domestic issuers meeting the requirements for trading in U.S. markets. Other Funds will be based on Underlying Indexes that will be comprised solely of foreign and domestic, or solely foreign, equity and/
7. Applicants represent that each Fund, or its respective Master Fund, will invest at least 80% of its assets (excluding securities lending collateral) in the component securities of its respective Underlying Index (“Component Securities”), or, in the case of Fixed Income Funds,
8. The Trust may offer Funds that seek to track Underlying Indexes constructed using 130/30 investment strategies (“130/30 Funds”) or other long/short investment strategies (“Long/Short Funds”). Each Long/Short Fund will establish (i) exposures equal to approximately 100% of the long positions specified by the Long/Short Index
9. A Fund will utilize either a replication or representative sampling strategy to track its Underlying Index. A Fund using a replication strategy will invest in the Component Securities of its Underlying Index in the same approximate proportions as in such Underlying Index. A Fund using a representative sampling strategy will hold some, but not necessarily all of the Component Securities of its Underlying Index. Applicants state that a Fund using a representative sampling strategy will not be expected to track the performance of its Underlying Index with the same degree of accuracy as would an investment vehicle that invested in every Component Security of the Underlying Index with the same weighting as the Underlying Index. Applicants expect that each Fund, or its respective Master Fund, will have an annual tracking error relative to the performance of its Underlying Index of less than 5%.
10. The Initial Funds are, and any Future Fund will be, entitled to use its Underlying Index pursuant to either a licensing agreement with the entity that compiles, creates, sponsors or maintains the Underlying Index (each, an “Index Provider”) or a sub-licensing arrangement with the Adviser, which will have a licensing agreement with such Index Provider.
11. Applicants recognize that Self-Indexing Funds could raise concerns regarding the ability of the Affiliated Index Provider to manipulate the Underlying Index to the benefit or detriment of the Self-Indexing Fund. Applicants further recognize the potential for conflicts that may arise with respect to the personal trading activity of personnel of the Affiliated Index Provider who have knowledge of changes to an Underlying Index prior to
12. Applicants propose that each day that the Trust, the NYSE and the national securities exchange (as defined in section 2(a)(26) of the Act) (an “Exchange”) on which the Fund's Shares are primarily listed (“Listing Exchange”) are open for business, including any day that a Fund is required to be open under section 22(e) of the Act (a “Business Day”), each Self-Indexing Fund will post on its Web site, before commencement of trading of Shares on the Listing Exchange, the identities and quantities of the Portfolio Holdings held by the Fund, or its respective Master Fund, that will form the basis for the Fund's calculation of its NAV at the end of the Business Day.
13. In addition, applicants do not believe the potential for conflicts of interest raised by the Adviser's use of the Underlying Indexes in connection with the management of the Self-Indexing Funds and the Affiliated Accounts will be substantially different from the potential conflicts presented by an adviser managing two or more registered funds. Both the Act and the Advisers Act contain various protections to address conflicts of interest where an adviser is managing two or more registered funds and these protections will also help address these conflicts with respect to the Self-Indexing Funds.
14. The Adviser and any Sub-Adviser has adopted or will adopt, pursuant to rule 206(4)-7 under the Advisers Act, written policies and procedures reasonably designed to prevent violations of the Advisers Act and the rules thereunder. These include policies and procedures designed to minimize potential conflicts of interest among the Self-Indexing Funds and the Affiliated Accounts, such as cross trading policies, as well as those designed to ensure the equitable allocation of portfolio transactions and brokerage commissions. In addition, the Initial Adviser has adopted policies and procedures as required under section 204A of the Advisers Act, which are reasonably designed in light of the nature of its business to prevent the misuse, in violation of the Advisers Act or the Exchange Act or the rules thereunder, of material non-public information by the Initial Adviser or an associated person (“Inside Information Policy”). Any other Adviser or Sub-Adviser will be required to adopt and maintain a similar Inside Information Policy. In accordance with the Code of Ethics (as defined below)
15. To the extent the Self-Indexing Funds transact with an affiliated person of the Adviser or Sub-Adviser, such transactions will comply with the Act, the rules thereunder and the terms and conditions of the requested order. In this regard, each Self-Indexing Fund's Board will periodically review the Self-Indexing Fund's use of an Affiliated Index Provider. Subject to the approval of the Self-Indexing Fund's Board, the Adviser, affiliated persons of the Adviser (“Adviser Affiliates”) and affiliated persons of any Sub-Adviser (“Sub-Adviser Affiliates”) may be authorized to provide custody, fund accounting and administration and transfer agency services to the Self-Indexing Funds. Any services provided by the Adviser, Adviser Affiliates, Sub-Adviser and Sub-Adviser Affiliates will be performed in accordance with the provisions of the Act, the rules under the Act and any relevant guidelines from the staff of the Commission.
16. The Shares of each Fund will be purchased and redeemed in Creation Units and generally on an in-kind basis. Except where the purchase or redemption will include cash under the limited circumstances specified below, purchasers will be required to purchase Creation Units by making an in-kind deposit of specified instruments (“Deposit Instruments”), and shareholders redeeming their Shares will receive an in-kind transfer of specified instruments (“Redemption Instruments”).
17. Purchases and redemptions of Creation Units may be made in whole or in part on a cash basis, rather than in kind, solely under the following circumstances: (a) To the extent there is a Cash Amount; (b) if, on a given Business Day, the Fund announces before the open of trading that all purchases, all redemptions or all purchases and redemptions on that day will be made entirely in cash; (c) if, upon receiving a purchase or redemption order from an Authorized Participant, the Fund determines to require the purchase or redemption, as applicable, to be made entirely in cash;
18. Creation Units will consist of specified large aggregations of Shares (
19. Each Business Day, before the open of trading on the Listing Exchange, each Fund will cause to be published through the NSCC the names and quantities of the instruments comprising the Deposit Instruments and the Redemption Instruments, as well as the estimated Cash Amount (if any), for that day. The list of Deposit Instruments and Redemption Instruments will apply until a new list is announced on the following Business Day, and there will be no intra-day changes to the list except to correct errors in the published list. Each Listing Exchange, or other major market data provider, will disseminate, every 15 seconds during regular Exchange trading hours, through the facilities of the Consolidated Tape Association, or other widely disseminated means, an amount for each Fund stated on a per individual Share basis representing the sum of (i) the estimated Cash Amount and (ii) the current value of the Deposit Instruments.
20. Transaction expenses, including operational processing and brokerage costs, will be incurred by a Fund when investors purchase or redeem Creation Units in-kind and such costs have the potential to dilute the interests of the Fund's existing shareholders. Each Fund will impose purchase or redemption transaction fees (“Transaction Fees”) in connection with effecting such purchases or redemptions of Creation Units. With respect to Feeder Funds, the Transaction Fee would be paid indirectly to the Master Fund.
21. Shares of each Fund will be listed and traded individually on an Exchange. It is expected that one or more member firms of an Exchange will be designated to act as a market maker (each, a “Market Maker”) and maintain a market for Shares trading on the Exchange. The price of Shares trading on an Exchange will be based on the current bid/offer market. Transactions involving the sale of Shares on an Exchange will be subject to customary brokerage commissions and charges.
22. Applicants expect that purchasers of Creation Units will include institutional investors and arbitrageurs. Market Makers, acting in their roles to provide a fair and orderly secondary market for the Shares, may from time to time find it appropriate to purchase or redeem Creation Units. Applicants expect that secondary market purchasers of Shares will include both institutional and retail investors.
23. Shares will not be individually redeemable, and owners of Shares may acquire those Shares from the Fund, or tender such Shares for redemption to the Fund, in Creation Units only. To redeem, an investor must accumulate enough Shares to constitute a Creation Unit. Redemption requests must be placed through an Authorized Participant. A redeeming investor may pay a Transaction Fee, calculated in the same manner as a Transaction Fee payable in connection with purchases of Creation Units.
24. Neither the Trust nor any Fund will be advertised or marketed or otherwise held out as a traditional open-end investment company or a “mutual fund.” Instead, each such Fund will be marketed as an “ETF.” All marketing materials that describe the features or method of obtaining, buying or selling Creation Units, or Shares traded on an Exchange, or refer to redeemability, will prominently disclose that Shares are not individually redeemable and will disclose that the owners of Shares may acquire those Shares from the Fund or tender such Shares for redemption to the Fund in Creation Units only. The Funds will provide copies of their annual and semi-annual shareholder reports to DTC Participants for distribution to beneficial owners of Shares.
1. Applicants request an order under section 6(c) of the Act for an exemption from sections 2(a)(32), 5(a)(1), 22(d), and 22(e) of the Act and rule 22c-1 under the Act, under sections 6(c) and 17(b) of the Act for an exemption from sections 17(a)(1) and 17(a)(2) of the Act, and under section 12(d)(1)(J) of the Act for an exemption from sections 12(d)(1)(A) and (B) of the Act.
2. Section 6(c) of the Act provides that the Commission may exempt any person, security or transaction, or any class of persons, securities or transactions, from any provision of the Act, if and to the extent that such exemption is necessary or appropriate in the public interest and consistent with the protection of investors and the purposes fairly intended by the policy and provisions of the Act. Section 17(b) of the Act authorizes the Commission to exempt a proposed transaction from section 17(a) of the Act if evidence establishes that the terms of the transaction, including the consideration to be paid or received, are reasonable and fair and do not involve overreaching on the part of any person concerned, and the proposed transaction is consistent with the policies of the registered investment company and the general provisions of the Act. Section 12(d)(1)(J) of the Act provides that the Commission may exempt any person, security, or transaction, or any class or classes of persons, securities or transactions, from any provisions of section 12(d)(1) if the exemption is consistent with the public interest and the protection of investors.
3. Section 5(a)(1) of the Act defines an “open-end company” as a management investment company that is offering for sale or has outstanding any redeemable security of which it is the issuer. Section 2(a)(32) of the Act defines a redeemable security as any security, other than short-term paper, under the terms of which the owner, upon its presentation to the issuer, is entitled to receive approximately a proportionate share of the issuer's current net assets, or the cash equivalent. Because Shares will not be individually redeemable, applicants request an order that would permit the Funds to register as open-end management investment companies and issue Shares that are redeemable in Creation Units only.
4. Section 22(d) of the Act, among other things, prohibits a dealer from selling a redeemable security that is currently being offered to the public by or through an underwriter, except at a current public offering price described in the prospectus. Rule 22c-1 under the Act generally requires that a dealer selling, redeeming or repurchasing a redeemable security do so only at a price based on its NAV. Applicants state that secondary market trading in Shares will take place at negotiated prices, not at a current offering price described in a Fund's prospectus, and not at a price based on NAV. Thus, purchases and sales of Shares in the secondary market will not comply with section 22(d) of the Act and rule 22c-1 under the Act. Applicants request an exemption under section 6(c) from these provisions.
5. Applicants assert that the concerns sought to be addressed by section 22(d) of the Act and rule 22c-1 under the Act with respect to pricing are equally satisfied by the proposed method of pricing Shares. Applicants maintain that while there is little legislative history regarding section 22(d), its provisions, as well as those of rule 22c-1, appear to have been designed to (a) prevent dilution caused by certain riskless-trading schemes by principal underwriters and contract dealers, (b) prevent unjust discrimination or preferential treatment among buyers, and (c) ensure an orderly distribution of investment company shares by eliminating price competition from dealers offering shares at less than the published sales price and repurchasing shares at more than the published redemption price.
6. Applicants believe that none of these purposes will be thwarted by permitting Shares to trade in the secondary market at negotiated prices. Applicants state that (a) secondary market trading in Shares does not involve a Fund as a party and will not result in dilution of an investment in Shares, and (b) to the extent different prices exist during a given trading day, or from day to day, such variances occur as a result of third-party market forces, such as supply and demand. Therefore, applicants assert that secondary market transactions in Shares will not lead to discrimination or preferential treatment among purchasers. Finally, applicants contend that the price at which Shares trade will be disciplined by arbitrage
7. Section 22(e) of the Act generally prohibits a registered investment company from suspending the right of redemption or postponing the date of payment of redemption proceeds for more than seven days after the tender of a security for redemption. Applicants state that settlement of redemptions for Foreign Funds will be contingent not only on the settlement cycle of the United States market, but also on current delivery cycles in local markets for underlying foreign Portfolio Holdings held by a Foreign Fund. Applicants state that the delivery cycles currently practicable for transferring Redemption Instruments to redeeming investors, coupled with local market holiday schedules, may require a delivery process of up to fifteen (15) calendar days. Accordingly, with respect to Foreign Funds only, applicants hereby request relief under section 6(c) from the requirement imposed by section 22(e) to allow Foreign Funds to pay redemption proceeds within fifteen calendar days following the tender of Creation Units for redemption.
8. Applicants believe that Congress adopted section 22(e) to prevent unreasonable, undisclosed or unforeseen delays in the actual payment of redemption proceeds. Applicants propose that allowing redemption payments for Creation Units of a Foreign Fund to be made within fifteen calendar days would not be inconsistent with the spirit and intent of section 22(e). Applicants suggest that a redemption payment occurring within fifteen calendar days following a redemption request would adequately afford investor protection.
9. Applicants are not seeking relief from section 22(e) with respect to Foreign Funds that do not effect creations and redemptions of Creation Units in-kind.
10. Section 12(d)(1)(A) of the Act prohibits a registered investment company from acquiring securities of an investment company if such securities represent more than 3% of the total outstanding voting stock of the acquired company, more than 5% of the total assets of the acquiring company, or, together with the securities of any other investment companies, more than 10% of the total assets of the acquiring company. Section 12(d)(1)(B) of the Act prohibits a registered open-end investment company, its principal underwriter and any other broker-dealer from knowingly selling the investment company's shares to another investment company if the sale will cause the acquiring company to own more than 3% of the acquired company's voting stock, or if the sale will cause more than 10% of the acquired company's voting stock to be owned by investment companies generally.
11. Applicants request an exemption to permit registered management investment companies and unit investment trusts (“UITs”) that are not advised or sponsored by the Adviser, and not part of the same “group of investment companies,” as defined in section 12(d)(1)(G)(ii) of the Act as the Funds (such management investment companies are referred to as “Investing Management Companies,” such UITs are referred to as “Investing Trusts,” and Investing Management Companies and Investing Trusts are collectively referred to as “Funds of Funds”), to acquire Shares beyond the limits of section 12(d)(1)(A) of the Act; and the Funds, and any principal underwriter for the Funds, and/or any Broker registered under the Exchange Act, to sell Shares to Funds of Funds beyond the limits of section 12(d)(1)(B) of the Act.
12. Each Investing Management Company will be advised by an investment adviser within the meaning of section 2(a)(20)(A) of the Act (the “Fund of Funds Adviser”) and may be sub-advised by investment advisers within the meaning of section 2(a)(20)(B) of the Act (each, a “Fund of Funds Sub-Adviser”). Any Fund of Funds Adviser will be registered under the Advisers Act. Any Fund of Funds Sub-Adviser will be registered under the Advisers Act or will not be required to register. Each Investing Trust will be sponsored by a sponsor (“Sponsor”).
13. Applicants submit that the proposed conditions to the requested relief adequately address the concerns underlying the limits in sections 12(d)(1)(A) and (B), which include concerns about undue influence by a fund of funds over underlying funds, excessive layering of fees and overly complex fund structures. Applicants believe that the requested exemption is consistent with the public interest and the protection of investors.
14. Applicants believe that neither a Fund of Funds nor a Fund of Funds Affiliate would be able to exert undue influence over a Fund.
15. Applicants propose other conditions to limit the potential for undue influence over the Funds, or their respective Master Funds, including that no Fund of Funds or Fund of Funds Affiliate (except to the extent it is acting in its capacity as an investment adviser to a Fund) will cause a Fund, or its respective Master Fund, to purchase a security in an offering of securities during the existence of an underwriting or selling syndicate of which a principal underwriter is an Underwriting Affiliate (“Affiliated Underwriting”). An
16. Applicants do not believe that the proposed arrangement will involve excessive layering of fees. The board of directors or trustees of any Investing Management Company, including a majority of the directors or trustees who are not “interested persons” within the meaning of section 2(a)(19) of the Act (“disinterested directors or trustees”), will find that the advisory fees charged under the contract are based on services provided that will be in addition to, rather than duplicative of, services provided under the advisory contract of any Fund, or its respective Master Fund, in which the Investing Management Company may invest. In addition, under condition B.5., a Fund of Funds Adviser, or a Fund of Funds' trustee or Sponsor, as applicable, will waive fees otherwise payable to it by the Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by a Fund, or its respective Master Fund, under rule 12b-1 under the Act) received from a Fund by the Fund of Funds Adviser, trustee or Sponsor or an affiliated person of the Fund of Funds Adviser, trustee or Sponsor, other than any advisory fees paid to the Fund of Funds Adviser, trustee or Sponsor or its affiliated person by a Fund, in connection with the investment by the Fund of Funds in the Fund. Applicants state that any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to a fund of funds as set forth in NASD Conduct Rule 2830.
17. Applicants submit that the proposed arrangement will not create an overly complex fund structure. Applicants note that no Fund, or its respective Master Fund, will acquire securities of any investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act in excess of the limits contained in section 12(d)(1)(A) of the Act, except to the extent (i) the Fund, or its respective Master Fund, acquires securities of another investment company pursuant to exemptive relief from the Commission permitting the Fund, or its respective Master Fund, to purchase shares of other investment companies for short-term cash management purposes; (ii) the Fund acquires securities of the Master Fund pursuant to Master-Feeder Relief; or (iii) the Fund invests in a Wholly-Owned Subsidiary that is a wholly-owned and controlled subsidiary of the Fund (or its respective Master Fund).
18. Applicants also note that a Fund may choose to reject a direct purchase of Shares in Creation Units by a Fund of Funds. To the extent that a Fund of Funds purchases Shares in the secondary market, a Fund would still retain its ability to reject any initial investment by a Fund of Funds in excess of the limits of section 12(d)(1)(A) by declining to enter into a FOF Participation Agreement with the Fund of Funds.
19. Applicants also are seeking the Master-Feeder Relief to permit the Feeder Funds to perform creations and redemptions of Shares in-kind in a master-feeder structure. Applicants assert that this structure is substantially identical to traditional master-feeder structures permitted pursuant to the exception provided in section 12(d)(1)(E) of the Act. Section 12(d)(1)(E) provides that the percentage limitations of section 12(d)(1)(A) and (B) shall not apply to a security issued by an investment company (in this case, the shares of the applicable Master Fund) if, among other things, that security is the only investment security held by the investing investment company (in this case, the Feeder Fund). Applicants believe the proposed master-feeder structure complies with section 12(d)(1)(E) because each Feeder Fund will hold only investment securities issued by its corresponding Master Fund; however, the Feeder Funds may receive securities other than securities of its corresponding Master Fund if a Feeder Fund accepts an in-kind creation. To the extent that a Feeder Fund may be deemed to be holding both shares of the Master Fund and other securities, applicants request relief from section 12(d)(1)(A) and (B). The Feeder Funds would operate in compliance with all other provisions of section 12(d)(1)(E).
20. Sections 17(a)(1) and (2) of the Act generally prohibit an affiliated person of a registered investment company, or an affiliated person of such a person, from selling any security to or purchasing any security from the company. Section 2(a)(3) of the Act defines “affiliated person” of another person to include (a) any person directly or indirectly owning, controlling or holding with power to vote 5% or more of the outstanding voting securities of the other person, (b) any person 5% or more of whose outstanding voting securities are directly or indirectly owned, controlled or held with the power to vote by the other person, and (c) any person directly or indirectly controlling, controlled by or under common control with the other person. Section 2(a)(9) of the Act defines “control” as the power to exercise a controlling influence over the management or policies of a company, and provides that a control relationship will be presumed where one person owns more than 25% of a company's voting securities. The Funds may be deemed to be controlled by the Adviser or an entity controlling, controlled by or under common control with the Adviser and hence affiliated persons of each other. In addition, the Funds may be deemed to be under common control with any other registered investment company (or series thereof) advised by an Adviser or an entity controlling, controlled by or under common control with an Adviser (an “Affiliated Fund”). Any investor, including Market Makers, owning 5% or
21. Applicants request an exemption from sections 17(a)(1) and 17(a)(2) of the Act pursuant to sections 6(c) and 17(b) of the Act to permit persons that are affiliated persons of the Funds, or an affiliated person of such affiliated person of the Funds, solely by virtue of one or more of the following: (a) Holding 5% or more, or in excess of 25%, of the outstanding Shares of one or more Funds; (b) an affiliation with a person with an ownership interest described in (a); or (c) holding 5% or more, or more than 25%, of the shares of one or more Affiliated Funds, to effectuate purchases and redemptions “in-kind.”
22. Applicants assert that no useful purpose would be served by prohibiting such affiliated persons from making “in-kind” purchases or “in-kind” redemptions of Shares of a Fund in Creation Units. Both the deposit procedures for “in-kind” purchases of Creation Units and the redemption procedures for “in-kind” redemptions of Creation Units will be effected in exactly the same manner for all purchases and redemptions, regardless of size or number. There will be no discrimination between purchasers or redeemers. Deposit Instruments and Redemption Instruments for each Fund will be valued in the identical manner as those Portfolio Holdings currently held by such Fund, or its respective Master Fund, and the valuation of the Deposit Instruments and Redemption Instruments will be made in an identical manner regardless of the identity of the purchaser or redeemer. Applicants do not believe that “in-kind” purchases and redemptions will result in abusive self-dealing or overreaching, but rather assert that such procedures will be implemented consistently with each Fund's objectives and with the general purposes of the Act. Applicants believe that “in-kind” purchases and redemptions will be made on terms reasonable to Applicants and any affiliated persons because they will be valued pursuant to verifiable objective standards. The method of valuing Portfolio Holdings held by a Fund is identical to that used for calculating “in-kind” purchase or redemption values and therefore creates no opportunity for affiliated persons or affiliated persons of affiliated persons of applicants to effect a transaction detrimental to the other holders of Shares of that Fund. Similarly, applicants submit that, by using the same standards for valuing Portfolio Holdings held by a Fund as are used for calculating “in-kind” redemptions or purchases, the Fund will ensure that its NAV will not be adversely affected by such securities transactions. Applicants also note that the ability to take deposits and make redemptions “in-kind” will help each Fund to track closely its Underlying Index and therefore aid in achieving the Fund's objectives.
23. Applicants also seek relief under sections 6(c) and 17(b) from section 17(a) to permit a Fund that is an affiliated person, or an affiliated person of an affiliated person, of a Fund of Funds to sell its Shares to and redeem its Shares from a Fund of Funds, and to engage in the accompanying in-kind transactions with the Fund of Funds.
24. To the extent that a Fund operates in a master-feeder structure, applicants also request relief permitting the Feeder Funds to engage in in-kind creations and redemptions with the applicable Master Fund. Applicants state that the customary section 17(a)(1) and 17(a)(2) relief would not be sufficient to permit such transactions because the Feeder Funds and the applicable Master Fund could also be affiliated by virtue of having the same investment adviser. However, applicants believe that in-kind creations and redemptions between a Feeder Fund and a Master Fund advised by the same investment adviser do not involve “overreaching” by an affiliated person. Such transactions will occur only at the Feeder Fund's proportionate share of the Master Fund's net assets, and the distributed securities will be valued in the same manner as they are valued for the purposes of calculating the applicable Master Fund's NAV. Further, all such transactions will be effected with respect to pre-determined securities and on the same terms with respect to all investors. Finally, such transaction would only occur as a result of, and to effectuate, a creation or redemption transaction between the Feeder Fund and a third-party investor. Applicants believe that the terms of the proposed transactions are reasonable and fair and do not involve overreaching on the part of any person concerned, the proposed transactions are consistent with the policy of each Fund and will be consistent with the investment objectives and policies of each Fund of Funds, and the proposed transactions are consistent with the general purposes of the Act.
Applicants agree that any order of the Commission granting the requested relief will be subject to the following conditions:
1. The requested relief to permit ETF operations, other than the Master-Feeder Relief, will expire on the effective date of any Commission rule under the Act that provides relief permitting the operation of index-based ETFs.
2. As long as a Fund operates in reliance on the requested order, the Shares of such Fund will be listed on an Exchange.
3. Neither the Trust nor any Fund will be advertised or marketed as an open-end investment company or a mutual
4. The Web site, which is and will be publicly accessible at no charge, will contain, on a per Share basis for each Fund, the prior Business Day's NAV and the market closing price or the midpoint of the bid/ask spread at the time of the calculation of such NAV (“Bid/Ask Price”), and a calculation of the premium or discount of the market closing price or Bid/Ask Price against such NAV.
5. Each Self-Indexing Fund, Long/Short Fund and 130/30 Fund will post on the Web site on each Business Day, before commencement of trading of Shares on the Exchange, the Fund's, or its respective Master Fund's, Portfolio Holdings.
6. No Adviser or any Sub-Adviser to a Self-Indexing Fund, directly or indirectly, will cause any Authorized Participant (or any investor on whose behalf an Authorized Participant may transact with the Self-Indexing Fund) to acquire any Deposit Instrument for the Self-Indexing Fund, or its respective Master Fund, through a transaction in which the Self-Indexing Fund, or its respective Master Fund, could not engage directly.
1. The members of a Fund of Funds' Advisory Group will not control (individually or in the aggregate) a Fund, or its respective Master Fund, within the meaning of section 2(a)(9) of the Act. The members of a Fund of Funds' Sub-Advisory Group will not control (individually or in the aggregate) a Fund, or its respective Master Fund, within the meaning of section 2(a)(9) of the Act. If, as a result of a decrease in the outstanding voting securities of a Fund, the Fund of Funds' Advisory Group or the Fund of Funds' Sub-Advisory Group, each in the aggregate, becomes a holder of more than 25 percent of the outstanding voting securities of a Fund, it will vote its Shares of the Fund in the same proportion as the vote of all other holders of the Fund's Shares. This condition does not apply to the Fund of Funds' Sub-Advisory Group with respect to a Fund, or its respective Master Fund, for which the Fund of Funds' Sub-Adviser or a person controlling, controlled by or under common control with the Fund of Funds' Sub-Adviser acts as the investment adviser within the meaning of section 2(a)(20)(A) of the Act.
2. No Fund of Funds or Fund of Funds Affiliate will cause any existing or potential investment by the Fund of Funds in a Fund to influence the terms of any services or transactions between the Fund of Funds or Fund of Funds Affiliate and the Fund, or its respective Master Fund, or a Fund Affiliate.
3. The board of directors or trustees of an Investing Management Company, including a majority of the disinterested directors or trustees, will adopt procedures reasonably designed to ensure that the Fund of Funds Adviser and Fund of Funds Sub-Adviser are conducting the investment program of the Investing Management Company without taking into account any consideration received by the Investing Management Company or a Fund of Funds Affiliate from a Fund, or its respective Master Fund, or Fund Affiliate in connection with any services or transactions.
4. Once an investment by a Fund of Funds in the securities of a Fund exceeds the limits in section 12(d)(1)(A)(i) of the Act, the Board of the Fund, or its respective Master Fund, including a majority of the directors or trustees who are not “interested persons” within the meaning of section 2(a)(19) of the Act (“non-interested Board members”), will determine that any consideration paid by the Fund, or its respective Master Fund, to the Fund of Funds or a Fund of Funds Affiliate in connection with any services or transactions: (i) Is fair and reasonable in relation to the nature and quality of the services and benefits received by the Fund, or its respective Master Fund; (ii) is within the range of consideration that the Fund would be required to pay to another unaffiliated entity in connection with the same services or transactions; and (iii) does not involve overreaching on the part of any person concerned. This condition does not apply with respect to any services or transactions between a Fund, or its respective Master Fund, and its investment adviser(s), or any person controlling, controlled by or under common control with such investment adviser(s).
5. The Fund of Funds Adviser, or trustee or Sponsor of an Investing Trust, as applicable, will waive fees otherwise payable to it by the Fund of Funds in an amount at least equal to any compensation (including fees received pursuant to any plan adopted by a Fund, or its respective Master Fund, under rule 12b-1 under the Act) received from a Fund, or its respective Master Fund, by the Fund of Funds Adviser, or trustee or Sponsor of the Investing Trust, or an affiliated person of the Fund of Funds Adviser, or trustee or Sponsor of the Investing Trust, other than any advisory fees paid to the Fund of Funds Adviser, or trustee or Sponsor of an Investing Trust, or its affiliated person by the Fund, or its respective Master Fund, in connection with the investment by the Fund of Funds in the Fund. Any Fund of Funds Sub-Adviser will waive fees otherwise payable to the Fund of Funds Sub-Adviser, directly or indirectly, by the Investing Management Company in an amount at least equal to any compensation received from a Fund, or its respective Master Fund, by the Fund of Funds Sub-Adviser, or an affiliated person of the Fund of Funds Sub-Adviser, other than any advisory fees paid to the Fund of Funds Sub-Adviser or its affiliated person by the Fund, or its respective Master Fund, in connection with the investment by the Investing Management Company in the Fund made at the direction of the Fund of Funds Sub-Adviser. In the event that the Fund of Funds Sub-Adviser waives fees, the benefit of the waiver will be passed through to the Investing Management Company.
6. No Fund of Funds or Fund of Funds Affiliate (except to the extent it is acting in its capacity as an investment adviser to a Fund) will cause a Fund, or its respective Master Fund, to purchase a security in any Affiliated Underwriting.
7. The Board of a Fund, or its respective Master Fund, including a majority of the non-interested Board members, will adopt procedures reasonably designed to monitor any purchases of securities by the Fund, or its respective Master Fund, in an Affiliated Underwriting, once an investment by a Fund of Funds in the securities of the Fund exceeds the limit of section 12(d)(1)(A)(i) of the Act, including any purchases made directly from an Underwriting Affiliate. The Board will review these purchases periodically, but no less frequently than annually, to determine whether the purchases were influenced by the investment by the Fund of Funds in the Fund. The Board will consider, among other things: (i) Whether the purchases were consistent with the investment objectives and policies of the Fund, or its respective Master Fund; (ii) how the performance of securities purchased in an Affiliated Underwriting compares to the performance of comparable securities purchased during a comparable period of time in underwritings other than Affiliated Underwritings or to a benchmark such as a comparable market index; and (iii)
8. Each Fund, or its respective Master Fund, will maintain and preserve permanently in an easily accessible place a written copy of the procedures described in the preceding condition, and any modifications to such procedures, and will maintain and preserve for a period of not less than six years from the end of the fiscal year in which any purchase in an Affiliated Underwriting occurred, the first two years in an easily accessible place, a written record of each purchase of securities in Affiliated Underwritings once an investment by a Fund of Funds in the securities of the Fund exceeds the limit of section 12(d)(1)(A)(i) of the Act, setting forth from whom the securities were acquired, the identity of the underwriting syndicate's members, the terms of the purchase, and the information or materials upon which the Board's determinations were made.
9. Before investing in a Fund in excess of the limit in section 12(d)(1)(A), a Fund of Funds and the Trust will execute a FOF Participation Agreement stating, without limitation, that their respective boards of directors or trustees and their investment advisers, or trustee and Sponsor, as applicable, understand the terms and conditions of the order, and agree to fulfill their responsibilities under the order. At the time of its investment in Shares of a Fund in excess of the limit in section 12(d)(1)(A)(i), a Fund of Funds will notify the Fund of the investment. At such time, the Fund of Funds will also transmit to the Fund a list of the names of each Fund of Funds Affiliate and Underwriting Affiliate. The Fund of Funds will notify the Fund of any changes to the list of the names as soon as reasonably practicable after a change occurs. The Fund and the Fund of Funds will maintain and preserve a copy of the order, the FOF Participation Agreement, and the list with any updated information for the duration of the investment and for a period of not less than six years thereafter, the first two years in an easily accessible place.
10. Before approving any advisory contract under section 15 of the Act, the board of directors or trustees of each Investing Management Company including a majority of the disinterested directors or trustees, will find that the advisory fees charged under such contract are based on services provided that will be in addition to, rather than duplicative of, the services provided under the advisory contract(s) of any Fund, or its respective Master Fund, in which the Investing Management Company may invest. These findings and their basis will be fully recorded in the minute books of the appropriate Investing Management Company.
11. Any sales charges and/or service fees charged with respect to shares of a Fund of Funds will not exceed the limits applicable to a fund of funds as set forth in NASD Conduct Rule 2830.
12. No Fund, or its respective Master Fund, will acquire securities of an investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act in excess of the limits contained in section 12(d)(1)(A) of the Act, except to the extent (i) the Fund, or its respective Master Fund, acquires securities of another investment company pursuant to exemptive relief from the Commission permitting the Fund, or its respective Master Fund, to acquire securities of one or more investment companies for short-term cash management purposes, (ii) the Fund acquires securities of the Master Fund pursuant to the Master-Feeder Relief, or (iii) the Fund invests in a Wholly-Owned Subsidiary that is a wholly-owned and controlled subsidiary of the Fund (or its respective Master Fund) as described in the Application. Further, no Wholly-Owned Subsidiary will acquire securities of any other investment company or company relying on section 3(c)(1) or 3(c)(7) of the Act other than money market funds that comply with rule 2a-7 for short-term cash management purposes.
For the Commission, by the Division of Investment Management, under delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to amend Rule 21.15, Data Dissemination, in connection with the operation BZX Options, as described below. In connection with this change the Exchange also proposes to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1. Finally, the Exchange also proposes a related change to Rule 20.6.
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these
The Exchange is proposing to modify Rule 21.15, Data Dissemination, which sets forth information regarding quotations and data feeds provided by BZX Options. Specifically, the Exchange proposes to adopt new paragraph (c) to provide information regarding the existence of Priority Customer interest on the BZX order book (“BZX Book”). In connection with this change the Exchange also proposes to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1. Finally, the Exchange also proposes a related change to Rule 20.6.
As proposed, the Exchange will make available to all market participants through the Options Price Reporting Authority (“OPRA”) an indication that there is Priority Customer interest included in the best bid or offer (“BBO”) disseminated by the Exchange. Further, the Exchange will identify Priority Customer orders and trades as such on messages disseminated by the Exchange through its Multicast PITCH data feed. The proposed rule is similar to and based on Rule 21.15(c) of the Exchange's affiliated options exchange, the options platform operated by Bats EDGX Exchange, Inc. (“EDGX Options”).
The Exchange notes that EDGX Options Rule 21.15(c) is identical to the proposed rule with the exception that EDGX Options Rule 21.15(c) currently refers to Customers, which term also includes broker-dealers and Public Customers, rather than Priority Customers as proposed by the Exchange. The Exchange notes that simultaneous with this proposal, Bats EDGX Exchange, Inc. is filing a proposal to modify Rule 21.15 to change the reference in such rule to “Priority Customer” and to adopt definitions of “Priority Customer” and “Priority Customer Order.”
In addition to the change described above, the Exchange proposes to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1 and to use such defined terms in proposed Rule 21.15(c). As proposed, a Priority Customer would mean any person or entity that is not: (A) a broker or dealer in securities; or (B) a Professional.
The Exchange proposes to adopt the definition of Priority Customer to exclude both broker-dealers and Professionals. This change is consistent with the Exchange's fee schedule, which already excludes Professionals from the definition of the term Customer for purposes of pricing on the Exchange.
In addition to the proposed changes described above, the Exchange also proposes to modify Rule 20.6(a)(1) to use the defined term of “Professional” rather than the term “Professional Customer,” which is not defined in Rule 16.1.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change does not introduce any burden on competition, but rather, would allow the Exchange to provide information provided by other option exchanges regarding the existence of customer interest on the order book.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
Because the proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become
A proposed rule change filed under Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange filed a proposal to make a modification to Rule 21.1 (Definitions) in connection with the operation of the attribution feature of EDGX Options, as described below. In addition, the Exchange proposes to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1 and to use such definitions throughout Rules 21.8, 21.10 and 21.15. Finally, the Exchange also proposes related changes to Rules 20.6 and 21.8.
The text of the proposed rule change is available at the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in Sections A, B, and C below, of the most significant parts of such statements.
As further described below, the Exchange is proposing to modify Rule 21.1(c) to remove the limitation related to Customer orders to allow such orders to be Attributable Orders (as such terms are defined below). In addition, the Exchange proposes to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1 and to use such definitions throughout Rules 21.8, 21.10 and 21.15. Finally, the Exchange also proposes related changes to Rules 20.6 and 21.8.
The Exchange is proposing to modify Rule 21.1, Definitions, which sets forth the various definitions applicable to the operation of the EDGX Options platform, including order types and order type modifiers accepted by EDGX Options. As set forth in Rule 21.1, an order can be attributed on EDGX Options, meaning that such order is displayed with not only a price and size but also a User's
Recently, the Exchange modified Rule 21.1(c) to limit the use of Attributable Orders to non-Customers, thereby eliminating the ability for a Customer Order to also be an Attributable Order.
In addition to the change described above, the Exchange proposes changes to Rules 16.1 to adopt definitions of “Priority Customer” and “Priority Customer Order” in Rule 16.1 and to use such definitions throughout Rules 21.8, 21.10 and 21.15. Specifically, in such Rules, the Exchange proposes to use the terms “Priority Customer” and “Priority Customer Order”, respectively, in place of the terms “Customer” and “Customer Order”. As proposed, a Priority Customer would mean any person or entity that is not: (A) A broker or dealer in securities; or (B) a Professional (as defined below). In turn, a Priority Customer Order would means an order for the account of a Priority Customer. The proposed definitions are similar to and based on the definitions of the same terms set forth in MIAX Rule 100. The Exchange proposes to adopt these new definitions in new paragraph (a)(45) and to re-number existing paragraphs (a)(45) through (a)(47) as paragraphs (a)(46) through (a)(48). In addition, because the defined term “Public Customer Order” is not currently utilized in Exchange Rules, the Exchange proposes to delete this definition, which is currently contained in paragraph (a)(48).
Pursuant to Rule 16.1(a)(19) a “Customer” is defined as a Public Customer or a broker-dealer. Under Rule 16.1(a)(47), a “Public Customer” is defined as a person that is not a broker or dealer in securities (“broker-dealer”). The Exchange separately defines a “Professional” as any person or entity that (A) is not a broker or dealer in securities, and (B) places more than 390 orders in listed options per day on average during a calendar month for its own beneficial account(s). The Exchange proposes to adopt the definition of Priority Customer to exclude both broker-dealers and Professionals. This change is consistent with the Exchange's fee schedule, which already excludes Professionals from the definition of the term Customer for purposes of pricing on the Exchange.
In addition, the Exchange proposes to modify Rules 21.8, 21.10, and 21.15 to refer to “Priority Customer” rather than “Customer” and “Priority Customer Order” rather than “Customer Order”, to more closely reflect the Exchange's current implementation of the Rules, which follows the definition of Customer on the Exchange's fee schedule and in Rule 20.6(a)(1) by excluding broker-dealers and Professionals. As noted above, the Exchange is also proposing to replace the phrase “Customer Order”, or in some instances “Customer order,” with the phrase “Priority Customer Order”.
The Exchange believes that each of these changes will more closely align the Exchange's rules with the Exchange's implementation of the Rules and the rules of other options exchanges.
To ensure clarity, the Exchange proposes related changes to Rule 21.8(d)(1) and Rule 21.8(e). Specifically, the Exchange proposes to restate the priority of Priority Customers as priority “over orders on behalf of all other types of participants” and to define all such other participants as non-Customers. As above, this change conforms the Rule to the Exchange's implementation of the Rule as well as the way that the Exchange believes the Rule was proposed and approved when read in light of Rule 21.8(e). The Exchange believes that the amended Rule, however, sets forth in a more clear fashion the fact that all other participants other than Priority Customers, including Professionals and broker-dealers, are considered as non-Customers for purposes of the Rule. Based on this proposed change, the Exchange also proposes to remove the reference to “non-Customers, including Professional Customers” in Rule 21.8(e) and to instead refer to the definition of non-Customer that is proposed to be added to Rule 21.8(d)(1).
In addition to the proposed changes to utilize the term Priority Customer instead of Customer and the term Priority Customer Order instead of Customer Order in the Rules listed above, the Exchange also proposes to modify Rule 20.6(a)(1) to use the defined term of “Professional” rather than the term “Professional Customer,” which is not defined in Rule 16.1.
The Exchange believes that its proposal is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange, and, in particular, with the requirements of Section 6(b) of the Act.
The proposed rule change will allow the Exchange to accept Attributable Orders from all market participants, including Priority Customers, while also designating Priority Customer orders as such on applicable data feeds. As set forth above, the Exchange recently limited the use of Attributable Orders to non-Customers due to systems limitations but is now proposing to remove this limitation. The Exchange is therefore seeking to re-introduce the feature that was originally intended in connection with the launch of EDGX Options. The proposed rule change will also achieve consistency with respect to the use of the term “Priority Customer” and “Priority Customer Order” both internally in aligning with the implementation of such Rules as well as with the rules of other options exchanges. As set forth above, each of the changes proposed above will align the Exchange's Rules with the current implementation of the Rules but will do so in a way that will avoid confusion regarding the application of the definitions used in such Rules. The Exchange believes that the proposed change is consistent with the Act for the reasons set forth above.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change is intended to make a modification to the Exchange's attribution offering to again permit Attributable Orders on behalf of all market participants, including Priority Customers. As noted above, this was the original intent when the Exchange's rules for EDGX Options were originally approved. The Exchange does not believe that such proposal, or the proposal to adopt the definitions of Priority Customer and Priority Customer Order as described above, will result in rules that are different than the rules of other options exchanges but rather that such rules will be better aligned with the implementation of the Exchange's Rules as well as the rules of other options exchanges.
The Exchange has not solicited, and does not intend to solicit, comments on this proposed rule change. The Exchange has not received any written comments from members or other interested parties.
Because the proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, the proposed rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to amend FINRA Rule 6184 (Transactions in Exchange-Traded Managed Fund Shares (“NextShares”)) to provide that the FINRA/Nasdaq Trade Reporting Facility (“FINRA/Nasdaq TRF”) will make available to market participants a daily file with the final trade price for each over-the-counter transaction in exchange-traded managed fund shares (“NextShares”) reported to the FINRA/Nasdaq TRF for public dissemination purposes.
Below is the text of the proposed rule change. Proposed new language is in italics; proposed deletions are in brackets.
(a) through (d) No Change.
Members that clear transactions in NextShares directly at NSCC,
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
FINRA recently adopted Rule 6184
In SR-NASDAQ-2015-036, Nasdaq stated that after a NextShares Fund's NAV is calculated, Nasdaq will price each NextShares trade executed on the exchange during the day at the Fund's NAV plus or minus the trade's executed premium or discount.
Similarly, Nasdaq, Inc., as the “Business Member” under the limited liability company agreement with FINRA establishing the FINRA/Nasdaq TRF, has determined to make available to market participants a daily file in FTP format with the final NAV-adjusted trade price for each OTC transaction in NextShares reported during the trading day to the FINRA/Nasdaq TRF for public dissemination purposes. Nasdaq has represented to FINRA that the daily FTP files will be accessible at no cost to market participants on Nasdaq's public Web site. FINRA is proposing to amend Rule 6184.02 to reflect the proposed FTP file.
FINRA has filed the proposed rule change for immediate effectiveness and proposes that the operative date will be on or about April 4, 2016, the date that the systems development work to support the proposed FTP file is expected to be completed by the FINRA/Nasdaq TRF.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change will enhance the pricing information relating to OTC transactions in NextShares available to market participants. The proposed rule change will not impose any reporting or other requirements on member firms, and as a result, will have no impact on member firms from a systems development and reporting perspective. Member firms that choose to trade NextShares may incur some costs to integrate the pricing information that will be provided pursuant to the proposed rule change. However, FINRA anticipates these costs to be minor because the pricing information will be accessible at no cost to market participants on Nasdaq's public Web site and also provided through data vendors, and firms will factor in any attendant costs when making the decision to enter into the market for NextShares.
Written comments were neither solicited nor received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) normally does not become operative before 30 days from the date of the filing. However, pursuant to Rule 19b-4(f)(6)(iii),
FINRA has asked the Commission to waive the 30-day operative delay. The Commission believes that waiving the 30-day operative delay is consistent with the protection of investors and the public interest. Such waiver will allow the proposed rule change to become operative on or about April 4, 2016, the date that Nasdaq has designated (and represented to FINRA) as the date by which it will complete the systems development work to support the proposed FTP file. This will ensure that additional pricing information relating to OTC transactions in NextShares will be available to market participants without delay and will supplement the FTP file that is already available for trades in NextShares executed on the Nasdaq exchange. Therefore, the Commission hereby waives the 30-day operative delay and designates the proposed rule change to be operative on or about April 4, 2016.
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is: (i) Necessary or appropriate in the public interest; (ii) for the protection of investors; or (iii) otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to the provisions of Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange is filing a proposal to amend the Exchange's Amended and Restated By-Laws.
The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend its Amended and Restated By-Laws (“By-Laws”) to eliminate the last sentence of Article II, Section 2.2(d),
This restriction was added to the By-Laws in connection with the Equity Rights Program (“ERP”)
MIAX has found that potential conflicts of interest are best addressed through such vehicles as the covenant of good faith and fair dealing and fiduciary duties applicable to limited liability company (“LLC”) managers under the Delaware Limited Liability Company Act (“LLC Act”)
Further, MIAX has reviewed the rules of other U.S. securities option exchanges and noted that most other option exchanges do not restrict their board (or other governing body) members from sitting on the board of directors or other governing body of another options exchange.
MIAX believes that this proposed rule change is consistent with Section 6(b) of the Act
MIAX is proposing to eliminate the restriction in its By-Laws prohibiting a Director, Observer or committee member of the Exchange's Board of Directors from simultaneously serving as a member of the governing body of a competitor. This proposed rule change is consistent with and will facilitate a Board structure and composition by MIAX that will strengthen its ability to carry out the purposes of the Act and comply with the provisions of the Act and the rules and regulations thereunder, and to enforce compliance by Exchange Members and persons associated with Exchange Members with the provisions of the Act and the rules and regulations thereunder and the rules of the Exchange. This proposed rule change is also consistent with the
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed change to the By-Laws relates to the corporate governance of MIAX, and as such, is not a competitive filing and does not impose a burden on competition.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On February 5, 2016, NYSE Arca, Inc. filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
Section 19(b)(2) of the Act
The Commission finds that it is appropriate to designate a longer period within which to take action on the proposed rule change so that it has sufficient time to consider the proposed rule change. Accordingly, the Commission, pursuant to Section 19(b)(2) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
U.S. Small Business Administration (SBA).
Notice of open Federal Advisory Committee meetings.
The SBA is issuing this notice to announce the location, date, time and agenda for the initial meeting of the Council on Underserved Communities (CUC) Advisory Board.
The meeting will be held on Monday, April 25th at 1:00 p.m. EST.
The meeting will be held at the U. S. Small Business Administration, in the Administrator's Large Conference Room, located at 409 3rd St. SW., Suite 7000, Washington, DC 20416.
The meeting is open to the public however advance notice of attendance is requested. Anyone wishing to be a listening participant must contact DeJuana L. Thompson by phone or email. Her contact information is DeJuana Thompson, Senior Advisor for Public Engagement, 409 Third Street SW., Washington, DC 20416, Phone, 202-205-6920, email,
Pursuant to section 10(a) of the Federal Advisory Committee Act (5 U.S.C. Appendix 2), SBA announces the meeting of the Council on Underserved Communities Advisory Board. This Board provides advice and counsel to the SBA Administrator and Associate Administrator. CUC members will examine the obstacles facing small businesses in underserved communities and recommend to SBA policy and programmatic changes to help strengthen SBA's programs and services to these communities.
The purpose of this meeting is to discuss following issues pertaining to the CUC Advisory Board.:
Tennessee Valley Authority (TVA).
Notice of charter renewal.
Pursuant to the Federal Advisory Committee Act (FACA) (5 U.S.C. Appendix 2), the TVA Board of Directors has renewed the Regional Resource Stewardship Council (Council) charter for an additional two years. The charter for the Ninth Term begins on April 29, 2016.
Beth A. Keel, 400 West Summit Hill Drive, WT 9D-K, Knoxville, Tennessee 37902-1499, (865) 632-6113.
Pursuant to FACA and its implementing regulations, and following consultation with the Committee Management Secretariat, General Services Administration (GSA), notice is hereby given that the Council has been renewed for a two-year period beginning April 29, 2016. The Council will provide advice to TVA on its issues affecting natural resource stewardship activities.
Numerous public and private entities are traditionally involved in the stewardship of the natural resources of the Tennessee Valley region. The Council was originally established in 1999 to advise TVA on its natural resource stewardship activities through balanced and broad range of diverse views and interests. It has been determined that the Council continues to be needed to provide an additional mechanism for public input regarding stewardship issues.
Tennessee Valley Authority (TVA).
Notice of meeting.
The TVA Regional Resource Stewardship Council (RRSC) will hold a meeting on Tuesday, April 26, 2016, to consider various matters.
The RRSC was established to advise TVA on its natural resource stewardship activities. Notice of this meeting is given under the Federal Advisory Committee Act (FACA), 5 U.S.C. App. 2.
The meeting agenda includes the following:
The RRSC will hear opinions and views of citizens by providing a public comment session starting at 10:15 a.m., EDT, on Tuesday, April 26. Persons wishing to speak are requested to register at the door by 9:45 a.m. EDT on Tuesday, April 26 and will be called on during the public comment period. Handout materials should be limited to one printed page. Written comments are also invited and may be mailed to the Regional Resource Stewardship Council, Tennessee Valley Authority, 400 West Summit Hill Drive, WT-9 D, Knoxville, Tennessee 37902.
The public meeting will be held on Tuesday, April 26, from 8:30 a.m. to 2:30 p.m. EDT.
The meeting will be held at the Tennessee Valley Authority Auditorium, 400 West Summit Hill Drive, Knoxville, Tennessee 37902, and will be open to the public. Anyone needing special access or accommodations should let the contact below know at least a week in advance.
Beth Keel, 400 West Summit Hill Drive, WT-9 D, Knoxville, Tennessee 37902, (865) 632-6113.
Internal Revenue Service (IRS), Treasury.
Notice of meeting.
An open meeting of the Taxpayer Advocacy Panel Tax Forms and Publications Project Committee will be conducted. The Taxpayer Advocacy Panel is soliciting public comments, ideas and suggestions on improving customer service at the Internal Revenue Service.
The meeting will be held Tuesday, April 19, 2016.
Donna Powers at 1-888-912-1227 or (954) 423-7977.
Notice is hereby given pursuant to section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. (1988) that an open meeting of the Taxpayer Advocacy Panel Tax Forms and Publications Project Committee will be held Tuesday, April 19 at 2:00 p.m.. Eastern Time via teleconference. The public is invited to make oral comments or submit written statements for consideration. Due to limited conference lines, notification of intent to participate must be made with Donna Powers. For more information please contact: Donna Powers at 1-888-912-1227 or (954) 423-7977 or write: TAP Office, 1000 S. Pine Island Road, Plantation, FL 33324 or contact us at the Web site:
Internal Revenue Service (IRS), Treasury.
Notice of meeting.
An open meeting of the Taxpayer Advocacy Panel Tax Forms and Publications Project Committee will be conducted. The Taxpayer Advocacy Panel is soliciting public comments, ideas and suggestions on improving customer service at the Internal Revenue Service.
The meeting will be held Monday, April 18, 2016.
Donna Powers at 1-888-912-1227 or (954) 423-7977.
Notice is hereby given pursuant to section 10(a)(2) of the Federal Advisory Committee Act, 5 U.S.C. App. (1988) that an open meeting of the Taxpayer Advocacy Panel Tax Forms and Publications Project Committee will be held Monday, April 18 at 2:00 p.m. Eastern Time via teleconference. The public is invited to make oral comments or submit written statements for consideration. Due to limited conference lines, notification of intent to participate must be made with Donna Powers. For more information please contact: Donna Powers at 1-888-912-1227 or (954) 423-7977 or write: TAP Office, 1000 S. Pine Island Road, Plantation, FL 33324 or contact us at the Web site:
In accordance with section 999(a)(3) of the Internal Revenue Code of 1986, the Department of the Treasury is publishing a current list of countries which require or may require participation in, or cooperation with, an international boycott (within the meaning of section 999(b)(3) of the Internal Revenue Code of 1986).
On the basis of the best information currently available to the Department of the Treasury, the following countries require or may require participation in, or cooperation with, an international boycott (within the meaning of section 999(b)(3) of the Internal Revenue Code of 1986).
Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).
Notice of proposed rulemaking.
This Notice of Proposed Rulemaking (NPRM) proposes to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines. PHMSA proposes changes to the integrity management (IM) requirements and proposes changes to address issues related to non-IM requirements. This NPRM also proposes modifying the regulation of onshore gas gathering lines.
Persons interested in submitting written comments on this NPRM must do so by June 7, 2016.
You may submit comments identified by the docket number PHMSA-2011-0023 by any of the following methods:
•
•
•
Mike Israni, by telephone at 202-366-4571, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP-30, Washington, DC 20590-0001.
PHMSA believes that the current regulatory requirements applicable to gas pipeline systems have increased the level of safety associated with the transportation of gas. Still, incidents with significant consequences and various causes continue to occur on gas pipeline systems. PHMSA has also identified concerns during inspections of gas pipeline operator programs that indicate a potential need to clarify and enhance some requirements. Based on this experience, this NPRM proposes additional safety measures to increase the level of safety for those pipelines that are not in HCAs as well as clarifications and selected enhancements to integrity management requirements to improve safety in HCAs.
On August 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) to seek feedback and comments regarding the revision of the Pipeline Safety Regulations applicable to the safety of gas transmission and gas gathering pipelines. In particular, PHMSA requested comments regarding whether integrity management (IM) requirements should be changed and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements.
Subsequent to issuance of the ANPRM, the National Transportation Safety Board (NTSB) adopted its report on the San Bruno accident on August 30, 2011. The NTSB issued safety recommendations P-11-1 and P-11-2 and P-11-8 through -20 to PHMSA, and issued safety recommendations P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others. Several of these NTSB recommendations related directly to the topics addressed in the August 25, 2011 ANPRM and have an impact on the proposed approach to rulemaking. Also subsequent to issuance of the ANPRM, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the Act) was enacted on January 3, 2012. Several of the Act's statutory requirements related directly to the topics addressed in the August 25, 2011 ANPRM and have an impact on the proposed approach to rulemaking.
Congress has authorized Federal regulation of the transportation of gas by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101
Congress established the current framework for regulating pipelines transporting gas in the Natural Gas Pipeline Safety Act of 1968, Public Law 90-481. That law delegated to DOT the authority to develop, prescribe, and enforce minimum Federal safety standards for the transportation of gas, including natural gas, flammable gas, or toxic or corrosive gas, by pipeline. Congress has since enacted additional legislation that is currently codified in the Pipeline Safety Laws, including:
In 1992, Congress required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” Public Law 102-508. In 1996, Congress directed that DOT conduct demonstration projects evaluating the application of risk management principles to pipeline safety regulation, and
PHMSA plans to address several of the topics in the ANPRM in separate rulemakings because of the diverse scope and nature of several NTSB recommendations and the statutory requirements of the Act that were covered in the ANPRM. This proposed rule addresses several IM topics, including: Revision of IM repair criteria for pipeline segments in HCAs to address cracking defects, non-immediate corrosion metal loss anomalies, and other defects; explicitly including functional requirements related to the nature and application of risk models currently invoked by reference to industry standards; explicitly specifying requirements for collecting, validating, and integrating pipeline data models currently invoked by reference to industry standards; strengthening requirements for applying knowledge gained through the IM Program models currently invoked by reference to industry standards; strengthening requirements on the selection and use of direct assessment methods models by incorporating recently issued industry standards by reference; adding requirements for monitoring gas quality and mitigating internal corrosion, and adding requirements for external corrosion management programs including above ground surveys, close interval surveys, and electrical interference surveys; and explicitly including requirements for management of change currently invoked by reference to industry standards. With respect to non-IM requirements, this NPRM proposes: A new “moderate consequence areas” definition; adding requirements for monitoring gas quality and mitigating internal corrosion; adding requirements for external corrosion management programs including above ground surveys, close interval surveys, and electrical interference surveys; additional requirements for management of change, including invoking the requirements of ASME/ANSI B31.8S, Section 11; establishing repair criteria for pipeline segments located in areas not in an HCA; and requirements for verification of maximum allowable operating pressure (MAOP) in accordance with new § 192.624 and for verification of pipeline material in accordance with new section § 192.607 for certain onshore, steel, gas transmission pipelines. This includes establishing and documenting MAOP if the pipeline MAOP was established in accordance with § 192.619(c) or the pipeline meets other criteria indicating a need for establishing MAOP.
In addition, this NPRM proposes modifying the regulation of onshore gas gathering lines. The proposed rulemaking would repeal the exemption for reporting requirements for gas gathering line operators and repeal the use of API RP 80 for determining regulated onshore gathering lines and add a new definition for “onshore production facility/operation” and a revised definition for “gathering lines.” The proposed rulemaking would also extend certain part 192 regulatory requirements to Type A lines in Class 1 locations for lines 8 inches or greater. Requirements that would apply to previously unregulated pipelines meeting these criteria would be limited to damage prevention, corrosion control (for metallic pipe), public education program, maximum allowable operating pressure limits, line markers, and emergency planning.
This NPRM also proposes requirements for additional topics that have arisen since issuance of the ANPRM. These include: (1) Requiring inspections by onshore pipeline operators of areas affected by an extreme weather event such as a hurricane or flood, landslide, an earthquake, a natural disaster, or other similar event; (2) revising the regulations to allow extension of the IM 7-year reassessment interval upon written notice per Section 5 of the Act; (3) adding a requirement to report each exceedance of the MAOP that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices per Section 23 of the Act; (4) adding requirements to ensure consideration of seismicity of the area in identifying and evaluating all potential threats per Section 29 of the Act; (5) adding regulations to require safety features on launchers and receivers for in-line inspection, scraper, and sphere facilities; and (6) incorporating consensus standards into the regulations for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment.
The overall goal of this proposed rule is to increase the level of safety associated with the transportation of gas by proposing requirements to address the causes of recent incidents with significant consequences, clarify and enhance some existing requirements, and address certain statutory mandates of the Act and NTSB recommendations.
Consistent with Executive Orders 12866 and 13563, PHMSA has prepared an assessment of the benefits and costs of the proposed rule as well as reasonable alternatives. PHMSA is publishing the Preliminary Regulatory Impact Analysis (PRIA) for this proposed rule simultaneously with this document, and it is available in the docket.
PHMSA estimates the total (15-year) present value of benefits from the proposed rule to be approximately $3,234 to $3,738 million
For the seven percent discount rate scenario, approximately 13 percent of benefits are due to safety benefits from incidents averted, 82 percent represent cost savings from MAOP verification in Topic Area 1, and four percent are attributable to reductions in greenhouse gas emissions. (For the three percent discount rate scenario, these percentages are approximately 13, 83, and 3 percent, respectively.)
The significant and expected growth in the nation's production and use of natural gas is placing unprecedented demands on the nation's pipeline system, underscoring the importance of moving this energy product safely and efficiently. With changing spatial patterns of natural gas production and use and an aging pipeline network, improved documentation and data collection are increasingly necessary for the industry to make reasoned safety choices and for preserving public confidence in its ability to do so. Congress recognized these needs when passing the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, calling for an examination of a broad range of issues pertaining to the safety of the nation's pipeline network, including a thorough application of the risk-based integrity assessment, repair, and validation system known as “integrity management” (IM).
This proposed rulemaking advances the goals established by Congress in the 2011 Act, which are consistent with the emerging needs of the natural gas pipeline system. This proposed rule also advances an important discussion about the need to adapt and expand risk-based safety practices in light of changing markets and a growing national population whose location choices increasingly encroach on existing pipelines. As some severe pipeline accidents have occurred in areas outside of high consequence areas (HCA) where the application of IM principles is not required, and as gas pipelines continue to experience failures from causes that IM was intended to address, this conversation is increasingly important.
This proposed rule strengthens protocols for IM, including protocols for inspections and repairs, and improves and streamlines information collection to help drive risk-based identification of the areas with the greatest safety deficiencies. Further, this proposed rule establishes requirements to periodically assess and extend aspects of IM to pipeline segments in locations where the surrounding population is expected to potentially be at risk from an incident. Even though these segments are not within currently defined HCAs, they could be located in areas with significant populations where incidents could have serious consequences. This change would facilitate prompt identification and remediation of potentially hazardous defects and anomalies while still allowing operators to make risk-based decisions on where to allocate their maintenance and repair resources.
The U.S. natural gas pipeline network is designed to transport natural gas to and from most locations in the lower 48 States. Approximately two-thirds of the lower 48 States depend almost entirely on the interstate transmission pipeline system for their supplies of natural gas.
Gas gathering lines are pipelines used to transport natural gas from production sites to central collection points, which are often gas treatment plants where pipeline-quality gas is separated from petroleum liquids and various impurities. Historically, these lines were of smaller diameters than gas transmission lines and operated at lower pressures. However, due to changing demand factors, some gathering lines are being constructed with diameters equal to or larger than typical transmission lines and are being operated at much higher pressures.
Transmission pipelines primarily transport natural gas from gas treatment
PHMSA and its State partners regulate pipeline safety for jurisdictional
Federal regulation of gas pipeline safety began in 1968 with the creation of the Office of Pipeline Safety and their subsequent issuance of interim minimum Federal safety standards for gas pipeline facilities and the transportation of natural and other gas in accordance with the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). These Federal safety standards were upgraded several times over the following decades to address different aspects of natural gas transportation by pipeline, including construction standards, pipeline materials, design standards, class locations, corrosion control, and maximum allowable operating pressure (MAOP).
These original Pipeline Safety Regulations were not designed with risk-based regulations in mind. In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and the environment. During this time, PHMSA found that many operators were performing forms of IM that varied in scope and sophistication but that there were no minimum standards or requirements.
In response to a hazardous liquid incident in Bellingham, WA, in 1999 that killed 3 people and a gas transmission incident in Carlsbad, NM, in 2000 that killed 12, IM regulations for gas transmission pipelines were finalized in 2004.
The IM regulations specify how pipeline operators must conduct comprehensive analyses to identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs, which are typically areas where population is highly concentrated. Currently, approximately 7 percent of onshore gas transmission pipeline mileage is located in HCAs. PHMSA and state inspectors review operators' written IM programs and associated records to verify that the operators have used all available information about their pipelines to assess risks and take appropriate actions to mitigate those risks.
Since the implementation of the IM regulations more than 10 years ago, many factors have changed. Most importantly, sweeping changes in the natural gas industry have caused significant shifts in supply and demand, and the nation's relatively safe but aging pipeline network faces increased pressures from these changes as well as from the increased exposure caused by a growing and geographically dispersing population. Long-identified pipeline safety issues, some of which IM set out to address, remain problems. Infrequent but severe accidents indicate that some pipelines continue to be vulnerable to failures stemming from outdated construction methods or materials. Some severe pipeline accidents have occurred in areas outside HCAs where the application of IM principles is not required. Gas pipelines continue to experience failures from causes that IM was intended to address, such as corrosion, and the measures currently in use have not always been effective in identifying and preventing these causes of pipeline damage.
There is a pressing need for an improved strategy to protect the safety and integrity of the nation's pipeline system. Following a significant pipeline incident in 2010 at San Bruno, CA, in which 8 people died and more than 50 people were injured, Congress, the National Transportation Safety Board (NTSB), and the Government Accountability Office (GAO) charged PHMSA with improving IM. Comments from a 2011 advanced notice of proposed rulemaking (ANPRM) suggested there were many common-sense improvements that could be made to IM, as well as a clear need to extend certain IM provisions to pipelines not now covered by the IM regulations. A large portion of the transmission pipeline industry has voluntarily committed to extending certain IM provisions to non-HCA pipe, which clearly underscores the common understanding of the need for this strategy.
Through this proposed rule, PHMSA is taking action to deliver a comprehensive strategy to improve gas transmission pipeline safety and reliability, through both immediate improvements to IM and a long-range review of risk management and information needs, while also accounting for a changing landscape and a changing population.
The U.S. natural gas industry has undergone changes of unprecedented magnitude and pace, increasing production by 33 percent between 2005 and 2013, from 19.5 trillion cubic feet per year to 25.7 trillion cubic feet per year.
While conventional natural gas production in the U.S. has fallen over the past decade by about 14 billion cubic feet per day, overall natural gas production has grown due to increased unconventional shale gas production. In 2004, unconventional shale gas accounted for about 5 percent of the total natural gas production in the U.S. Since then, unconventional shale gas
This increase in unconventional natural gas production shifted production away from traditional gas-rich regions towards onshore shale gas regions. In 2004, the Gulf of Mexico produced about 20 percent of the nation's natural gas supply, but by2013, that number had fallen to 5 percent. During that same time, Pennsylvania's share of production grew from 1 percent to 13 percent. An analysis conducted by the Department of Energy's (DOE) Office of Energy Policy and Systems Analysis projects that the most significant increases in production through 2030 will occur in the Marcellus and Utica Basins in the Appalachian Basin,
The recent increase in domestic natural gas production has led to decreased gas price volatility and lower average prices.
These historically low prices for this commodity are fueling tremendous consumption growth and changes in markets and spatial patterns of consumption. A shift towards natural gas-fueled electric power generation is helping to serve the needs of the nation's growing population while helping reduce greenhouse gas emissions, and American industries are taking advantage of cheap energy by investing in onshore production capacity, while also exploring economic opportunities for international energy export.
Plentiful domestic natural gas supply and comparatively low natural gas prices have changed the economics of electric power markets.
Further, the increased availability of low-cost natural gas has brought jobs back to American soil, and increasing investment in projects designed to take advantage of the significant increase in supplies of low-cost gas available in the U.S. suggests this trend will continue.
Despite the significant increase in domestic gas production, the widespread distribution of domestic gas demand, combined with significant flexibility and capacity in the existing transmission system, mitigates the level of pipeline expansion and investment required to accommodate growing and shifting demand. Some of the new gas production is located near existing or emerging sources of demand, which reduces the need for additional natural gas pipeline infrastructure. In many instances where new natural gas pipelines are needed, the network is being expanded by participants pursuing lowest-cost options to move product to market—often making investments to enhance network capacity on existing lines rather than increasing coverage through new infrastructure. Where this capacity is not increasing via additional mileage, it is increasing through larger pipeline diameters or higher operating pressures. In short, the nation's existing, and in many cases, aging, pipeline system is facing the full brunt of this dramatic increase in natural gas supply and the shifting energy needs of the country.
The U.S. Energy Information Administration estimates that between 2004 and 2013, the natural gas industry spent about $56 billion expanding the natural gas pipeline network. Between 2008 and 2013, pipeline capacity additions totaled more than 110 Bcf/d.
Building new infrastructure, or replacing and modernizing old infrastructure, is expensive and requires a long lead-time for planning. Frequently, the most inexpensive way to move new production to demand centers is by using available existing infrastructure. For several reasons, the U.S.'s extensive pre-existing gas network is currently underutilized: (1) Pipelines are long-lived assets that reflect historic supply and demand trends; (2) pipelines often are sized to meet high initial production levels and
In cases where utilization of the existing pipeline network is high, the next most cost-effective solution is to add capacity to existing lines via compression. While this is technically a form of infrastructure investment, it is less costly, faster, and simpler for market participants in comparison to building a new pipeline. Adding compression, however, may raise average pipeline operating pressures, exposing previously hidden defects.
Developers also recognize that building new pipelines is challenging due to societal fears and cost, so new pipelines are typically designed in such a way that they can handle additional capacity if needed. In New England, new pipeline projects have been proposed to address pending supply constraints and higher prices. However, public acceptance presents a substantial challenge to natural gas pipeline development. Investments and proposals to pay for new natural gas transmission pipeline capacity and services often face significant challenges in determining feasible rights of way and developing community support for the projects.
Because there is so much emphasis on using the existing pipeline system to meet the country's energy needs, it is increasingly important for that system to be safe and efficient. In order to keep the public safe and to assure the nation's energy security, operators and regulators must have an intimate understanding of the threats to and operations of the entire pipeline system.
Data gathering and integration are important elements of good IM practices, and while many strides have been made over the years to collect more and better data, several data gaps still exist. Ironically, the comparatively positive safety record of the nation's pipeline system to date makes it harder to quantify some of these gaps. Over the 20-year period of 1995-2014, transmission facilities accounted for 42 fatalities and 174 injuries, or about one-seventh of the total fatalities and injuries on the nation's natural gas pipeline system.
On September 9, 2010, a 30-inch-diameter segment of an intrastate natural gas transmission pipeline owned and operated by the Pacific Gas and Electric Company ruptured in a residential area of San Bruno, California. The rupture produced a crater about 72 feet long by 26 feet wide. The section of pipe that ruptured, which was about 28 feet long and weighed about 3,000 pounds, was found 100 feet south of the crater. The natural gas that was released subsequently ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight people were killed, many were injured, and many more were evacuated from the area.
The San Bruno incident exposed several problems in the way data on pipeline conditions is collected and managed, showing that many operators have inadequate records regarding the physical and operational characteristics of their pipelines. Many of these records are necessary for the correct setting and validation of MAOP, which is critically important for providing an appropriate margin of safety to the public.
Much of operator and PHMSA's data is obtained through testing and inspection under IM requirements. However, this testing can be expensive, and the approaches to obtaining data that are most efficient over the long term may require significant upfront costs to modernize pipes and make them suitable for automated inspection. As a result, there continue to be data gaps that make it hard to fully understand the risks to and the integrity of the nation's pipeline system.
To assess a pipeline's integrity, operators generally choose between three methods of testing a pipeline: Inline inspection (ILI), pressure testing, and direct assessment (DA). There is a marked difference in the distribution of assessment methods between interstate and intrastate pipelines. In 2013, we estimate that about two-thirds of interstate pipeline mileage was suitable for in-line inspection, compared to only about half of intrastate pipeline mileage. Because a larger percentage of intrastate pipelines are unable to accommodate ILI tools, intrastate operators use more pressure testing and DA than interstate operators.
ILIs are performed by using special tools, sometimes referred to as “smart pigs,” which are usually pushed through a pipeline by the pressure of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can prevent excessive cost to the operator and possible service disruptions to consumers. Further, ILI is a non-destructive testing technique, and it can be less costly on a per-unit basis to perform than other assessment methods.
Pressure tests are typically used by pipeline operators as a means to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service, as well as periodically during a pipeline's operating life. In a pressure test, a test medium inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline.
Direct assessment (DA) is the evaluation of various locations on a pipeline for corrosion threats. Operators will review records, indirectly inspect the pipeline, or use mathematical models and environmental surveys to find likely locations on a pipeline where corrosion might be occurring. Areas that are likely to have suffered from corrosion are subsequently excavated and examined. DA can be prohibitively expensive to use unless targeting specific locations, which may not give an accurate representation of the condition of lengths of entire pipeline segments.
Ongoing research and industry response to the ANPRM
In this proposed rulemaking, PHMSA would expand the range of permissible assessment methods while imposing new requirements to guide operators' selection of appropriate methods. Allowing alternatives to hydrostatic testing (including ILI technologies), combined with further research and development to make ILI testing more accurate, could help to drive innovation in pipeline integrity testing technologies. This could eventually lead to improved safety and system reliability through better data collection and assessment.
While the existing pipeline network's capacity is expected to bear the brunt of the increasing demand for natural gas in this country, due in part due to the location of new gas resources, new production patterns are causing unique concerns for some pipeline operators. The significant growth of production outside the Gulf Coast region—especially in Pennsylvania and Ohio—is causing a reorientation of the nation's transmission pipeline network. The most significant of these changes will require reversing flows on pipelines to move Marcellus and Utica gas to the southeastern Atlantic region and the Midwest.
Reversing a pipeline's flow can cause added stresses on the system due to changes in pressure gradients, flow rates, and product velocity, which can create new risks of internal corrosion. Occasional failures on natural gas transmission pipelines have occurred after operational changes that include flow reversals and product changes. PHMSA has noticed a large number of recent or proposed flow reversals and product changes on a number of gas transmission lines. In response to this phenomenon, PHMSA issued an Advisory Bulletin notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline.
Further, the rise of shale gas production is altering not just the extent, but also the characteristics of the nation's gas gathering systems. Gas fields are being developed in new geographic areas, thus requiring entirely new gathering systems and expanded networks of gathering lines. Producers are employing gathering lines with diameters as large as 36 inches and maximum operating pressures up to 1480 psig, far exceeding historical design and operating pressure of typical gathering lines and making them similar to large transmission lines. Most of these new gas gathering lines are unregulated, and PHMSA does not collect incident data or report annual data on these unregulated lines.
However, PHMSA is aware of incidents that show gathering lines are subject to the same sorts of failures common to other pipelines that the agency does regulate. For example, on November 14, 2008, three homes were destroyed and one person was injured when a gas gathering line ruptured in Grady County, OK. On June 8, 2010, two workers died when a bulldozer struck a gas gathering line in Darrouzett, TX, and on June 29, 2010, three men working on a gas gathering line in Grady County, OK, were injured when it ruptured. The dramatic expansion in natural gas production and changes in typical gathering line characteristics require PHMSA to review its regulatory approach to gas gathering pipelines to address new safety and environmental risks.
In addition to demands placed on the nation's pipeline system due to increased and changing use, there are many other factors—including recurring issues that IM was initially developed to address—that affect the integrity of the nation's pipelines.
Data indicate that some pipelines continue to be vulnerable to issues stemming from outdated construction methods or materials. Much of the older line pipe in the nation's gas transmission infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process. For example, line pipe manufactured using low frequency electric resistance welding is susceptible to seam failure. Because these manufacturing techniques were used during the time before the Federal gas regulations were issued, many of those pipes are subsequently exempt from certain regulations, most notably the requirement to pressure test the pipeline or otherwise verify its integrity to establish MAOP. A substantial amount of this type of pipe is still in service. The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yet-severe failures that are attributed to longitudinal seam defects continue to occur. The NTSB's investigation of the San Bruno incident determined that the pipe failed due to a similar defect. Additionally, between 2010 and 2014, fifteen other reportable incidents were attributed to seam failures, resulting in over $8 million of property damage.
The nation's pipeline system also faces a greater risk from failure due to extreme weather events such as hurricanes, floods, mudslides, tornadoes, and earthquakes. A 2011 crude oil spill into the Yellowstone River near Laurel, MT, was caused by channel migration and river bottom scour, leaving a large span of the pipeline exposed to prolonged current forces and debris washing downstream in the river. Those external forces damaged the exposed pipeline. In October 1994, flooding along the San Jacinto River led to the failure of eight hazardous liquid pipelines and also undermined a number of other pipelines. The escaping products were ignited, leading to smoke inhalation and burn injuries of 547 people. From 2003 to 2013, there were 85 reportable incidents in which storms or other severe natural force conditions damaged pipelines and resulted in their failure. Operators reported total damages of over $104M from these incidents. PHMSA has issued several Advisory Bulletins to operators warning about extreme weather events and the consequences of flooding events, including river scour and river channel migration.
Considering recent incidents and many of the factors outlined above, PHMSA believes IM has led to several improvements in managing pipeline safety, yet the agency believes there is still more to do to improve the safety of natural gas transmission pipelines and ensure public confidence.
The current IM program is both a set of regulations and an overall regulatory approach to improve pipeline operators' ability to identify and mitigate the risks to their pipeline systems. The objectives of IM are to accelerate and improve the quality of integrity assessments, promote more rigorous and systematic management of integrity, strengthen oversight, and increase public confidence. On the operator level, an IM program consists of multiple
The initial definition for HCAs was finalized on August 6, 2002,
The incident at San Bruno in 2010 motivated a comprehensive reexamination of gas transmission pipeline safety. Congress responded to concerns in light of the San Bruno incident by passing the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which directed the DOT to reexamine many of its safety requirements, including the expansion of IM regulations for transmission pipelines.
Further, both the NTSB and the GAO issued several recommendations to PHMSA to improve its IM program and pipeline safety. The NTSB noted, in a 2015 study,
Many of these mandates and recommendations caused PHMSA to evaluate whether IM system requirements, or elements thereof, should be expanded beyond HCAs to afford protection to a larger percentage of the nation's population. Additionally, several of these mandates and recommendations asked PHMSA to enhance the existing IM regulations by addressing MAOP verification, inadequate operator records, legacy pipe issues, and inadequate integrity assessments. Further, PHMSA was charged with reducing data gaps and improving data integration, considering the regulatory framework for gas gathering systems, and deleting the “grandfather clause” to require all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic spike pressure test. This proposed rule addresses several of the recommendations from the 2015 study including P-15-18 (IM-ILI capability), P-15-20 (IM-ILI tools), P-15-21 (IM-Direct Assessments), and P-21 (IM-Data Integration).
To address these statutory mandates, the post-San Bruno NTSB and GAO recommendations, and other pipeline safety mandates, PHMSA posed a series of questions to the public in the context of an August 2011 ANPRM titled “Pipeline Safety: Safety of Gas Transmission Pipelines” (PHMSA-2011-0023). In that document, PHMSA asked whether the regulations governing the safety of gas transmission pipelines needed changing. In particular, PHMSA asked whether IM requirements should be changed, including through adding more prescriptive language in some areas, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. Among the specific issues PHMSA considered concerning IM requirements were whether the definition of an HCA should be revised, and whether additional restrictions should be placed on the use of specific pipeline assessment methods. In the ANPRM, PHMSA also considered changes to non-IM requirements, including valve spacing and installation, corrosion control, and whether regulations for gathering lines needed to be modified.
PHMSA received 103 comments in response to the ANPRM, which are summarized in more detail later in this document. Feedback from the ANPRM helped to identify a series of common-sense improvements to IM, including improvements to assessment goals such as integrity verification, MAOP verification, and material documentation; clarified repair criteria; clarified protocol for identifying threats, risk assessments and management, and prevention and mitigation measures; expanded and enhanced corrosion control; requirements for inspecting pipelines after incidents of extreme weather; and new guidance on how to calculate MAOP in order to set operating parameters more accurately and predict the risks of an incident.
Many of these aspects of IM have been an integral part of PHMSA's expectations since the inception of the IM program. As specified in the first IM rule, PHMSA expects operators to start with an IM framework, evolve a more detailed and comprehensive IM program, and continually improve their IM programs as they learn more about the IM process and the material condition of their pipelines through integrity assessments. This NPRM's proposals regarding operators' processes for implementing IM reflect PHMSA's expectations regarding the degree of progress operators should be making, or should have made, during the first 10 years of IM program implementation.
To address issues involving the increased risk posed by larger-diameter, higher-pressure gathering lines, PHMSA is proposing to issue requirements for certain currently unregulated gas gathering pipelines that are intended to prevent the most frequent causes of failure—corrosion and excavation damage—and to improve emergency response preparedness. Minimum Federal safety standards would also bring an appropriate level of consistency to the current mix of regulations that differ from state to state.
PHMSA believes these proposed changes will improve the safety and protection of pipeline workers, the public, property, and the environment by improving the detection and remediation of unsafe conditions, ensuring that certain currently unregulated pipelines are subject to appropriate regulatory oversight, and speeding mitigation of adverse effects of pipeline failures. In addition to safety benefits, the rule is expected to improve the performance and extend the economic life of critical pipeline infrastructure that transports domestically produced natural gas energy, thus supporting national economic and security energy objectives.
In addition to the common sense improvements to IM, responses to the ANPRM reinforced the importance of carefully reconsidering the scope of areas covered by IM. While PHMSA's IM program manages risks primarily by focusing oversight on areas with the greatest population density, responses to the ANPRM highlight the imperative of protecting the safety of communities throughout the country in light of a changing landscape of production, consumption, and product movement that merits a refreshed look at the current scope of IM coverage.
In the 2011 Act, Congress required PHMSA to have pipeline operators conduct a records verification to ensure that their records accurately reflect the physical and operational characteristics of pipelines in certain HCAs and class locations, and to confirm the established MAOP of the pipelines. The results of that action indicate that problems similar to the contributing factors of the San Bruno incident are more widespread than previously believed, affecting both HCA and non-HCA segments. This indicates that a rupture on the scale of San Bruno, with the potential to affect populations, the environment, or commerce, could occur elsewhere on the nation's pipeline system.
In fact, devastating incidents have occurred outside of HCAs in rural areas where populations are sparse but present. On August 19, 2000, a 30-inch-diameter gas transmission pipeline ruptured adjacent to the Pecos River near Carlsbad, NM. The released gas ignited and burned for 55 minutes. Twelve persons who were camping under a concrete-decked steel bridge that supported the pipeline across the river were killed, and their vehicles were destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river were damaged extensively.
On December 14, 2007, two men were driving in a pickup truck on Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline ruptured. One of the men was killed, and the other was injured.
On December 11, 2012, a 20-inch-diameter gas transmission line ruptured in a sparsely populated area about 106 feet west of Interstate 77 (I-77) in Sissonville, WV. An area of fire damage about 820 feet wide extended nearly 1,100 feet along the pipeline right-of-way. Three houses were destroyed by the fire, and several other houses were damaged. Reported losses, repairs, and upgrades from this incident totaled over $8.5 million, and major transportation delays occurred. I-77 was closed in both directions because of the fire and resulting damage to the road surface. The northbound lanes were closed for about 14 hours, and the southbound lanes were closed for about 19 hours while the road was resurfaced, causing delays to both travelers and commercial shipping.
Because the nation's population is growing, moving, and dispersing, population density is a changing measure, and we need to be prepared for further shifts in the coming decades. The current definition of an HCA uses building density as a proxy for approximating the presence of communities and surrounding infrastructure. This can be a meaningful metric for prioritizing implementation of safety and risk management protocols for areas where an accident would have the greatest likelihood of putting human life in danger, but it is not necessarily an accurate reflection of whether an incident will have a significant impact on people. Requiring assessment and repair criteria for pipelines that, if ruptured, could pose a threat to areas where any people live, work, or congregate would improve public safety and would improve public confidence in the nation's natural gas pipeline system.
Feedback from industry indicated that some pipeline operators are already moving towards expanding the protections of IM beyond HCAs. In 2012, the Interstate Natural Gas Association of America (INGAA) issued a “Commitment to Pipeline Safety,”
• Stage 1—INGAA members will complete an initial assessment using some degree of IM on their pipelines, covering 90% of the population living, working, or congregating along INGAA member pipelines, by the end of 2012. This represents roughly 64% of INGAA member pipeline mileage, including the 4% of pipelines that are in HCAs.
• Stage 2—By 2020, INGAA members will consistently and comprehensively apply IM principles to those pipelines.
• Stage 3—By 2030, INGAA members will apply IM principles to pipelines, extending IM protection to 100% of the population living along INGAA member pipelines. This stage would cover roughly 16% of pipeline mileage, bringing the total coverage by 2030 to approximately 80% of INGAA's pipeline mileage.
• Stage 4—Beyond 2030, INGAA members will apply IM principles to the remaining 20% of pipeline mileage where no population resides.
To accomplish this commitment, INGAA's members are performing actions that include applying risk management beyond HCAs; raising the standards for corrosion management; demonstrating “fitness for service” on pre-regulation pipelines; and evaluating, refining, and improving operators' ability to assess and mitigate safety threats. Ultimately, these actions aim to extend protection to people who live near pipelines but not within defined HCAs.
INGAA's commitment and other stakeholder feedback on this issue have triggered an important exchange about measuring the risks that exist in less-densely populated areas and the impacts of expanding greater protections to those areas. If constant improvement and zero incidents are goals for pipeline operators, INGAA's plan to extend and prioritize IM assessments and principles to all parts of their pipeline networks that are located near any concentrations of population is an effective way to achieve those goals. Such an approach is needed to help clarify vulnerabilities and prioritize improvements, and this proposed rulemaking takes important steps forward towards developing such an approach.
The question then, is how to implement risk management standards that most accurately target the safety of communities, while also providing sufficient ability to prioritize areas of greatest possible risk and/or impact. Addressing that question has been, and remains, an important part of this proposed rule, recognizing that the answer will remain fluid based on factors that continue to change.
Given INGAA's commitment, feedback from the ANPRM, the results of incident investigations, and IM considerations, PHMSA has determined it is appropriate to improve aspects of the current IM program and codify requirements for additional gas transmission pipelines to receive integrity assessments on a periodic basis to monitor for, detect, and remediate pipeline defects and anomalies. In addition, in order to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while minimizing the cost of identifying such locations, PHMSA proposes to base the requirements for identifying those locations on processes already being implemented by pipeline operators and that protect people on a risk-prioritized basis.
Establishing integrity assessment requirements and associated repair conditions for non-HCA pipe segments is important for providing safety to the public. Although those segments are not within defined HCAs, they will usually be located in populated areas, and pipeline accidents in these areas may cause fatalities, significant property damage, or disrupt livelihoods. This rulemaking proposes a newly defined moderate consequence area (MCA) to identify additional non-HCA pipeline segments that would require integrity assessments, thus assuring timely discovery and repair of pipeline defects in MCA segments. These changes would ensure prompt remediation of anomalous conditions that could potentially impact people, property, or the environment, and commensurate with the severity of the defects, while at the same time allowing operators to allocate their resources to HCAs on a higher-priority basis. INGAA's commitment and PHMSA's MCA definition are comparable, which shows a common understanding of the importance of this issue and a path towards a solution.
On August 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) to seek public comments regarding the revision of the Pipeline Safety Regulations applicable to the safety of gas transmission pipelines. In particular, PHMSA requested comments regarding whether integrity management (IM) requirements should be changed and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. The ANPRM may be viewed at
A. Modifying the Definition of HCA (to be addressed in separate rulemaking),
B. Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs (partially addressed in separate rulemaking—aspects related to Remote Control Valves and Leak Detection will be addressed in separate rulemaking, other aspects are being addressed in this NPRM),
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and Integrating Pipeline Data,
E. Making Requirements Related to the Nature and Application of Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through the IM Program,
G. Strengthening Requirements on the Selection and Use of Assessment Methods,
H. Valve Spacing and the Need for Remotely or Automatically Controlled Valves (to be addressed in separate rulemaking),
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage (to be considered for separate rulemaking),
L. Management of Change,
M. Quality Management Systems (QMS) (to be considered for separate rulemaking),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
A summary of comments and responses to those comments are provided later in the document.
On August 30, 2011, following the issuance of the ANPRM, the NTSB adopted its report on the gas pipeline accident that occurred on September 9, 2010, in San Bruno, California. On September 26, 2011, the NTSB issued safety recommendations P-11-8 through -20 to PHMSA, and issued safety recommendations P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others. The NTSB made these recommendations following its investigation of the tragic September 9, 2010 natural gas pipeline rupture in the city of San Bruno, California. Several of the NTSB recommendations related directly to the topics addressed in the August 25, 2011 ANPRM and impacted the proposed approach to rulemaking. The potentially impacted topics and the related NTSB recommendations include, but are not limited to:
• Topic B—Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs. NTSB Recommendation P-11-10: “
• Topic D—Improving Requirements for Collecting, Validating, and Integrating Pipeline Data. NTSB Recommendation P-11-19: “
• Topic G—Strengthening Requirements on the Selection and Use of Assessment Methods. NTSB Recommendation P-11-17: “
• Topic H—Valve Spacing and the Need for Remotely or Automatically Controlled Valves. NTSB Recommendation P-11-11: “
• Topic J—Pipe Manufactured Using Longitudinal Weld Seams. NTSB Recommendation P-11-15: “
• Topic N—Exemption of Facilities Installed Prior to the Regulations. NTSB Recommendation P-11-14:
Also subsequent to issuance of the ANPRM, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the Act) was enacted on January 3, 2012. Several of the Act's statutory requirements relate directly to the topics addressed in the August 25, 2011 ANPRM. The related topics and statutory citations include, but are not limited to:
○ Section 5(e)—Allow periodic reassessments to be extended for an additional 6 months if the operator submits sufficient justification.
○ Section 5(f)—Requires regulations issued by the Secretary, if any, to expand integrity management system requirements, or elements thereof, beyond high-consequence areas.
○ Section 21—Regulation of Gas (and Hazardous Liquid) Gathering Lines
○ Section 23—Testing regulations to confirm the material strength of previously untested natural gas transmission pipelines.
○ Section 29—Consider seismicity when evaluating pipeline threats.
This NPRM proposes new requirements and revisions to existing requirements to address topics discussed in the ANPRM, including some topics from the Act and the NTSB recommendations. Each topic area discussed in the ANPRM, as well as additional topics that have arisen since issuance of the ANPRM, is summarized below. Details of the changes proposed in this rule are discussed below in section V. Section-by-Section Analysis.
• Topic A—Modifying the Definition of HCA. The ANPRM requested comments regarding expanding the definition of an HCA so that more miles of pipe would be subject to IM requirements and so that all Class 3 and 4 locations would be subject to the IM requirements. The Act, Section 5, requires that the Secretary of Transportation complete an evaluation and issue a report on whether integrity management requirements should be expanded beyond HCAs and whether such expansion would mitigate the need for class location requirements. PHMSA has prepared the class location report and a copy is available in the docket (
Although PHMSA is not proposing to expand the definition of an HCA, PHMSA is proposing to expand certain IM requirements beyond HCAs by creating a new “moderate consequence areas (MCA).” MCAs would be used to define the subset of non-HCA pipeline locations where periodic integrity assessments are required (§ 192.710), where material documentation verification is required (§ 192.607), and where MAOP verification is required (§§ 192.619(e) and 192.624). The proposed criteria for determining MCA locations would use the same process and the same definitions as currently used to identify HCAs, except that the threshold for buildings intended for human occupancy and the threshold for persons that occupy other defined sites, that are located within the potential impact radius, would both be lowered from 20 to 5. The intention is that any pipeline location at which persons are normally expected to be located would be afforded extra safety protections described above. In addition, as a result of the Sissonville, West Virginia incident, NTSB issued recommendation P-14-01, to revise the gas regulations to add principal arterial roadways including interstates, other freeways and expressways, and other principal arterial roadways as defined in the Federal Highway Administration's
In addition, a major constituency of the pipeline industry (INGAA) has committed to apply IM principles to all segments where any persons are located. This is comparable to PHMSA's proposed MCA definition. PHMSA seeks comment on the relative merits of expanding High Consequence Areas
Another alternative PHMSA considered was a shorter a compliance deadline (10 years) and a shorter reassessment interval (15 years) for MCA assessments. The assessment timeframes in the proposed rule were selected based on a graded approach which would apply relaxed timeframes to MCAs, as compared to HCAs. The industry was originally required to perform baseline assessments for approximately 20,000 miles of HCA pipe within approximately 8 years from the effective date of the integrity management rule. PHMSA estimates that approximately 41,000 miles of pipe would require an assessment within 15 years under this proposed rule, thus constituting a comparable level of effort on the part of industry. The maximum HCA reassessment interval is 20 years for low stress pipe. The 20 year interval was selected to align with the longest interval allowed for any HCA pipe, which is 20 years for pipe operating less than 30% SMYS. A reassessment interval of 15 years for MCAs would be shorter than the reassessment interval for some HCAs. PHMSA also considered that compliance with the proposed rule would be performed in parallel with ongoing HCA reassessments at the same time, thus resulting in greater demand for ILI tools and industry resources than during the original IM baseline assessment period. In addition, the proposed rule incorporates other assessment goals, including integrity verification, maximum allowable operating pressure (MAOP) verification, and material documentation, thus constituting a larger/more costly assessment effort than originally required under IM rules. For the above reasons, PHMSA believes that this proposed rule would require full utilization or expansion of industry resources devoted to assessments. Therefore, PHMSA believes that compressing the timeframes would place unreasonably high demands on the industry's assessment capabilities. PHMSA also considered the possibility that placing burdensome demands on the industry's assessment capability might drive assessment costs higher. PHMSA seeks comments on the potential safety benefits, avoided lost gas, economic costs, and operational considerations involved in longer or shorter compliance periods for initial MCA assessment periods and re-assessment intervals.
More generally, PHMSA seeks comment on the approach and scope of the proposed rule with respect to applying integrity management program elements to additional pipe segments not currently designated as HCA, including,
• Topic B—Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs. The ANPRM requested comments regarding whether the requirements of Section 49 CFR 192.935 for pipelines in HCAs should be more prescriptive and whether these requirements, or other requirements for additional preventive and mitigative measures, should apply to pipelines outside of HCAs. Section 5 of the Act requires the Secretary of Transportation to evaluate and report to Congress on expanding IM requirements to non-HCA pipelines. PHMSA will further evaluate applying P&M measures to non-HCA areas after this evaluation is complete.
This NPRM proposes rulemaking for amending the integrity management rule to add requirements for selected preventive and mitigative measures (internal and external corrosion control).
Two special topics associated with preventive and mitigative measures, leak detection and automatic valve upgrades, were addressed by the NTSB and Congress. The NTSB recommended that all operators of natural gas transmission and distribution pipelines equip their supervisory control and data acquisition systems with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; such tools could include a real-time leak detection system and appropriately spaced flow and pressure transmitters along covered transmission lines (recommendation P-11-10). In addition, Section 8 of the Act requires issuance of a report on leak detection systems used by operators of hazardous liquid pipelines which was completed and submitted to Congress in December 2012. Although that study is specific to hazardous liquid pipelines, its analysis and conclusions could influence PHMSA's approach to leak detection for gas pipelines. In response to the NTSB recommendations, PHMSA conducted as part of a larger study on pipeline leak detection technology a public workshop in 2012. This study, among other things, examined how enhancements to SCADA systems can improve recognition of pipeline leak locations. Additionally, in 2012 PHMSA held a pipeline research forum to identify technological gaps, potentially including the advancement of leak detection methodologies. PHMSA is developing a rulemaking with respect to leak detection in consideration of these studies and ongoing research. In addition, PHMSA is focusing this rulemaking on regulations oriented toward preventing incidents. Leak detection (in the context of mitigating pipe breaks as described in NTSB P-11-10)
PHMSA completed and submitted the valve study to congress in December 2012. PHMSA is developing a separate rulemaking related to the need for remotely or automatically controlled valves to addresses the NTSB recommendations and statutory requirements related to this topic as discussed under Topic H.
• Topic C—Modifying Repair Criteria. The ANPRM requested comments regarding amending the integrity management regulations by revising the repair criteria for pipelines in HCAs to provide greater assurance that injurious anomalies and defects are repaired before the defect can grow to a size that leads to a leak or rupture. PHMSA is proposing in this rule to revise the repair criteria for pipelines in HCAs. Revisions include repair criteria for cracks and crack-like defects, corrosion metal loss for defects less severe than an immediate condition (already included), and mechanical damage defects.
In addition, the ANPRM requested comments regarding establishing repair criteria for pipeline segments located in areas that are not in HCAs. PHMSA is proposing rulemaking for establishing repair criteria for pipelines that are not in HCAs. Such repair criteria would be similar to the repair criteria for HCAs, with more relaxed deadlines for non-immediate conditions. It is acknowledged that applying repair criteria to pipelines that are not in HCAs is one of the factors to be considered in the integrity management evaluation required in the Act, as discussed in Topic A above.
• Topic D—Improving Requirements for Collecting, Validating, and Integrating Pipeline Data. The ANPRM
PHMSA issued Advisory Bulletin 12-06 to remind operators of gas pipeline facilities to verify their records relating to operating specifications for maximum allowable operating pressure (MAOP) required by 49 CFR 192.517. On January 10, 2011, PHMSA also issued Advisory Bulletin 11-01, which reminded operators that if they are relying on the review of design, construction, inspection, testing and other related data to establish MAOP, they must ensure that the records used are reliable, traceable, verifiable, and complete. PHMSA is proposing in this rule to add specificity to the data integration language in the IM rule to establish a number of pipeline attributes that must be included in these analyses, by explicitly requiring that operators integrate analyzed information, and by requiring that data be verified and validated. In addition, PHMSA has determined that additional rules are needed to ensure that records used to establish MAOP are reliable, traceable, verifiable, and complete. The proposed rule would add a new paragraph (e) to section 192.619 to codify this requirement and to require that such records be retained for the life of the pipeline.
• Topic E—Making Requirements Related to the Nature and Application of Risk Models More Detailed. The ANPRM requested comments regarding making requirements related to the nature and application of risk models more specific to improve the usefulness of these analyses in informing decisions to control risks from pipelines. This NPRM contains proposed requirements that address this topic.
• Topic F—Strengthening Requirements for Applying Knowledge Gained Through the IM Program. The ANPRM requested comments regarding strengthening requirements related to operators' use of insights gained from implementation of its IM program. In this NPRM, PHMSA proposes detailed requirements for strengthening integrity management requirements for applying knowledge gained through the IM Program. These requirements include provisions for analyzing interacting threats, potential failures, and worst-case incident scenarios from initial failure to incident termination. Though not proposed, PHMSA seeks comment on whether a time period for updating aerial photography and patrol information should be established.
• Topic G—Strengthening Requirements on the Selection and Use of Assessment Methods for pipelines requiring assessment. The ANPRM requested comments regarding the applicability, selection, and use of assessment methods, including the application of existing consensus standards. NTSB recommendation P-11-17 related to this topic, recommends that all gas pipelines be upgraded to accommodate ILI tools. PHMSA will consider separate rulemaking for upgrading pipelines pending further evaluation of the issue from new data being collected in the annual reports.
This NPRM proposes to strengthen requirements for the selection and use of assessment methods. The proposed rule would provide more detailed guidance for the selection of assessment methods, including the requirements in new § 192.493 when performing an assessment using an in-line inspection tool. This NPRM also proposes to add more specific requirements for use of internal inspection tools to require that an operator using this method must explicitly consider uncertainties in reported results when identifying anomalies. In addition, the proposed rulemaking would add a “spike” hydrostatic pressure test, which is particularly well suited to address SCC and other cracking or crack-like defects, guided wave ultrasonic testing (GWUT), which is particularly appropriate in cases where short segments, such as roads or railroad crossings, are difficult to assess, and excavation and
The issue of selection and use of assessment methods is related to the statutory mandate in the Act for the Comptroller General of the United States to evaluate whether risk-based reassessment intervals are a more effective alternative. The Act requires an evaluation of reassessment intervals and the anomalies found in reassessments. While not directly addressing selection of assessment methods, the results of the evaluation will have an influence on the general approach for conducting future integrity assessments. PHMSA will consider the Comptroller General's evaluation when it becomes available. Additional rulemaking may be considered after PHMSA considers the results of the evaluation.
• Topic H—Valve Spacing and the Need for Remotely or Automatically Controlled Valves. The ANPRM requested comments regarding proposed changes to the requirements for sectionalizing block valves. In response to the NTSB recommendations, PHMSA held a public workshop in 2012 on pipeline valve issues, which included the need for additional valve installation on both natural gas and hazardous liquid transmission pipelines. PHMSA also included this topic in the 2012 Pipeline Research Forum. In addition, Section 4 of the Act requires issuance of regulations on the use of automatic or remote-controlled shut-off valves, or equivalent technology, where economically, technically, and operationally feasible on transmission pipeline facilities constructed or entirely replaced after the date of the final rule. The Act also requires completion of a study by the Comptroller General of the United States on the ability of transmission pipeline facility operators to respond to a hazardous liquid or gas release from a pipeline segment located in an HCA. Separate rulemaking on this topic will be considered based on the results of the study.
• Topic I—Corrosion Control. The ANPRM requested comments regarding proposed revisions to subpart I to improve the specificity of existing requirements. This NPRM proposes to revise subpart I, including a general update to the technical requirements in appendix D to part 192 for cathodic protection.
• Topic J—Pipe Manufactured Using Longitudinal Weld Seams. In recommendation P-11-15, the NTSB recommended that PHMSA amend its regulations to require that any longitudinal seam in an HCA be pressure tested in order to consider the seam to be “stable.” This issue is addressed in Topic N. PHMSA proposes to address this issue by revising the integrity management requirements in § 192.917(e)(3) to specify that longitudinal seams may not be treated as stable defects unless the segment has been pressure tested (and therefore would require an integrity assessment for seam threats). Also, PHMSA proposes to add new requirements for verification of maximum allowable operating pressure (MAOP) in new § 192.624.
• Topic K—Establishing Requirements Applicable to Underground Gas Storage. The ANPRM requested comments regarding establishing requirements within part 192 applicable to underground gas storage in order to help assure safety of
• Topic L—Management of Change. The ANPRM requested comments regarding adding requirements for management of change to provide a greater degree of control over this element of pipeline risk. This NPRM contains proposed requirements that address this topic. Specifically, PHMSA proposes to revise the general applicability requirements in § 192.13 to require each operator of an onshore gas transmission pipeline to develop and follow a management of change process, as outlined in ASME/ANSI B31.8S, section 11, that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary.
• Topic M—Quality Management Systems (QMS). The ANPRM requested comments regarding whether and how to impose requirements related to quality management systems. PHMSA will consider separate rulemaking for this topic.
• Topic N—Exemption of Facilities Installed Prior to the Regulations. The ANPRM requested comments regarding proposed changes to part 192 regulations that would repeal exemptions to pressure test requirements. The NTSB recommended that PHMSA repeal 49 CFR 192.619(c) and require that all gas transmission pipelines be pressure tested to establish MAOP (recommendation P-11-14). In addition, section 23 of the Act requires issuance of regulations requiring tests to confirm the material strength of previously untested natural gas transmission lines. In response to the NTSB recommendation and the Act, this NPRM proposes requirements for verification of maximum allowable operating pressure (MAOP) in accordance with new § 192.624 for certain onshore, steel, gas transmission pipelines, including establishing and documenting MAOP if the pipeline MAOP was established in accordance with § 192.619(c).
The Act also requires verification of records to ensure they accurately reflect the physical and operational characteristics of the pipelines and to confirm the established maximum allowable operating pressure of the pipelines. PHMSA issued Advisory Bulletin 12-06 on May 7, 2012 to notify operators of this required action. PHMSA has initiated an information collection effort to gather data needed to accurately characterize the quantity and location of pre-1970 gas transmission pipeline operating under an MAOP established by 49 CFR 192.619(c). This NPRM proposes requirements in new § 192.607 for certain onshore, steel, gas transmission pipelines to confirm and record the physical and operational characteristics of pipelines for which adequate records are not available.
• Topic O—Modifying the Regulation of Gas Gathering Lines. The ANPRM requested comments regarding modifying the regulations relative to gas gathering lines. The Act required several actions related to this topic, including: review existing regulations for gathering lines; provide a report to Congress; and make recommendations on: (1) The sufficiency of existing regulations, (2) the economic impacts, technical practicability, and challenges of applying existing federal regulations to gathering lines, and (3) subject to a risk-based assessment, the need to modify or revoke existing exemptions from Federal regulation for gas and hazardous liquid gathering lines. PHMSA proposes to address aspects of this topic identified before enactment of the Act in this NPRM. The report submitted to Congress will be evaluated to determine the need for any future rulemaking, specifically the need to apply integrity management concepts to gas gathering lines.
In addition, on August 20, 2014, the Government Accountability Office (GAO) released a report (GAO Report 14-667) to address the increased risk posed by new gathering pipeline construction in shale development areas. The GAO recommended that rulemaking be pursued for gathering pipeline safety that addresses the risks of larger-diameter, higher-pressure gathering pipelines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. PHMSA proposes to address this recommendation as described below in the “Section-by-Section Analysis” under § 192.9.
• Inspection of Pipelines Following a Severe Weather Event. Existing pipeline regulations prescribe requirements for surveillance periodically patrolling of pipeline to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation, including unusual operating and maintenance conditions. The cause of the 2011 hazardous liquid pipeline accident resulting in a crude oil spill into the Yellowstone River near Laurel, Montana was scouring at the river crossing due to flooding. In this case, annual heavy flooding occurred in the Spring of the 2011. In late May, the operator shut down the pipeline for several hours to assess the state of the pipeline. Following the assessment, the operator restarted the pipeline and agreed to monitor the river area on a daily basis. On July 1, 2011 the pipeline ruptured which resulted in the release of 1,500 barrels of crude oil into the Yellowstone River. A second break, due to exposure to flood conditions, occurred several years later on the same pipeline led to an additional spill in the Yellowstone River. Other examples include Hurricane Katrina (2005) which resulted in significant damage to the oil and gas production structures and the San Jacinto flood (1994) which resulted in 8 ruptures and undermining of 29 other pipelines. In the context of the San Jacinto flood, “undermining” occurred when support material for the pipelines was removed due to erosion driven by the floodwaters. As a result, the unsupported pipelines were subjected to stress from the floodwaters that resulted in fatigue cracks in the pipe walls. Based on these examples of extreme weather events that did result, or could have resulted, in pipeline incidents, PHMSA has determined that additional regulations are needed to require, and establish standards for, inspection of the pipeline and right-of-way for “other factors affecting safety and operation” following an extreme weather event, such as a hurricane or flood, an earthquake, a natural disaster, or other similar event that has the likelihood of damage to infrastructure. The proposed rule would require such inspections, specify the timeframe in which such inspections should commence, and specify the appropriate remedial actions that must be taken to ensure safe pipeline operations. The new regulation would apply to onshore transmission pipelines and their rights-of-way.
• Notification for 7-Year Reassessment Interval Extension. Subsection 5(e) of the Act identifies a technical correction amending section 60109(c)(3)(B) of title 49 of the United States Code to allow the Secretary of Transportation to extend the 7- calendar year reassessment interval for an additional 6 months if the operator submits written notice to the Secretary with sufficient justification of the need for the extension. PHMSA would expect that any justification, at a minimum, would need to demonstrate that the extension does not pose a safety risk. PHMSA proposes to codify this statutory requirement.
• Reporting Exceedances of Maximum Allowable Operating Pressure. Section 23 of the Act requires operators to report to PHMSA each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. Implicit in § 192.605 is the intent for operators to establish operational and maintenance controls and procedures to effectively preclude operation at pressures that exceed MAOP. PHMSA expects that operators' procedures should already address this aspect of operations and maintenance, as it is a long-standing, critical aspect of safe pipeline operations. PHMSA issued ADB 12-11 to address exceedances of MAOP. However, PHMSA proposes to codify this statutory requirement in § 192.605.
• Consideration of Seismicity. Section 29 of the Act states that in identifying and evaluating all potential threats to each pipeline segment, an operator of a pipeline facility must consider the seismicity of the area. PHMSA proposes to codify this statutory requirement by adding requirements to explicitly reference seismicity for data gathering and integration, threat identification, and implementation of preventive and mitigative measures.
• Safety Regulations for In-line Inspection (ILI), Scraper, and Sphere Facilities. PHMSA is proposing to add explicit requirements for safety features on launchers and receivers associated with ILI, scraper and sphere facilities.
• Consensus Standards for Pipeline Assessments. The proposed rule would incorporate by reference industry standards for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment. Periodic assessment of the condition of gas transmission pipelines in HCAs is required by 49 CFR 192.921 and 192.937. The regulations provide minimal requirements for the use of these assessment techniques since at the time these regulations were established, industry standards did not exist addressing how these techniques should be applied. Incorporation of standards subsequently published by the American Petroleum Institute (API), the National Association of Corrosion Engineers (NACE), and the American Society of Nondestructive Testing (ASNT) would assure better consistency, accuracy and quality in pipeline assessments conducted using these techniques.
An Integrity Verification Process (IVP) workshop was held on August 7, 2013. At the workshop, PHMSA, the National Association of State Pipeline Safety Representatives and various other stakeholders presented information and comments were sought on a proposed IVP that will help address mandates set forth in Section 23, Maximum Allowable Operating Pressure, of the Act and the NTSB Recommendations P-11-14 (repeal pressure test exemptions) and P-11-15 (stability of manufacturing and construction defects). Key aspects of the proposed IVP process include criteria for establishing which pipe segments would be subject to the IVP, technical requirements for verifying material properties where adequate records are not available, and technical requirements for re-establishing MAOP where adequate records are not available or the existing MAOP was established under § 192.619(c). Comments were received from the American Gas Association, the Interstate Natural Gas Association of America, and other stakeholders addressing the draft IVP flow chart, technical concerns for implementing the proposed IVP, and other issues. The detailed comments are available under Docket No. PHMSA-2013-0119. PHMSA considered and incorporated the stakeholder input, as appropriate, into this NPRM, which proposes requirements to address the current exemptions to pressure test requirements, manufacturing and construction defect stability, verification of MAOP where records to establish MAOP are not available or inadequate (new §§ 192.619(e) and 192.624), and verification and documentation of pipeline material for certain onshore, steel, gas transmission pipelines (new § 192.607).
In Section II of the ANPRM, PHMSA sought comments concerning the significance of the proposed issues to pipeline safety; whether new/revised regulations are needed and, if so, suggestions as to what changes are needed; and likely costs that would be associated with implementing any new/revised requirements. PHMSA posed specific questions to solicit stakeholder input. These included questions related to 15 specific topic areas in two broad categories:
1. Should IM requirements be revised and strengthened to bring more pipeline mileage under IM requirements and to better assure safety of pipeline segments in HCAs? Specific topics included:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and Integrating Pipeline Data,
E. Making Requirements Related to the Nature and Application of Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through the IM Program,
G. Strengthening Requirements on the Selection and Use of Assessment Methods.
2. Should non-IM requirements be strengthened or expanded to address other issues associated with pipeline system integrity. Specific topics included:
H. Valve Spacing and the Need for Remotely or Automatically Controlled Valves,
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems (QMS),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
PHMSA received a total of 1,463 comments; 1,080 from industry sources (Trade Associations/Unions, Pipeline Operators and Consultants); 316 comments from the public (Environmental Groups, Government Agencies/Municipalities, NAPSR and individual members of the general public); and 67 general comments not directly related to the ANPRM questions or categories. Commenters included:
Commenters responded to ANPRM questions, but also submitted comments on subjects generally related to gas pipeline safety regulation (but not related to an ANPRM topic) and general comments related to a topic but not in response to any specific question. This NPRM presents a summary of the comments received (similar or duplicate comments are consolidated). The general (no-topic) comments are presented first under the heading “General Comments.” Comments on each topic follow under the heading “Comments on ANPRM Section II Topics on Which PHMSA Sought Comment,” beginning with general comments related to the topic and then proceeding to each individual question.
1. A number of commenters associated with the pipeline industry suggested that PHMSA should defer action on the changes discussed in the ANPRM until the studies required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 are completed. They contended the Act presents critical issues that require priority attention. They believe the questions raised by Congress, and to which the studies are addressed, could lead to fundamental changes in how pipeline safety is regulated and these changes need to be understood before new rules are written. Several commenters also suggested PHMSA lacks the resources to pursue simultaneously the required studies and complicated rulemakings. The Railroad Commission of Texas also suggested no new requirements be proposed until the effects of the new Act are understood, since they believe that the Act will change the scope of regulatory authority and impose additional costs on industry and regulators.
PHMSA has placed studies and evaluations that relate to the topics in this proposed rulemaking on the docket. PHMSA seeks public comment on those reports and will consider comments before finalizing this rule. Other topics not addressed in this rulemaking that require additional study or evaluation will be addressed separately. Areas for safety improvement that have previously been identified and that are not dependent on the outcome of the required studies are also the subject of the proposals in this Notice.
2. INGAA, AGA, and several pipeline operators and consultants commented that the ANPRM suggested that PHMSA intends to pursue prescriptive regulation in a number of areas. They objected to this approach. They prefer performance-based regulation, under which operators have greater flexibility in deciding how the required safety goal can be met, considering the specific circumstances of their pipeline systems. They noted that integrity management, a performance-based approach, has greatly improved pipeline safety, and suggested PHMSA consider expanding the elements to be covered in an IM plan and providing more well-defined guidelines on how these expanded plans should evolve over time. They noted that implementing pipeline safety regulations is a complex process and implementing prescriptive requirements is usually inefficient. They also noted that prescriptive requirements tend to discourage technological advancements which can lead to improved means to assure safety.
PHMSA believes performance-based regulations are central to improving pipeline performance. In some instances, however, prescriptive
3. AGA, Texas Pipeline Association, Texas Oil and Gas Association, and a number of pipeline operators objected to the scope and pace of change in pipeline safety regulation. These commenters noted that the ANPRM covered a number of complex issues. In addition, they noted that pipeline operators are still implementing a number of large new initiatives including control room management, public awareness, distribution integrity management, and damage prevention. They commented that the industry needs time to complete implementing these other new regulations and PHMSA and the industry need time to evaluate the effect they have on pipeline safety. AGA specifically expressed concern that the pace of change could result in unintended adverse consequences. The Texas Associations suggested that any expansion of non-HCA regulations should address highest risks first and be structured to tailor requirements to different pipeline conditions because other approaches are likely to result in increased costs with little safety benefit. MidAmerican commented that the ANPRM appeared to be based on an incorrect assumption that there are no current requirements applicable to non-HCA pipe; they noted that part 192 includes many requirements applicable to non-HCA segments and that they assure safety. Atmos suggested PHMSA avoid the “one size fits all” approach to pipeline safety regulations.
PHMSA understands that assimilation of change is an important consideration and agrees that the ANPRM covers a number of complex issues. Many of the more complex issues contemplated in the ANPRM, such as leak detection and automatic valves, will be addressed by separate rulemaking so that more careful and detailed analysis can be completed. However, PHMSA is proposing rulemaking in a number of areas to assure that the regulations continue to provide an adequate level of safety for both HCAs and non-HCAs. Additional discussion of the basis for the proposed rulemaking is presented in the response to comments received for each ANPRM topic and in Section V below (Section-by-Section Analysis).
4. A number of industry commenters suggested that PHMSA exercise care in developing broad requirements that may be inappropriate for some types of pipelines. In particular, APGA noted that “transmission” pipeline operated by local distribution companies is very different from long-distance transmission lines. They are typically smaller diameter, operate at lower pressures, and are often made of plastic. AGA and distribution pipeline operators noted that leaks are a routine management issue for distribution pipelines and those requirements appropriate to leak response for transmission pipelines would not be appropriate in a distribution context. The Texas Oil & Gas Association requested that any changes be examined for possible unexpected impact on gathering lines, which also differ from transmission pipelines.
PHMSA is aware of the varying nature of pipeline systems. One aspect of performance-based requirements is the ability of operators to customize the integrity management program so that it is appropriate to its circumstances.
5. AGA and some pipeline operators noted that the ANPRM suggested that PHMSA intends to extrapolate hazardous liquid pipeline experience to gas pipelines. In particular, they expressed concern regarding the discussion of leak detection. They noted pin-point leak detection may be practical for non-compressible liquids but is not for gas.
PHMSA appreciates the significant differences between hazardous liquid pipelines and gas pipelines with respect to leak detection. PHMSA is sponsoring studies and research to address leak detection in a responsible way, while still being responsive to related NTSB recommendations. PHMSA is considering separate rulemaking for leak detection that will address these studies and research.
6. Pipeline industry trade associations reported that their members plan to implement voluntary approaches to improve pipeline safety. INGAA reported it has implemented a strategy to achieve a goal of zero pipeline incidents. This strategy includes voluntary application of IM principles to non-HCA pipeline segments where people live. Their goal is to apply ASME/ANSI B31.8S, Managing System Integrity of Gas Pipelines, principles to 90 percent of people who live or work in close proximity to pipelines by 2020, and 100 percent by 2030. INGAA's strategy also includes assuring the fitness for service of pipelines installed before federal safety regulations were promulgated, improving incident response time (to less than one hour in populated areas), and implementing the Pipelines and Informed Planning Alliance (PIPA) guidelines. AGA similarly reported their intentions to address improvements to safety proactively by applying Operator Qualification to new construction, continuing to advance IM principles (including developing industry guidelines for data management and data quality), and working with a coalition of PIPA stakeholders to adopt PIPA-recommended best practices, among other initiatives.
PHMSA commends the pipeline industry for these initiatives and is committed to working with the industry to improve performance toward the goal of zero pipeline incidents.
7. A number of comments addressed the cost-benefit analyses that will be required in support of rulemaking that results from this ANPRM. AGA noted that a detailed estimate has not been completed but that preliminary evaluations suggest that the cost of implementing the initiatives included in the ANPRM could well exceed the cost of implementing the 2003 gas transmission IM rule. APGA agreed that some of the concepts discussed in the ANPRM are potentially very costly and must be considered carefully. Accufacts cautioned PHMSA to be wary of efforts to distort the cost-benefit analyses by hyper inflating costs. As an example, Accufacts pointed to estimates of costs to perform hydrostatic tests ranging from $500,000 to $1,000,000 per mile compared to costs of $29,400 to $40,000 per mile cited in the NTSB report on the San Bruno accident.
PHMSA acknowledges that estimates of hydrostatic test costs can vary and that there is risk in using overstated estimates in the analysis of benefits and costs since regulatory decisions regarding public safety can be based on these results. For the Preliminary Regulatory Impact Assessment (PRIA) for this proposed rule PHMSA used vendor pricing data to develop unit costs for pressure testing. These costs represent the contractor's costs to complete an eight hour pressure test for
8. AGA and several pipeline operators suggested PHMSA should establish jointly with industry a committee to evaluate pipeline data and to determine whether more data is needed. They commented industry has repeatedly made this request and PHMSA has, to date, not responded. They contended PHMSA's current analysis of pipeline safety performance data is inadequate. Similarly, Panhandle Energy noted a number of the questions in the ANPRM requested data on various subjects; Panhandle expressed its belief that PHMSA collects and has access to at least some of data requested, and this data, collected pursuant to regulatory requirements, should be more complete, and consistently collected and reported, than piecemeal collections of data in response to this ANPRM. Expressing a somewhat contrary view, El Paso suggested more data should be collected and analyzed before notices of proposed rulemakings are prepared; PHMSA needs to collect and analyze data to determine the proper path for future requirements, if any.
In response to NTSB recommendation P-11-19, PHMSA held a pipeline safety data workshop in January 2013. The workshop: (1) Summarized the data OPS collects, who it is collected from, and why it is collected; (2) addressed how stakeholders, including OPS, industry, and the public use the data; (3) addressed data quality improvement efforts and performance measures; and (4) discussed the best method(s) for collecting, analyzing, and ensuring transparency of additional data needed to improve performance measures. PHMSA considered the results of the workshop as well as the comments to the ANPRM related to pipeline safety performance data.
9. APGA suggested PHMSA revise the definitions of transmission and distribution pipelines to be more risk-based. APGA contended that the current definitions are not risk-based and lead to inappropriate outcomes. In particular, classification of some pipelines as “transmission” based on functional aspects of the current definition leads to inappropriate application of requirements. In a similar vein, Oleksa and Associates suggested it may be time to reduce IM requirements on low-stress transmission pipelines, which pose lower risk than high-stress lines. Texas Pipeline Association and Texas Oil & Gas Association commented PHMSA should not extrapolate experience with interstate pipelines to intrastate lines, which differ in design and operation.
The definition of transmission vs. distribution pipelines and the applicability requirements for integrity management in High Consequence Areas is not within the scope of this proposed rule. The general topic of the scope and applicability of integrity management is addressed in the class location report which available in the docket.
10. Northern Natural Gas recommended all exemptions from one-call requirements be eliminated. They noted excavation damage remains, by far, the single greatest threat to pipeline safety and management of excavation damage, through one-call programs, has been demonstrated to be an effective means of countering that threat.
This comment is not within the scope of the ANPRM topics. However, PHMSA has revised the pipeline safety regulations related to pipeline damage prevention programs, which includes one-call programs, in an final rule issued July 23, 2015 (80 FR 43836).
11. The Gas Processors Association, Texas Pipeline Association, and Texas Oil & Gas Association commented regarding current efforts to clarify the applicability of part 192 requirements, particularly requirements for distribution integrity management, to farm taps. They suggested PHMSA is engaged in an expansion of requirements in this area without notice or a demonstrated safety need. They suggested PHMSA initiate a rulemaking specifically to clarify requirements applicable to farm taps.
Treatment of farm taps is not within the scope of the ANPRM topics. However, PHMSA has engaged in dialogue with industry on this topic and will continue to consider options to address this issue in a separate action.
12. Northern Natural Gas suggested PHMSA reduce the time allowed for conducting a baseline assessment in cases where a new HCA is found, tailored to the circumstances of the particular segment. Northern expressed its belief this would address threats to integrity in areas affecting population more quickly than current requirements.
Currently, § 192.905(c) requires that newly identified HCAs be incorporated into the baseline assessment plan within one year. PHMSA does not currently have plans to address this requirement. However, periodically DOT or PHMSA seeks public input on retrospective review of existing regulations under Executive Order 13563. PHMSA encourages the commenter to raise this issue the next time DOT or PHMSA solicits comments on retrospective review of existing regulations.
13. Alliance Pipeline suggested many pipeline safety questions can be answered by applying INGAA's five guiding principles of pipeline safety. They noted INGAA has developed the Integrity Management-Continuous Improvement (IMCI) Initiative to implement these principles and suggested PHMSA actively engage with INGAA in developing workable solutions to pipeline safety issues.
PHMSA appreciates the industry efforts to improve pipeline safety and is committed to working with all stakeholders toward this end.
14. Paiute Pipeline and Southwest Gas commented integrity management requirements have not been in effect long enough to gauge their effectiveness and decide whether additional changes are needed. The companies noted the first, baseline assessments of pipeline segments subject to those requirements are only now being completed. AGA and other pipeline operators agreed, noting IM is still new, operators are still refining their processes, and PHMSA should approach change with caution.
While the first round of baseline assessments are only now being completed, the gas IM rule has been in place approximately 10 years. PHMSA expects that operator IM programs should have significantly matured in this timeframe.
15. Panhandle Energy suggested that PHMSA evaluate rule changes that could have prevented incidents which occurred in recent years. Any initiatives that would not have contributed to improved safety, they suggest, should be postponed or treated as lower priority activities. Panhandle suggested rulemaking without a sound basis is not
One of the major motivations for PHMSA's issuance of the ANPRM was to solicit information useful to ensuring that pipeline safety reforms have a sound basis. PHMSA is also required by Executive Orders 12866 and 13563 to ensure that the benefits of its rules justify the costs, to the extent permitted by law. PHMSA has prepared an initial regulatory impact analysis for this proposed rule, which is available in the docket for this rule. PHMSA encourages the commenter as well as other members of the public to review the analysis and provide input for improving the final rule.
16. AGA and several pipeline operators commented that, while enhancements can be made, IM requirements need not be subjected to wholesale change. They cited GAO and NTSB reports on the efficacy of transmission pipeline integrity management and the lack of pipeline safety issues among the NTSB's “Most Wanted” issues.
While PHMSA believes that IM has led to improvements in managing pipeline integrity, recent incidents and accidents demonstrate that much work remains to improve pipeline safety.
17. AGA and pipeline operators noted that transmission and distribution integrity management are not distinct activities for most intrastate pipeline operators. They contended that the ANPRM seemed to be based on a presumption that operators manage their transmission and distribution pipeline safety differently, and that this assumption is without basis.
PHMSA has promulgated specific IM rules for both transmission and distribution systems with a view toward allowing operators to customize their performance based programs as appropriate to their specific systems.
18. AGA and several pipeline operators suggested that any changes to public awareness requirements should be made at the state level. They noted that federal requirements in this area are new and that effectiveness reviews are still in progress.
This issue is not within the scope of the ANPRM. However, PHMSA has revised the pipeline safety regulations related to pipeline damage prevention programs in a final rule issued July 23, 2015 (80 FR 43836).
19. NACE International suggested that adopting its standards for corrosion control would be the best means to accomplish the goal of maintaining pipelines safe and functional for long periods of time.
This NPRM proposes to incorporate industry consensus standards into the regulations for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment. In addition, this NPRM proposes to enhance subpart I requirements for corrosion control and to revise Appendix D to improve requirements for cathodic protection.
20. The NTSB commented that regulations for gas transmission pipelines can and should be improved and expressed its support for the overall intent of the ANPRM. The NTSB noted publication of the ANPRM prior to its recommendations resulting from the San Bruno incident investigation precluded any mention in the ANPRM of these NTSB safety recommendations. The NTSB suggested PHMSA should seek comment on its recommendations.
PHMSA has reviewed the NTSB recommendations that were issued on September 26, 2011 and found that several recommendations related directly to the topics addressed in the ANPRM and that may impact the proposed approach to rulemaking. The topics impacted are discussed above in the Background section above, in sections II.C and II.E, and include NTSB Recommendations P-11-10, P-11-11, P-11-14, P-11-15, P-11-17, and P-11-19. The NTSB's other recommendations will be addressed in separate proceedings.
21. El Paso suggested that the proper approach to attain the highest pipeline safety levels is through a structured, deliberate rulemaking that closely examines all issue aspects prior to making informed decisions.
PHMSA agrees and is taking a careful, structured, and phased approach to enhancing pipeline safety regulations and IM performance standards.
22. Thomas M. Lael, a pipeline industry consultant, suggested any new regulations be concise and clear. He contended past lack of clarity has created the need for many re-interpretations and enforcement problems.
PHMSA concurs but also notes that performance-based regulations, by their nature, are not as specific, nor as easily measurable, as prescriptive regulations, but are more likely to improve safety and the cost-effectiveness of regulations. PHMSA provides guidance to help stakeholders understand the intent and scope of performance-based regulations.
1. A member of the public stated that the ANPRM did not provide specific options for consideration. As written, only those with direct involvement in the industry could understand it well enough to comment. Presenting the options more specifically would allow for better informed public comment. The discussion should also include a regional component, since issues affecting different states/regions are not the same.
By its nature, the ANPRM did not propose specific alternatives or rules, but solicited input to help inform future proposals. This NPRM provides specific proposed rules for public comment.
2. The Alaska Natural Gas Development Authority stated that the regulations should require consideration of earthquakes, as recent history shows they can be very important to safety of high-pressure gas lines.
Section 29 of the Act states that in identifying and evaluating all potential threats to each pipeline segment, an operator of a pipeline facility shall consider the seismicity of the area. Rulemaking for this issue is addressed in this NPRM and would add requirements to explicitly reference seismicity for data gathering and integration, threat identification and implementation of preventive and mitigative measures.
3. The Environmental Defense Fund pointed out that methane is a very potent greenhouse gas. They commented that PHMSA should consider and minimize the potential environmental effects of any future rulemaking. They suggested EPA's Natural Gas Star program as a model.
The proposals in this rulemaking are designed to minimize the risk of pipeline failures, which will result in environmental benefits. The draft environmental assessment addresses the environmental effects of this rulemaking.
In addition, the RIA provides estimates of the environmental benefits of this proposed rule. Natural gas transported in transmission pipelines contains heat-trapping gases that contribute to global climate change and its attendant societal costs. Of these gases, of primary importance for evaluation are methane—by far, the largest constituent of natural gas—and carbon dioxide. Other natural gas components (ethane, propane, etc.) contribute as well, but they account for a much smaller percentage of the natural gas mixture and, as a result, are much less significant than methane in terms of their environmental impact. The proposed rule is expected to prevent incidents, leaks, and other types of failures that might occur, thereby preventing future releases of greenhouse gases (GHG) to the atmosphere, thus avoiding additional contributions to global climate change. PHMSA estimated net GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on the estimated number of incidents averted and emissions from pressure tests and ILI upgrades.
4. A member of the public questioned the openness and clarity of PHMSA's enforcement of pipeline safety regulations, and the use of civil penalty revenues.
This comment is not within the scope of the ANPRM topics, however, it should be noted that PHMSA embraces transparency in its regulatory oversight program and has established a Pipeline Safety Stakeholder Communications Web site,
5. One member of the public suggested that DOT define “safe corridors” for above-ground construction of pipelines. The commenter suggested this would be similar, in principle, to the interstate highway system. It would help to keep pipelines separated from residences, avoid corrosive environments, and make pipelines available for routine direct examination. At a minimum, this commenter suggested the regulations should specify a minimum separation between new pipelines and residences, as does the New Jersey state code, or homebuyers be informed when a home is within the potential impact radius of a gas transmission pipeline so they may make an informed buying decision.
This comment addresses pipeline siting and routing, which is outside the scope of PHMSA's statutory authority. As specified in 49 U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is prohibited from regulating activities associated with locating and routing pipelines. Paragraph (e) of the statute states “Location and routing of facilities.—This chapter does not authorize the Secretary of Transportation to prescribe the location or routing of a pipeline facility.” However, PHMSA is an active participant in the Pipeline and Informed Planning Alliance (PIPA) and encourages all stakeholders to learn about, and become involved with, PIPA. More information can be obtained online at:
6. One member of the public noted there is an increasing trend in significant incidents and suggested that this trend may be related to undue influence of the pipeline industry on the regulations under which it operates. The commenter recommended regulations should not be weakened in favor of industry. The League of Women Voters of Pennsylvania also recommended that regulatory agencies be insulated from political and other influences of natural gas pipeline companies to avoid the appearance of a conflict of interest.
PHMSA appreciates these comments. PHMSA is committed to improving pipeline safety, and that is the goal of this endeavor. Significant incidents on Gas Transmission (GT) pipelines have averaged between 70 and 80 incidents per year over the past 9 years. The existing integrity management regulations in 49 CFR part 192, subpart O, addresses pipeline integrity in HCAs, which is only about 7 percent of the GT pipeline mileage. This proposed NPRM is focused on strengthening requirements in HCAs and applying integrity management principles to areas outside HCAs to better address safety issues. In addition, the proposed rule seeks to address significant issues that caused or contributed to the San Bruno accident, which include lack of pressure test, inadequate records, poor materials, and inadequate integrity assessment. The operator reports submitted to PHMSA as mandated by the Act confirm that these issues are widespread for both HCA and non-HCA pipe segments.
7. The Harris County Fire Marshall's Office (HCFM) suggested stiffer regulations are needed for gas transmission pipeline safety, because of the large potential for negative impact and catastrophic consequences. HCFM expressed concern about corrosion control and current inspection practices for aging transmission infrastructure.
This NPRM proposes enhanced corrosion control requirements, including periodic close interval surveys, post construction surveys for coating damage, and interference current surveys. This NPRM also proposes enhanced requirements for internal corrosion and external corrosion management programs.
8. The Pipeline Safety Trust (PST) commented that the ANPRM, itself, may heighten and fuel existing public concerns about pipeline safety. PST noted that many of the questions asked the industry to provide information they believe the public would believe PHMSA should already have. PST expressed its view that the number and types of questions asked in the ANPRM reflect gaps in PHMSA's knowledge of gas transmission pipeline systems and operator practices.
PHMSA appreciates these comments. PHMSA is committed to improving pipeline safety and stakeholder input is valuable to the regulatory process.
9. Professional Engineers in California Government (PECG) commented that private companies should not be solely responsible for the safety of their pipelines. PECG contended that this approach has not worked. PECG also suggested PHMSA examine options for increasing the number of inspectors at state pipeline regulatory agencies and require public inspectors be on site for pipeline construction and testing. They contended such inspection is necessary to assure that older pipelines are tested adequately and replaced when needed.
PHMSA appreciates these comments. PHMSA is committed to ensuring that operators maintain and operate their pipelines safely. This rulemaking contains a number of measures aimed at enhancing oversight.
10. The City and County of San Francisco (CCSF) noted the scope of potential rulemaking discussed in the
This comment is outside the scope of this rulemaking. PHMSA is addressing NTSB recommendation P-11-20 separately.
11. Two members of the public suggested the processes of the Federal Energy Regulatory Commission (FERC) for siting pipelines should be revised. One suggested a Commission on Public Accountability and Safety Standards be established, consisting of a majority of local public officials, first responder experts, and independent qualified engineers, to make recommendations for FERC's pre-application process and standards. The purpose would be to assure standards require public accountability for review and vetting of pipeline safety issues with local authorities when pipelines are proposed. The other commenter suggested the relationship between FERC and DOT should be clarified, that a company's enforcement history be taken into account in siting decisions, and PHMSA be a full party to all FERC proceedings. The commenter believes this is necessary because FERC does not have a public safety mandate.
PHMSA is a separate agency from FERC and has no statutory authority with respect to pipeline siting or approval. As specified in 49 U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is prohibited from regulating activities associated with locating and routing pipelines. Paragraph (e) of the statute states “Location and routing of facilities.—This chapter does not authorize the Secretary of Transportation to prescribe the location or routing of a pipeline facility.” However, PHMSA is an active participant in the Pipeline and Informed Planning Alliance (PIPA) and encourages all stakeholders to learn about, and become involved with, PIPA. More information can be obtained online at:
12. Two members of the public commented federal regulations should not override local ordinances. They noted the concern of local authorities is safety, while others are concerned about industry costs. They believe federal regulations that allow operators significant discretion are a poor basis to supersede specific local requirements.
PHMSA appreciates these comments. Federal regulations provide for a uniform body of standards and requirements related to pipeline safety. PHMSA is receptive to input from state and local authorities on pipeline safety issues. States and local authorities may adopt requirements that are more stringent than and consistent with the federal regulations for their intrastate pipelines if they have a 49 U.S.C. 60105 certification.
13. One member of the public suggested regulations require periodic safety audits by an auditor not selected by the pipeline operator. The commenter further suggested that local authorities should have approval authority in the choice of the auditor. The commenter contended this approach would strengthen public confidence in pipeline safety.
PHMSA appreciates this comment. Highly trained federal and state pipeline inspectors conduct inspections of pipeline operators, their facilities, and their compliance programs on a regular basis.
In section II of the ANPRM, commenters were urged to consider whether additional safety measures are necessary to increase the level of safety for those pipelines that are in non-HCA areas as well as whether the current IM requirements need to be clarified and in some cases enhanced to assure that they continue to provide an adequate level of safety in HCAs. PHMSA posed specific questions to solicit stakeholder input. These included questions related to the following topics:
A. Modifying the Definition of HCA,
B. Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs,
C. Modifying Repair Criteria,
D. Improving Requirements for Collecting, Validating, and Integrating Pipeline Data,
E. Making requirements Related to the Nature and Application of Risk Models More Prescriptive,
F. Strengthening Requirements for Applying Knowledge Gained Through the IM Program
G. Strengthening Requirements on the Selection and Use of Assessment Methods,
H. Valve Spacing and the Need for Remotely or Automatically Controlled Valves,
I. Corrosion Control,
J. Pipe Manufactured Using Longitudinal Weld Seams,
K. Establishing Requirements Applicable to Underground Gas Storage,
L. Management of Change,
M. Quality Management Systems (QMS),
N. Exemption of Facilities Installed Prior to the Regulations,
O. Modifying the Regulation of Gas Gathering Lines.
Each topic is summarized as presented in the ANPRM, then general comments related to the topic are presented, followed by each individual question and comments received for the question.
The ANPRM stated that “IM requirements in subpart O of part 192 specify how pipeline operators must identify, prioritize, assess, evaluate, repair and validate;
1. INGAA and a number of pipeline operators noted this is an opportune time for considering the next steps in integrity management, since baseline assessments under the current IM rules are now being completed. INGAA noted its policy goal is to apply IM principles
2. MidAmerican commented it would be reasonable to differentiate between transmission pipelines operating above and below 30 percent specified minimum yield strength (SMYS) in terms of IM requirements. They estimated that less than 3 percent of local distribution company (LDC) transmission lines operate at greater than 30 percent SMYS.
3. MidAmerican and a member of the public suggested PHMSA eliminate class locations in favor of better-defined HCAs. They contend such a change would result in administrative savings for pipeline operators.
4. Southwest Gas and Paiute commented no new regulations should be promulgated in this area until the study required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 is completed.
PHMSA appreciates the information provided by the commenters. Section 5 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the Act) (Pub. L. 112-90) requires the Secretary of Transportation to “evaluate (1) whether integrity management system requirements, or elements thereof, should be expanded beyond high-consequence areas; and (2) with respect to gas transmission pipeline facilities, whether applying integrity management program requirements, or elements thereof, to additional areas would mitigate the need for class location requirements.” PHMSA has completed the report mandated by the Act that documents that evaluation and addresses whether integrity management (IM) program requirements should be expanded beyond high consequence areas (HCAs) and, specifically for gas transmission pipelines regulated under 49 Code of Federal Regulations (CFR) part 192, whether such expansion would mitigate the need for class location designations and corresponding requirements. The class location report is available for review in the docket.
In October 2010 and August 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published notices in the
PHMSA has carefully considered the input and comments. At this time PHMSA plans to propose an approach that balances the need to provide additional protections for persons within the potential impact radius (PIR) of a pipeline rupture (outside of a defined HCA), and the need to prudently apply IM resources in a fashion that continues to emphasize the risk priority of HCAs. PHMSA, therefore, is considering an approach that would require selected aspects of IM programs (namely, integrity assessments and repair criteria) to be applicable for non-HCA segments. For hazardous liquid pipelines, PHMSA would propose to apply these requirements to non-HCA pipeline segments. For gas transmission pipelines, PHMSA would propose to apply these requirements where persons live and work and could reasonably be expected to be located within a pipeline PIR. Under this approach, PHMSA would propose requirements that integrity assessments be conducted, and that injurious anomalies and defects be repaired in a timely manner, using similar standards in place for HCAs. However, the other program elements of a full IM program contained in 49 CFR part 192, subpart O, or 49 CFR 195.452 (as applicable) would not be required for non-HCA segments.
The Act also required the Secretary of Transportation to evaluate if expanding IM outside of HCAs, as discussed above, would mitigate the need for class location requirements. In August 2013, PHMSA published a notice in the
Based upon stakeholder input and findings from lessons learned, incident investigations, assessments, IM, and operating, maintenance, design and construction considerations, PHMSA believes the application of integrity management assessment and remediation requirements to MCAs does not warrant elimination of class locations. Class locations affect all gas pipelines, including transmission (interstate and intrastate), gathering, and distribution pipelines, whether they are constructed of steel pipe or plastic pipe. Class location is integral to determining MAOPs, design pressures, pipeline repairs, high consequence areas (HCAs), and operating and maintenance inspections and surveillance intervals. Class locations affect 12 subparts and 28 sections of 49 CFR part 192 for gas pipelines. The subparts and sections are listed and discussed in Sections 3.1.2.4 and 3.7.2.2. While assessment and remediation of defects on gas transmission pipelines is an important risk mitigation program, it does not adequately compensate for other aspects of class location as it relates to other types of gas pipelines and as it relates (for all gas pipelines) to the original pipeline design and construction such as the design factor, initial pressure testing, establishment of MAOP, O&M activities, and other aspects of pipeline safety, that are based on class location. Thus, PHMSA has determined not to eliminate class location requirements.
With respect to the application of gas transmission IM requirements to pipeline operating at less than 30% SMYS, as part of its consideration of the issues discussed in Topics J and N, PHMSA considered but rejected the suggestion that pipelines operating less than 30% SMYS be differentiated from those operating at higher stress levels.
1. INGAA, industry consultant Thomas Lael, and a number of pipeline operators commented that modification of the HCA definition is unnecessary. They contended that the current definition is already risk-based and provides an effective basis for IM requirements along with a reasonable point from which to expand the application of IM principles by voluntary action. Accufacts commented that PHMSA should focus on closing gaps and loopholes rather than increasing HCA mileage, and that increasing covered mileage would only create the illusion of more safety.
2. AGA, APGA, and a number of gas distribution pipeline operators also opposed changes to the definition. They commented that other requirements of part 192 already address the primary threats for pipe outside HCA. They noted that much effort went into establishing the current definition, there is no safety rationale to abandon it, and change would be inconsistent with risk-based principles and would dilute safety efforts. AGA further noted that imprudent expansion would be contrary to Congressional intent, in that it would dilute the focus on densely populated and environmentally sensitive areas. AGA commented that PHMSA should make no change in this area before completing the related studies required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
3. Taking a contrary position, a number of commenters not affiliated with the pipeline industry supported increasing the pipeline mileage classified as HCA. One private citizen suggested that all pipelines in cities with population greater than 100,000 should be classified as HCA. This commenter believes that existing regulations result in insufficient requirements for urban pipelines. Another citizen suggested that all high-stress lines with a “receptor,” which he defines as “something which needs to be protected,” should be assessed. If changes to the HCA definition are needed to accomplish this, then he contended those changes should be made. The Pipeline Safety Trust would strengthen IM requirements and expand them to all transmission pipelines, although they allow that the details could be different for pipelines not currently classified as HCA. PST believes this would be an effective way to identify and eliminate threats.
4. The Oklahoma Independent Petroleum Association (OKIPA) commented that any changes to the HCA definition must be supported by a scientifically-valid assessment of risks and a complete cost-benefit analysis.
5. The Iowa Association of Municipal Utilities commented that PHMSA should not revise the HCA definition without taking into account the differences between high-pressure transmission pipelines and low-pressure, low-risk lines that are also classified as transmission. IAMU reported “transmission lines” operated by Iowa Municipal Utilities are typically 2 to 4 inches in diameter and have potential impact radii less than 90 feet.
6. The Texas Pipeline Association and Texas Oil & Gas Association contended that expanding HCA pipeline mileage would increase assessment costs, particularly if the arbitrary requirement for reassessments every 7 years is not changed. These associations also believe that additional assessments will result in significant service interruptions. They suggested that assessment requirements be expanded to other pipelines, if needed, rather than changing the definition of HCA, contending that this would allow a more reasoned approach not burdened by the requirement for 7-year reassessments.
7. The Texas Pipeline Association, Texas Oil & Gas Association and several pipeline operators disagreed with the ANPRM assertion that most non-HCA transmission pipeline has been subject to ILI inspections. They noted much non-HCA pipeline has been pigged (
8. MidAmerican suggested that there is no reason to believe that changes to the HCA definition would improve safety. They also noted that the effects of other recent regulatory changes have not yet been realized and could mask any effect of changes in HCA. At the same time, the company noted that revising the definition of an HCA to encompass potential impact circles with 15 structures intended for human occupancy, vs. the current 20, would increase the amount of HCA mileage on its pipeline system by about 10 percent, contending that the safety benefit of such a change would be questionable. They suggested it would be better to focus on pipe in HCAs rather than adding lower-risk pipe, since part 192 already provides a good level of safety for all pipelines.
9. INGAA and a number of pipeline operators commented that increasing the amount of HCA mileage would add or increase costs for hundreds of state and local government agencies. The increases would result from increased demands for identification, certification, and compliance auditing.
10. Northern Natural Gas suggested that PHMSA consider expanding HCA coverage by modifying the specifics of Method 2 for defining HCAs over time. Changes could include reducing the number of structures in potential impact circles that define an HCA, reducing the number of people that defines an identified site, etc. The company believes this kind of change would have the benefit of continued use of the “science” represented by the C-FER Technologies circle for determining HCAs (see part 192, appendix E, figure E.I.A). Northern also suggested PHMSA define a time period for occupation of an identified site which, they contended, would eliminate the need to address locations where a gathering of people is truly transient.
11. TransCanada reported its belief that the current HCA criteria provide an appropriate risk focus. In support of this belief, they noted that only 3 percent of their US transmission pipeline mileage is in HCAs but this includes 45 percent of the population within a potential impact radius of their pipelines.
12. The Iowa Utilities Board opposed changes to the HCA criteria to encompass more mileage. IUB commented that such changes would divert resources from application to higher-risk pipeline segments and there has been no demonstration that non-HCA pipeline segments pose as much risk as those currently defined as HCA.
13. Two private citizens and the Commissioners of Wyoming County, Pennsylvania, suggested the existence of one structure intended for human occupancy within a potential impact circle should be sufficient to define an HCA. These commenters noted that catastrophic consequences (
14. The Pipeline Safety Trust commented that there should be a single set of criteria defining HCAs and that these criteria should be known to the public. They contended the public currently has no information on the criteria defining HCAs.
15. The California Public Utilities Commission commented that HCA criteria should be revised to include more pipeline mileage and that method 2 (use of potential impact circles) should be eliminated.
16. The Alaska Natural Gas Development Authority suggested that the definition of an HCA should accommodate the phenomenon of rapid growth in previously rural areas. They noted that such growth has occurred within Alaska due, in part, to disposal of state lands.
17. NAPSR suggested that PHMSA require all transmission pipelines to meet Class 3 and 4 requirements and eliminate HCAs. NAPSR contended that focusing resources on higher-risk pipelines is bad public policy, since an accident anywhere poses a risk to public safety and reduces public confidence.
18. The Texas Pipeline Association, Texas Oil & Gas Association and several pipeline operators objected to the implication in the ANPRM that assessment costs have decreased. They contended that costs have actually increased due to such factors as operational cost escalation and increased costs to address cased pipeline segments.
19. INGAA and a number of pipeline operators contended that costs cannot be estimated accurately absent a specific regulatory proposal. They suggested that additional costs would be minimal if expanding HCA mileage results in actions similar to INGAA's Integrity Management—Continuous Improvement (IMCI) action plan, but that costs could be high if different requirements are imposed.
20. INGAA reported that a recent survey showed that its members' identified baseline IM assessments will cover 64 percent of members' pipeline mileage, only 4 percent of which is in HCAs. INGAA stated that these assessments will have covered 90 percent of the population within a potential impact radius of the pipelines.
21. Southwest Gas and Paiute provided cost estimates for conducting IM assessments on their pipeline systems: $45,000 per mile for direct assessment, up to $125,000 per mile for in-line inspection, and from $200,000 to $2 million per instance where changes need to be made to a pipeline to accommodate instrumented pigs.
22. The California Public Utilities Commission and MidAmerican commented that costs would increase if the changes suggested in the ANPRM were made, but they provided no specific estimates.
23. APGA noted that costs incurred by or passed on to municipal utilities are costs to local governments, since the utilities are, themselves, government agencies.
24. Paiute and Southwest Gas noted that costs to local governments, including preparation of permits, paving repairs, etc., can be high.
25. An anonymous commenter suggested that costs are not likely to increase much, since most operators already assess more than HCAs and IM has fostered growth in ILI vendors.
26. Kern River noted that its costs would not increase much, since the company is already under similar restrictive requirements via special permit.
27. Accufacts noted that safety is not free. They suggested that relative ranking of assessment methods, by cost, is not likely to have changed. They cautioned that costs used in cost-benefit analyses supporting any rules must be credible and should have an auditable trail available to the public. They suggested that serious accidents can be a “cost” of associated deregulation and lack of proper, effective, and efficient safety regulatory oversight for this critical infrastructure.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that the definition of HCAs is adequate, and does not propose to modify the definition of scope of HCAs in this proposed rulemaking. However, to afford additional protections to other segments along the pipeline, PHMSA is proposing to apply selected IM program elements (namely assessment and remediation of defects) to areas outside HCAs that are newly defined as MCAs. PHMSA believe this approach applies appropriate risk-based levels of safety.
1. Industry trade associations, pipeline operators, and the Iowa Utilities Board objected to the suggestion all Class 3 and 4 locations should be treated as HCA. They noted class location does not have a direct relationship to risk. Small, low-pressure pipelines with no structures intended for human occupancy within the PIR (or for which the PIR is contained entirely within the right of way) could be Class 3 or 4 under current definitions. INGAA noted approximately 90 percent of Class 3 and 4 mileage not in HCA is presently assessed through over testing during IM assessments. Kern River commented that class location is an outmoded system that is confusing and unduly complex. Many of these commenters noted there is no demonstration of need for including all Class 3 and 4 areas, since existing HCA criteria adequately identify areas posing higher risks.
2. Public commenters took a contrary position, suggesting class locations are a reasonable basis for increasing HCA mileage. Pipeline Safety Trust and California Public Utilities Commission commented all Class 3 and 4 locations should be HCA. They noted these are all highly populated areas putting more people at risk from pipeline accidents. CPUC noted the location of the significant 2010 pipeline accident in San Bruno, CA, could have avoided HCA classification if method 2 of the current definition had been used. An anonymous commenter supported this position, suggesting all Class 3 and 4 locations be treated as HCA and use of method 2 be restricted to Class 1 and 2 locations; this commenter contended use of method 2 to exclude some portions of Class 3 and 4 locations from HCA classification is inappropriate. This commenter further suggested the definition of Class 4 locations be revised, contending that the criterion of 4-story buildings being “prevalent” is not specific enough. Thomas Lael, an industry consultant, suggested all Class 4 locations should be HCA. Lael contended that this would be an easy change and would assure that the highest risk pipe is included.
3. NAPSR also suggested all Class 3 and 4 locations should be classified as HCA. NAPSR noted this is an alternative to their preferred solution of eliminating HCA and requiring that all transmission pipelines meet Class 3 and 4 requirements.
4. One public commenter went further. He suggested a new classification, Class 5, be established encompassing all pipeline in cities with populations of more than 100,000. He further suggested pipe in this new class should meet enhanced construction requirements, including required installation of automatic valves to isolate the pipeline in the event of an incident. He contended the existing regulations impose inadequate safety requirements on urban pipelines.
5. Accufacts suggested PHMSA focus first on closing loopholes and gaps rather than increasing HCA mileage. They commented increasing covered mileage without closing gaps would produce only the illusion of safety.
6. Northern Natural Gas suggested PHMSA consider an option of eliminating method 2 of the current HCA definition. They contended such a change would be easy to accomplish. At the same time, they questioned its efficacy, suggesting that it would result in limited or no increase in safety while imposing large costs.
7. INGAA and many pipeline operators objected to the suggested increase in the width of a class location unit for larger, high-pressure pipelines. They noted such a change would contravene the goals of IM and divert resources to pipe of lower risk, and pipe of this type posing high risks to population concentrations is already included as HCA based on its potential impact radius (which could be larger than 220 yards).
8. Here, again, public commenters generally took a contrary position. Pipeline Safety Trust suggested class location width should be at least as much as the potential impact radius. PST noted the PIR is intended to focus on areas requiring more protection while the existing class location width is arbitrary. Two private citizens agreed, one noting that large-diameter, high-pressure gathering pipelines in the Marcellus shale area are located slightly more than 220 yards from pre-existing houses and the other suggesting the class location width in higher-class areas should be 220 yards or the PIR, whichever is larger. Accufacts would go further, suggesting class location width be increased for large-diameter pipe regardless of pressure. Accufacts contended diameter is a more significant factor in determining the potential extent of post-accident damage than is pressure, noting the devastation resulting from the San Bruno accident extended to a much greater distance than the PIR. The Texas Pipeline Association and Texas Oil & Gas Association commented no change should be made until the studies required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 are completed.
9. INGAA and a number of pipeline companies submitted data concerning the amount of pipeline mileage currently in HCAs. INGAA's data is based on a survey of its members.
10. Iowa Association of Municipal Utilities reported its members have zero HCA miles in any class. Most member transmission pipelines are in Class 1 locations. Members have 1.46 miles of Class 2 pipe and one mile in Class 3.
11. Ameren Illinois reported 3.5 of its 82 HCA miles are in Class 1 or 2.
12. Kern River reported it has 18.51 HCA miles in Class 1 and 3.14 miles in Class 2, of a total of 95.96 miles of HCA.
13. On March 15, 2012, PHMSA received a petition for rulemaking from the Jersey City Mayor's office contending that the current Class Location system “does not sufficiently reflect high density urban areas, as the regulation fails to contemplate either (1) the dramatic differences in population densities between highly congested areas and other less dense Class 4 Locations, or (2) the full continuum of population densities found in urban areas themselves.” Based on this, Jersey City petitioned PHMSA to add three (3) new Class Locations, which would be defined as follows:
• A Class 5 location is any class location unit that includes one or more building(s) with between four (4) and eight (8) stories;
• A Class 6 location is any class location unit that includes one or more building(s) with between nine (9) and forty (40) stories;
• A Class 7 location is any class location unit that includes at least one building with at least forty-one (41) stories.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that HCAs should not be based exclusively on class location. Similarly, PHMSA does not propose to define MCAs based on class location. PHMSA proposes that
1. INGAA and several pipeline operators commented the method described in paragraph 2 in the
2. Texas Pipeline Association, Texas Oil & Gas Association, and Ameren Illinois contended the existing criteria do not capture areas not posing risk. They noted the criteria were based on the science of pipeline accidents to identify high-risk areas.
3. Paiute and Southwest Gas commented neither more HCA miles nor additional safety measures are needed. They contended existing criteria are adequate and rule provisions for preventive and mitigative measures and to consider pipe with similar conditions when anomalies are found in HCA are sufficient to address non-HCA pipeline segments.
4. APGA recommended the regulations be modified to treat transmission pipelines operated by local distribution companies, most of which operate at less than 30 percent SMYS, under distribution integrity management rather than transmission IM. APGA suggested this is an optimum time to make this change, which was discussed in the phase 1 work leading up to the distribution IM rule. Atmos agreed, noting failure by leakage rather than rupture, similar to distribution pipelines, is much more prevalent for this low-stress pipeline and it thus poses much lower risks.
5. Northern Natural Gas suggested PHMSA revisit its treatment of “well defined areas” that constitute identified sites. They contended current practice treats an entire area as an identified site even if only an unoccupied corner is within the PIR and persons congregating are outside that critical radius.
6. MidAmerican suggested PHMSA consider adding a multiplier to the PIR equation for higher-stress pipelines. They contended this could capture more high-risk pipe without adversely affecting low-stress pipelines that pose considerably less risk.
7. Atmos commented no change should be made which would increase the amount of HCA mileage, contending that this would dilute the current focus on high-risk pipe.
8. INGAA and several of its members suggested PHMSA rely on its Integrity Management—Continuous Improvement (IMCI) initiative to address pipeline in non-HCA areas.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that the existing method for identifying HCAs and calculating PIR is appropriate and is not proposing a change to either. However, PHMSA disagrees that existing requirements are sufficient for non-HCAs segments. PHMSA believes non-HCA segments where people congregate should be afforded additional protections. Therefore, PHMSA is proposing that selected IM program elements (assessment and remediation of defects) be applied to MCAs.
1. INGAA, AGA, GPTC and a number of pipeline operators contended the existing PIR criteria are sufficiently conservative. They noted the criteria were derived from scientific analysis of the consequences of past pipeline accidents. Texas Pipeline Association and Texas Oil & Gas Association commented there is no reason to modify the PIR criteria or to establish alternate criteria to define HCAs; they contended there is no evidence the current PIR definition has provided insufficient protection to the public.
2. One private citizen and Alaska's Department of Natural Resources suggested HCA criteria should be revised to consider parallel pipelines in a common right of way, contending that an accident on one pipeline could impact adjacent lines, thus compounding consequences. They further suggested requirements for pipelines in common rights of way should include minimum spacing between the pipelines.
3. An anonymous commenter suggested plume releases be considered to determine which pipeline segments can affect an HCA, contending that this would be a good practice.
4. AGA, Texas Pipeline Association, Texas Oil & Gas Association, GPTC, and several pipeline operators cautioned against use of the term “right of way” in the context of defining HCAs. They noted this term is imprecise and the actual location of the pipeline, rather than an ill-defined right of way, is the important factor in evaluating risk.
5. Accufacts, INGAA, and numerous pipeline operators cautioned against discussions that imply that the PIR concept is applicable to considerations of risk from pipeline leaks. These commenters noted that the PIR is based on the consequences of a pipeline rupture and resulting conflagrations and was never intended to address leaks not involving fires.
6. ITT Exelis Geospatial Systems, a company providing services to the pipeline industry, noted accurate location of a pipeline is as important to assuring adequate protection of high-risk populations as is the calculation of PIR.
7. Accufacts suggested PHMSA require a report of the actual impact area, including aerial photographs, within 24 hours of any pipeline rupture. Accufacts contended this data would provide a further basis for continuing review of PIR adequacy.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that the existing definition of PIR is appropriate at this time. PHMSA believes that adjusting the PIR formula based on parallel pipelines in the right-of-way, or other right-of-way factors, are premature at this time. Also, PHMSA acknowledges that the PIR approach only applies such incidents resulting in explosions and fires. While certain gases might be better modeled using plume models, such models have not been carefully studied or developed. However, PHMSA plans to pursue (outside the scope of this rulemaking) additional incident reporting requirements for the purpose of further evaluating the extent of damage following incidents.
1. INGAA, AGA, Texas Pipeline Association, Texas Oil & Gas Association, and many pipeline operators objected to any potential inclusion of “critical infrastructure” in HCA criteria. They noted there is no history of problems caused by impacts on infrastructure, there is little public risk involved, data regarding such infrastructure would be difficult for pipeline operators to obtain, and issues involving potential interactions with critical infrastructure are usually addressed during pipeline planning and construction.
2. GPTC and Nicor recommended HCA criteria not be revised to include critical infrastructure. They noted the intent of defining HCAs is to address risk to life and not property damage and damages to local infrastructure are unlikely to result in consequences similar to those that could affect population concentrations near the
3. Pipeline Safety Trust, Accufacts, NAPSR, Alaska Department of Natural Resources, California Public Utilities Commission and ITT Exelis Geospatial Systems recommended critical infrastructure be included among HCA-defining criteria. Several of these commenters suggested infrastructure beyond electric transmission be considered, including, for example, water and sewage treatment plants, fire stations, and communications facilities. The commenters noted damages to critical infrastructure can lead to cascading effects and additional public safety consequences. ITT Exelis acknowledged these considerations may be secondary to loss of life but contended they are still important to public safety.
4. Northern Natural Gas, Kern River, MidAmerican, Paiute, and Southwest Gas noted determining the impact of damages to infrastructure items is complex. These commenters suggested it is not practical to define what constitutes “critical” infrastructure, from a public safety standpoint, on a generic basis. They recommended PHMSA leave consequence determination to operators, as part of their risk assessments, providing additional guidance for such considerations if needed.
5. An anonymous commenter suggested more frequent tests of cathodic protection and coating surveys be required in areas potentially subject to induced currents from nearby electric transmission infrastructure.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that there have been relatively few pipeline incidents that have had a major impact on critical infrastructure. PHMSA also acknowledges that the PIR formula was developed based on life safety (
1. INGAA and its pipeline operator members commented no additional public involvement is needed. INGAA noted consultation is required under the current regulations, and it seldom identifies any relevant information. Additional involvement, INGAA contends, would likely lead to inconsistencies and would degrade the technical/scientific basis for determining HCAs.
2. AGA and several of its member companies suggested local government agencies should provide information when requested by pipeline operators. They contended additional required involvement would pose an additional burden on pipeline operators while adding no benefit. AGA noted information from its members suggests that local government agencies very rarely point out identified sites not otherwise known to the pipeline operator.
3. Texas Pipeline Association, Texas Oil & Gas Association, GPTC, Nicor, Ameren Illinois and Oleksa and Associates (a pipeline industry consultant) suggested further involvement of local governments not be required. These commenters contended pipeline operators have more relevant knowledge and involvement of inexperienced entities in identifying HCAs is more likely to result in confusion than useful information. The Texas associations suggested current public awareness requirements afford sufficient involvement of local agencies.
4. Accufacts noted local governmental agencies have maps identifying locations important to public safety and suggested these maps should be used by pipeline operators in HCA determinations. Accufacts believes this could assist operators in assuring consideration of accurate, complete, and current information.
5. Northern Natural Gas reported it has a phone number and email address that local residents and agencies can use to provide input to its HCA determinations. Northern further reported no HCAs have been identified from information provided via these avenues that were not otherwise known to the company.
6. Public commenters suggested local residents and government agencies should receive more information concerning pipelines and HCAs. One commenter suggested operators should provide copies of IM plans upon request, and should provide prior notification to residents within a PIR of assessments and a subsequent report of assessment results or problems otherwise identified. This individual also suggested locations of HCAs and assessment trend results should be provided to local communities upon request. The League of Women Voters of Pennsylvania suggested distribution integrity management plans should be readily available and the public should be involved in decisions related to those plans.
7. Pipeline Safety Trust commented public review should be part of any process by which PHMSA reviews or approves of HCA identifications.
8. Wyoming County Pennsylvania Commissioners suggested stakeholder meetings and public comment periods be required as part of HCA identification. They noted local residents know their communities better than others, including expected changes that could affect HCA identification.
9. AGA and several of its member operators recommended local governments play no role in oversight of HCA determinations. They contended this would increase burden and result in inconsistencies and confusion.
10. An anonymous commenter suggested existing public awareness contacts should be used to improve HCA determinations. The commenter expressed the belief this existing structure could allow low-cost involvement of local officials in such determinations.
11. The NTSB suggested PHMSA work with states to employ oversight of pipeline IM plans based on objective metrics. The NTSB noted this would be consistent with recommendation P-11-20 resulting from its investigation of the San Bruno, CA pipeline accident.
12. Iowa Association of Municipal Utilities noted local government employees are involved when HCA determinations are made by municipal utilities and further requirements for
PHMSA appreciates the information provided by the commenters. PHMSA is continuing to evaluate this aspect of integrity management but has not yet reached any conclusions. PHMSA may consider this input for future action, if applicable.
1. Pipeline operators and their associations generally agreed additional measures were not needed outside HCA. INGAA and several transmission pipeline operators suggested operators be allowed to apply the principles of ASME/ANSI B31.8S voluntarily, as needed. INGAA noted this is the concept behind its Integrity Management—Continuous Improvement (IMCI) initiative.
2. AGA and a number of its member operators noted the regulations already require implementation of preventive and mitigative measures outside of HCA for low-stress pipe (§ 192.935(d)). These requirements include using qualified personnel to conduct work that could adversely affect the integrity of the covered segment, collecting excavation damage information, and participating in one-call systems.
3. Ameren Illinois and MidAmerican commented additional measures are not needed, because existing operations & maintenance requirements already assure integrity.
4. GPTC and Nicor agreed, noting it would be inappropriate to apply IM measures outside of HCA and existing requirements are assuring an adequate level of safety.
5. Atmos contended the existing provision requiring that operators evaluate and remediate non-HCA pipeline segments when corrosion is found during an IM assessment of a covered pipeline segment (§ 192.917(e)(5)) already provides that actions be taken to assure the integrity of non-HCA pipeline segments.
6. Texas Pipeline Association and Texas Oil & Gas Association would not object to a phased expansion of IM requirements provided that required assessment intervals are scientifically based. The associations noted Texas pipelines are already subject to the broader requirements of the Texas IM rule. They commented phased implementation would assure the next-highest risks are addressed first and would allow time for IM-support resources to grow.
7. Iowa Association of Municipal Utilities commented new requirements are not needed for its members' pipelines. These lines are small-diameter, low-pressure, odorized, and already pose low risk.
8. Northern Natural Gas suggested PHMSA expand the HCA definition gradually over time rather than imposing IM requirements outside HCA. Northern commented such an approach would retain and expand the focus on areas posing the highest risk.
9. Accufacts commented repair criteria, including required response times, and reporting of anomalies should be the same in- or outside HCA, since the progression of an anomaly to failure is unrelated to whether the anomaly exists within or outside of an HCA.
10. Pipeline Safety Trust suggested non-HCA pipeline segments should be subject to a baseline of IM requirements.
11. The Commissioners of Wyoming County Pennsylvania suggested PHMSA consolidate operators' best practices and require assessment of all pipe frequently enough to realize a benefit. They commented this approach would assure a consistent level of public protection regardless of the practices of individual pipeline operators.
12. California Public Utilities Commission noted this question would be moot if method 2 for defining HCA is eliminated.
PHMSA appreciates the information provided by the commenters. Although most industry commenters did not support expansion of integrity management requirements outside HCAs, PHMSA believes additional protections are needed for pipeline segments where people are expected within the PIR. In this NPRM, PHMSA proposes an approach that balances the need to provide additional protections for persons within the potential impact radius (PIR) of a pipeline rupture (outside of a defined HCA), and the need to prudently apply IM resources in a fashion that continues to emphasize the risk priority of HCAs. The proposed regulation would require selected aspects of IM programs (namely, integrity assessments and repair criteria) to be applicable for selected non-HCA segments defined as MCAs. An MCA would be a segment located where persons live and work and could reasonably be expected to be located within a pipeline PIR. PHMSA would propose requirements that integrity assessments be conducted, and that injurious anomalies and defects be repaired in a timely manner, using similar standards in place for HCAs. However, the other program elements of a full IM program contained in 49 CFR part 192, subpart O would not be required for MCA segments.
1. Most industry commenters, including INGAA, AGA, and numerous pipeline operators supported this proposed requirement. They noted submission of this data will be required for PHMSA to comply with the mapping provisions of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
2. Accufacts, Alaska Department of Natural Resources, California Public Utility Commission, and one private citizen agreed, suggesting PHMSA should know where HCAs are located and that this information is important to emergency responders. CPUC also suggested operators should be required to submit this information to State regulatory authorities as well.
3. Pipeline Safety Trust also supported this proposal, adding the information should be shared with the public.
4. League of Women Voters of Pennsylvania and Accufacts also supported making maps identifying pipeline locations, including HCA, available to the public.
5. Atmos, Northern Natural Gas, Kern River, Nicor, and GPTC opposed a requirement to submit this information. They noted this is a large amount of information which is available for audits and questioned how it would be used by PHMSA and how related security issues would be addressed.
6. Ameren Illinois suggested a requirement to submit HCA locations is not needed, since location data on the entire pipeline system must already be submitted to the National Pipeline Mapping System.
7. Texas Pipeline Association, Texas Oil & Gas Association, and MidAmerican agreed that providing HCA information as part of NPMS submissions is adequate. They noted this is consistent with Section 6 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
PHMSA appreciates the information provided by the commenters. Most commenters supported the submittal of HCA information in geospatial format. As noted by one commenter, this is required by the Act. Although outside
1. Responses to this question consisted of speculation regarding reasons why the number of HCA miles may have declined. No commenters reported having specific data to describe the reducing trend.
2. AGA suggested pipe replacement, reductions in MAOP, and use of better data could be among the many reasons for a decline in HCA mileage.
3. INGAA speculated the reduction could be a result of operators changing from method 1 to method 2 to identify HCAs and abandoning or retiring older pipelines.
4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, and a private citizen agreed a change in the method for identifying HCAs is a likely reason for the decreasing mileage trend.
5. Northern Natural Gas commented changes in land use over time result in changes in the pipeline segments identified as HCA. Northern noted it has changed from method 1 to method 2 for identifying HCA but that the change had resulted in an increase in HCA mileage rather than a decrease. Kern River also reported that its HCA mileage is increasing, citing changes in land use along the pipeline as the reason for this change.
6. GPTC and Nicor suggested operational changes and removal of pipe from service could be the cause of the observed changes.
7. Iowa Utilities Board noted reductions in pressure and other operational changes can eliminate covered pipeline segments. IUB also suggested a change from method 1 to method 2 and better analyses of potential impact circles, etc. could have resulted in decreased HCA mileage.
8. MidAmerican noted its HCA mileage has fluctuated but remains relatively constant overall. They noted periodic fluctuations result from changes in various parameters that go into identifying HCAs.
9. A private citizen suggested operators may be buying properties within potential impact circles and razing them or that new pipelines in rural areas may be replacing current pipelines.
10. An anonymous commenter suggested HCA mileage is decreasing because operators are getting better at identifying HCAs. The commenter noted operators have been doing so for 9 years.
PHMSA appreciates the information provided by the commenters. PHMSA considered this input in its evaluation mandated by the Act.
1. Accufacts commented property damage costs reported to PHMSA following pipeline incidents appear to be understated. Accufacts noted this raises serious questions about the validity of cost-benefit analyses performed using this data.
2. Iowa Association of Municipal Utilities commented the costs to comply with IM-like requirements are not justified for small, low-pressure transmission pipelines such as those operated by its members. Significant costs to develop IM plans, evaluate remote valves, and comply with other IM requirements must be passed on to a small rate base for many municipal utilities.
3. ITT Exelis Geospatial Systems suggested HCA criteria be revised and requirements for protection of critical infrastructure and populated areas be made more prescriptive. They commented such changes would require that leak surveys be performed more frequently, providing improved safety.
4. ITT Exelis Geospatial Systems reported its leak detection systems, developed as part of research jointly sponsored with DOT and other agencies, could facilitate this testing and initial costs would be offset by longer term savings.
5. California Public Utilities Commission observed the public has indicated its desire for more prescriptive safety requirements.
The Act requires that the Secretary of Transportation to evaluate whether integrity management requirements should be expanded beyond HCAs and whether such expansion would mitigate the need for class location requirements. The proposed rulemaking does not change the HCA definition. However, PHMSA is proposing pipeline assessment requirements in new § 192.710 for newly defined moderate consequence areas (MCAs). PHMSA is also proposing new requirements in § 192.607 for verification of pipeline material and § 192.624 for MAOP verification would also apply to MCAs. PHMSA performed a Preliminary Regulatory Impact Analysis, using the best available data and information. It is available on the docket and PHMSA invites comments on the PRIA.
Section 192.935 requires gas transmission pipeline operators to take additional measures, beyond those already required by part 192, to prevent a pipeline failure and to mitigate the consequences of a potential failure in a HCA following the completion of a risk assessment. Section 192.935(a) specifies examples of additional measures, which include, but are not limited to installing automatic Shut-off Valves or Remote Control Valves; installing computerized monitoring and leak detection systems; replacing pipe segments with pipe of heavier wall thickness; providing additional training to personnel on response procedures; conducting drills with local emergency responders; and implementing additional inspection and maintenance programs. In the ANPRM, PHMSA expressed concern that these additional measures are not explicitly required. As a result, operators may not be employing the appropriate additional measures as intended. Section 192.935(b) specifies that operators are also required to enhance their damage prevention programs and to take additional measures to protect HCA segments subject to the threat of outside force damage (non-excavation). PHMSA also noted in the ANPRM that the provisions in § 192.935 only apply to HCAs and that the expansion of the HCA definition would increase the mileage of pipelines subject to § 192.935. Further, PHMSA acknowledged the consideration of expanding preventive and mitigative measures to pipelines outside of HCAs. The following are general comments received related to the topic as well as comments related to the specific questions:
1. INGAA suggested PHMSA can substantially improve prevention and mitigation of accidents caused by excavation damage by facilitating full implementation of state damage prevention programs. INGAA further suggested PHMSA actively promote the use of 811 one-call programs. INGAA noted excavation damage remains the most prevalent cause of serious incidents and failure to notify is a primary cause of these incidents. Many pipeline operators supported the INGAA comments.
2. INGAA, supported by many of its pipeline operator members, noted it has a policy goal to apply integrity management principles, voluntarily, to pipelines beyond HCAs. Their goal is to address 90 percent of the population near pipelines by 2020 and 100 percent by 2030 through application of appropriate principles from ASME/ANSI B31.8S.
3. AGA supported application of IM principles, but not assessment requirements, outside HCAs. AGA commented requiring operators to understand and address risks is a good application of IM principles. Many pipeline operators supported the AGA comments.
4. AGA commented the ANPRM incorrectly states that § 192.935 applies only to pipe within HCAs. AGA noted paragraph (d) of that section applies to low-stress pipe in Class 3 and 4 areas that is not in HCAs.
5. California Public Utilities Commission suggested pipelines installed prior to the promulgation of federal pipeline safety requirements (so-called “pre-code” pipe) be reassessed more frequently.
6. Alaska Natural Gas Development Authority commented Alaska's experience indicates improved pipeline design and construction requirements are needed to assure pipeline integrity. These would include stronger pipe, improved requirements for mainline valves (including spacing and remote operation), and improved corrosion control. The Authority also commented that design requirements need to accommodate likely changes in class location, noting that explosive growth in some Alaska areas has resulted in rapid changes from Class 1 to Class 3.
7. One private citizen suggested some level of assessment should be required for all pipelines.
8. Another private citizen suggested integrity management plans for densely populated areas (Class 4 and Class 5—a new class suggested by the commenter encompassing cities with population greater than 100,000) should be developed in consultation with local emergency responders. The commenter further suggested these plans should be available at the FERC environmental impact study stage and should be reviewed with local authorities.
9. Another private citizen suggested information should be shared across pipeline operators, noting this would augment the knowledge of individual companies and improve safety. Similarly, the commenter suggested PHMSA require operators to submit a list of preventive and mitigative measures that have been implemented and reports of their effectiveness. The commenter noted PHMSA should know this information but apparently does not, as indicated by questions posed in this ANPRM (particularly questions B.1 and B.2).
1. Most industry commenters indicated ASME/ANSI B31.8S is a common standard used to guide decisions concerning preventive and mitigative measures. INGAA suggested enhancing this standard would be the best approach to provide additional guidance for selection and implementation of these measures. Other commenters also cited the GPTC Guide as a useful guideline. INGAA listed other standards used by pipeline operators, including:
AGA also noted that operators are guided by their own risk assessments. Many pipeline operators supported the INGAA and AGA comments.
2. Northern Natural Gas reported it does not rely on a specific consensus standard to select preventive and mitigative measures. It relies, instead, on company subject matter experts guided by statistical analyses of their risk model.
3. Paiute and Southwest Gas reported they use an algorithm combining risk scores, threats, and the value of specific measures. Company engineers analyze the results of applying this algorithm and develop preventive and mitigative measure implementation plans.
4. An anonymous commenter noted many pipeline operators are implementing actions that could be considered preventive and mitigative measures but these actions may not be identified as such if they are implemented as part of operations and maintenance activities and not specifically included in IM plans.
5. INGAA suggested PHMSA would benefit by applying ASME/ANSI B31.8S in its IM enforcement activities.
1. INGAA reported many pipeline operators have implemented additional preventive and mitigative measures. INGAA does not keep data on this and did not provide examples. Some pipeline operators submitted examples in support of the INGAA comments. Preventive and mitigative measures cited in these examples include:
• Additional reconnaissance (after seismic events, floods, etc.);
• Concrete mats over pipelines in areas particularly susceptible to excavation damage;
• Encroachment sensors;
• Remotely operated valves;
• Removal of casings;
• Completion of CIS surveys;
• Clearing of rights-of-way;
• Derating/deactivating of pipelines;
• Relocation of pipelines;
• Increased inspection of river crossings;
• Lowering of shallow pipelines;
• Installation of additional marker posts;
• Revising marking standards for locates;
• Completing depth-of-cover surveys;
• Enhancing right-of-way patrols.
In addition, one pipeline operator reported augmented implementation of many requirements of part 192 and implementation of some requirements (
2. AGA also reported many additional preventive and mitigative actions have been implemented but, again, does not keep data on them. Examples cited by AGA and its operator members included increased use of indirect inspection tools, increased patrols, and investigation of apparent instances of encroachment.
3. GPTC reported data is not collected concerning voluntary measures.
4. Texas Pipeline Association and Texas Oil & Gas Association similarly reported that they do not collect this data, and there was only limited response to a survey of their operators regarding this question. The associations reported their understanding that measures are not generally implemented system-wide.
5. California Public Utilities Commission reported some CA operators are stationing personnel at the location of excavations near transmission pipelines. CAPUC also noted California's one-call law requires a mandatory field meeting before any excavation near a transmission pipeline operating above 60 psi.
6. An anonymous commenter suggested operators avoid implementing non-required actions for fear they will lead to new requirements.
7. Industry comments indicated data is not collected concerning the extent of implementation of voluntary preventive and mitigative measures. Some measures are implemented in specific HCAs while others may be implemented more broadly across a pipeline system. The extent depends largely on the threat being addressed and its prevalence.
8. Northern Natural Gas reported it has implemented voluntary measures outside HCA, citing as examples high-visibility markers in Class 1 areas and use of LIDAR leak detection. Northern reported broad implementation of voluntary measures is more prevalent than site specific use.
9. MidAmerican reported virtually all of its transmission pipeline mileage is subject to at least one preventive and mitigative measure.
10. Paiute reported nine measures are applied to all of its 856 miles of transmission pipeline while 13 are applicable to all 27 miles of HCA.
11. Similarly, Southwest Gas has implemented nine measures on 841 miles and 13 on all 191 miles of HCA.
12. AGA reported that approximately 195,000 non-HCA miles have been assessed, generally through assessing pipe upstream and downstream of the HCA segment.
1. Industry commenters unanimously agreed no new prescriptive requirements are needed. INGAA pointed out selection of preventive and mitigative measures is based on criteria in consensus standards and operator judgment. INGAA contended this allows appropriate customization and results in improved safety. AGA agreed, noting operators are in the best position to decide what is needed for their pipeline systems. GPTC stated that its Guide is sufficient, and there has been no demonstrated safety need for additional requirements. Several pipeline operators suggested conducting assessments and making repairs provides the most effective safety improvement.
2. Paiute and Southwest Gas suggested a best practices workshop to share industry experience could be beneficial.
3. Accufacts suggested additional prescriptiveness is needed to guide decisions regarding remote and automatically operated valves in HCA.
4. The Alaska Department of Natural Resources would suggest signoff by a professional engineer on preventive and mitigative action decisions.
5. The NTSB recommended improved use of metrics in inspection protocols, citing their recommendations P-11-18 and 19.
6. One private citizen suggested the lack of specifically-required actions in the regulations represents a deficiency in the pipeline safety regulatory program. The commenter suggested the extent of operator judgment be limited and that state and local officials should participate in developing a list of applicable preventive and mitigative actions.
7. An anonymous commenter suggested including more examples of preventive and mitigative actions in the regulations would help guide operator consideration of appropriate actions. The commenter also suggested operators be required to update their risk analyses, and selection of preventive and mitigative actions, more frequently including after changes in their pipeline systems or the occurrence of significant events.
1. INGAA, supported by many of its pipeline operator members, commented prescriptive requirements are not needed. INGAA contended prescriptive requirements are neither effective nor efficient and that ASME/ANSI B31.8S and the GPTC Guide provide sufficient guidance.
2. AGA commented one-call requirements and the actions required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 are the only actions that should be required on a system-wide basis. AGA further suggested it could be appropriate to apply the additional measures required of low-pressure pipelines in § 192.935(d) to pipelines operating above 30 percent SMYS.
3. Texas Pipeline Association and Texas Oil & Gas Association recommended no new requirements be adopted applying specific preventive and mitigative actions throughout pipeline systems. The associations noted part 192 already requires application of some measures throughout pipeline systems and expressed their conclusion these already-specified measures are sufficient.
4. MidAmerican commented requiring application of specified measures throughout pipeline systems would provide a disincentive for the application of other measures which could be more appropriate.
5. The NTSB recommended requirements for leak detection in SCADA systems should be improved, citing their recommendation P-11-10.
6. California Public Utilities Commission recommended operators be required to station stand-by personnel at excavations near transmission pipelines and operator procedures should specify the actions these stand-by personnel must take. CPUC further suggested these standby activities should be a covered task under operators' personnel qualification programs.
7. Pipeline Safety Trust recommended PHMSA mandate the NTSB recommendations, noting many are similar to the specific measures suggested in this question. PST further commented operators should not be allowed sufficient latitude to render a regulation meaningless.
8. An anonymous commenter suggested the regulations should not specify particular preventive and mitigative measures but should emphasize consideration of potential accident consequences when selecting actions. The commenter noted there are too many variables to specify particular actions in regulation.
9. A private citizen suggested operators should be required to conduct drills with local responders periodically as part of their integrity management programs. The commenter noted such drills would improve coordination and would validate the ability to respond in the event of an emergency.
10. A private citizen suggested stronger enforcement is needed based on the belief that operators should already be taking many of the actions suggested in this question.
11. With respect to the specific actions suggested in this question:
a. Line-of-sight markers: National Utility Locating Contractors Association recommended line-of-sight markers be required, noting that they would reduce the instances of excavators failing to call for a locate, which the Common Ground Alliance's Damage Information Reporting Tool (DIRT) continues to indicate is a major cause of excavation damage. The Association further recommended the message on markers should be visible from all angles, noting that most current markers are only visible from two directions. The Commissioners of Wyoming County Pennsylvania, and MidAmerican suggested line-of-sight markers should be required, noting that they are a low-cost good practice for improving safety. An industry consultant disagreed, noting installation would be impractical in many areas where the sight line is obscured by crops, terrain, etc.
b. Depth of cover: MidAmerican opposed required depth of cover surveys, commenting they are not a good indicator of likely damage and such surveys are inherently inaccurate. Texas Pipeline Association and Texas Oil & Gas Association suggested compliance with depth of cover requirements over time is impractical. They noted operators do not have full control over rights of way and that owners can make changes. For example, a landowner may pave an area following grading which reduces the depth of cover. California Public Utilities Commission recommended depth of cover surveys be required wherever external corrosion direct assessment is applied and where vehicles or other loads capable of damaging the pipeline have access to the surface over the pipeline. Wyoming County Pennsylvania's Commissioners suggested depth of cover surveys be required as a good safety practice.
c. Close interval surveys: MidAmerican recommended against requiring these surveys. The company noted they are only one means of determining the adequacy of cathodic protection. The Commissioners of Wyoming County Pennsylvania recommended such surveys be required as a good safety practice.
d. Coating surveys and re-coating: MidAmerican opposed a requirement for coating surveys, noting holidays are found and repaired through in-line inspection and external direct assessment. The company further noted pipe replacement is often a superior repair to recoating. The Wyoming County Commissioner commented periodic coating surveys are a good practice and recommended that they be required.
e. Additional right of way patrols: MidAmerican and the Wyoming County Commissioners agreed increased frequency of patrols would be appropriate. MidAmerican noted patrols are a relatively low cost action that generates useful data.
f. Shorter ILI intervals: MidAmerican opposed shorter intervals, noting many lines cannot accommodate in-line inspection or more frequent runs. The Wyoming County Commissioners argued that frequent assessment is a good practice that should be required.
g. Additional gas quality monitoring: MidAmerican opposed such a requirement, arguing it would be redundant for distribution pipeline operators receiving gas from suppliers. The Wyoming County Commissioners argued frequent gas monitoring would be a good practice.
h. Improved pipeline marking standards: MidAmerican agreed implementing new marking standards would be a low cost action. Wyoming County again noted this is a good practice.
1. INGAA, supported by many of its member companies, argued preventive and mitigative measures should be applied to non-HCA areas on a risk basis rather than by prescriptive requirement. INGAA commented this is a more effective and efficient means of increasing pipeline safety.
2. AGA commented codifying different requirements for non-HCA areas would likely cause confusion and extending existing IM requirements to non-HCA areas would create an enormous burden for PHMSA and states. AGA noted the NTSB has already questioned the ability of regulators to apply the existing IM inspection protocols to HCA mileage. AGA recommended one-call and the actions required by statute be the only additional measures required system-wide.
3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association, and two pipeline operators opposed requirements for preventive and mitigative actions in non-HCA areas. These commenters argued it is important to allow pipeline operators the flexibility to select actions that are appropriate to their circumstances and implementing actions required arbitrarily would be expensive and ineffective.
4. Northern Natural Gas suggested PHMSA expand the HCA definition gradually over time rather than imposing IM requirements outside HCA. Northern commented such an approach would retain and expand the focus on areas posing the highest risk.
5. MidAmerican opposed additional requirements for preventive and mitigative actions, noting all pipeline is covered by other requirements in part 192 and it is better to focus enhanced requirements on areas posing highest risk.
6. AGA commented measures required in HCA should always be equal to or more stringent than measures required outside of HCA. AGA noted this is a fundamental principle of integrity management: Focusing on areas posing higher risks.
7. Ameren Illinois and an anonymous commenter suggested better enforcement and/or specificity for provisions requiring operators consider other areas of their systems when problems are discovered would be more effective than requiring preventive and mitigative measures outside HCA.
8. ITT Exelis Geospatial Systems commented requirements should be the same in- or outside HCA. They contended non-HCA areas are not monitored for leakage as often as Class 3 and 4 locations. They suggested their LIDAR system would allow effective and efficient leak surveys in all locations.
9. A public citizen recommended exposed pipe be wrapped in bright colors and protected from damage whether inside or outside of HCA. The commenter suggested analysis of data from CGA's Damage Information Reporting Tool would be an effective preventive measure.
1. Northern Natural Gas reported the additional cost of preventative and mitigative measures it employs, including instrumented aerial leakage surveys, close-interval surveys, additional mailings and additional signage, has been approximately $950,000. Northern further reported the approximate cost of conducting assessments through in-line inspection or pressure testing for all high-consequence areas every seven years is $45,000,000 and reduction of the inspection interval would increase the cost accordingly.
Section 5 of the Act requires that the Secretary of Transportation complete an evaluation and issue a report on whether integrity management requirements should be expanded beyond HCAs and whether such expansion would mitigate the need for class location requirements. Aspects of this topic that relate to applying a risk analysis to determine additional preventive and mitigative measures for non-HCA pipeline segments will be addressed later, pending completion of the evaluation and report. PHMSA will review the comments received on this topic and will address them in the future in light of these statutory requirements.
Section 3 of the Act requires that the Secretary of Transportation complete an evaluation and issue a report on the impact of excavation damage on pipeline safety. Aspects of this topic that relate to additional preventive and mitigative measures for damage prevention will be addressed after completion of the evaluation and report. PHMSA will review the comments received on this topic and will address them in the future in light of this evaluation and report.
Section 6 of the Act requires that the Secretary of Transportation provide guidance on public awareness and emergency response plans. Aspects of this topic that relate to additional preventive and mitigative measures for public awareness and emergency response will be further evaluated in conjunction with this statutory mandate. PHMSA will review the comments received on this topic and will address them in the future in light of this evaluation.
Two specific areas of preventive and mitigative actions addressed in the IM requirements (49 CFR 192.935) are leak detection and automatic/remote control valves. The IM rule does not require specific measures be taken to address these aspects of pipeline design and operations, but does include them among candidate preventive and mitigative measures operators should consider. Both of these topics are the subject of recommendations that the NTSB made (recommendations P-11-10 and P-11-11) following the San Bruno explosion. In response to these recommendations, PHMSA conducted a public workshop on March 27, 2012, to seek stakeholder input on these issues, and is sponsoring additional research and development to further inform PHMSA's response on these issues. Aspects of this topic that relate to leak detection and automatic/remote control valves will be addressed after completion and evaluation of the above activities. PHMSA will review the comments received on leak detection and automatic/remote control valves and will address them in the future in light of this evaluation.
PHMSA is proposing to add requirements for enhanced preventive and mitigative measures to address internal and external corrosion control. The intent of the IM rulemaking is to enhance protections for high consequence areas. PHMSA believes that enhanced requirements for internal corrosion and external corrosion control are prudent. To address internal corrosion, PHMSA is proposing specific requirements for operators to monitor gas quality and contaminants and to take actions to mitigate adverse conditions. To address external corrosion, PHMSA is proposing specific requirements for operators to monitor and confirm the effectiveness of external corrosion control through electrical interference surveys and indirect assessments, including cathodic protection surveys and coating surveys, to take actions needed to mitigate conditions that are unfavorable to effective cathodic protection, and to integrate the results of these surveys with integrity assessment and other integrity-related data. PHMSA addresses this topic in more detail in response to comments related to Topic I, Corrosion Control.
Specific comments submitted for Topic B that are related to risk and integrity assessments are addressed under Topics E and G.
The existing integrity management regulations establish criteria for the timely repair of injurious anomalies and defects discovered in the pipe (49 CFR 192.933). These criteria apply to pipeline segments in an HCA, but not to segments outside an HCA. The ANPRM announced that PHMSA is considering amending the integrity management rule by revising the repair criteria to provide greater assurance that injurious anomalies and defects are repaired before the defect can grow to a size that leads to a leak or rupture. In addition, PHMSA is considering establishing repair criteria for pipeline segments located in areas that are not in an HCA in order to provide greater assurance that defects on non-HCA pipeline segments are repaired in a timely manner. The following are general comments received related to the topic and then comments related to the specific questions:
1. INGAA reported its members' commitment to apply ASME/ANSI B31.8S corrosion anomaly criteria both inside and outside of HCAs. INGAA noted that new research to refine and extend the technical bases for responding to corrosion anomalies identified primarily by ILI has been completed by Pipeline Research Council International, whose report was expected to be published in the first quarter of 2012. INGAA also reported a commitment to develop and use criteria for mitigation of dents, corrosion pitting, expanded pipe corrosion, and selective seam weld corrosion. Numerous pipeline operators supported INGAA's comments.
2. AGA suggested that ASME/ANSI B31.8S should be the basis for defining anomalies requiring remediation. Anomalies not meeting the criteria in that standard, in AGA's opinion, do not require repair. AGA further commented that risk prioritization of maintenance and anomaly response should not be regulated because operators are in the best position to know the factors influencing prioritization for apparently-similar anomalies. AGA also suggested that PHMSA review INGAA's paper “Anomaly Response and Mitigation Outside of High Consequence Areas when Using in Line Inspection,” dated May 30, 2010, as this paper forms the basis for current industry response outside of HCAs. Numerous pipeline operators supported AGA's comments.
3. Accufacts contended that there have been too many corrosion-caused ruptures occurring shortly after in-line
4. Alaska Department of Natural Resources commented that repairs should be made using permanent methods, and that clamps and similar repairs are not sufficient.
PHMSA appreciates the information provided by the commenters. Because the current repair criteria only address corrosion metal loss as an immediate condition, PHMSA agrees that more prescriptive repair criteria are needed to address significant corrosion metal loss that does not meet the immediate repair criterion, similar to the hazardous liquid integrity management repair criteria at 49 CFR 195.452(h). In addition, other conditions that are not currently addressed in the repair criteria, such as stress corrosion cracking and selective seam weld corrosion, are addressed in ASME B31.8S and other sources, but not explicitly addressed in part 192. PHMSA is proposing to enhance the repair criteria for HCA segments and is also proposing to add specific repair criteria for pipeline in non-HCA segments. In general, PHMSA is proposing to add more immediate repair conditions and more one-year conditions for HCA segments. The additional criteria address conditions not previously addressed, such as stress corrosion cracking, and also include more specific one-year criteria for corrosion metal loss, based on the design factor for the class location in which the pipeline is located, to address corrosion metal loss that reduces the design safety factor of the pipe. PHMSA is also proposing to apply similar repair criteria in non-HCA segments, except that response times will be tiered, with longer response times for non-immediate conditions. PHMSA reviewed available industry literature, including ASME/ANSI B31.8S, in developing the proposed repair criteria. Specific aspects of the proposed rules are discussed in response to the specific questions for Topic C, below.
PHMSA has not addressed the specific procedures and techniques for performing repairs in this rulemaking, but may do so at a later date.
1. INGAA, supported by numerous pipeline operators, commented the FPR criterion need not be changed, noting there have been no reported incidents due to the criterion being too lax. INGAA also objected to PHMSA's characterization of this issue, noting that repair criteria already exceed 1.1 FPR; the 1.1 FPR criterion in the regulations governs response to anomalies and not the criteria to which repairs must be made.
2. AGA, supported by numerous of its pipeline operator members, commented that the FPR criterion should not be changed. AGA contended that the criterion already provides a 10 percent safety margin and is based on sound engineering practices.
3. Northern Natural Gas and Kern River stated that conservatism is present in burst pressure calculations and in the measurement of anomalies (considering tool tolerance), providing a safety margin greater than 10 percent.
4. Accufacts argued against changing the FPR criterion, but suggested that PHMSA require operators to use better assumptions in their failure analyses. Accufacts suggested that the regulations should focus on preventing failures but that existing safety margins need not be increased.
5. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, and MidAmerican opposed changes to this criterion. These commenters noted that experience through the baseline inspections has demonstrated the criterion is adequate and ASME/ANSI B31.8S remains a good guide for anomaly response. Atmos added that this criterion separates immediate repairs from scheduled repairs: It allows a risk-based focus on more serious anomalies but does not mean that anomalies providing more than 10 percent margin to burst pressure are never addressed.
6. California Public Utilities Commission suggested that the FPR criterion be increased to 1.25 times MAOP. CPUC noted that the 10 percent margin in the current criterion can be completely erased by the 10 percent margin to safety relief settings allowed by § 192.201.
7. INGAA commented that additional repair criteria are not needed. INGAA noted that §§ 192.485(a) and 192.713(a) already specify repair criteria applicable to pipe outside HCA. Numerous pipeline operators supported INGAA's comments.
8. AGA, supported by numerous of its pipeline operator members, suggested that safety margins for repairs need not be the same as those for new construction. AGA argued that the construction margins are intended to address potential unknowns and forces applied during construction, which are not applicable to repairs.
9. Accufacts, Northern Natural Gas, and an anonymous commenter agreed that repairs, once initiated, should meet new construction safety margins.
10. INGAA and several of its pipeline operator members argued that repair criteria should not be more stringent where class location has changed. INGAA noted that § 192.611 does not change the original design criteria for segments that have been subject to a change in class location and there is no incident experience suggesting that additional safety margin is needed in these cases.
11. Northern Natural Gas and Kern River argued against a change in repair criteria where class location has changed, noting that the likelihood of failure of an anomaly is not affected by the class location and that treatment in accordance with integrity management requirements already considers risk.
12. MidAmerican, Paiute, and Southwest Gas added that use of the factor failure pressure divided by MAOP in ASME/ANSI B31.8S already reflects any change in MAOP necessitated by a change in class location.
13. Accufacts commented that repair criteria should be commensurate with the more restrictive design criteria of higher class locations.
14. INGAA commented no new metal loss criterion is needed, noting that its members use HCA response criteria as a guide for responding to indications of metal loss outside of HCAs. Numerous pipeline operators supported INGAA's comments.
15. AGA commented any metal loss criterion should reflect current science and should be the same regardless of class location. AGA suggested that immediate response to any indication of a dent with metal loss is not needed, noting that there have been many examples of dents with metal loss not sufficient to require recalculating remaining strength. AGA also noted the external corrosion direct assessment standard requires a similar response regardless of whether an indication is in
16. Accufacts encouraged PHMSA to establish a prompt-action criterion for wall loss inside or outside HCAs, suggesting the focus should be on preventing ruptures regardless of where they occur. Accufacts also cautioned PHMSA against accepting studies attempting to show that 80 percent wall loss is sometimes acceptable, and stated that continued operation with such wall loss is too risky for onshore pipelines.
PHMSA appreciates the information provided by the commenters. The majority of comments supported no changes to the immediate repair criterion of predicted failure pressure of less than or equal to 1.1 times MAOP for HCAs, and PHMSA is not proposing to change this criterion; however, PHMSA is proposing several changes to enhance the repair criteria both for HCA segments and non-HCA segments. For immediate conditions, PHMSA proposes to add the following to the immediate repair criteria: Metal loss greater than 80% of nominal wall thickness, indication of metal-loss affecting certain types of longitudinal seams, significant stress corrosion cracking, and selective seam weld corrosion. These additional repair criteria would address specific issues or gaps with the existing criteria. The methods specified in the IM rule to calculate predicted failure pressure are explicitly not valid if metal loss exceeds 80% of wall thickness. Corrosion affecting a longitudinal seam, especially associated with seam types that are known to be susceptible to latent manufacturing defects such as the failed pipe at San Bruno, and selective seam weld corrosion are known near-term integrity threats. Stress corrosion cracking is listed in ASME B31.8S as an immediate repair condition, which is not reflected in the current IM regulations. PHMSA proposes to add requirements to address these gaps.
The current regulations include no explicit metal loss repair criteria, other than one immediate condition. The regulations direct operators to use Figure 4 in ASME B31.8S to determine non-immediate metal loss repair criteria. PHMSA now proposes to explicitly include selected metal loss repair conditions in the one-year criteria. These proposed criteria are consistent with similar criteria currently invoked in the hazardous liquid integrity management rule at 40 CFR 195.452(h). In addition, PHMSA proposes to incorporate safety factors commensurate with the class location in which the pipeline is located, to include predicted failure pressure less than or equal to 1.25 times MAOP for Class 1 locations, 1.39 times MAOP for Class 2 locations, 1.67 times MAOP for Class 3 locations, and 2.00 times MAOP for Class 4 locations in HCAs. Lastly, in response to the lessons learned from the Marshall, Michigan, rupture, PHMSA proposes to include any crack or crack-like defect that does not meet the proposed immediate criteria as a one year condition. PHMSA proposes to apply these same criteria as two-year conditions for non-HCAs.
PHMSA agrees with Accufacts' comment that the regulations should focus on preventing failures but that existing safety margins are adequate when properly applied. Therefore, the proposed rule does not propose to increase safety margins such as the design factor. PHMSA maintains that the proposed changes discussed above provide a tiered, risk-based approach to metal loss repair criteria and by requiring predicted failure pressures as a function of class locations does not compound safety margins. Counter to INGAA's and AGA's comments that repair criteria should not be more stringent where class location has changed, PHMSA believes the tiered approach to metal loss repair criteria, which is a function of class location, provides a logical framework to address the risk presented by these types of pipeline anomalies.
In conjunction with enhanced repair criteria, PHMSA is proposing specific new regulations to require that operators properly analyze uncertainties and other factors that could lead to non-conservative predictions of failure pressure, and time remaining to failure, when evaluating ILI anomaly indications. PHMSA specifically is proposing that operators must analyze specific known sources of uncertainty regarding ILI tool performance, anomaly interactions, and other sources of uncertainty when determining if an anomaly meets any repair criterion.
1. INGAA suggested that new criteria are not needed, commenting that operators generally treat non-HCA anomalies in a manner similar to HCA anomalies, except for response time. INGAA stated that industry costs to address non-HCA anomalies should be nominal unless immediate response is required because this is consistent with current operator practice, which INGAA stated is to apply ASME/ANSI B31.8S response criteria for anomalies both inside and outside HCAs.
2. Texas Pipeline Association and Texas Oil & Gas Association commented that differing repair criteria, if any, should be based upon the population at risk, since there is no valid engineering basis for treating anomalies differently depending on location.
3. Atmos and Northern Natural Gas suggested that non-HCA anomalies should be treated like HCA anomalies, although additional schedule flexibility should be allowed. Northern reported that it applies HCA metal loss criteria everywhere because it is prudent, although response time differs for non-HCA anomalies. Northern reported that it has expended approximately $7.7 million on anomaly repairs, $7 million of which was outside an HCA.
4. Kern River agreed that IM schedules are too stringent to apply everywhere and providing schedule flexibility will reduce costs.
5. MidAmerican disagreed with the suggestion that non-HCA and HCA anomalies be treated alike. MidAmerican commented that it is illogical to back off from focusing sooner on anomalies that pose greater risks.
6. California Public Utilities Commission commented that all locations identified by the method described in paragraph 1 in the definition of HCA in § 192.903 should be subject to HCA repair criteria.
7. Pipeline Safety Trust, Accufacts, and NAPSR commented that the same repair criteria and response schedule should apply regardless of where an anomaly is located. These commenters contended that there is no logical justification for different treatment, that any risk to the pipeline and public safety should be resolved, and that a pipeline accident anywhere is seen by the public as a failure to exercise adequate control of pipeline safety. NAPSR, in particular, suggested that all anomalies should be repaired immediately, regardless of where they are located.
8. Iowa Utilities Board, Iowa Association of Municipal Utilities, GPTC, Nicor, Ameren Illinois and an anonymous commenter contended that HCA repair criteria should not be applied outside HCAs. These commenters noted that there has been no demonstrated safety need for new criteria, that non-HCA anomalies are adequately addressed under existing operations and maintenance requirements, and that the cost to apply HCA repair criteria everywhere is not justified. IAMU particularly noted that
9. A private citizen supported application of HCA repair criteria in non-HCA areas, particularly where there are “receptors,” which the commenter defines as “something which needs to be protected.”
PHMSA appreciates the information provided by the commenters. PHMSA proposes to modify the general requirement for repair of pipelines to include immediate repair condition criteria, one-year conditions, and monitored conditions. The definition of these conditions would be the same as the existing definitions for covered segments (
PHMSA believes that establishing these non-HCA segment repair conditions are important because, even though they are not within the defined high consequence locations, they could be located in populated areas and are not without consequence. For example, as reported by operators in the 2011 annual reports, while there are approximately 20,000 miles of gas transmission pipe in HCA segments, there are approximately 65,000 miles of pipe in Class 2, 3, and 4 populated areas. PHMSA believes it is prudent and appropriate to include criteria to assure the timely repair of injurious pipeline defects in non-HCA segments. These changes will ensure the prompt remediation of anomalous conditions on all gas pipeline segments while allowing operators to allocate their resources to high consequence areas on a higher priority basis.
1. INGAA, and many pipeline operators, opposed the suggested tiering. They commented that anomalies meeting response criteria should be addressed in an appropriate time frame whether inside or outside HCAs.
2. AGA, supported by many of its operator members, suggested that PHMSA not adopt any risk tiering beyond the current requirements to focus first on HCA anomalies. AGA noted that outside factors,
3. Texas Pipeline Association and Texas Oil & Gas Association commented that PHMSA should allow risk tiering system-wide, not just in differentiating between responses in and outside HCA. The associations suggested that this could be an improvement to requirements addressing anomalies. At the same time, they noted the description in the ANPRM is sketchy and requested PHMSA propose specific requirements for comment.
4. Iowa Association of Municipal Utilities commented that no new requirements are needed, and that the existing requirements are sufficient for the small, low-stress transmission pipelines operated by its members.
5. Atmos commented that the risk tiering concept is confusing and stated that it was considered and rejected when the initial IM rules were promulgated.
6. Northern Natural Gas commented that allowing a longer response time for anomalies outside HCA would be a form of risk tiering. The company reported it has incorporated this practice in its procedures.
7. Accufacts agreed that a focus on HCA anomalies is needed but cautioned against ignoring anomalies outside HCAs. Accufacts noted the progression of an anomaly to failure does not depend on whether or not it is located in an HCA.
PHMSA appreciates the information provided by the commenters. Current regulations do not prescribe response timeframes for anomalies outside HCAs. As stated by Northern Natural Gas, allowing a longer response time for anomalies outside HCAs (compared to response times for anomalies inside HCAs) would be a form of risk-tiering. PHMSA is proposing such an approach, which would establish three timeframes for performing repairs in non-HCA areas: Immediate repair conditions, 2-year repair conditions, and monitored conditions. These changes will ensure the prompt remediation of anomalous conditions on all gas pipeline segments, while allowing operators to allocate their resources to those areas that present a higher risk.
1. INGAA commented that repair schedules outside HCAs should be similar to those in HCAs but should allow for more scheduling latitude. This comment was supported by comments received from many of its operator members. They also noted that adding requirements to repair non-HCA anomalies would significantly increase the number of required repairs and that an inappropriate requirement for rapid response would dilute the focus on risk-significant repairs. INGAA suggested that repair schedules should be more a function of anomaly growth rates than location along the pipeline. INGAA further suggested that inappropriately rapid response schedules would increase risk; experience shows that most anomalies that have been found and repaired are old, do not require a rapid response, and that mandating rapid response to such anomalies would necessarily dilute other safety activities.
2. Texas Pipeline Association and Texas Oil & Gas Association expressed doubt that significant risk reduction would result from shortened repair schedules, given the logistics and related work involved in repairs.
3. GPTC, Nicor, and an anonymous commenter objected to applying HCA repair criteria outside HCAs. They believe that the costs for such an approach are not justified and non-HCA anomalies are appropriately dealt with under operations and maintenance requirements and procedures.
4. Ameren Illinois, Paiute, and Southwest Gas agreed that prescriptive repair schedules are not needed outside HCAs. They expressed a belief that operators must have scheduling flexibility to accommodate the needs of their operations.
5. MidAmerican suggested that immediate repair criteria be applied both in HCAs and outside HCAs, but that other criteria be limited to HCAs.
6. Northern Natural Gas suggested that PHMSA should require operators to determine response schedules for non-HCA anomalies as part of this rulemaking.
7. Iowa Association of Municipal Utilities commented that the existing requirements are sufficient for the small, low-stress transmission pipelines operated by its members.
8. California Public Utilities Commission commented that all method
9. MidAmerican, Paiute, and Southwest Gas commented that shortened response schedules will not reduce risk. These operators suggested that response times should be based on risk rather than being established arbitrarily.
PHMSA appreciates the information provided by the commenters. PHMSA believes repair schedules outside HCAs should be similar to those in HCAs but should allow for more scheduling latitude. PHMSA proposes to establish three timeframes for remediating defects in non-HCA areas: Immediate repair conditions, 2-year repair conditions (rather than one-year for HCAs), and monitored conditions. These changes will ensure the prompt remediation of anomalous conditions on all gas pipeline segments, commensurate with risk, while allowing operators to allocate their resources to those areas that present a higher risk.
1. INGAA commented that ILI tool capabilities have improved to the point where it is appropriate to revise the dent-with-metal loss criterion. This comment was supported by comments received from many of its operator members. INGAA suggested that Section 851.4(f) of ASME/ANSI B31.8 provides appropriate guidance in this area.
2. AGA suggested that it would be appropriate to eliminate the immediate response criterion for “dent with metal loss.” This comment was supported by comments received from many of its operator members. They commented that industry experience has shown that many dents do not require immediate repair.
3. Texas Pipeline Association, Texas Oil & Gas Association, MidAmerican, Paiute, Southwest Gas, and Atmos supported revising this criterion. These commenters noted that improvements in ILI allow better distinction between a gouge and corrosion wall loss. MidAmerican further commented that there are problems with implementing § 192.933 as written.
4. Northern Natural Gas stated that it would support treating these anomalies as mechanical damage, and suggested that this would simplify the regulations.
5. Ameren Illinois suggested further study of this proposal taking into account current ILI technology.
6. Accufacts and an anonymous commenter opposed changes to this criterion. These commenters suggested that ILI is still not adequate to determine reliably the time to failure of this compound threat.
7. GPTC and Nicor suggested that PHMSA consider updating the Dent Study technical report
PHMSA appreciates the information provided by the commenters. PHMSA is not proposing to update the dent-with-metal-loss criterion at this time. PHMSA will continue to evaluate this criterion, including consideration of additional research to better define the repair criteria for this specific type of defect.
1. INGAA, supported by many of its member companies, reported that operators use many methods to accommodate ILI uncertainties, not simply adding tool tolerance to results. INGAA suggested API-1163, In-line Inspection Systems Qualification Standard, as an appropriate guide. INGAA noted this standard is non-prescriptive; INGAA expressed its belief prescriptive standards would stifle innovation. INGAA also reported that ASME has plans to update its standard on “Gas Transmission and Distribution Piping Systems,” ASME/ANSI B31.8S, regarding treatment of uncertainties based on the results of Pipeline Research Council International (PRCI) research that was underway at the time comments were submitted.
2. AGA and a number of pipeline operators suggested that tool tolerances should be added to ILI results.
3. Texas Pipeline Association, Texas Oil & Gas Association, and Atmos reported their understanding that most operators follow ASME/ANSI B31.8S as a guide.
4. Northern Natural Gas and Kern River expressed their conclusion that PHMSA's Gas Integrity Management Program Frequently Asked Question FAQ-68 provides sufficient guidance on the treatment of uncertainties (FAQs can be viewed at
5. Texas Pipeline Association and Texas Oil & Gas Association agreed that prescriptive requirements should not be imposed, because the rapidly-developing technology would soon render them obsolete.
6. GPTC, Nicor, MidAmerican, and Atmos argued that prescriptive methods for validating tool performance are not an appropriate subject for regulation.
7. Ameren Illinois commented that it sees no technical justification for establishing requirements in this area.
8. Accufacts suggested that PHMSA specify minimum standards for ILI validation, including specifying a required number of digs. Alaska Department of Natural Resources and California Public Utilities Commission took a similar stance, all arguing that standards assure public confidence and consistency of results.
9. A private citizen commented that voluntary standards are not sufficient because they cannot be enforced.
10. An anonymous commenter recommended against adopting requirements for treatment of inaccuracies. The commenter opined that operators are doing better in this area, contending that smaller operators, in particular, needed time to learn. The commenter suggested that specific rules would set many operators back.
11. INGAA and many of its pipeline operators commented that incorporating standards into part 192 that compete with industry standards would be counterproductive. INGAA noted that API-1163, API-579-1, Fitness-for-Service, and ASNT ILI-PQ, In-Line Inspection Personnel Qualification and Certification Standard, are already in wide use and contended specifying standards in the regulations would stifle further development.
12. GPTC and Nicor agreed with INGAA, noting that the regulatory approval process cannot keep up with technological development.
13. Northern Natural Gas recommended that PHMSA not adopt standards for addressing ILI inaccuracies, contending the many
14. MidAmerican reported its belief that operators have sufficient incentive to work with ILI vendors to assure appropriate validation of ILI results.
15. Paiute and Southwest Gas argued against adoption of regulatory standards to treat ILI uncertainties, noting that this subject is already addressed in ASME/ANSI B31.8S.
16. AGA, supported by a number of its member companies, suggested that PHMSA should not prescribe IM methods, noting that operators have demonstrated the ability to conduct assessments without them.
17. Accufacts, Alaska Natural Gas Development Authority, and California Public Utilities Commission argued for requirements prescribing assessment methods for various threats. These commenters suggested that such requirements would be a bridge to better risk management strategies and contended that there is currently an over-reliance on direct assessment.
PHMSA appreciates the information provided by the commenters. The majority of comments do not support adopting explicit standards or analytical methodologies to account for the known accuracy of in-line inspection tools. PHMSA concurs that prescriptive rules to account for the accuracy of in-line inspection tools is not practical, however it is beneficial to all to clarify PHMSA's expectations with respect to current performance-based regulations in this area which specify that internal inspection may be used to identify and evaluate potential pipeline threats. Therefore, PHMSA proposes to add detailed performance-based rule language to require that operators using ILI must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or equivalent for determining uncertainties) in identifying anomalies. While ASME/ANSI B31.8S discusses uncertainties, PHMSA believes it will improve the visibility and emphasis on this important issue to explicitly address uncertainties in the rule text.
1. AGA and its pipeline operator members argued against the adoption of standards. AGA commented that voluntary use has proven to be sufficient and expressed its position that consensus standards should not be adopted into regulations until widespread experience has been gained with their use. AGA contended that premature adoption would stifle technological innovation.
2. INGAA and many of its members commented that PHMSA's process for review and adoption of standards must be streamlined if existing consensus standards are incorporated into regulations. Such improvements, INGAA contended, would assure that standard improvements are adopted without delay.
3. An anonymous commenter, GPTC, and Nicor cited similar concerns in suggesting that standards not be adopted into regulations, contending that the rulemaking process cannot keep up with technological change.
4. Texas Pipeline Association and Texas Oil & Gas Association objected to the adoption of ILI standards in regulations, contending that voluntary use is more appropriate.
5. MidAmerican commented that operator qualification requirements should be applied to ILI, as this would provide higher assurance of defect discovery. Beyond this, however, MidAmerican contended that the use of consensus standards should remain voluntary, as this allows the operator to select those standards most appropriate to its circumstances.
6. Paiute and Southwest Gas objected to the incorporation of ILI standards into regulations. The companies expressed a belief that there is no technical basis for doing so. They commented that the question, as posed in the ANPRM, implies that anomalies are not now being found and contended that there is no evidence to support this implication.
7. A private citizen, Thomas Lael, and Alaska Department of Natural Resources commented that PHMSA should require operators to meet specified standards. Mr. Lael referred to an incident that occurred following a pipeline assessment conducted in Ohio in 2011; Mr. Lael contended that the reasons the incident cause was not identified by the assessment are unknown to the public.
8. Pipeline Safety Trust commented that PHMSA should assure assessment tools are capable and are used properly.
9. The NTSB recommended that PHMSA require all pipelines to be made piggable, giving priority to older lines, citing their recommendation P-11-17.
PHMSA appreciates the information provided by the commenters. The majority of industry comments do not support the incorporation of ILI standards into regulations. However, based on the information presented below, PHMSA has concluded that it is prudent to propose incorporating available consensus ILI standards into the regulations. The current pipeline safety regulations for integrity management of segments in HCAs contained in 49 CFR 192.921 and 192.937 require that operators assess the material condition of pipelines in certain circumstances and allow use of in-line inspection tools for these assessments. PHMSA proposes to incorporate similar requirements for non-HCA pipe segments in § 192.710. Operators are required to follow the requirements of ASME/ANSI B31.8S in selecting the appropriate ILI tools. However, ASME B31.8S provides only limited guidance for conducting ILI assessments. At the time the integrity management rules were promulgated, there was no consensus industry standard that addressed performance of ILI. Three related standards have since been published: API STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010. API-1163 serves as an umbrella document to be used with and complement the NACE and ASNT standards. These three standards have enabled service providers and pipeline operators to provide processes that will qualify the equipment, people, processes, and software utilized in the in-line inspection industry. The incorporation of these standards into pipeline safety regulations developed through best practices of the industry based on the experience of numerous operators will promote high quality and more consistent assessment practices. Therefore, PHMSA is proposing to incorporate these industry standards into the regulations to provide clearer guidance for conducting integrity assessments with in-line inspection. PHMSA will continue to evaluate the need for additional guidance for conducting integrity assessments.
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No comments were received in response to this question.
The ANPRM requested comments regarding whether more prescriptive requirements for collecting, validating, integrating and reporting pipeline data are necessary. The current IM regulations require that gas transmission pipeline operators gather and integrate existing data and information concerning their entire pipeline that could be relevant to pipeline segments in HCAs (§ 192.917(b)). Operators are then required to use this information in a risk assessment of the HCA segments (§ 192.917(c)) that must subsequently be used to determine whether additional preventive and mitigative measures are needed (§ 192.935) and to define the intervals at which IM reassessments must be performed (§ 192.939). Operators' risk analyses and conclusions can only be as good as the information used to perform the analyses. On August 30, 2011, after the ANPRM was issued, the NTSB adopted its report on the gas pipeline accident that occurred on September 9, 2010, in San Bruno, California. Results from the NTSB investigation indicate that the pipeline operator's records regarding the physical attributes of the pipe segments involved in the incident were erroneous. NTSB recommendation P-11-19 recommended that PHMSA require IM programs be assessed to assure that they are based on clear and meaningful metrics. In addition, Section 23 of the Act requires verification to ensure that records accurately reflect the physical and operational characteristics of pipelines. PHMSA issued an Advisory Bulletin (76 FR 1504; January 10, 2011) on this issue. The following are general comments received related to the topic as well as comments related to the specific questions:
1. INGAA reported that it is presently working on data integration guidelines. INGAA cautioned that requirements in this area can be very costly, since they often necessitate redesign of existing data management systems.
2. AGA commented that no records requirements would have prevented the San Bruno accident, and stated that verifying records does not assure completeness, as unknown parameters remain unknown.
3. A private citizen suggested that PHMSA should require operators to identify segments where they lack knowledge of critical parameters. The commenter suggested that this could facilitate emergency communications and help prioritize pipe replacement programs.
PHMSA appreciates the information provided by the commenters. PHMSA is proposing to clarify requirements for collecting, validating, and integrating data. The current rule invokes ASME/ANSI B31.8S requirements for data collection and integration. To provide greater visibility and emphasis on this important aspect of integrity management, PHMSA is proposing to place these requirements in the rule text, rather than incorporating ASME/ANSI B31.8S by reference. The proposed requirements clarify PHMSA's expectations regarding the minimum list of data an operator must collect, and also includes performance-based language that requires the operator to validate data it will use to make integrity-related decisions, and require operators to integrate all such data in a way that improves the analysis. The proposed rule would also require operators to use reliable, objective data to the maximum extent practical. To the degree that subjective data from subject matter experts must be used, PHMSA proposes to require that an operator's program include specific integrity assessment and findings data for the threat features to compensate for subject matter expert (SME) bias. The importance of these aspects of integrity management was emphasized by both the NTSB (Recommendation P-11-19) and Congress (The Act, Section 11(a)(4)).
1. INGAA reported that its members have completed a concerted effort to validate pipeline historical records pursuant to PHMSA Advisory Bulletin 11-01 (issued January 10, 2011).
2. Texas Pipeline Association and Texas Oil & Gas Association commented that there is no great benefit to be gained from adding a verification requirement for historical data to the regulations. The associations believe that most operators will correct their records when they become aware of errors regardless of how the erroneous information is discovered. The associations suggested that there could be value in validating databases against original records, since an underlying problem of the San Bruno accident was errors in transferring original records into a database.
3. Ameren Illinois reported that it collects data on exposed pipe in accordance with §§ 192.459 and 192.475.
4. Northern Natural Gas and Kern River reported that their primary integration tool is integrity alignment sheets, which show the class location, profile, aerial photography, alignment and structure data, in-line inspection results, other integrity data,
5. Paiute and Southwest Gas reported that they confirm the location and properties of its pipeline as opportunities arise; more data are collected as assessments are conducted.
6. California Public Utilities Commission suggested that operators be explicitly required to obtain all historical records and that there be an officer statement that a thorough search for all records has been conducted.
7. A private citizen commented on the lack of some historical data, implying that operators should be required to validate their knowledge of older pipelines.
8. An anonymous commenter stated that older data is typically not validated.
9. INGAA and AGA reported that pipeline operators take advantage of exposed pipe to collect and validate data on in-service pipelines. This includes excavations for ILI validation, those conducted as part of direct assessment, and removed or replaced pipelines. A number of pipeline operators provided comments supporting the comments of each association.
10. GPTC and Nicor suggested that excavations not be required for the sole purpose of validating data, contending that the risks posed by such a requirement would outweigh any benefit obtained.
11. MidAmerican reported that it validates information when pipeline is excavated and through its routine practices.
PHMSA appreciates the information provided by the commenters. See response to question D.4.
1. AGA, Paiute, and Southwest Gas reported that operators use exposed pipe as an opportunity to collect information. AGA further suggested, however, that PHMSA should not draft a rule governing these practices. AGA contended the circumstances of pipe exposures vary too much to be addressed by a regulatory requirement. AGA expressed its conclusion that the requirements in § 192.605(b)(3) provide adequate guidance and that section 23 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 provides additional guidance. AGA noted that operators investigate identified inaccuracies and errors. A number of other pipeline operators provided comments supporting AGA's comments.
2. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, MidAmerican, and Ameren Illinois reported that operators typically collect information on pipe type and condition, but not on historical information and pipe specifications. They commented that collecting this information would require additional testing and pose operational impacts.
3. Iowa Utilities Board and Iowa Association of Municipal Utilities commented that any new requirement should be limited to collecting readily obtainable data, principally that which can be determined visually. They suggested that the data elements in ANPRM questions D.1 and D.3 go beyond what can readily be observed or obtained and it would be impractical to require this data to be collected during pipe exposures.
4. California Public Utilities Commission commented that any new requirements to collect data during pipe exposures should address all instances of exposure rather than be limited to HCAs, noting that non-HCA segments can become HCA segments due to changes in land use near the pipeline.
5. Thomas Lael and Alaska Department of Natural Resources commented that operators should be required to collect specific data during pipe exposures. These commenters contended that not all operators currently collect available data during pipe exposures.
6. MidAmerican, Paiute, and Southwest Gas commented that no new requirements are needed because the requirements in part 192 and guidance in ASME/ANSI B31.8S are sufficient.
7. An anonymous commenter suggested that operators be required to collect data if they do not have enough information to analyze the risks of the pipeline segment.
PHMSA appreciates the information provided by the commenters. The expanded rule language does not impose new requirements for collecting specific data during pipe exposures, but the response to question D.4 discusses proposed changes to collection and validation practices to improve data integration and risk assessment practices.
1. AGA, GPTC, Nicor, Paiute, and Southwest Gas reported that operators do try to verify information but that operator practices are too numerous to list in response to this general question. They contended that the requirements for external corrosion control in § 192.459 and for internal corrosion control in § 192.475 and the guidance in Advisory Bulletin 11-01 are sufficient and no new requirements are needed. A number of other pipeline operators provided comments supporting AGA's comments.
2. INGAA, supported by many of its pipeline operator members, commented that there are limited, if any, methods to determine accurately mechanical properties of pipe that is
3. Texas Pipeline Association and Texas Oil & Gas Association commented that operators do not validate mill data after initial construction.
4. Ameren Illinois reported that data review and correction is a normal part of the business of pipeline operation. Ameren commented that additional work in this area is likely to result from Advisory Bulletin 11-01.
5. Northern Natural Gas reported that data correction occurs when a discrepancy is identified. Northern also noted that it has added data to its risk model over time, principally related to determination of the potential consequences of a pipeline accident.
6. MidAmerican commented that operators validate pipeline information periodically.
7. California Public Utilities Commission reported that California pipeline operators have begun validating pipeline data since the San Bruno accident. CPUC commented that operators should determine pipeline specifications for all exposed facilities and use them to validate their records.
8. Paiute and Southwest Gas reported that it is their practice to obtain pipeline data before an integrity management excavation and then to validate that information in the field.
9. MidAmerican reported that it uses a geospatial database as its principal tool for collecting and validating pipeline information.
10. An anonymous commenter suggested that pipeline operators do not routinely collect information to validate their databases during pipeline excavations.
PHMSA appreciates the information provided by the commenters. See response to question D.4.
1. INGAA, GPTC, Nicor, Ameren Illinois, MidAmerican, Paiute and Southwest Gas commented that additional prescriptive requirements are not needed. These commenters suggested that Advisory Bulletin ADB-11-01, subpart O of part 192, and ASME/ANSI B31.8S are sufficient to govern these practices. INGAA added requirements for data validation during excavations could introduce workplace hazards that would outweigh any benefit to be gained. In the event PHMSA proceeds to propose new requirements, INGAA requested they be limited to a reasonable process and allow assumptions to be made to fill information gaps, suggesting this would be a more cost-effective approach than
2. AGA, supported by a number of its pipeline operator members, commented that there is no evidence to support a need for more prescriptive requirements leading to better data collection or validation and, therefore, no such requirements are needed.
3. Pipeline Safety Trust, NAPSR, California Public Utilities Commission, and Commissioners of Wyoming County, Pennsylvania, commented that requirements for data collection, validation, and use should be more prescriptive. These commenters noted that the investigation of the San Bruno accident identified at least one pipeline operator was not doing an adequate job of data validation. They noted that NTSB recommendations P-11-18 and P-11-19 apply to this topic. NAPSR specifically requested that new requirements specify precise inspection criteria.
4. Texas Pipeline Association and Texas Oil & Gas Association suggested that there is no value in periodic validation of pipeline data and new requirements are not needed in this area. Northern Natural Gas agreed, noting that pipeline data does not change over time, and relevant data that is subject to change, is that data needed to evaluate the consequences of potential pipeline accidents.
5. Accufacts commented that more specific criteria, including minimum data requirements, are needed for record retention. Accufacts noted that integrity management is data-based and that too many operators claim that data is lost or cannot be found.
6. Alaska Department of Natural Resources suggested that data integration should be required in interpreting ILI results.
7. An anonymous commenter suggested that specific requirements are not needed in this area, contending that most data has been validated through normal operator practices.
8. A private citizen suggested that PHMSA require pipeline operators to post all records for access by state and local government officials, PHMSA, and the media. The commenter suggested such a “sunshine” provision would improve recordkeeping, even if no one ever examines the posted records.
PHMSA appreciates the information provided by the commenters in response to questions D.1 through D.4. Commenters disagreed on the need and benefit of making current requirements more prescriptive so operators will strengthen their collection and validation practices. PHMSA believes enhancing regulations in this area is an important element of good integrity management practices. On July 21, 2011, in response to the San Bruno incident, PHMSA sponsored a public workshop on risk assessment and related data analysis and recordkeeping issues to seek input from stakeholders. Based in part on the input received at this workshop, and the information submitted in response to the ANPRM, PHMSA proposes to clarify the performance-based requirements for collecting, validating, and integrating pipeline data by adding specificity to the data integration language, establishing a number of pipeline attributes that must be included in these analyses, explicitly requiring that operators integrate analyzed information, and ensuring data is reliable. The rule also requires operators to use validated, objective data to the maximum extent practical. PHMSA also understands that objective sources such as as—built drawings, alignment sheets, material specifications, and design, construction, inspection, testing, maintenance, manufacturer, or other related documents are not always available or obtainable. To the degree that subjective data from subject matter experts must be used, PHMSA proposes to require that an operator's program include specific features to compensate for subject matter expert bias. PHMSA believes that these proposed changes would not impose new requirements or more prescriptive requirements, but clarifies the intent of the regulation. However, PHMSA requests public comment on whether and the extent to which this proposal may change behavior.
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No comments were received in response to this question.
The ANPRM requested comments regarding whether requirements related to the nature and application of risk models should be made more prescriptive to improve the usefulness of these analyses in controlling risks from pipelines. Current regulations require that gas transmission pipeline operators perform risk analyses of their pipelines and use these analyses to make certain decisions to assure the integrity of their pipeline and to enhance protection against the consequences of potential incidents. The regulations do not prescribe the type of risk analysis nor do they impose any requirements regarding its breadth and scope, other than requiring that it consider the entire pipeline. PHMSA's experience in inspecting operator compliance with IM requirements has identified that most pipeline operators use a relative index-model approach to performing their risk assessments and that there is a wide range in scope and quality of the resulting analyses. It is not clear that all of the observed risk analyses can support robust decision-making and management of the pipeline risk. The following are general comments received related to the topic as well as comments related to the specific questions:
1. INGAA and Chevron commented that continuing the performance-based regulatory approach, exemplified by integrity management, is critically important to pipeline safety. They suggested that prescriptive management systems are task oriented, do not adjust easily to new information or knowledge, inhibit innovation, and could thwart safety improvements. A number of other pipeline operators provided comments supporting INGAA's comments.
2. Accufacts commented that risk management approaches permitted in IM need additional prescriptive measures to clarify strengths and weaknesses and to assure compliance. Public perception resulting from the number of serious incidents is that current risk analysis and risk management approaches are not sufficient. The impression is that risk management is being used to justify unwise lowest cost decisions rather than being used as a tool to avoid failure. Accufacts further suggested that interactive threats need to be addressed by prescriptive requirements in safety
3. Oleksa and Associates suggested that it would be statistically more valid for many (perhaps most) operators for PHMSA to perform continual evaluation and assessment using established performance measures along with data submitted by operators on annual, incident, and safety-related condition reports, and then to promulgate more prescriptive regulations resulting from that assessment. Oleksa suggested that it may be time to re-evaluate the overall concept of integrity management to determine whether it makes sense for each operator to make assessments that might be more valid if made on a national level. Oleksa also stated that there should be a concerted effort in promulgating any new regulations towards making the regulations simple enough so that they can be understood relatively easily.
4. TransCanada commented that PHMSA's IM regulations should provide explicit metrics for operators to demonstrate safety decision processes without restricting the opportunity to use more accurate and advanced methods. TransCanada said that any efforts to make risk models more prescriptive should focus on process elements while providing operators the flexibility to build processes which recognize the unique characteristics of their pipeline systems. The company also opined that issuing more detailed guidelines on specific integrity management plan elements would enhance the current, performance-based approach and generate additional benefits that the public and operators desire.
5. Dominion East Ohio Gas opposed making requirements for risk models more prescriptive. Like INGAA, they that noted prescriptive management systems are task oriented and do not adjust easily to new information or knowledge. They inhibit innovation and could thwart safety improvements.
6. NAPSR strongly urged PHMSA to make the nature and application of risk models more prescriptive. NAPSR commented that PHMSA has not provided any data that supports the theory that risk modeling provides a stronger safety environment and contended that, in fact, the opposite may be occurring.
7. A private citizen suggested that PHMSA correlate the quality of an operator's risk model with the number of enforcement actions against that operator.
8. A private citizen suggested that risk analysis requirements should remain flexible, commenting that prescribed methods or requirements could mask operator-specific issues.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that prescriptive rules for risk assessments are not appropriate because one-size-fits-all regulations would not be effective for such a diverse industry. However, PHMSA does believe that operator risk models and risk assessments should have substantially improved since the initial framework programs established nearly 10 years ago. While simple index or relative (qualitative) ranking models were useful to prioritize HCA segments for purposes of scheduling integrity baseline assessments, those models have limited utility to perform the analyses needed to better understand pipeline risks, better understand failure mechanisms (especially for interacting threats), or to identify effective preventive and mitigative measures. PHMSA is proposing to further clarify its expectations for this aspect of the performance-based regulations to further improve pipeline safety. On July 21, 2011, PHMSA sponsored a public workshop on risk assessment to seek input from stakeholders. PHMSA has evaluated the input it received at this workshop. PHMSA proposes to clarify the risk assessment aspects of the IM rule to explicitly articulate functional requirements and to assure that risk assessments are adequate to: (1) Evaluate the effects of interacting threats, (2) determine intervals for continual integrity reassessments, (3) determine additional preventive and mitigative measures needed, (4) analyze how a potential failure could affect HCAs, including the consequences of the entire worst-case incident scenario from initial failure to incident termination, (5) identify the contribution to risk of each risk factor, or each unique combination of risk factors that interact or simultaneously contribute to risk at a common location, (6) account and compensate for uncertainties in the model and the data used in the risk assessment, and (7) evaluate predicted risk reduction associated with preventive and mitigative measures. In addition, in response to NTSB recommendation P-11-18, PHMSA proposes to require that operators validate their risk models in light of incident, leak, and failure history and other historical information. PHMSA also proposes to expand the list of example preventive and mitigative measures to include the following items: establish and implement adequate operations and maintenance processes that could affect safety; establish and deploy adequate resources for successful execution of activities, processes, and systems associated with operations, maintenance, preventive measures, mitigative measures, and managing pipeline integrity; and correct the root cause of past incidents to prevent recurrence.
In response to Oleksa's comments, PHMSA is addressing performance measures outside of this rulemaking. Performance measures will be addressed separately in response to NTSB safety recommendations P-11-18 and P-11-19.
1. INGAA, AGA, and many pipeline operators reported that they do not believe there is a pipeline safety benefit for PHMSA to “strengthen” or revise the requirements on functions that risk models must perform or in mandating the use of specific risk models. These commenters noted that there is a tremendous amount of diversity in the pipeline systems of individual operators and operators must have the flexibility to select the risk model that best supports their systems.
2. GPTC commented that there is no `one-size-fits-all' risk model. GPTC further commented PHMSA has offered no data supporting the need to strengthen requirements or mandate a particular risk model.
3. Kern River noted that differences exist between pipeline operators on how much detail is needed in their risk assessment models. The specific factors and required risk model complexity will differ for each pipeline company based on its active threats, the preventive and mitigative measures employed, its data acquisition methods and the amount of required data.
4. MidAmerican commented that no change is needed to requirements concerning risk models. MidAmerican noted that ASME/ANSI B31.8S provides extremely detailed requirements in this area, and suggested that operators should have the freedom to choose the risk model best suited to their operation. Northern Natural Gas agreed, noting that there are large differences within the industry on the complexity of the risk assessment models used based on the
5. Paiute and Southwest Gas opposed more restrictive requirements for risk modeling. They noted that operators have a decade of experience working with IM and therefore, should have the flexibility to choose the risk model that best suits their system.
6. Accufacts commented that this is an area that needs more prescriptive requirements. Accufacts questioned whether the current approach of reliance on risk modeling is even appropriate. They stated that there appears to be a disconnect between the use of risk models and risk analysis with pipeline operation and the ability of regulators to apply and enforce the approach.
7. TransCanada noted that mandating the use of a specific risk model may result in a more uniform approach across the industry, but may also force operators to abandon their existing risk models, including the improvements made to them based on 10 years of integrity management experience. This would not appear to advance risk modeling and might even be counterproductive.
8. WKM Consultancy commented that mandating a specific risk assessment model would not be a beneficial addition to regulations. Such a mandate would stifle creativity and require extensive definitions and documentation of that methodology. A mandated model would introduce a prescriptive element with substantial “overhead” related to the maintenance of the model's documentation by the regulators. They suggested that a better solution would be to develop guidelines of essential ingredients necessary in any pipeline risk assessment.
9. An anonymous commenter opposed requiring the use of a specific risk model, suggesting that operators should use models with which they are comfortable. The commenter did suggest that PHMSA strengthen requirements concerning the use of risk models for purposes other than risk-ranking segments, expressing a belief that most operators are using their models only for that purpose.
10. California Public Utilities Commission recommended that PHMSA require statistical data be maintained and used to support the weightings assigned by risk models to various threats.
PHMSA appreciates the information provided by the commenters. A large number of comments do not support adding a requirement for a specific risk assessment model or for strengthening or revising the required functions that risk models must perform. PHMSA agrees that prescribing the use of particular risk assessment models is not appropriate for such a diverse industry, and notes that relative index models have been successfully used to rank pipelines to prioritize baseline assessments. However, PHMSA believes that the integrity management rule anticipates that operators would continually improve their risk assessment processes and that there are specific risk assessment attributes related to the nature and application of risk models that need clarification. Such attributes and shortcomings were discussed at the “Improving Pipeline Risk Assessments and Recordkeeping” workshop with stakeholders, held on July 21, 2011.
PHMSA proposes to articulate clear functional requirements, in performance-based terms, for risk assessment methods used by operators. While PHMSA does not propose to prescribe the specific risk assessment model operators must use, PHMSA does propose to clarify the characteristics of a mature risk assessment program. These include: (1) Identifying risk drivers; (2) evaluating interactive threats; (3) assuring the use of traceable and verifiable information and data; (4) accounting for uncertainties in the risk model and the data used; (5) incorporating a root cause analysis of past incidents; (6) validating the risk model in light of incident, leak and failure history and other historical information; (7) using the risk assessment to establish criteria for acceptable risk levels; and (8) determining what additional preventive and mitigative measures are needed to achieve risk reduction goals. PHMSA proposes to clarify that the risk assessment method selected by the operator must be capable of successfully performing these functions.
1. Industry commenters, including INGAA, AGA, Texas Pipeline Association, Texas Oil & Gas Association, WKM Consultancy, and many pipeline operators reported that PHMSA's understanding is correct and that risk models in use generally
2. AGA, supported by a number of its pipeline operator members, commented that risk models currently in use are sufficiently robust. Ameren Illinois and GPTC expressed a similar belief.
3. INGAA, supported by some of its members, noted that there is room for improvement in the current practices of risk modeling. INGAA reported that the industry has established committees to identify advancements in risk modeling.
4. WKM Consultancy commented that the more robust of the relative risk index techniques are often capable of fulfilling some aspects of IM risk management requirements such as prioritization, but that other aspects of the risk management requirements are not well supported by relative risk assessments. They suggested that some risk assessment models in current use could benefit from application of more robust and modern techniques.
5. Kern River commented that a relative risk model is sufficiently robust to support decisions on preventive and mitigative measures and assessment intervals.
6. MidAmerican reported that its risk model complies with ASME/ANSI B31.8S and is sufficiently robust to support decisions that are not specifically related to assessments. MidAmerican further stated that its risk model produces results consistent with its subject matter expert assessments of relative risk.
7. Paiute and Southwest Gas reported their conclusion that their risk models are robust and support the process of evaluation and selection of preventive and mitigative measures.
8. Texas Pipeline Association and Texas Oil & Gas Association noted that all sources of information relative to the integrity of a transmission pipeline segment and the identified risk should be used in the selection of preventive and mitigative measures. Atmos agreed, noting that preventive and mitigative measures for a given pipeline segment are based on the identified threats.
9. A private citizen suggested that consideration of system-wide high risk (
PHMSA appreciates the information provided by the commenters. Although a large number of comments contend risk models currently in use are sufficiently robust, PHMSA believes that there are specific risk assessment attributes not found in many of the simple index or relative risk models currently in use. The July 21, 2011, workshop on “Improving Pipeline Risk Assessments and Recordkeeping” identified several shortcomings in risk assessments conducted using qualitative, index, or relative risk methodologies, and PHMSA is proposing to clarify requirements to address these issues including the need for better or more prescriptive guidance to address data gaps, data integration, uncertainty, interacting threats, risk management, and quantitative approaches instead of subjective or qualitative approaches. The proposed regulation would require operators to conduct risk assessments that effectively analyze the identified threats and potential consequences of an incident for each HCA segment. Additionally, the proposed regulation would require the risk assessment to include evaluation of the effects of interacting threats, including those threats and anomalous conditions not previously evaluated. It should be further noted that the intent of the original IM rule is that any risk assessment would consider system-wide risk.
1. INGAA commented that operators should develop internal communication plans and they should follow Section 10.3 of ASME/ANSI B31.8S in doing so. AGA similarly noted that the methods used to disseminate results of the risk evaluation to executive management are operator specific and detailed in the operator's integrity management plan. A number of pipeline operators provided comments supporting both INGAA's and AGA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association noted that the results of risk modeling are usually used in conjunction with assessment results to inform executive management of actions required beyond normal repair, additional preventive and mitigative measures, discussion of high risk pipelines, and progress in meeting assessment goals.
3. WKM Consultancy commented that operators are obliged to communicate all aspects of integrity management to higher level managers at regular intervals. They noted that all prudent operators are very interested in risk management and results of risk modeling are usually a centerpiece of discussion and decision-making.
4. Ameren Illinois reported that its IM plan provides for informing executive management of existing risks.
5. Atmos reported that it provides executive management with periodic updates on the status of its integrity management program. During these updates, Atmos' executive management reviews baseline assessment plans, assessment results, anomalies discovered and mitigated, anomalies discovered and scheduled for repair, leading causes of anomalies, and preventive and mitigative actions taken.
6. Kern River noted that it provides its executive management with reports describing integrity management program activities and results and that the company engages the use of the risk model as an input to financial planning and maintenance planning. MidAmerican also reported that risk scores are used to support capital, operating and maintenance expenditures to executive management.
7. Northern Natural Gas reported that it provides executive management with reports describing integrity management program activities and results. Its executive management is engaged in the process and the use of the risk model to prioritize projects.
8. Paiute and Southwest Gas reported that integrity management activities are discussed with executive management quarterly.
9. An anonymous commenter suggested that operators generally do not use risk models to inform executives, because they would have to explain the models in order to do so.
PHMSA appreciates the information provided by the commenters. PHMSA understands that internal company processes for communication with executive management are specific to each company. To strengthen the application of risk assessment, PHMSA is proposing to clarify requirements by providing more specific and detailed examples of the kinds of preventive and mitigative measures operators should consider. The proposed rulemaking would include the following specific examples of preventive and mitigative measures that operators should consider: Establish and implement adequate operations and maintenance processes; establish and deploy adequate resources for successful execution of activities, processes, and systems associated with operations, maintenance, preventive measures, mitigative measures, and managing pipeline integrity; and correct the root cause of past incidents to prevent recurrence. The last item necessarily requires a robust root cause analysis that identifies underlying programmatic or policy issues that create or facilitate conditions or circumstances that ultimately lead to pipeline failures.
1. INGAA and many of its pipeline operator members commented that existing models can and do provide an understanding of segment risk through threat identification, performing “what if” analyses, and identifying preventive and mitigative measures that will reduce risk.
2. AGA and GPTC noted that existing models selected by operators are sufficiently robust to allow the integration of large volumes of data and information to achieve a comprehensive overall risk evaluation for their systems. These risk models allow an operator to understand the specific threats associated with each pipeline segment and the preventive and mitigative measures that would be most appropriate. A number of pipeline operators provided comments supporting AGA's comments.
3. WKM Consultancy opined that currently used risk assessment models generally can significantly improve the ability to manage risks. They noted that a formal risk assessment provides the structure to increase understanding, reduce subjectivity, and ensure that important considerations are not overlooked.
4. Atmos reported that its model can be used to generate a report listing the significant variables contributing to a relatively higher risk factor score, and that if a contributing variable can be controlled, the risk model can support further actions to control the variable.
5. Ameren Illinois reported that it uses a robust risk model that can integrate various risk factors in order to evaluate its system.
6. Kern River and Northern Natural Gas commented that existing risk models can be used to understand major contributors to segment risk and support decisions regarding how to manage these contributors. By identifying threat drivers in the risk results and analyzing the data used by the model, integrity management personnel are able to reduce risk through preventive and mitigative measures, improvements in data quality, and shorter reassessment intervals.
7. MidAmerican reported that its risk model is used to understand major contributors to risk and to support decisions regarding how to manage those contributors.
8. Paiute and Southwest Gas reported that they conduct a review of threat-specific indices to identify the major contributors to risk for each threat.
9. Texas Pipeline Association and Texas Oil & Gas Association noted that risk modeling can be used to generate reports listing the significant variables contributing to high risk scores.
10. An anonymous commenter noted that risk models can serve these functions and some operators use them in this way. The commenter opined that most operators “aren't there yet,” and that operators who use models for this purpose have more enthusiasm for integrity management and more executive management support.
PHMSA appreciates the information provided by the commenters. The majority of the comments suggest that current risk models provide an adequate understanding of major contributors to risk. PHMSA believes it is prudent to clarify the required attributes of risk assessment in this area and proposes to include performance-based language to assure that risk assessments adequately identify the contribution to risk of each risk factor, or each unique combination of risk factors that interact or simultaneously contribute to risk at a common location.
1. INGAA noted that continuous improvement is required, and that industry is working on improvements to ASME/ANSI B31.8S. AGA similarly noted that risk models are periodically improved by operators by integrating new data and the results of integrity assessments. A number of pipeline operators provided comments supporting INGAA's and AGA's comments.
2. GPTC commented that new data and information are received on an ongoing basis. This new data, and results of integrity assessments, are reviewed, integrated, and added to risk models periodically.
3. WKM Consultancy suggested that a limited amount of standardization would be appropriate. They opined that this would ensure that all risk assessments contain, at a minimum, a short list of essential ingredients. For example, all assessments should produce a profile showing changes in risk along a pipeline route.
4. Ameren Illinois reported that its risk model allows for integration of information for continuous improvement.
5. Atmos commented that there is the potential for the risk model process to handle unknown data in a more useful manner. Atmos suggested that a higher risk score with “known” data attributes should be considered more relevant for decisions on preventive and mitigative measures than a similar score derived from “unknown” data attributes.
6. Kern River suggested that industry-wide research into failure probabilities and effectiveness of preventive and mitigative measures would facilitate more rigorous quantitative models. Kern River noted that vendors are continuously improving risk models.
7. MidAmerican suggested that risk models could be improved with better tracking, recording, and retrieval of assessment results. With feedback and information sharing, refining coefficients within the model will produce more accurate risk results.
8. Northern Natural Gas reported that its risk assessment process is improved every year and that its risk model vendor is heavily involved with the company in understanding how the risk results are used.
9. Paiute and Southwest Gas suggested that risk models will be improved as additional information is gained through an assessment cycle and that this continuous improvement process will then repeat through subsequent assessment cycles.
10. Texas Pipeline Association and Texas Oil & Gas Association observed that there is no `one size fits all' solution to this issue.
PHMSA appreciates the information provided by the commenters. The comments speak in general terms about incremental improvement of existing index-type or qualitative relative risk models. PHMSA believes that such models, while appropriate and useful for limited purposes such as ranking segments to prioritize baseline assessments, fall far short of the type of model needed to fully execute a mature integrity management program. PHMSA proposes to clearly articulate the requirements for validation of the risk assessment and proposes to clarify that an operator must ensure validity of the methods used to conduct the risk assessment in light of incident, leak, and failure history and other historical information. Additionally, the proposed rule would require that validation must: (1) Ensure the risk assessment methods produce a risk characterization that is consistent with the operator's and industry experience, including evaluations of the cause of past incidents as determined by root cause analysis or other means; and (2) include analysis of the factors used to characterize both the probability of loss of pipeline integrity and consequences of the postulated loss of pipeline integrity.
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No comments were received in response to this question.
The ANPRM requested comments regarding strengthening requirements related to operators' use of insights gained from implementation of an IM program. IM assessments provide information about the condition of the pipeline. Identified anomalies that exceed criteria in § 192.933 must be remediated immediately (§ 192.933(d)(1)) or within one year (§ 192.933(d)(2)) or must be monitored on future assessments (§ 192.933(d)(3)). Operators are also expected to apply knowledge gained through these assessments to assure the integrity of their entire pipeline as part of its threat identification and risk analysis process in accordance with § 192.917.
Section 192.917(e)(5) explicitly requires that operators must evaluate other portions of their pipeline if an assessment identifies corrosion requiring repair under the criteria of § 192.933. The operator must “evaluate and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar material coating and environmental characteristics.”
Section 192.917 also requires that operators conduct risk assessments that follow American Society of Mechanical Engineers/American National Standards Institute (ASME/ANSI) B31.8S, Section
1. MidAmerican suggested that application of knowledge gained through integrity management should not be treated any differently than any other information gained from work on or surveillance of the pipeline. MidAmerican considers this to be adequately addressed by § 192.613.
PHMSA continues to believe that there are many important integrity management requirements related to insights gained from implementation of the IM program beyond those covered by the continuing surveillance requirements of § 192.613. Integrity management assessments provide information about the condition of the pipeline and operators are expected to apply the knowledge gained through these assessments to assure the integrity of their entire pipeline. PHMSA believes that the knowledge gained through IM assessments should be integrated into the risk assessment process, which is not required by § 192.613.
1. INGAA and a number of pipeline operators noted that operators use available information and field knowledge to comply with this requirement.
2. AGA, supported by a number of its member companies, reported that operator practices are too distinct and varied to list. AGA stated that § 192.917(e)(5) is prescriptive enough and no new requirements are needed.
3. GPTC and Nicor cited NACE SP0169 and NACE RP0177 as examples of standards that can be used to guide compliance with § 192.917(e)(5).
4. Texas Pipeline Association and Texas Oil & Gas Association commented that operators use cathodic protection surveys and/or spot checks to determine whether failure is likely.
5. Northern Natural Gas reported that it takes the actions specified in § 192.917(e)(5) and includes consideration of incidents and safety related conditions.
6. Kern River, Paiute, and Southwest Gas stated that they use root cause evaluations of incidents to comply with § 192.917(e)(5).
PHMSA appreciates the information provided by the commenters. The comments provide little information related to specific operator practices for compliance with § 192.917(e)(5). PHMSA is not proposing to amend § 192.917(e)(5) at this time; however, PHMSA proposes to clarify requirements in § 192.917(b) to ensure that the data gathering and integration process includes an analysis of both the HCA segments and similar non-HCA segments and integrates information about pipeline attributes and other relevant information, including data gathered through integrity assessments.
1. Based on a limited response by their members to a survey, Texas Pipeline Association and Texas Oil & Gas Association reported that repair of corrosion beyond the initially-identified anomaly is rare.
2. Ameren Illinois reported that it has experienced two instances in which it repaired other segments after identifying corrosion on a covered pipeline segment.
3. MidAmerican reported that it has experienced a few instances of corrosion where coating was damaged during installation of a vent, and some at air-to-soil interfaces.
4. Northern Natural Gas has experienced no instances in which other pipeline segments required repair. Northern added that corrosion wall loss requiring repair is, itself, rare.
5. Paiute and Southwest Gas reported that they had not identified any immediate repair corrosion conditions.
PHMSA appreciates the information provided by the commenters. See the response to question F.1.
1. INGAA and several pipeline operators reported that operators update risk analyses whenever new information is obtained and particularly after unexpected events.
2. AGA, GPTC, Nicor, Kern River, and TransCanada commented that risk analyses are updated at least annually.
3. Northern Natural Gas reported that its procedures provide for updating to include assessment results and changes in environmental factors.
4. Paiute and Southwest Gas reported that risk model updating is a continuous process. Rankings are updated at 18- to 24-month intervals. Ameren Illinois and Atmos similarly reported that updating is an ongoing activity.
5. Texas Pipeline Association and Texas Oil & Gas Association commented that most operators have dedicated teams to perform risk model updates.
6. Alaska Department of Natural Resources commented that risk models should be reviewed whenever significant operational or environmental changes occur. AKDNR contended that risk models are not valid if there are significant changes in these areas.
7. NAPSR reported its conclusion that risk models should be updated after every O&M activity or any finding that a required activity was not performed.
8. INGAA and a number of pipeline operators reported that data is updated using a common spatial reference system,
9. AGA, supported by a number of its member companies, reported that data integration does not always involve use of geospatial tools.
10. Atmos reported that it uses internal teams of subject matter experts for data integration and that its maps are not layered for technical data use.
11. Northern Natural Gas, Paiute, and Southwest Gas stated that they perform integration on alignment sheets based on integrity management summaries and subject matter expert reviews.
12. Texas Pipeline Association and Texas Oil & Gas Association reported that many pipeline operators are migrating to GIS systems.
13. INGAA and many pipeline operators commented that information from aerial photography should be updated annually. They noted that this would be consistent with the frequency of reviewing HCA designations and operator budgeting and contended that more frequent updates would not increase risk model accuracy. INGAA suggested that other information, including information related to external events, should be updated based on the nature and severity of experienced events.
14. AGA, Paiute, and Southwest Gas noted that not all operators use aerial photography and expressed their belief that such use should not be required. AGA noted that there are many tools, including routine patrols, to gather data about the pipeline environment. A number of member pipeline operators supported AGA's comments.
15. Northern Natural Gas reported that it updates information periodically, but with no set frequency. Northern noted that some areas are stable while change can occur rapidly in others.
16. Texas Pipeline Association and Texas Oil & Gas Association recommended annual updates as a minimum. The associations noted that this recognizes the time required to produce/acquire assessment data.
PHMSA appreciates the information provided by the commenters. After review of the comments, PHMSA agrees that annual updates are desirable and many operators perform full updates, or partial data updates (such as updating aerial photos), annually. Some pipeline segments may be in rapidly changing, dynamic environments, while others may remain static for years. PHMSA also agrees that prescriptive requirements to perform a full risk assessment annually are not necessary and potentially burdensome, especially for very small operators, whose systems and conditions do not change often. PHMSA is satisfied that the current requirement, which contains a performance based requirement to update risk assessments as frequently as needed to assure the integrity of each HCA segment is adequate, if properly implemented, and is not proposing a prescribed frequency at this time. However, PHMSA proposes to clarify requirements in §§ 192.917 and 192.937(b) to ensure the continual process of evaluation and assessment is based on an updated and effective data integration and risk assessment process as specified in § 192.917.
1. INGAA and numerous pipeline operators recommended that reviews be annual, as suggested in PHMSA's Gas Integrity Management Program Frequently Asked Question FAQ-234, arguing that this is practical and sufficient (FAQs can be viewed at
2. AGA, GPTC, and a number of other pipeline operators commented that no maximum period should be specified for review of risk assessments. These commenters argued that no one-size-fits-all interval would be appropriate and expressed their conclusion that the current requirements in § 192.937 are adequate.
3. California Public Utilities Commission recommended that reviews be required annually, at intervals not to exceed 15 months, consistent with other requirements within part 192.
4. An anonymous commenter suggested that a specified review period would be counterproductive, arguing that most operators would simply default to the required interval, even if more frequent reviews were appropriate.
PHMSA appreciates the information provided by the commenters. See PHMSA response to comments related to Question F.3.
1. INGAA and many pipeline operators opined that no new requirements are needed in this area. They noted that prescriptive requirements often become out of date as technology improves.
2. AGA and numerous pipeline operators agreed that no new requirements are needed, noting that existing regulations and sharing of information through industry groups is sufficient.
3. Texas Pipeline Association and Texas Oil & Gas Association opined that existing requirements are adequate.
4. Accufacts suggested that requirements should be more prescriptive concerning threat evaluation and interactive threats, as this is the heart of integrity management.
5. An anonymous commenter suggested that new requirements be established governing assessments conducted by pressure testing. The commenter opined that the requirements in subpart J are inadequate and represent an “easy out” for some operators.
PHMSA appreciates the information provided by the commenters. While PHMSA believes that explicit requirements should be included to address interactive threats, PHMSA also believes that prescriptive rules for how an operator must evaluate interactive threats are not practical. Therefore, PHMSA proposes to clarify performance-based requirements to include an evaluation of the effects of interacting threats and for the continual process of evaluation and assessment to include interacting threats in identification of threats specific to each HCA segment. Comments on integrity assessment methods are addressed in Topic G.
1. INGAA, supported by a number of pipeline operators, commented that experience and information gained from a variety of sources, including GIS data, corrosion data, ILI data/results, work management activities, SCADA, encroachments, leaks etc., is utilized in data integration. INGAA reported that operators have made major investments
2. AGA, GPTC, and a number of pipeline operators commented that a prescriptive requirement would be inappropriate because there is too much variability among operators and their risk assessment methods. AGA expressed its conclusion that there is no single methodology that incorporates the wide variety of pipeline information used by operators.
3. MidAmerican suggested that an operator needs a robust computer model to integrate diverse data dynamically into one table with one set stationing.
4. Kern River reported that it uses extensive GIS and cathodic protection databases for these purposes.
5. An anonymous commenter recommended that PHMSA require knowledge of cathodic protection current level, amount, and direction of current flow. The commenter opined that this information is not now generally collected, and that it would allow for early detection of coating failures and CP interferences.
PHMSA appreciates the information provided by the commenters. An integral part of applying information from the IM Program to the risk assessment and other analyses is the collection, validation, and integration of pipeline data. PHMSA proposes to clarify the data integration language in the requirements by repealing the reference to ASME/ANSI B31.8S and including requirements associated with data integration directly in the rule text: (1) Establishing a number of pipeline attributes that must be included in these analyses, (2) clarifying that operators must integrate analyzed information, and (3) ensuring that data are verified and validated.
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No comments were received in response to this question.
The existing IM regulations require that baseline and periodic assessments of pipeline segments in an HCA be performed using one of four methods:
(1) In-line inspection;
(2) Pressure test in accordance with subpart J;
(3) Direct assessment to address the threats of external and internal corrosion and SCC; or
(4) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of line pipe.
Operators must notify PHMSA in advance if they plan to use “other technology.” Operators must apply one or more methods, depending on the threats to which the HCA segment is susceptible. The ANPRM requested comments related to the applicability, selection, and use of each assessment method, existing consensus standards and requirements, and the potential need to strengthen the requirements. The ANPRM then listed questions for consideration and comment. The following are general comments received related to the topic as well as comments related to the specific questions:
1. INGAA, supported by a number of its pipeline operator members, noted that they are committed to work with technology providers and researchers to improve the integrity management assessment capabilities of its members. Further, INGAA members are sharing their experiences with applying these new and improved assessment methods to specific threats. INGAA opined that a great advantage of the integrity management structure, as opposed to a prescriptive regulatory regime, is the creation of an environment conducive to technological development, innovation and improved knowledge.
2. Accufacts suggested that a more prescriptive regulation is needed clarifying the applicability and limitations of direct assessment. Accufacts is concerned that operators are selecting direct assessment due to a cost bias while ignoring that it cannot be used for all threats and should not be used on some pipeline segments.
3. Chevron commented that PHMSA should continue to allow operators to select and use the most effective method to assess each pipeline segment.
4. NAPSR recommended that PHMSA implement a regulatory change that requires both ILI and pressure testing for all transmission pipelines and requires a reduction in MAOP until either the ILI or the pressure tests are performed.
5. MidAmerican, a gas distribution company, noted that many of its transmission pipelines are short, small diameter lines that cannot be pigged.
6. Dominion East Ohio suggested that PHMSA should be funding more research leading to the development of assessment tools, particularly smart tools, to increase the number of assessment options available rather than limiting the tools that can be used.
7. A public citizen commented that pipe with unknown or uncertain specifications should be subject to the most stringent testing requirements.
8. Two public citizens addressed required assessment intervals. One suggested that all pipe that puts the public at significant risk should be tested, by hydro testing or some other means, at approximately ten-year intervals. Another commenter recommended that assessments be required more frequently in densely populated areas.
9. PST opined that the need to ask the questions in this section makes clear that PHMSA's current level of oversight and review of IM planning and implementation is inadequate, and calls into question the value of many IM programs, particularly those relying to any extent on direct assessment methods. PST recommended that the regulations be significantly strengthened to require PHMSA's review and administration approval of any IM program.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that pipeline operators should be able to select the best assessment
PHMSA understands the Pipeline Safety Trust's recommendation that the regulations require PHMSA's review and approval of any IM program. PHMSA believes its current approach to inspection of operator IM programs is both flexible and appropriate.
1. INGAA reported that operators have used in-line inspection, pressure testing, and direct assessment, with in-line inspection being most prevalent. INGAA commented that all three methods have been successful at identifying anomalies requiring repair. A number of pipeline operators supported INGAA's comments.
2. AGA and Ameren Illinois stated that all assessment methods used by pipeline operators have been used to identify, or have identified, anomalies requiring repair. A number of pipeline operators supported AGA's comments.
3. Accufacts recommended that PHMSA publically report the number of anomalies discovered and repaired by anomaly type, time to repair, state, and assessment method for both HCAs and non-HCAs.
4. Texas Pipeline Association, Texas Oil & Gas Association, Atmos, Paiute, and Southwest Gas noted that the transmission pipeline annual report includes the number of immediate and scheduled anomalies identified by each assessment method.
5. ITT Exelis Geospatial Systems reported that aerial leak surveys using laser technology, which is not one of the assessment methods specified in the regulations, have been successful in identifying pipeline leaks.
6. Kern River reported that it did not identify any immediate or scheduled repairs from January 1, 2004, through December 31, 2010.
7. MidAmerican noted that it has used all three allowed assessment methods. Approximately 42 percent of the company's pipeline has been assessed using direct assessment. All anomalies requiring repair have been identified using in-line inspection.
8. Northern Natural Gas reported that it identified seven immediate repair anomalies in the period from January 1, 2004, through December 31, 2010. The total number of repairs made during this same period averaged 0.1 per mile.
9. An anonymous commenter noted that few leaks are detected using subpart J pressure testing.
10. GPTC reported that it has no data with which to respond to this question.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that all three methods have been successful at identifying anomalies requiring repair. However, by its nature, direct assessment is a sampling-type assessment method. Hydrostatic pressure testing and in-line inspection both assess the entire segment. PHMSA, therefore, believes that these methods provide a higher level of assurance (though still not 100%) that no injurious pipeline defects remain in the pipe after the assessment is completed and anomalies repaired. Based on this inherent difference, PHMSA proposes to revise the requirements to: (1) Allow direct assessment only if a line is not capable of inspection by internal inspection tools; (2) add a newly defined assessment method: “spike” hydrostatic test; (3) add excavation and
1. INGAA, supported by a number of its pipeline operator members, noted that ILI is effective, but has its own limitations; pressure testing and direct assessment can provide information that ILI cannot. INGAA commented that operators must be allowed to use all assessment techniques without encumbrances or conditions because all techniques are effective.
2. AGA and a number of its members commented that ILI is one option of a variety of methods available to operators and suggested that applying additional ILI assessment requirements would hinder operators' ability to select the tool with the appropriate capabilities to address pipeline threats. AGA commented that this would be inappropriate and operators must be allowed to use any of the three assessment methods, without conditions, based on the circumstances and threats applicable to their pipelines.
3. Air Products and Chemicals, Inc. opposed a requirement to use ILI whenever possible. The company noted
4. TransCanada opposed requiring use of ILI. The company noted that ILI has its advantages, but it also has limitations, and commented that operators must be able to select the methods best suited to evaluate identified threats, given the wide range of circumstances and threats that may be applicable to particular pipeline segments.
5. NACE International noted that assessments using only ILI do not necessarily provide the most information about pipeline conditions; other assessment methods may be more appropriate for some threats. NACE also noted that not all pipelines are piggable. NACE believes that each assessment method has strengths and weaknesses, each should be used where appropriate, and overly prescriptive rules can supplant sound engineering judgment, stifle innovation, and prevent the development of new technologies.
6. Accufacts commented that all new pipelines should be configured to permit ILI and a timetable should be established to convert older pipelines for ILI. At the same time, Accufacts cautioned that one particular approach to ILI should not be oversold, and suggested that limitations on use of certain assessment methods should be strongly clarified in regulations. Accufacts suggested that PHMSA needs to clarify the major strengths and weaknesses of the various assessment methods identified and to improve subpart J, including requiring the reporting of hydro testing pressure ranges, both minimum and maximum pressures, as a percentage of SMYS when appropriate.
7. MidAmerican suggested that operators be allowed to address threats by category using the guidance in ASME/ANSI B31.8S. MidAmerican noted that it cannot use ILI on all of its transmission pipelines, 42 percent of which have been assessed using direct assessment. MidAmerican suggested that operators continue to use their threat assessments to determine which pipelines should be retrofitted to accommodate ILI.
8. Northern Natural Gas reported that it uses ILI whenever possible but it cannot be used on all of its lines due to their small diameter. Northern noted that pressure testing and direct assessment may be more appropriate for some threats and that the operator is responsible for selecting the best assessment method. Northern opined that the guidance on tool selection in ASME/ANSI B31.8S is sufficient.
9. Texas Pipeline Association and Texas Oil & Gas Association recommended that ILI not be the required assessment method of choice and that operators continue to have the flexibility to select the appropriate assessment method, noting that other methods may be better for a particular threat. The associations noted that ILI technology is improving rapidly and expressed concern that rulemaking cannot keep pace with technological advancement and that prescribing tools could result in assessments being conducted with inferior technology.
10. Thomas M. Lael, an industry consultant, noted that no assessment method, including ILI, is perfect. Lael suggested that use of alternating methods be required to realize the strengths of all methods.
11. A citizen commenter suggested that use of direct assessment be limited, since it does not provide sufficient information about the pipeline.
12. An anonymous commenter noted that requiring ILI would not be cost beneficial, because corrosion metal loss is a relatively slow process.
13. GPTC noted that ILI cannot be used on all pipelines and recommended that operators have the latitude to select the assessment method most appropriate for their pipelines. Oleksa and Associates similarly noted that ILI cannot be used on some pipelines.
14. Paiute and Southwest Gas opposed a requirement to use ILI whenever possible. The companies noted that ILI provides current pipe conditions but no information on environmental conditions surrounding the pipe. They commented that operators should not be discouraged from using any appropriate assessment method.
15. Ameren Illinois opposed requiring the use of ILI, noting that it is neither practical nor feasible to require ILI assessments on all pipelines.
16. California Public Utilities Commission recommended that pressure testing and ILI be the only methods allowed for IM assessments. CPUC suggested that the use of direct assessment be limited to confirmatory direct assessments and lines that have been pressure tested to subpart J requirements. CPUC further recommended that the regulations prescribe acceptable ILI tool types to address specific threats.
17. A private citizen suggested that pressure testing should not be allowed as an assessment method because it provides no information about anomalies not resulting in leaks or failures. The commenter suggested that use of pressure testing should be limited to verifying the integrity of new or repaired pipelines.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that operators should be able to select the methods best suited to evaluate identified threats. However, PHMSA believes rulemaking for strengthening requirements for the selection and use of assessment methods is needed to address specific issues identified from the San Bruno incident. PHMSA proposes more prescriptive guidance for the selection of assessment methods, especially related to the use of direct assessment and to assess for cracks and crack-like defects, as indicated in the response to general comments, above. For HCA segments, PHMSA proposes that the use of direct assessment as the assessment method would be allowed only if the pipeline is not capable of being inspected by internal, in-line inspection tools. For non-HCA segments, assessments would have to be done within 15 years and every 20 years thereafter. To facilitate the identification of non-HCA areas that require integrity assessment, PHMSA proposes to define a “Moderate Consequence Area” or MCA. PHMSA also proposes additional requirements for selection and use of internal inspection tools, including a requirement to explicitly consider uncertainties such as tool tolerance in reported results in identifying anomalies.
PHMSA disagrees with the suggestion that pressure testing should not be allowed as an assessment method. In many circumstances, pressure testing is a good indicator of a pipeline's integrity. Although it does not assess subcritical defects, it provides assurance of adequate design safety margin and can be useful in particular for lines that are not piggable.
1. Industry commenters, including AGA, INGAA, Texas Pipeline Association, Texas Oil and Gas Association, and numerous pipeline operators noted that the requirements applicable to direct assessment, specified in NACE Standard SP0502-2008 and incorporated into subpart O by reference, require a feasibility study to determine if use of direct assessment is appropriate. If it cannot be determined during the pre-assessment phase that adequate data is available, another assessment method must be selected. Industry commenters noted that it is the operator's responsibility to select an appropriate assessment method.
2. Paiute and Southwest Gas disagreed with the statement that “direct assessment is not a valid method to use where there are pipe properties or other essential data gaps.” The companies noted that the data gathered and evaluated conforms to Section 4 of ASME/ANSI B31.8S (incorporated by reference) which allows use of conservative proxy values when data gaps exist.
3. California Public Utilities Commission recommended that pressure testing and ILI be the only methods allowed for IM assessments. CPUC suggested that use of direct assessment be limited to confirmatory direct assessments and lines that have been pressure tested to subpart J requirements.
PHMSA appreciates the information provided by the commenters. PHMSA agrees that pressure testing and ILI are preferred integrity assessment methods, over direct assessment. However, when properly implemented, DA can be a valuable integrity assessment tool. PHMSA proposes to retain direct assessment as an assessment method where warranted, but proposes to revise the requirements in §§ 192.921 and 192.937 to allow use of direct assessment or other method only if a line is not capable of inspection by internal inspection tools.
1. A number of industry commenters submitted data concerning the number of pipeline miles that have been modified to accommodate ILI:
• INGAA reported that more than 30,000 miles of pipeline have been modified across the industry.
• Atmos reported that it has modified approximately 2,800 miles.
• Northern Natural Gas reported that it has modified approximately 2,500 miles.
• MidAmerican reported that it has modified 38 miles.
• Paiute and Southwest Gas reported that they have made modifications but have not tracked the total mileage on which they were performed.
• Ameren Illinois and Kern River reported that they have modified no pipelines. Kern River noted specifically that all of its mainline is piggable.
2. AGA reported that it has no data concerning the number of miles modified, but noted that operators are required to assure that new and replaced pipelines can accommodate ILI tools. AGA contended that modifying pipelines to accommodate ILI tools is more onerous for intrastate transmission pipeline operators than for interstate operators. A number of operators supported AGA's comments.
3. Texas Pipeline Association and GPTC reported that they have no data with which to respond to this question.
4. California Public Utilities Commission supported additional requirements to expand modifications to accommodate ILI but reported that it has no opinion on how these requirements should be structured.
5. MidAmerican noted that one-third of its 770 miles of transmission pipeline is of a diameter smaller than available ILI tools.
6. Northern Natural Gas commented that PHMSA should not consider additional requirements to expand modifications of pipelines to accommodate ILI tools, and that the inspection method and determination to assess additional line segments outside of HCAs should be based on specific risk factors and type and configuration of pipeline facility. The company noted that some lines cannot be assessed using ILI.
7. Paiute and Southwest Gas noted that § 192.150 requires that newly constructed or replacement pipelines be designed to accommodate ILI tools. They contended that the decision to modify other pipelines should be an operator decision based on the best assessment method.
8. Texas Pipeline Association and Texas Oil & Gas Association opined that PHMSA does not need to develop additional requirements for the modification of transmission pipelines to accommodate ILI tools. The associations noted that the regulations already cover this for new and replacement pipelines and that there is a financial incentive for operators to use ILI tools versus other assessment methods. Atmos agreed, also noting that there are numerous advantages to ILI that incentivize operators to use that method when they can.
9. Accufacts commented that PHMSA should report publicly the number of miles of transmission pipeline that can be inspected by ILI as well as the number of miles inspected by other assessment methods both for HCAs and non-HCAs.
PHMSA appreciates the information provided by the commenters. In its report on the San Bruno incident, the NTSB recommended that all natural gas transmission pipelines be configured so as to accommodate in-line inspection tools, with priority given to older pipelines (recommendation P-11-17). In its initial response to the NTSB recommendation, PHMSA stated that implementing this recommendation will involve significant technical and economic challenges and is likely to require time to implement. Additional data is needed to evaluate this issue. Therefore, further rulemaking will be considered separately in order to complete this evaluation. PHMSA will review the comments received on the ANPRM and will address this issue in the future.
1. INGAA, supported by a number of its operator members, noted that standards are continuously upgraded and improved and recommended that PHMSA adopt performance-based language that will allow operators to select appropriate standards.
2. AGA, supported by a number of its members, noted that ILI technology is advancing rapidly and it would be unwise to restrict innovation by handcuffing it to a slow-developing rulemaking process. AGA recommended that PHMSA not adopt ILI standards into the code. Ameren Illinois agreed that standards should not be incorporated, because to do so would limit operators' ability to use up-to-date standards.
3. GPTC argued that there is no justification to enact additional prescriptive regulations for ILI assessments of pipelines. GPTC contended that performance standards allow operators to select the best approach.
4. Atmos, MidAmerican, Northern Natural Gas, Paiute, and Southwest Gas all cited one or more of API1163, ASNT ILI-PQ-2005 and RP0102-2002, and ASME/ANSI B31.8S as standards used to conduct ILI assessments. All agreed that use of industry standards should remain voluntary. Paiute and Southwest Gas, in particular, commented that technology is developing rapidly, and that incorporating current standards into the regulations may hold operators accountable to a level of performance that may be outdated.
5. Texas Pipeline Association and Texas Oil & Gas Association also opposed incorporating ILI standards into the regulations. TPA commented that there are incentives for operators to take appropriate measures to obtain accurate and reliable ILI results.
6. An anonymous commenter suggested that incorporating standards could be counterproductive, since operators would usually stop with the required actions. The commenter suggested that a better approach would be to require operators to have precise specifications, guidelines, and a written process for ILI, none of which should be developed by the operator's ILI vendor. The commenter also suggested that a similar approach be adopted for stress corrosion cracking direct assessment (SCCDA).
7. California Public Utilities Commission and a private citizen recommended that standards be incorporated for mandatory compliance, arguing that this is necessary to assure quality and accuracy.
PHMSA appreciates the information provided by the commenters. The current pipeline safety regulations in 49 CFR 192.921 and 192.937 require that operators assess the material condition of pipelines in certain circumstances and allow use of in-line inspection tools for these assessments. Operators are required to follow the requirements of ASME/ANSI B31.8S in selecting the appropriate ILI tools. ASME B31.8S provides limited guidance for conducting ILI assessments. At the time these rules were promulgated, there was no consensus industry standard that addressed ILI. Three related standards have been published: API STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010. These standards address the qualification of inline inspection systems, the procedure for performing ILI, and the qualification of personnel conducting ILI, respectively. The incorporation of these standards into pipeline safety regulations will promote a higher level of safety by establishing consistent standards. Therefore, PHMSA is proposing to incorporate these industry standards into the regulations to provide better guidance for conducting integrity assessments with in-line inspection. PHMSA also encourages and actively supports the development of new and better technology for integrity assessments. Therefore, the rule also allows the application and use of new technology, provided that PHMSA is notified in advance. PHMSA will continue to evaluate the need for additional guidance for conducting integrity assessments or applying new technology.
1. INGAA commented that standards exist for ICDA and SCCDA. AGA agreed that NACE SP0206 addresses ICDA and SP0204 addresses SCCDA. AGA opposed adopting these standards into the regulations, however, commenting that a standard must be demonstrated to be effective before it can be incorporated. AGA noted that there are long-standing issues with the ICDA standard. Numerous pipeline operators provided comments supporting the INGAA and AGA comments.
2. GPTC, Atmos, Ameren Illinois, MidAmerican, Paiute, Southwest Gas, Texas Gas Association and Texas Oil & Gas Association all referenced one or more of: NACE SP0502, NACE SP0206, ASME/ANSI B31.8S, and GRI02-0057. All agreed that the standards should not be incorporated by reference, arguing that this would stifle innovation or require operators to follow requirements that may become outdated, or both. Paiute and Southwest Gas specifically recommended that PHMSA collect additional information on industry best practices and compile/review IM results related to internal corrosion and SCC before taking any action towards incorporating the standards.
3. NACE International reported its conclusion that the existing standards for ICDA and SCCDA should be incorporated into regulations. NACE also cautioned that overly-prescriptive regulations can prevent innovation and development of new technologies.
4. Northern Natural Gas reported that it used NACE SP0206 in developing its ICDA procedures and there would be no impact on the company if the standard were adopted into regulations. Northern further reported it does not use SCCDA.
5. Accufacts commented that few technical gains have been made in the abilities of direct assessment methods to reliably identify or assess at-risk anomalies, especially with regards to SCC.
6. California Public Utilities Commission argued that pressure testing and ILI should be the only assessment methods allowed. The Commission contended that direct assessment should be limited to use during confirmatory direct assessments and for lines that have been pressure tested to subpart J requirements.
7. An anonymous commenter noted that Kiefner, NACE, and ASTM all provide useful references for SCCDA and ICDA.
8. INGAA, supported by several of its operator members, noted that ASME/ANSI B31.8S addresses remediation and pressure testing. INGAA recommended that PHMSA adopt the 2010 version of this standard, arguing that it is improved over the 2004 standard that is currently incorporated by reference into Section 192.7 and that it addresses near-neutral SCC. The 2010 edition also includes specific guidance for SCC mitigation by means of hydrostatic pressure testing in the event SCC is identified on a pipeline.
9. MidAmerican reported that it uses ASME B31G to determine remaining wall strength and that it remediates conditions in accordance with § 192.933(d) and ASME/ANSI B31.8S.
PHMSA appreciates the information provided by the commenters. Section 192.927 specifies requirements for gas transmission pipeline operators who use ICDA for IM assessments. The requirements in § 192.927 were promulgated before there were consensus standards published that addressed ICDA. Section 192.927 requires that operators follow ASME/ANSI B31.8S provisions related to ICDA. PHMSA has reviewed NACE SP0206-2006 and finds that it is more comprehensive and rigorous than either § 192.927 or ASME B31.8S in many respects. In addition, Section 192.929 specifies requirements for gas transmission pipeline operators who use SCCDA for IM assessments. The requirements in § 192.929 were promulgated before there were consensus industry standards published that addressed SCCDA. Section 192.929 requires that operators follow Appendix A3 of ASME/ANSI B31.8S. This appendix provides some guidance for
1. INGAA suggested NACE SP0204, by itself, does not address the full life cycle concerns of SCC but in combination with ASME/ANSI B31.8S the full life cycle concerns are addressed. A number of pipeline operators supported INGAA's comments.
2. AGA, supported by a number of its members, suggested PHMSA should determine whether NACE SP0204 addresses full life cycle concerns.
3. GPTC, Texas Pipeline Association, Texas Oil & Gas Association, and Ameren Illinois commented it was not clear what PHMSA meant by “full life cycle concerns.”
4. NACE International reported that SP0204 does not address the full life cycle concerns of SCC; however, NACE noted that it has developed a 2011 “Guide to Improving Pipeline Safety by Corrosion Management” which will be converted into a NACE standard.
5. MidAmerican reported its conclusion that NACE SP0204 does address full life cycle concerns.
6. Paiute and Southwest Gas reported their conclusion that the existing standards are adequate, but deferred to NACE concerning the breadth of coverage of NACE standards.
PHMSA appreciates the information provided by the commenters. PHMSA believes that NACE SP0204-2008 is the best available guidance and is proposing to incorporate this industry standard into the regulations for conducting integrity assessments with SCCDA. In addition, other proposed requirements for integrity assessments and remediation in §§ 192.710, 192.713, 192.624, and subpart O provide greater assurance that the full life cycle concerns associated with SCC are addressed.
1. Industry commenters responding to this question unanimously noted that no statistics have been collected on the use of NACE SP0204. INGAA noted, in addition, that the SCC Joint Industry Project (JIP) represents the experience of operators of 160,000 miles of gas transmission pipeline.
2. Paiute and Southwest Gas reported that they have not identified any SCC on their pipeline systems.
3. An anonymous commenter noted that there has been one incident attributed to factors not addressed in current standards. The commenter noted that the only common factors among SCC colonies was high soil resistivity and disbanded coating.
PHMSA appreciates the information provided by the commenters. As described in the response to Question G.6, PHMSA is proposing to incorporate NACE SP0204-2008 into the regulations. PHMSA will continue to gather information in this area and will evaluate the need for more specific requirements or guidance to address the threat of SCC.
1. INGAA and a number of its pipeline operators argued that this should be a case-by-case decision guided by INGAA's Fitness for Service protocol. INGAA noted that new pipelines require a part 192, subpart J, pressure test while older pipelines may have been strength tested.
2. AGA, supported by a number of its pipeline operators, opined that a one-time pressure test is sufficient. AGA noted that Congress accepted the stability of pipelines that had undergone a post construction pressure test.
3. GPTC argued that a one-time pressure test is sufficient; however, such a test should not be mandated for pipelines not tested after construction unless a significant risk has been demonstrated. GPTC noted that manufacturing and construction defects are not time-related.
4. American Public Gas Association objected to any requirement for a one-time pressure test, noting that it is not practical to conduct such a test on most transmission pipelines operated by municipal pipeline operators.
5. Atmos noted that the decision to perform one-time pressure tests to address manufacturing and construction defects requires more information and consideration than can be conveyed in response to a single question. Atmos reported that it could not determine if the one-time pressure test requirement would apply to all pipeline segments or to pipelines with certain characteristics. Some of Atmos' pipelines could not be removed from service for testing without impacts on customers.
6. Ameren Illinois argued that no one-time pressure test should be required, noting that a pressure test is already required before a pipeline is placed in service.
7. Northern Natural Gas argued that a one-time pressure test should not be required in all cases. Northern noted that assessment of manufacturing and construction defect threats should be determined based on the risk level and pipeline type for pipeline segments do not have an existing pressure test.
8. MidAmerican opined that a one-time pressure test should be a requirement for manufacturing and construction defects, noting defects that survive a pressure test are unlikely to fail during the useful life of the pipeline.
9. Oleksa and Associates noted that: (1) A one-time pressure test is all that is needed for manufacturing and construction defects; (2) an in-service pipeline should only be pressure tested if there is clear reason to believe a strength test would be beneficial; and (3) many pipelines operate at such low levels of stress that a strength test is not necessary.
10. Paiute and Southwest Gas commented that a pressure test should be conducted in accordance with subpart J when initially placing a pipeline in service. The operators reported that they support the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 which will require systematic pressure testing (or other alternative methods of equal or greater effectiveness) of certain, previously untested transmission pipelines located in HCAs and operating at a pressure greater than 30% SMYS. Texas Pipeline Association and Texas Oil & Gas Association agreed, noting that testing of new pipelines is already required and the Act requires use of pressure testing or alternate means to verify MAOP.
11. Thomas Lael and California Public Utilities Commission argued that all pipelines should be subjected to a pressure test. CPUC noted that an unspecified technical paper published by Kiefner shows that a pressure test to 1.25 times MAOP will be sufficient to demonstrate the stability of manufacturing and construction defects and girth welds.
12. The NTSB recommended that PHMSA amend part 192 so that manufacturing and construction defects can only be considered stable if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the MAOP.
13. Accufacts suggested that a requirement for a one-time pressure test is needed, noting the NTSB safety recommendations issued following San Bruno made it clear that there are problems with the current IM regulations, especially as they relate to systems that were in operation before the implementation of federal regulations.
14. A private citizen suggested that a one-time pressure test or reduction of MAOP should be required for all low-frequency electric resistance welded (LFERW) pipe.
15. A private citizen suggested that a one-time pressure test conducted in combination with ILI should be required as a baseline for subsequent ILI inspections.
16. An anonymous commenter opined that no one-time pressure test is needed unless there is a history of seam failure or SCC.
PHMSA appreciates the information provided by the commenters. The majority of comments support performance of a one-time pressure test to address manufacturing and construction defects. The ANPRM requested comments regarding proposed changes to part 192 regulations that would repeal 49 CFR 192.619(c) and the NTSB issued recommendations to repeal 49 CFR 192.619(c) for all gas transmission pipelines (P-11-14) and to require a pressure test before concluding that manufacturing- and construction-related defects can be considered stable (P-11-15). In addition, Section 23 of the Act requires issuance of regulations regarding the use of tests to confirm the material strength of previously untested natural gas transmission lines.
An Integrity Verification Process (IVP) workshop was held in 2013. At the workshop, PHMSA, the National Association of State Pipeline Safety Representatives, and various other stakeholders presented information and comments were sought on a proposed IVP that will help address these issues. Key aspects of the proposed IVP process include criteria for establishing which pipe segments would be subject to the IVP, technical requirements for verifying material properties where adequate records are not available, and technical requirements for re-establishing MAOP where adequate records are not available or the existing MAOP was established under § 192.619(c). Comments were received from the American Gas Association, the Interstate Natural Gas Association of America, and other stakeholders and addressed the draft IVP flow chart, technical concerns for implementing the proposed IVP, and other issues. The detailed comments are available on Docket No. PHMSA-2013-0119. PHMSA considered and incorporated the stakeholder input, as appropriate into this NPRM, which proposes requirements to address pipelines that established MAOP under 49 CFR 192.619(c), manufacturing and construction defect stability, verification of MAOP (where records that establish MAOP are not available or inadequate), and verification and documentation of pipeline material for certain onshore, steel, gas transmission pipelines.
1. INGAA, AGA, GPTC, and numerous pipeline operators noted that direct assessment is a cyclical process that continually incorporates analysis of information made available from the direct and indirect assessment tools used. The direct assessment process requires that more restrictive criteria be applied on first use and as operators become more experienced with the methodology and gather more data on the pipeline, more informed pipeline integrity decisions are made. The commenters stated that operators using the direct assessment process must continuously assess the effectiveness of the methodology.
2. Paiute and Southwest gas commented that operators confirm the findings of the pre-assessment and indirect assessment steps as part of the four-step direct assessment process. Validation digs are required to confirm the effectiveness of the direct assessment process.
3. Texas Pipeline Association and Texas Oil & Gas Association noted that direct examinations are made as part of every direct assessment. In Texas, operators have generally been required by the Railroad Commission to demonstrate comparisons of direct assessment results to ILI results on a portion of their pipeline where both have been performed. The associations contended that this process of validating should be considered a quality audit.
4. Northern Natural Gas agreed that verification of the effectiveness of direct assessment is already a part of the required post-assessment step of the four-step direct assessment process. Ameren Illinois agreed that this process is effectively a quality audit.
5. Atmos reported that records are kept of the indicated anomalies and the actual anomalies discovered through direct examination, thus assuring the quality and validation of direct assessments.
6. Accufacts opined that there appear to be serious deficiencies in the application of direct assessment on gas pipelines.
7. An anonymous commenter noted that direct assessment, if used correctly, is informative and proactive, and best suited to identify preventive and mitigative actions and to establish assessment intervals.
PHMSA appreciates the information provided by the commenters. The majority of comments state that quality audits are performed for direct assessments, however, PHMSA believes, as one comment suggests, that there are weaknesses in the use of direct assessments. For example, SCCDA is not as effective, and does not provide an equivalent understanding of pipe conditions with respect to SCC defects, as ILI or hydrostatic pressure testing. Accordingly, PHMSA proposes to revise the requirements in §§ 192.921 and 192.937 for direct assessment to allow use of this method only if a line is not capable of inspection by internal inspection tools.
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No comments were received in response to this question.
The ANPRM requested comments regarding proposed changes to the requirements for sectionalizing block valves. Gas transmission pipelines are required to incorporate sectionalizing block valves. These valves can be used to isolate a section of the pipeline for maintenance or in response to an incident. Valves are required to be installed at closer intervals in areas where the population density near the pipeline is higher.
Sectionalizing block valves are not required to be remotely-operable or to operate automatically in the event of an unexpected reduction in pressure (
The ANPRM then listed questions for consideration and comment. The following are general comments received related to the topic as well as comments related to the specific questions:
1. INGAA argued that while valves, spacing, and selection are important, public safety requires a broader review of incident responses and consequences. Performance-based Incident Mitigation Management (IMM), using valves and other tools, will, according to INGAA, improve incident response, reduce incident duration and minimize adverse impacts. IMM plans identify comprehensive actions that improve mitigation performance and minimize overall incident impact. These plans cover various aspects of response, including how operators detect failures, how they place and operate valves, how they evacuate natural gas from pipeline segments, and how they prioritize coordination efforts with emergency responders. A number of pipeline operators supported INGAA's comments, including Panhandle, TransCanada, Spectra Williams, Southern Star, and others.
2. AGA submitted a white paper that discussed potential benefits associated with remote control valves and automatic shutoff valves; however, the paper acknowledged that these valves will not prevent incidents. A number of pipeline operators supported AGA's comments.
3. APGA reported automatic or remotely-controlled valves are not practical for municipal pipeline operators because they do not have remote monitoring or control of their pipelines. APGA also cautioned that the use of automatic valves could lead to false closures, an unintended and adverse consequence.
4. Atmos commented that the existing requirements for valve spacing allow for safe and reliable service to its customers. The company noted that requiring the installation of remote control valves or automatic shutoff valves would add minimal value to the overall safety and operation of its transmission pipeline systems. In addition, industry studies have concluded that remote or automatic features on block valves would not reduce injuries or fatalities associated with an incident.
5. MidAmerican commented that installation of automatic shutoff valves would be costly, have minimal impact on improving safety, and could cause customer outages on its pipeline system. At the same time, MidAmerican acknowledged that some applications of remote/automatic control valves could have merit, but that the election should lie with the operator given the complexity of pipeline systems and other factors that bear on that decision. MidAmerican reported its conclusion that ASME/ANSI B31.8S provides adequate guidance for the installation of sectionalizing valves. While MidAmerican opposes a requirement to install automatic or remotely-controlled valves, the company suggested factors PHMSA should consider if it decides to adopt such a requirement. Specifically, PHMSA should allow operators flexibility in deciding between automatic and remote valves and should clarify when action on a pipeline is considered a new installation versus a repair or replacement in-kind.
6. TransCanada noted that industry studies have shown automatic or remote block valves do not prevent incidents and have a minimal effect on significant consequences, since most of the human impacts from a rupture occur in the first few seconds, well before any valve technology could reduce the flow of natural gas. TransCanada supports the use of Incident Mitigation Management (IMM) to improve incident response, reduce incident duration, and minimize adverse impacts.
7. Chevron argued operators should have the flexibility to select the most effective measures based on specific locations, risks, and conditions of the pipeline segment. Chevron noted that the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 requires a study of incident response in HCAs that must consider the swiftness of leak detection and pipeline shut-down capabilities and the location of the nearest personnel. The study must also evaluate the costs, risks, and benefits of installing automatic or remote controlled shut-off valves.
8. A private citizen suggested that periodic drills be held with local emergency responders, pipeline operators should provide specialized equipment to local responders in densely populated areas, and pipeline operators pay a fee to those municipalities to support incident response. The commenter further recommended that leak detection analyses be computerized.
9. Dominion East Ohio contended that current regulations are adequate and that automatic shutoff valves and remote control valves are an important preventive and mitigative measure to consider using. However, these valves do not prevent accidents and have very limited impact in preventing injuries and deaths caused by an initial pipeline failure.
10. Accufacts suggested that further prescriptive regulation is required concerning the placement, selection, and choice of manual, remotely-controlled, or automatic shutoff valves.
11. The Pipeline Safety Trust (PST) questioned the conclusions of the DOT study, “Remotely Controlled Valves on Interstate Natural Gas Pipelines, (Feasibility Determination Mandated by the Accountable Pipeline Safety and Partnership Act of 1996), September 1999, which concluded that remote control valves were and remain economically unfeasible. The PST noted that the study also stated that there could be a potential benefit in terminating the gas flow to a rupture
12. A private citizen suggested that local authorities regularly review incidents in densely populated areas, as self-policing by pipeline operators is insufficient. The commenter also recommended that pipeline construction and modifications be subject to signoff by a licensed professional engineer and be certified for compliance with applicable regulations by a corporate officer subject to criminal penalties, in order to reduce the incentive to cut corners.
13. Northern Natural Gas and a private citizen recommended that the current one-call exemptions for government agencies be eliminated.
1. AGA and a number of pipeline operators contended that the existing requirements in § 192.179 are adequate. AGA noted that studies have shown there is no safety benefit to having more remote or automatic valves and operators should be permitted to determine the need for additional valves and spacing. AGA contended that there is no safety reason to change the existing regulation and argued that remote or automatic valves should not be mandated for any specific set of circumstances, since they are only one option for pipeline shutdown.
2. Texas Pipeline Association and Texas Oil & Gas Association commented that spacing requirements for natural gas transmission lines have been shown to be adequate for emergency situations. Both associations observed that block valves are not in place to prevent accidents and that the greatest impact of an accident is from the initial gas release, before automatic or remote valves could actuate. The associations also noted that the addition of more block valves would increase the risk to aboveground infrastructure.
3. Accufacts contended that the existing spacing requirements are inadequate and noted that valve spacing plays a significant role in the “isolation blowdown” time, or the time to depressurize a gas pipeline segment once isolation valves are closed after a rupture. Accufacts also recommended that additional sectionalizing valves be required when class locations change.
4. Iowa Utilities Board (IUB) suggested that ease of access and the time to respond should be factors relevant to a decision as to whether to install automatic or remote valves. IUB noted that the considerations are different for valves in remote areas compared to urban valves.
5. California Public Utilities Board reported that the issue of valve spacing is under review by the State.
6. A private citizen suggested that valves be required at one-mile intervals in densely populated urban areas and that they close automatically in the event of an incident, since the duration of the fire resulting from an incident is directly proportional to the volume of gas between valves. AGA commented that it is not the amount of gas between valves but rather it is the volume between a valve and a rupture that determines the volume released.
7. Wyoming County Pennsylvania's Commissioners suggested that it is necessary to modify separation distances and to establish adequate distances for gathering lines, including in Class 1 areas. The Commissioners acknowledged that the spacing required for Class 3 locations may be more acceptable than the spacing required for Class 1 areas, but noted that it will take longer to reach a block valve with 10 mile spacing in Pennsylvania's Marcellus Shale regions.
8. An anonymous commenter responded that current valve spacing requirements are adequate and suggested that automation be required if it would take 20 to 30 minutes to respond to a mainline valve.
9. AGA, supported by a number of pipeline operators, noted that operators evaluate the need for additional block valves when they become aware of changes in class location.
10. Atmos commented that the need for additional block valves should be evaluated when class locations change, if pipe replacement is needed to comply with the new class locations. Atmos recommended valve installations, if any, should only be required within the replaced pipeline section. Atmos further recommended that automatic or remote valves should not be required between compressor stations due to the risk of false closures and the extensive modifications that would be required.
11. MidAmerican opposed a requirement to install new block valves when a class location changes or to establish more stringent spacing requirements, noting that ASME/ANSI B31.8 provides adequate guidance for block valve considerations. Texas Pipeline Association, Texas Oil & Gas Association, and Northern Natural Gas agreed, noting that the required class location study includes consideration of current spacing as well as other criteria.
12. The Commissioners of Wyoming County Pennsylvania stated that it is imperative that a suitable number of additional block valves be required when population increases and class location changes, arguing that this is necessary to assure adequate public safety measures are in place.
13. An anonymous commenter suggested that new valves should not be required when HCA or class location boundaries change, noting that such changes occur rather frequently.
14. Northern Natural Gas argued that a prescriptive standard for valve spacing may not necessarily provide additional risk reduction, noting that many Class 2 and 3 locations are short pipe segments within an extended Class 1 location.
15. Texas Pipeline Association and Texas Oil & Gas Association noted that more block valves would not decrease the damage from a pipeline accident, noting that PHMSA studies have shown that fatalities and significant property damage occur within 3 minutes of a pipeline rupture while a remotely-operated valve takes 10 minutes to close. This and other studies have shown the only benefit to adding more valves is reducing the amount of gas lost in an accident.
16. Accufacts contended that a more scientific discussion will demonstrate a maximum spacing of eight miles will provide sufficient risk reduction.
17. MidAmerican suggested that block valves should be automatic or remotely-operated only when adequate response times cannot be achieved by operator personnel. When response times are adequate, MidAmerican contended that use of automatic or remote valves should be at the operator's discretion.
18. Northern Natural Gas suggested that the decision to use remote or automatic shut-off valves should be
19. Paiute and Southwest Gas argued that operators should have the flexibility to evaluate and determine whether remote or automatic valves would be beneficial. The companies noted that § 192.935 already requires the consideration of additional valves as a preventive and mitigative measure.
20. Accufacts contended that decisions on valve spacing and whether they should be manual, remote, or automatic will be dependent on the time established for first responders to safely enter an actual gas transmission impact zone following rupture. Accufacts noted that California has set a goal of 30 minutes for first response time.
21. A private citizen suggested that automatic shutoff valves should be used in densely populated areas because they provide the most rapid response.
22. The Commissioners of Wyoming County Pennsylvania suggested that standardization is necessary with remotely and automatically controlled shutoffs. The Commissioners contended that the operator needs to employ remote or automatic valves when transmission and gathering lines are routed through areas that are not easily accessible.
23. INGAA noted that § 192.620 requires a one-hour time frame for closing a valve, and contended this is practical for valves that would isolate pipelines in HCAs and consistent with requirements for alternative MAOP in § 192.620. A number of pipeline operators supported INGAA's comments.
24. Atmos suggested that mandating a minimum time to reach a valve site is impractical, because many variables exist in a dynamic state that affect an operator's ability to reach a block valve site.
25. MidAmerican opposed a specified time frame for response to a valve site, noting that operators should respond in an expedient manner without specified time limits.
26. Northern Natural Gas suggested PHMSA consider a two-hour response time for valves in HCA.
27. Texas Pipeline Association and Texas Oil & Gas Association noted that conditions determine how quickly an operator can reach a valve site in the event of an incident and operators make every effort to respond expeditiously when an incident occurs. The associations opposed adoption of a required response time.
28. TransCanada reported its conclusion that having personnel on site within one hour is reasonable for planning purposes. If this cannot be met, TransCanada suggested that possible valve automation should be required.
29. The Commissioners of Wyoming County Pennsylvania reported their conclusion that there would be value in establishing a maximum response time, especially in Class 1 locations where block valves may be 10 miles apart.
30. INGAA and a number of its pipeline operator members noted that studies have shown consistently that there is no value in installing additional block valves or in automating valves. They suggested that it would be more beneficial to apply resources that would be required to comply with any new requirements in this area towards preventing accidents.
31. MidAmerican reported that installing additional block valves would entail significant costs and suggested that increasing the number of valves could cost in excess of $40 million for its pipeline system. Northern Natural Gas agreed that costs could be substantial, without providing a specific estimate for its pipeline system.
32. Paiute and Southwest Gas estimated that costs to install new valves could range from $100,000 to $1 million per installation.
33. An anonymous commenter estimated that retrofitting a 36-inch valve for remote operation would cost approximately $30,000 plus subsequent maintenance costs.
34. Accufacts noted that the San Bruno accident demonstrated that there is a cost associated with not properly spacing, installing or automating valves in high consequence areas.
1. INGAA, AGA, GPTC and several pipeline operators took the position that no new requirements are needed. These associations argued that § 192.179 provides appropriate minimum standards and reported that operators install additional valves in accordance with their integrity management plans or other factors that they consider voluntarily.
2. Paiute and Southwest Gas opined that no additional criteria are needed. They noted that numerous industry studies have shown that there is little or no safety benefit to installing additional automatic or remote valves. They suggested that operators should have the flexibility to determine, based on local circumstances, where additional valves are needed.
3. Atmos suggested that valve accessibility be given more consideration, noting that installing valves in locations that provide improved accessibility could lead to spacing greater than allowed under current regulations. Atmos further suggested that environmental factors such as water crossings and areas prone to flooding should be taken into consideration.
4. MidAmerican opined that additional factors should be considered and pointed to ASME/ANSI B31.8 for examples.
5. Accufacts concluded that additional factors need to be taken into consideration, noting that protection of identified sites in Class 1 and 2 locations will require shorter valve spacing than is currently required by regulations.
6. The California Public Utilities Commission noted that there are numerous factors to be considered that affect response time, and that this issue is under review by the State.
7. The Texas Pipeline Association, Texas Oil & Gas Association, and Commissioners of Wyoming County Pennsylvania suggested that factors other than class location should not be added to the regulations. They noted that class location serves as a surrogate for the level of risk posed by a pipeline.
1. INGAA and a number of its pipeline operator members opposed applying § 192.179 requirements retroactively to class location changes. INGAA suggested that, rather than absorbing the cost of installing new valves, other preventive and mitigative measures applied through an integrity management plan would produce greater benefits.
2. AGA and a number of its members opposed requiring new valves be installed when class location changes, arguing that no safety benefit will result.
3. Northern Natural Gas expressed its opinion that current regulations are adequate, noting that class location change studies require consideration of block valve spacing.
4. MidAmerican opined that the existing regulations are adequate and noted that ASME/ANSI B31.8 provides other factors for consideration.
5. GPTC expressed its belief that existing requirements are adequate, noting that operators voluntarily consider other factors in establishing valve locations.
6. Atmos suggested that PHMSA not require the installation of new valves
7. Accufacts suggested that new valves should be required following class location changes, but suggested that a reasonable time should be provided for such valves to be installed and operational.
8. The Texas Pipeline Association and Texas Oil & Gas Association commented that no safety benefit has been demonstrated for the installation of additional valves. The associations suggested that installing additional valves could be counterproductive, since more above-ground valves could pose an additional risk to the public.
9. The California Public Utilities Commission opined that the regulations should require explicitly that additional valves be installed when class location changes, but expressly withheld an opinion on related costs.
10. A private citizen suggested that all requirements related to class location should apply when class location changes, unless PHMSA adopts an expanded definition for HCA to replace class location considerations.
11. An anonymous commenter stated that most operators anticipate changes to Class 3 or 4 when pipelines are designed and constructed. The commenter estimated that installing a new 36-inch valve would cost $70 to $100 thousand, not including down time and lost product.
12. The Commissioners of Wyoming County Pennsylvania commented that the regulations need to be revised to explicitly require that new valves be installed when class locations change. The Commissioners suggested that this needs to extend to both transmission and gathering lines in Class 1 areas.
1. INGAA and a number of pipeline operators noted that studies have indicated valve spacing has limited impact on the duration of an incident. INGAA suggested that a performance-based approach to incident mitigation management would better inform valve placement.
2. AGA opposed requiring additional valves under any scenario. A number of pipeline operators supported AGA's comments.
3. Accufacts suggested that new valves should be installed when a site becomes an HCA regardless of class location, but a reasonable time should be allowed for such valves to be installed and become operational.
4. Ameren Illinois opposed requiring new valves under other conditions, opining that existing requirements are adequate.
5. GPTC and Atmos commented that existing regulations are a sufficient baseline for determining valve location, noting that operators often use more stringent spacing criteria during initial construction.
6. MidAmerican opposed requiring that installation of new valves on existing pipelines for any reason other than a class location change, noting that ASME/ANSI B31.8 provides additional factors for operators to consider in determining valve location.
7. Northern Natural Gas noted that existing regulations require that operators consider additional valves as a preventive and mitigative measure and expressed its conclusion that this requirement is sufficient.
8. Paiute and Southwest Gas suggested that operators should have the flexibility to evaluate and determine where remotely-controlled or automatic valves would be beneficial. The companies noted that § 192.935 requires the consideration of additional valves as a preventive and mitigative measure and industry studies indicate little or no safety benefit to installing additional valves.
9. The California Public Utilities Commission suggested that conditions that would impede access to a valve may need to be considered in determining valve placement.
1. INGAA estimated that 40 to 50 percent of mainline block valves are remotely-operated or automatic. INGAA did not provide an estimate specifically for automatic valves. INGAA noted that application of Incident Mitigation Management would lead operators to conclusions as to whether a valve should be remote or automatic. A number of pipeline operators supported INGAA's comments.
2. AGA and GPTC reported that they have no data with which to respond to this question.
3. Ameren Illinois reported that it has no remotely-controlled valves.
4. Atmos reported that remote and automatic valves are not installed routinely. Remotely-controlled valves are installed on a small number of select pipelines, representing approximately 0.1 percent of all valves.
5. Kern River reported that 66 percent of its mainline block valves, and all block valves in HCA, are remotely-controlled.
6. MidAmerican reported that less than one percent of its valves are remotely-controlled and a similarly small percentage of them are automatic.
7. Northern Natural Gas reported that remotely-controlled valves are located only at compressor stations on its pipeline system.
8. Paiute reported that less than 10 percent of the valves on its system are remotely-controlled. Paiute has no automatic valves.
9. Southwest Gas reported that it has no remotely-controlled or automatic valves, due to the urban nature of its pipeline system.
10. Texas Pipeline Association reported that a limited survey of its members indicated the number of remotely-controlled valves varies from 1 to 18 percent; the number of automatic valves varies from zero to 18 percent.
1. INGAA and a number of pipeline operators opposed consideration of such a requirement. They commented that no one solution should be mandated and Incident Mitigation Management should guide operators to decisions as to which valves should be remote or automatic.
2. AGA and a number of pipeline operators also opposed consideration of such a requirement, noting remotely-controlled valves are only one option for shutting down a pipeline.
3. Accufacts opposed such a generic requirement, noting small-diameter gas transmission pipelines may not merit automation because of the science of pipeline diameter rupture associated with high heat flux releases.
4. GPTC opined that remotely-controlled valves do not improve safety, thus there is no basis for requiring their use. GPTC noted that operators voluntarily consider many factors in establishing valve locations.
5. Atmos opposed consideration of this requirement, noting there are issues with false closures and the costs of conversion or installation are extensive. Atmos also noted that industry studies have shown no increase in safety from having more remotely-controlled or automatic valves.
6. Kern River opined that this should be an operator decision, noting that integrity management regulations require the consideration of remote or automatic valves as part of identifying preventive and mitigative measures.
7. MidAmerican strongly opposed requiring all sectionalizing block valves to be remotely controlled. MidAmerican stated that the location and type of valve should be based on an engineering assessment. A requirement that all valves be remote would increase costs and may provide disincentives to installation of additional valves.
8. Northern Natural Gas opposed such a requirement, commenting this should be a case-by-case decision based on risk reduction.
9. Paiute and Southwest Gas reported their conclusion that the existing requirements in § 192.179 are adequate. The companies recommended that operators have the flexibility to evaluate and determine where remote or automatic valves would be beneficial. They noted that § 192.935 requires the consideration of additional valves as a preventive and mitigative measure and industry studies indicate little or no safety benefit to installing additional remote or automatic valves.
10. The Texas Pipeline Association and Texas Oil & Gas Association opposed consideration of a requirement that all block valves be remotely-operable. The associations noted that it would be tremendously expensive to do so, and it would require power and communication sources that may not be readily available at valve sites.
11. The California Public Utilities Commission commented that this could be impractical for distribution systems considering space limitations and the practicability of supplying communication facilities for valves. This issue is under review by the State for transmission facilities.
12. The Iowa Utilities Board noted that remotely-operated valves require a SCADA or other type of remote monitoring and operating system. A requirement that all sectionalizing valves be remotely-operable would thus be a de facto requirement that all operators, regardless of size or the potential consequences of an accident, install a SCADA system. Small operators and municipal utilities in Iowa do not have such systems.
13. The Commissioners of Wyoming County Pennsylvania commented that it might be desirable for all valves to be remotely-operable or automatic, but PHMSA must consider what is reasonable and adequate.
14. An anonymous commenter opposed consideration of a requirement that all valves be remotely-operable, noting that most gas pipeline accident consequences occur immediately upon release, before a remote valve could have any effect.
1. INGAA and a number of pipeline operators opposed PHMSA's establishment of prescriptive criteria, suggesting instead that PHMSA develop guidance for Incident Mitigation Management.
2. AGA, GPTC, and a number of pipeline operators commented that requirements in § 192.179 are adequate. AGA noted that operators already consider additional valves in their emergency response portfolio and install them where economically, technically, and operationally feasible. Some operators noted that numerous industry studies indicate that there is little or no safety benefit to installing additional remote or automatic valves and § 192.935 already requires the consideration of additional valves as a preventive and mitigative measure.
3. Accufacts supported the consideration of prescriptive criteria, arguing that prescriptive regulation should be mandated for certain gas transmission pipelines in HCAs, especially larger-diameter pipelines in certain areas where manual closure times can be long.
4. Ameren Illinois opposed additional prescriptive criteria, arguing that existing requirements are sufficient and that additional valves should be considered when economically, technically, and operationally feasible to address specific safety concerns.
5. California Public Utilities Commission expressed its conclusion that prescriptive decision criteria may need to be added for all Method 1 HCA locations.
6. The Iowa Utilities Board, the Texas Pipeline Association and the Texas Oil & Gas Association questioned whether it is possible to write prescriptive decision criteria that can reasonably address all possible situations and circumstances or always provide the best option. These commenters suggested that operator judgment and discretion should play a part in these decisions.
7. MidAmerican expressed its belief that pipeline safety would not be enhanced by additional prescriptive criteria and opposed specific requirements for valve location near HCAs, noting that ASME/ANSI B31.8 provides considerations for operators to take into account when deciding on valve locations.
8. An anonymous commenter suggested that prescriptive criteria could be useful in assuring a degree of consistency among pipeline operators.
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No comments were received in response to this question.
PHMSA appreciates the information provided by the commenters. Based on the investigation of the San Bruno incident, the NTSB recommended (P-11-11) that PHMSA promulgate regulations to explicitly require that automatic shutoff valves or remote control valves in high consequence areas and in Class 3 and 4 locations be installed and spaced at intervals considering the population factors listed in the regulations. In addition, Section 4 of the Act requires issuance of regulations on the use of automatic or remote-controlled shut-off valves, or equivalent technology, if appropriate, and where economically, technically, and operationally feasible. The Act also requires the Comptroller General of the United States to complete a study on the ability of transmission pipeline facility operators to respond to a hazardous liquid or gas release from a pipeline segment located in a high-consequence area. On March 27, 2012, PHMSA sponsored a public workshop to seek stakeholder input on this issue. On October 5, 2012, PHMSA also briefed stakeholders, via a webcast, on the status of an ongoing study conducted by Oak Ridge National Laboratory on understanding the application of automatic control and remote control shutoff valves. The final study was published in December 2012. PHMSA also included this topic in the July 18, 2012 Pipeline Research Forum. PHMSA will take further action on this topic after completion of the assessment of the findings from these activities. PHMSA will consider the comments
Gas transmission pipelines are generally constructed of steel pipe, and corrosion is a potential threat. Subpart I of part 192 addresses the requirements for corrosion control of gas transmission pipelines, including the requirements related to external corrosion, internal corrosion, and atmospheric corrosion. However, this subpart does not include requirements for the specific threat of Stress Corrosion Cracking (SCC). The ANPRM requested comments regarding revisions to subpart I to improve the specificity of existing requirements and to add requirements relative to SCC.
Existing requirements have proven effective in reducing the occurrence of incidents caused by external corrosion. Many of the provisions in subpart I, however, are general in nature. In addition, the current regulations do not include provisions that address issues that experience has shown are important to protecting pipelines from corrosion damage, including:
• Post-construction surveys for coating damage.
• Post-construction close interval survey (CIS) to assess the adequacy of cathodic protection (CP) and inform the location of CP test stations.
• Periodic interference current surveys to detect and address electrical currents that could reduce the effectiveness of CP.
• Periodic use of cleaning pigs or sampling of accumulated liquids to assure that internal corrosion is not occurring.
Corrosion control regulations applicable to gas transmission pipelines currently do not include requirements relative to SCC. SCC is cracking induced from the combined influence of tensile stress and a corrosive medium. SCC has caused numerous pipeline failures on hazardous liquids pipelines, including a 2003 failure on a Kinder Morgan pipeline in Arizona, a 2004 failure on an Explorer Pipeline Company pipeline in Oklahoma, a 2005 failure on an Enterprise Products Operating line in Missouri, and a 2008 failure on an Oneok NGL Pipeline in Iowa. More effective methods of preventing, detecting, assessing and remediating SCC in pipelines are important to making further reductions in pipeline failures.
The ANPRM then listed questions for consideration and comment. The following are general comments received related to the topic as well as comments related to the specific questions:
1. AGA opined that the questions posed under this topic are unclear and disjointed and do not differentiate between distribution and transmission pipelines. In addition, AGA stated that PHMSA did not provide a rationale for why there is any concern over subpart I. A number of pipeline operators supported AGA's comments.
2. MidAmerican noted that PHMSA says current requirements are adequate yet goes on to propose new requirements.
3. INGAA reported that its members commit to mitigating corrosion anomalies in accordance with ASME/ANSI B31.8S, both inside and outside HCAs. INGAA argued that enhanced external corrosion management methods, such as close interval surveys and post-construction coating surveys, should not be required singularly and arbitrarily by new prescriptive regulations, since these methods can be redundant or inferior when combined with other assessment techniques. INGAA argued that these methods should continue to be used by operators on a threat-specific basis, as is currently practiced under performance-based regulations and consensus-based IM programs. A number of pipeline operators supported INGAA's comments.
4. Chevron argued that more prescriptive requirements are unnecessary, noting that current regulations allow operators the flexibility to select the most effective corrosion control method for the specific corrosion threats to a pipeline segment.
5. MidAmerican reported that it has never identified internal corrosion on its pipeline system and prescriptive requirements related to that threat would divert resources. MidAmerican opined that subpart I provides an adequate level of safety and any changes in that subpart should be approached carefully because they could be beneficial or detrimental for reducing risk. MidAmerican further noted that NACE SP0204 and ASME/ANSI B31.8S provide adequate guidance in this area.
6. TransCanada suggested that PHMSA incorporate the new SCC management provision in ASME/ANSI B31.8S as the basis for identifying and mitigating SCC and be responsive to further enhancements. TransCanada also suggested that the best way to manage corrosion anomalies is through assessments.
7. Dominion East Ohio opined that existing regulations in this area are adequate.
8. NAPSR urged PHMSA to establish or adopt standards or procedures, through a rulemaking proceeding, for improving the methods of preventing, detecting, assessing, and remediating stress corrosion cracking. NAPSR also suggested that PHMSA consider additional requirements to perform periodic coating surveys at compressor discharges and other high-temperature areas potentially susceptible to SCC and develop a training module for pipeline operators and federal and state inspectors that would include the identification of potential areas of SCC, detecting, assessing and remediating SCC.
9. A private citizen reported that his analysis of data from over 5000 lightning strikes indicates that cathodic protection systems make pipelines a frequent target for lightning.
10. A private citizen suggested that enforcement of cathodic protection requirements be strengthened, stating that the number of enforcement actions indicates that operators are not operating or maintaining CP as required.
11. A private citizen suggested that in-line inspection (ILI) capable of detecting seam issues should be required for pipe susceptible to selective seam weld corrosion, since pressure testing is not adequate to detect non-leak anomalies. If not possible, the commenter would require that this pipe be replaced.
PHMSA appreciates the information provided by the commenters. In light of the contributing factors to the San Bruno incident, including PG&E's reliance on direct assessment under circumstances for which direct assessment was not effective, and the incident in Marshall, Michigan, where fracture features were consistent with stress corrosion cracking, PHMSA believes that more specific measures are needed to address both stress corrosion cracking and selective seam weld corrosion. Based on lessons learned from incident investigations, such as the 2012 incident in Sissonville, West Virginia and the 2007 incident in Delhi, Louisiana, and improved capabilities of corrosion evaluation tools and methods, PHMSA believes that more specific minimum requirements are needed for control of both internal and external corrosion. In addition, cathodic protection is a well-established corrosion control tool, and PHMSA believes the benefits of cathodic protection outweigh any potential risks. Therefore, PHMSA proposes several
1. INGAA and a number of pipeline operators commented that adding prescriptive requirements would be disruptive to operators, noting PHMSA has acknowledged the effectiveness of performance-based elements of the current requirements.
2. The AGA, the GPTC, the Texas Pipeline Association, the Texas Oil & Gas Association, and numerous pipeline operators questioned the need to amend subpart I. AGA noted that this is one of the more prescriptive sections of the code and has a 40-year history of demonstrated effectiveness.
3. Ameren Illinois opined it is not necessary to revise subpart I, because integrity management regulations require operators to identify threats and to manage them.
4. MidAmerican opposed more specific requirements for corrosion control, noting that there is wide diversity among pipelines and it is unlikely that a single set of specific requirements would apply effectively to all pipelines. MidAmerican suggested that additional specific requirements must be tailored to a wide range of pipeline configurations to be of any value.
5. Northern Natural Gas reported that IM results demonstrate that corrosion has been adequately addressed on its pipeline system.
6. Paiute and Southwest Gas noted that subpart I is one of the most prescriptive sections of the code, subpart O provides an additional layer of regulation, and NACE standards are robust and incorporated by reference.
7. Panhandle Energy commented that existing performance based regulations require the pipeline operator to establish procedures to determine the adequacy of CP monitoring locations and appropriate remediation schedules based on circumstances that are unique to each pipeline. Panhandle observed that PHMSA appears to be attempting to establish “One Size Fits All” prescriptive requirements and opined that such changes would have no positive effect on safety and may be detrimental.
8. Accufacts observed that too many pipeline operators are assuming that IM assessments can replace subpart I requirements when the intent was that the regulations work in conjunction with one another. Accufacts suggested that prescriptive regulation is needed to avoid serious misapplication of the IM section and to assure that subpart I regulations are implemented to keep corrosion under control.
9. Panhandle observed that the ANPRM states that “prompt” as used in § 192.465(d) is not defined, and does not recognize the definition of “prompt remedial action” outlined in the 1989 Office of Pipeline Safety's Operation and Enforcement Manual. Panhandle noted that the enforcement guidance requires PHMSA to evaluate the circumstances and provide rationale for any determination of “unreasonable delay” in any enforcement action associated with § 192.465(d). Panhandle observed that such evaluations are inherent in the enforcement of performance-based regulations and stand in sharp contrast to the “check-box” enforcement mentality of prescriptive regulations. Panhandle complained that the language of the ANPRM contradicts more than 20 years of enforcement history. Panhandle interpreted the ANPRM to mean that PHMSA has no authority to interpret part 192 other than through rulemaking.
10. An anonymous commenter suggested that PHMSA delete the requirement regarding 300 mV pipe-to-soil reading shift and adopt NACE SP0169.
11. The California Public Utilities Commission suggested that PHMSA consider modifying acceptance criteria to be based on instant-off readings, arguing that this would provide improved specificity concerning IR drop.
PHMSA appreciates the information provided by the commenters. The majority of industry comments do not support revising subpart I to provide additional specificity to requirements. However, for the reasons discussed in this NPRM, PHMSA believes that certain regulations can be improved to better address issues that experience has shown can be important to protecting pipelines from corrosion damage, and that prudent operators currently implement. Therefore, PHMSA proposes to amend subparts G and I to: (1) Enhance requirements for electrical surveys (
1. INGAA and a number of pipeline operators argued that post-construction surveys are of limited use, arguing that they can identify damaged coating but not necessarily areas where SCC can occur.
2. AGA, supported by a number of its pipeline operator members, opined that existing requirements for post-construction surveys for coating damage and cathodic protection are sufficient and operators need flexibility to apply their resources to the highest risk areas.
3. GPTC agreed that existing regulations are sufficient, noting that operators are not experiencing difficulties related to post-construction surveys for coating damage or for determining the adequacy of CP.
4. Ameren Illinois noted that part 192 requirements are followed for the installation of new coated steel pipe and it will develop a process to deal with any problems that may be identified through integrity management. Atmos agreed, noting that post-construction baseline surveys are typically performed.
5. Kern River opined that corrosion control measures and mitigation are site specific and therefore universal conditions and mitigation requirements would likely be ineffective and inefficient. Performance-based criteria are the best way to ensure the integrity of the pipeline with the most innovative and effective solutions.
6. MidAmerican opposed new requirements, noting that areas of coating damage on pipelines are protected from corrosion by cathodic protection and existing requirements are adequate in this area.
7. NACE concluded that current regulations have proven adequate and
8. Paiute and Southwest Gas opined that current requirements for coatings (§ 192.461) and cathodic protection (§ 192.463) are sufficient.
9. Northern Natural Gas stated that no new requirements are needed, observing that it takes action when CP surveys indicate a concern.
10. Panhandle argued that the proposed requirement for post construction coating does not address the cause of coating damage during construction and INGAA best practices have proven to be an effective means to provide pipeline safety, affording flexibility and recognizing the inherent limitations of coating surveys. Panhandle observed that PHMSA's requirements for the investigation of anomalies found during post construction coating surveys on alternate MAOP lines are overly conservative, waste resources, do not enhance pipeline safety, and should not be considered for use in any proposed rulemaking. Panhandle further recommended that any proposed regulations related to pipeline temperature should not use the 120 degrees Fahrenheit value used in § 192.620, since studies have demonstrated pipeline coatings can withstand temperatures up to 150 degrees. Panhandle further argued that industry experience verifies that the vast majority of coating holidays associated with pipeline construction are not an integrity threat when cathodic protection is applied to the pipeline. It also suggested that verification of pipeline integrity through ILI or pressure testing better utilizes resources than excavation and repair of pinholes in pipeline coating systems.
11. Panhandle observed that, from its experience with over 900 completed excavations, the coating anomaly ranking system of NACE SP0502 is extremely conservative and should only be used as part of the ECDA process.
12. Texas Pipeline Association and Texas Oil & Gas Association suggested that PHMSA should consider requiring close interval surveys at 5-year intervals.
13. TransCanada noted that enhanced external corrosion management methods, such as close interval surveys and post construction coating surveys, have proven effective in helping identify and mitigate certain corrosion damage conditions. TransCanada argued, however, that these methods should not be required singularly and arbitrarily by new prescriptive requirements, as they can be redundant or inferior when combined with other assessment techniques.
14. Pipeline Safety Trust suggested that additional post-construction surveying should be required to identify damage to or weakness in coating and to ensure the integrity of CP.
15. An anonymous commenter suggested that PHMSA require close interval survey before energizing new CP components, after backfill has settled, noting that this would ensure test stations are located in areas that will assure adequate protection.
16. The Commissioners of Wyoming County Pennsylvania recommended that PHMSA review operator practices and codify the “best practices” in this area.
PHMSA appreciates the information provided by the commenters. The majority of industry comments do not support revising subpart I to prescribe additional requirements for post-construction surveys for coating damage or to determine the adequacy of CP. However, as detailed in the ANPRM, experience has shown that construction activities can damage coating and that identifying and remediating this damage can help protect pipeline integrity. PHMSA does agree that prescriptive practices for conducting coating surveys, as well as the criteria for remediation and other responses to indications of coating damage, are not always appropriate because coating damage is case-specific. Therefore, PHMSA proposes to add a requirement that each coating be assessed to ensure integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG) and damage be remediated if damage is discovered. In addition, for HCA segments, PHMSA proposes enhanced preventive and mitigative measures and repair criteria for repair of coating with a voltage drop classified as moderate or severe.
1. INGAA and a number of pipeline operators recommended that PHMSA not establish new requirements in this area without discussing the topic with operators first. INGAA pointed out that guidance already exists in the form of Advisory Bulletin ADB-03-06 and NACE SP0169.
2. Kern River opposed new requirements for periodic surveys, arguing that §§ 192.465, 192.467, and 192.473 adequately address the concerns.
3. Ameren Illinois also opposed new requirements. Ameren reported that it conducts testing annually at sites where stray currents are expected and noted that integrity management regulations already require operators to identify and address threats.
4. NACE International suggested that current regulations are adequate and have served the public interest. NACE noted operators are currently taking action to identify interference currents and protect their pipelines, and it has provided guidance through standards and technical papers.
5. Atmos noted that interference surveys would be a part of an investigation into cathodic protection systems that do not provide minimum levels of protection. Operators are already required to maintain minimum levels of protection.
6. Northern Natural Gas reported that it conducts additional surveys when issues are discovered during periodic maintenance, when new foreign line crossing are installed, or for new construction, but opposed new requirements in this area.
7. Paiute and Southwest Gas opposed new requirements, noting that operators should have the flexibility to allocate their resources in a manner that best suits their system.
8. Panhandle opposed new requirements, noting that existing performance-based regulations have proven adequate to address the threat of stray currents. Panhandle commented that the gas pipeline industry recognized and reacted to the threat of AC interference decades prior to the ANPRM, and suggested that the lack of justification from PHMSA on this issue is a strong indicator that industry has reacted appropriately to integrity threats in accordance with the requirements of § 192.473. Panhandle noted that interference currents have been addressed in several industry standards and publications. In particular, Section 9,
9. Texas Pipeline Association and Texas Oil & Gas Association stated that current regulations are sufficient; however, if new regulations are promulgated, the associations recommended that PHMSA use the liquid pipeline requirement for periodic interference surveys and be applicable only to foreign line crossings and
10. An anonymous commenter stated that new regulations are not needed, as most operators will conduct surveys on their own, generally when pipe-to-soil readings drop.
PHMSA appreciates the information provided by the commenters. Industry comments do not support revising subpart I to require periodic interference current surveys. However, as detailed in the ANPRM, pipelines are often routed near, in parallel with, or in common rights-of-way with, electrical transmission lines or other pipelines that can induce interference currents, which, in turn, can induce corrosion. Recent incidents on pipelines operated by Kern River and Center Point are examples of incidents this requirement seeks to prevent. Section 192.473 currently requires that operators of pipelines subject to stray currents have a program to minimize detrimental effects but does not require surveys, mitigation, or provide any criteria for determining the adequacy of such programs. Therefore, PHMSA proposes to add a requirement that the continuing program to minimize the detrimental effects of stray currents must include: (1) Interference surveys to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected; (2) analysis of the results of the survey; and (3) prompt remediation of problems after completing the survey to protect the pipeline segment from deleterious current. For HCA segments, PHMSA proposes to address this in enhanced preventive and mitigative measures, and to include performance criteria.
I.4. Should PHMSA require additional measures to prevent internal corrosion in gas transmission pipelines? If so, what measures should be required?
1. INGAA, AGA, GPTC, and numerous pipeline operators contended that existing requirements are adequate to manage internal corrosion. INGAA noted that subparts I and O include requirements for controlling internal corrosion and assessments are being performed on almost all gas transmission lines. INGAA further commented that controlling gas quality is most important.
2. Ameren Illinois opposed new requirements addressing internal corrosion, noting that § 192.475 addresses the topic and subpart O requires operators to respond to risks that are identified.
3. Kern River and Northern Natural Gas opposed new requirements, noting that industry data show IC is a minor threat to natural gas transmission pipelines. Kern River commented that ASME/ANSI B31.8S, Appendix A2, covers the analysis of gas constituents. Northern monitors gas quality and takes corrective action as needed.
4. MidAmerican opposed new requirements, commenting that internal corrosion is a regional problem and does not occur in many areas of the country. MidAmerican requested that current integrity management regulations be revised to eliminate the need to conduct internal corrosion direct assessment when internal corrosion is not a threat.
5. NACE International opined that current regulations in subpart I are adequate to address internal corrosion, and PHMSA's proposed prescriptive requirements are not feasible.
6. Panhandle observed that requirements to minimize the potential for internal corrosion in gas transmission pipelines are included in §§ 192.475, 192.476, and 192.477. In addition, OPS issued ADB-00-02 requiring pipeline operators to review their internal corrosion monitoring programs and operation. IM regulations in subpart O require integrity management assessments that address the threat of internal corrosion. INGAA members report that completion of baseline assessments required by subpart O will result in the assessment of more than half of the gas transmission pipeline mileage in the U.S. Panhandle commented that several proposed prescriptive internal corrosion requirements provided in the ANPRM are not feasible and noted that liquids tend to accumulate in low spots that typically are not accessible for sampling. Panhandle opined that vigilant enforcement of gas quality standards is the most essential component of an internal corrosion control program.
7. Texas Pipeline Association and Texas Oil & Gas Association argued that no benefit would be gained by additional requirements in this area. The associations observed that internal corrosion threats are highly localized and monitoring and remediation efforts must be customized for local conditions.
8. IUB noted that not all pipelines are susceptible to internal corrosion and commented that operators and state inspection personnel should not be unduly burdened by additional measures when problems do not exist.
9. An anonymous commenter suggested that PHMSA require each operator to have a subject matter expert well qualified in internal corrosion, arguing that most operators currently rely on third-party contractors.
PHMSA appreciates the information provided by the commenters. The majority of industry comments do not support revising subpart I to require additional measures to prevent internal corrosion in gas transmission pipelines. However, the current requirements for internal corrosion control are non-specific and PHMSA believes that there is benefit in enhancing the current internal corrosion control requirements to establish a more effective minimum standard for internal corrosion management. Therefore, PHMSA proposes to add a requirement that each operator develop and implement a program to monitor for and mitigate the presence of, deleterious gas stream constituents and that the program be reviewed at least semi-annually. For HCA segments, PHMSA proposes to address this in enhanced preventive and mitigative measures to include objective performance criteria.
1. INGAA and a number of pipeline operators recommended that PHMSA avoid prescriptive requirements for the prevention, detection, assessment, and remediation of SCC. The commenters noted that SCC varies from pipeline to pipeline and suggested that threat management should be through a framework of processes and decision making that can tailor threat management to the requirements of each pipeline.
2. AGA and a number of its pipeline operators also objected to new requirements in this area, noting that numerous industry documents exist that provide guidance to address SCC.
3. Panhandle suggested that PHMSA avoid prescriptive standards for the prevention, detection, assessment, and remediation of SCC on gas transmission systems given the complex and variable nature of the factors contributing to the formation and growth of SCC, arguing performance-based standards allow operators the maximum flexibility to develop and apply situational techniques for detecting, assessing, and remediating this threat. Panhandle noted that multiple standards and publications are available to address internal corrosion and that the Pipeline
4. GPTC, Ameren Illinois, Atmos, Paiute, and Southwest Gas argued that existing regulations are sufficient and noted that there are numerous industry documents that provide additional guidance for addressing SCC.
5. TransCanada suggested that PHMSA adopt the current version of ASME/ANSI B31.8S.
6. The Commissioners of Wyoming County Pennsylvania opined that it is reasonable for PHMSA to prescribe practices or standards that address prevention, detection, assessment and remediation of SCC on transmission and gas gathering lines, including those in Class 1 locations. The Commissioners argued that it is important to address this aspect of corrosion given aging of existing pipelines and the significant number of new pipelines.
7. Air Products and Chemicals argued that operators should not be required to undertake SCC prevention, detection, assessment and remediation activities where a pipeline does not meet the B31.8S criterion for SCC. Air Products further commented that it is important that PHMSA's regulations and standards reflect the threshold concept of susceptibility to SCC, and that a pipeline that does not meet the B31.8S criteria for SCC risk should not be required to undertake SCC prevention, detection, assessment, and remediation activities.
8. NACE International stated that overly prescriptive rules can supplant sound engineering judgment and prevent innovation and the development of new technologies.
9. Northern Natural Gas argued that the current regulations and industry standards provide adequate guidance and that the assessment criteria address operating temperature and coating type. Northern Natural Gas noted that operating temperature is addressed in PHMSA Gas FAQ 223 and that the reassessment interval should be determined by the results of the integrity assessment performed pursuant to ASME B31.8S.
10. MidAmerican pointed out that these concerns are addressed in the pre-assessment phase of direct assessment and adequately covered in ASME/ANSI B31.8S.
11. Texas Pipeline Association and Texas Oil & Gas Association suggested that additional regulations related to SCC could prove beneficial. At the same time, the associations recommended that PHMSA not require additional surveys or shorter intervals, arguing that the current regulations are based on sound engineering practices.
12. A private citizen commented that SCC should be addressed as part of a comprehensive corrosion control program.
13. An anonymous commenter noted that a reliable survey technique for SCC does not now exist and suggested that PHMSA require shorter assessment intervals for pipelines with a history of SCC.
14. INGAA argued that pipe temperature and coating are not sufficient to identify SCC. INGAA contended that ASME/ANSI B31.8S adequately covers prevention, detection, assessments, and remediation of SCC and criteria to capture all pipe potentially susceptible to SCC would be overly conservative. A number of pipeline operators supported INGAA's comments.
15. NACE International opined that there are too many factors involved, and they are too interrelated and location-specific, to allow prescribing an optimal assessment interval for SCC.
PHMSA appreciates the information provided by the commenters. The majority of industry comments do not support new requirements for the prevention, detection, assessment, and remediation of SCC. PHMSA recognizes that SCC is an important safety concern, but does not believe the current methods for managing SCC anomalies supports prescribing a detailed SCC management approach that would be effective for all operators. PHMSA does not propose to amend subpart I to prescribe an SCC management plan at this time. PHMSA will continue to study this issue and support ongoing research. PHMSA plans to hold a public forum on the development of SCC standards in the future. Once that process is complete, PHMSA will consider new minimum safety standards for managing the threat of SCC. However, under topics C and G, above, PHMSA does propose to include more specific requirements for conducting integrity assessments for the threat of SCC and for enhancing the HCA and non-HCA repair criteria to address SCC.
1. INGAA and a number of pipeline operators stated that NACE SP0204 does not address the full life cycle of concerns of SCC. INGAA added that SP0204, along with ASME/ANSI B31.8S, NACE publication 35103, STP-TP-011, and Canadian recommended practices, do cover the full life cycle concerns.
2. NACE International reported that its standard (SP0204) does not address the full life cycle concerns of SCC.
3. GPTC noted that existing regulations and standards address SCC concerns and commented that it is not clear what is meant by “full life cycle concerns.”
4. Ameren Illinois argued that full life cycle concerns are addressed in the pre-assessment phase of stress corrosion cracking direct assessment (SCCDA) and new prescriptive requirements are not needed.
5. Northern Natural Gas commented that ASME/ANSI B31.8S should be used in conjunction with NACE SP0204.
6. Panhandle reported that SCCDA was never intended to address full life cycle management for SCC. The standard does not address aspects such as the formation or nucleation of cracks or calculations to assess the severity of cracks. Panhandle opined that the collective body of SCC research does address the full life cycle, but cautioned the full body of knowledge of all documents must be considered as some may be dated and do not reflect current knowledge on SCC management.
7. An anonymous commenter suggested that NACE SP0204 does not address full life cycle concerns, noting that SCC has been found in circumstances where the standard would suggest it should not be expected.
PHMSA appreciates the information provided by the commenters and agrees that sufficient information is not available at this time to specify prescriptive standards for SCC management. See the response to comments received on question I.5.
1. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas Association, and numerous pipeline operators reported that no data has been collected on the application of any current standard. INGAA added that available statistics indicate that the annual number of failures due to SCC is generally decreasing and noted that a high percentage of in-service failures, failures during hydro testing, and instances where SCC cracks greater than 10 percent were found during excavations have met the screening criteria of ASME/ANSI B31.8S (which are identical to the NACE criteria).
2. Northern Natural Gas reported that it has found one instance of SCC and no segments were identified subject to similar circumstances.
PHMSA appreciates the information provided by the commenters and agrees that sufficient information is not available at this time to specify prescriptive standards for SCC management. PHMSA will be studying this issue and soliciting further input from stakeholders in the future. See the response to comments received on question I.5.
1. NACE International suggested that existing standards should be updated and improved rather than developing new standards, noting that such updating is as normal part of the standards process.
2. INGAA and a number of its pipeline operators supported the development of voluntary standards to cover detection, assessment, mitigation, periodic assessment, and evaluation of effectiveness.
3. Panhandle supported the development of industry standards to manage SCC but does not believe that such a document can be completed until the gaps in the understanding of SCC have been addressed.
4. GPTC, Ameren Illinois, and Northern Natural Gas opined that the combination of ASME/ANSI B31.8S and ASME STP-PT-011 provide adequate guidance.
5. Atmos recommended that further investigation be required if SCC outside of the criterion specified in NACE SP0204-2008 is found. Atmos stated that any new standards that are developed should be voluntary so that operators have additional methodologies available for mitigating the threat of SCC as currently required by § 192.929.
6. Texas Pipeline Association and Texas Oil & Gas Association recommended any new standards for SCC apply only to Class 1 locations, based on their conclusion that pipe designed for Class 2 conditions (and above) is not susceptible to SCC.
PHMSA appreciates the information provided by the commenters and agrees that sufficient information is not available at this time to specify prescriptive standards for SCC management. PHMSA will be studying this issue and soliciting further input from stakeholders in the future. See the response to comments received on question I.5.
1. INGAA, supported by a number of its pipeline operators, opined that the existing regulations are adequate, and commented that prescriptive limits, such as those in § 192.620, would not be as effective in reducing the potential for internal corrosion.
2. GPTC recommended that § 192.476 be revised to reflect only those liquids that act as an electrolyte (
3. AGA sees no need to clarify the definition and noted that the stated constituents pose no threat if water is not present.
4. Atmos, Paiute, and Southwest Gas noted that gas tariffs maintain gas quality and water must be present with the constituents listed to produce a corrosive gas stream. Paiute opined that § 192.929 and ASME/ANSI B31.8S are sufficient.
5. NACE International expressed uncertainty as to why the definition needs to be clarified. NACE also noted that there are more factors than those listed in the question that affect the corrosiveness of a gas stream.
6. MidAmerican, Ameren Illinois, and Northern Natural Gas noted that ASME/ANSI B31.8S requires analysis of gas constituents and argued that operators know what constitutes a corrosive gas stream. The operators do not believe the definition needs to be changed.
7. Kern River suggested that the definition should be changed, noting that water must be present, in addition to the listed constituents, to make a gas stream corrosive.
8. Texas Pipeline Association and Texas Oil & Gas Association suggested no change to the definition is needed, since operators understand the listed constituents, when combined with water, can cause internal corrosion.
9. An anonymous commenter suggested that PHMSA not attempt to list constituents that could make a gas stream corrosive, arguing there are too many scenarios to cover. The commenter noted that the issue is not simple: H
PHMSA appreciates the information provided by commenters, and consistent with the majority of comments, PHMSA does not propose to revise the definition of corrosive gas at this time. However, PHMSA does propose to clarify the regulations by listing examples of constituents that are potentially corrosive, and to propose objective performance criteria for monitoring gas stream contaminants for HCA segments.
1. INGAA, supported by a number of pipeline operators, suggested that safety would be best served by following a risk-based approach to determine intervals for corrosion control or close interval surveys, arguing that prescriptive requirements applicable to all pipelines would divert safety resources from other high-risk tasks.
2. AGA, GPTC, and a number of pipeline operators argued that there is no reason for PHMSA to specify timing of close interval surveys, contending that the current subpart I requirements have proven to be successful and the use of CIS as an indirect assessment tool is built into NACE SP0502.
3. Ameren Illinois opposed the prescribed intervals for close interval surveys, arguing that § 192.463 and 192.465 are adequate. In addition, Ameren noted that § 192.917(e)(5) requires an operator to evaluate and remediate corrosion in both covered and non-covered segments when corrosion is found.
4. Atmos opposed required timing for close interval surveys, arguing that CIS is just one tool that can be used to determine the effectiveness of CP.
5. MidAmerican expressed its conclusion that establishing required timing intervals for close interval surveys would not be beneficial. MidAmerican noted that specific pipeline characteristics need to be taken
6. Paiute and Southwest Gas opposed required periodicity for close interval surveys, arguing that NACE SP0207 provides adequate guidance.
7. Northern Natural Gas commented that PHMSA should not prescribe external corrosion control survey intervals for close interval surveys, noting that its integrity management program demonstrates that external corrosion is being managed effectively.
8. Texas Pipeline Association and Texas Oil & Gas Association argued that industry experience demonstrates existing requirements are adequate.
9. An anonymous commenter suggested that specified periodicity for close interval surveys could have benefit, especially where a history of external corrosion exists.
PHMSA appreciates the information provided by the commenters. Recent experience, including the December 2012 explosion near Sissonville, WV and the 2007 incident near Delhi, LA, underscores the need to be more attentive to external corrosion mitigation activities. PHMSA proposes to enhance the requirements of subpart I to require that operators conduct close-interval surveys if annual test station readings indicate that cathodic protection is below the level of protection required in subpart I, or to restore adequate corrosion control. For HCA segments, PHMSA proposes to address these requirements in enhanced preventive and mitigative measures, to include an objective timeframe for restoration of deficient cathodic protection.
1. INGAA stated it does not believe it is feasible to develop prescriptive measures that identify necessary and sufficient monitoring and mitigation efforts in all environments. A number of pipeline operators supported INGAA's comments.
2. AGA and a number of its operator members expressed their conclusion that the requirements of subpart I are sufficient, noting that they address HCA and non HCA alike.
3. GPTC commented that the question does not make clear why additional measures should be prescribed given that operators have been successfully mitigating corrosion deficiencies for many years.
4. Ameren Illinois expressed its conclusion that the science of corrosion mitigation is sufficiently advanced and appropriate mitigation measures are well known. Atmos, Paiute, and Southwest Gas agreed, concluding that subpart I is sufficient when implemented properly by appropriately trained and qualified personnel.
5. MidAmerican opposed new requirements, arguing that current regulations address all practical mitigation efforts.
6. Texas Pipeline Association and Texas Oil & Gas Association suggested that more time should be allowed before additional prescriptive requirements on cathodic protection are considered, noting that corrosion leaks are trending downward.
7. The Commissioners of Wyoming County Pennsylvania suggested that it is reasonable that PHMSA prescribe corrosion control measures for HCAs and non-HCAs with clearly defined conditions and appropriate mitigation efforts. They cited information from NACE indicating that 25 percent of all accidents are caused by corrosion and these accidents account for 36 percent of all accident damage. The Commissioners noted that gathering lines in the Marcellus Shale area have diameters and pressures similar to transmission lines and should be subjected to the same requirements.
8. An anonymous commenter recommended that PHMSA not prescribe specific measures.
PHMSA appreciates the comments provided, and consistent with the majority of comments, does not propose additional regulatory changes at this time, other than to prescribe measures to promptly restore cathodic protection, as discussed in the response to comments received for question I.10.
1. INGAA reported that most major operators in North America have adopted threat management closely aligned to CEPA standards, but that no specific data exist that correlate the use of CEPA methods to anomaly detection. INGAA reported a Joint Industry Project (JIP) study that shows that applying NACE SP0204, ASME/ANSI B31.8S, CEPA, and other standards has led to a significant reduction in in-service failures. Numerous pipeline operators supported INGAA comments.
2. AGA, supported by a number of its pipeline operator members, questioned why a discussion of CEPA standards was included in the ANPRM. AGA suggested that CEPA practices are well suited to Canadian infrastructure, but not necessarily applicable in the United States and noted that CEPA is not often discussed by Canadian members at AGA meetings.
3. GPTC expressed that its membership has little knowledge of CEPA standards, commented that it is not clear what is meant by full life cycle concerns, and argued that existing standards and regulations adequately address SCC concerns. GPTC is not aware of any data correlating the efficacy of CEPA to other standards.
4. Paiute and Southwest Gas reported that they have not implemented CEPA standards.
PHMSA appreciates the information provided by the commenters. PHMSA acknowledges the comments provided on the use of the CEPA SCC Recommended Practice and will consider that standard in its study of comprehensive safety requirements for SCC.
1. INGAA reported its conclusion that CEPA standards address full life cycle concerns for near-neutral SCC. Many management techniques in CEPA standards are also applicable to high-pH SCC, but the two are not identical. Several pipeline operators supported INGAA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association expressed their conclusion that CEPA standards address the full life cycle concerns of SCC.
PHMSA appreciates the information provided by the commenters. PHMSA acknowledges the comments provided on the use of the CEPA SCC Recommended Practice and will consider that standard in its study of
1. INGAA, supported by a number of its pipeline operator members, reported that there are no related European standards and Australia has a standard similar to ASME/ANSI B31.8S. INGAA noted that SCC failures of pipelines installed since 1980 are rare and observed that quality coating and cathodic protection are the most effective means of preventing SCC.
2. GPTC stated that NACE SP0204 and 35103, ASME/ANSI B31.8S, and GPTC guide material address SCC. Paiute and Southwest Gas agreed that NACE standards and GPTC provide relevant guidance.
3. AGA commented that it does not have the statistics available to advise whether or not additional requirements are needed to address SCC threats.
4. Atmos, Texas Pipeline Association and Texas Oil & Gas Association reported that they have no knowledge of other SCC standards or practices.
5. Northern Natural Gas cited ASME/ANSI B31.8S and ASME STP-PT-011.
PHMSA appreciates the information provided by the commenters. PHMSA acknowledges the comments provided on the standards, and will consider these standards in its study of comprehensive safety requirements for SCC.
1. INGAA noted that the measurement of ILI crack detection tool performance is an ongoing research activity, both within JIP Phase II and within the Pipeline Research Council International, which is actively supported by the tool vendors and the pipeline operators. Several issues regarding the acquisition and interpretation of information need to be standardized by the practitioners before a clear picture can emerge. The implications of tool tolerance on predicted failure pressure are being studied in the JIP Phase II.
2. GPTC, Atmos, Paiute, Southwest Gas, and an anonymous commenter reported that they are unaware of any relevant statistics.
3. Northern Natural Gas reported that it has used electro-magnetic acoustic transducer (EMAT) ILI with some success.
4. Panhandle commented that magnetic particle inspection (MPI) is effective at locating surface-breaking linear indications, a subset of SCC. Furthermore, abrasive wheel grinding in conjunction with MPI is an effective method to size the length and depth of surface-breaking linear indications, limited by the amount of metal that can be removed from in-service pipelines. Panhandle noted that PRCI research indicates that laser UT techniques can effectively locate and size SCC, but this method is relatively new and Panhandle has no experience with its use. Panhandle also reported that the use of EMAT has yet to be acknowledged as a replacement for hydrostatic testing but it is being evaluated in Phase II of the SCC Joint Industry Project (JIP); results of the study will be used to determine the path forward for EMAT technology.
5. Texas Pipeline Association and Texas Oil & Gas Association reported that they have no knowledge of relevant references other than the Baker study.
PHMSA appreciates the information provided by the commenters and will consider this information in its study of comprehensive safety requirements for SCC.
1. INGAA and a number of pipeline operators noted that detecting SCC close to a longitudinal seam is difficult and even harder near a girth weld. INGAA commented that developing tools to reliably detect and assess SCC near longitudinal seams is a continuing challenge.
2. GPTC reported that SCC tools are available; however, GPTC cautioned that the ability to accurately and reliably detect the severity of SCC associated with longitudinal seams is dependent on specific operating conditions.
3. Atmos commented that it knows of no tools that can accurately detect and estimate the severity of SCC near a longitudinal seam.
4. Paiute and Southwest Gas reported that tools are being developed but are, as of yet, not accurate at determining the severity of SCC associated with longitudinal seams.
5. Northern Natural Gas reported that it has used electro-magnetic acoustic transducer (EMAT) ILI with some success. Panhandle added that difficulties in using EMAT are further complicated when cracking is associated with a longitudinal seam.
6. Texas Pipeline Association and Texas Oil & Gas Association expressed their conclusion that the best methods to assess for SCC near longitudinal seams are pressure testing and EMAT, although they noted that some operators have had success with transverse flux ILI.
7. An anonymous commenter reported that new ILI tools exist but that analysts are not yet consistent in using them.
PHMSA appreciates the information provided by the commenters and will consider this information in its study of comprehensive safety requirements for SCC.
1. INGAA, supported by a number of pipeline operators, noted that operators are already required to perform an analysis to determine the likelihood of SCC. INGAA added that operators address the pipelines with the highest likelihood of SCC and apply lessons learned, as appropriate, to lower-likelihood pipelines.
2. Texas Pipeline Association and Texas Oil & Gas Association indicated that a requirement to perform a critical analysis for SCC is unnecessary, since guidance in ASME/ANSI B31.8S is sufficient. Northern Natural Gas also stated that additional requirements are unnecessary, noting that it conducted an analysis of critical factors affecting SCC and identified no new factors over those in B31.8S, Appendix 3.
3. Atmos stated that PHMSA's question was unclear whether to expand the threat of SCC to all pipeline segments or expand the requirements for investigating the presence of SCC within HCA segments? Atmos concluded that subpart O requirements provide a framework for operators to integrate data, rank risk, identify threats, and apply appropriate mitigative actions; additional requirements are not needed.
4. Texas Pipeline Association and Texas Oil & Gas Association suggested that PHMSA conduct a workshop to share industry experience with SCC.
PHMSA appreciates the information provided by the commenters and will consider this information in its study of comprehensive safety requirements for SCC.
1. INGAA, Panhandle, Atmos, and Northern Natural Gas noted that subpart O already requires that all credible threats be identified and assessed. A number of pipeline operators supported INGAA's comments.
2. Texas Pipeline Association and Texas Oil & Gas Association also indicated that they read subpart O as requiring assessment using a method that can detect SCC if that threat is credible. The associations both added, however, that they would not object to making this requirement more explicit.
3. GPTC opined that existing regulations and standards are adequate to address SCC issues.
4. Southwest Gas opposed a new requirement, noting that § 192.929 and ASME/ANSI B31.8S are sufficient.
PHMSA appreciates the information provided by the commenters and will consider this information in its study of comprehensive safety requirements for SCC. As indicated above in the response to comments received on question I.5, PHMSA proposes more explicit requirements for selection of appropriate methods for integrity assessments for SCC.
1. INGAA, Kern River, Paiute, and Southwest Gas commented that these issues are already addressed in subpart O, which requires operators to keep records, measure program effectiveness, continually evaluate and assess systems, integrate data, and show continual improvement. INGAA added that metrics bearing on the effectiveness of a corrosion control program are already among those required to be collected by ASME/ANSI B31.8S. These metrics are not required to be submitted, but are available for review during inspections. A number of pipeline operators supported INGAA's comments.
2. MidAmerican commented that subparts I and O include these requirements. Northern Natural Gas agreed that it manages these threats through O&M and IM activities.
3. Panhandle noted that subpart I requires operators to maintain effective corrosion control programs to mitigate the threat of corrosion and § 192.945 requires operators to measure, on a semi-annual basis, whether the integrity management program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting HCAs.
4. GPTC and AGA, supported by a number of its pipeline operator members, opposed requiring operators to submit corrosion management metrics. AGA noted that operators need flexibility to select the appropriate analysis methods and key performance indicators. Furthermore, operators review corrosion control program effectiveness, and plans of intrastate operators are reviewed by state commissions.
5. Ameren Illinois opposed new requirements, noting that subpart O already requires operators to identify and respond to risks.
6. Atmos questioned whether PHMSA is proposing to measure the effectiveness of corrosion management programs across all pipeline segments or to measure the effectiveness of corrosion management programs in HCA segments. Atmos added that the data points enumerated by PHMSA in this question would be difficult to gather on an operator's entire pipeline system.
7. Texas Pipeline Association and Texas Oil & Gas Association stated that they do not see a need for a requirement to periodically analyze the effectiveness of an operator's corrosion management program, arguing that existing requirements are sufficient.
8. Panhandle argued that the standardization of corrosion control efforts, as would be required for performance metric tracking, would require additional prescriptive requirements in subpart O. Panhandle does not believe that elimination of performance-based language is beneficial.
9. The Commissioners of Wyoming County Pennsylvania suggested that any communication between operators and PHMSA regarding corrosion management would be helpful in facilitating operator compliance and best practices.
10. Paiute and Southwest Gas reported that they opposed a requirement to report additional performance metrics absent a definition of how new data would be collected and used.
PHMSA appreciates the information provided by the commenters. Following publication of the ANPRM, the NTSB issued recommendations in response to the San Bruno pipeline incident, including a specific recommendation (P-11-19) that PHMSA establish standards for evaluating effective program performance. PHMSA will evaluate standards for integration of pipeline corrosion data to enhance corrosion management performance as part of its response to that recommendation.
1. INGAA, supported by a number of its pipeline operator members, commented that continued study and evaluation of the root causes of the San Bruno explosion, documentation of findings, and communication of results are needed rather than additional prescriptive requirements.
2. AGA, GPTC, and a number of pipeline operators argued that no further action is needed, given that current methodologies adequately address corrosion issues and operators are subject to periodic audits by federal and state safety regulators.
3. Accufacts suggested that PHMSA needs to assure that IM programs are not solely relied upon to prevent corrosion failure.
4. Texas Pipeline Association and Texas Oil & Gas Association reported that they do not see any deficiencies necessitating new regulations.
PHMSA appreciates the information provided by the commenters. As discussed above, PHMSA is proposing some enhanced measures for corrosion control in subpart I and subpart O.
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No comments were received in response to this question.
The ANPRM requested comments regarding additional integrity management and pressure testing
• Pressure tested after construction and prior to being placed into gas service in accordance with subpart J; and
• Manufactured in accordance with a referenced standard (most gas transmission pipe has been manufactured in accordance with American Petroleum Institute Standard 5L, 5LX or 5LS, “Specification for Line Pipe” (API 5L) referenced in 49 CFR part 192).
Many gas transmission pipelines built from the 1940's through 1970 were manufactured in accordance with API 5L, but may not have been pressure tested similar to a subpart J pressure test. For pipelines built prior to 1971, § 192.619(a) allows MAOP to be based on the highest 5-year operating pressure established prior to July 1, 1970, in lieu of a pressure test. Accordingly, some of this pre-existing pipe possesses variable characteristics throughout the longitudinal weld or pipe body.
As a result of 12 hazardous liquid pipeline failures that occurred during 1986 and 1987 involving pre-1970 ERW pipe, PHMSA issued an alert notice (ALN-88-01, January 28, 1988) to advise operators with pre-1970 ERW pipe of the 12 pipeline failures and the actions to take. Subsequent to this notice, one additional failure on a gas transmission pipeline, and eight additional failures on hazardous liquid pipelines occurred, which resulted in PHMSA issuing another alert notice (ALN-89-01, March 8, 1989) to advise operators of additional findings since the previous alert notice. These notices identified the fact that some failures appeared to be due to selective seam weld corrosion, but that other failures appeared to have resulted from flat growth of manufacturing defects in the ERW seam. In these notices, PHMSA specifically advised all gas transmission and hazardous liquid pipeline operators with pre-1970 ERW pipe to consider hydrostatic testing of affected pipelines, to avoid increasing a pipeline's long-standing operating pressure, to assure effectiveness of the CP system, and to conduct metallurgical exams in the event of an ERW seam failure.
Since 2002, there have been at least 22 reportable incidents on gas transmission pipeline caused by manufacturing or seam defects. In addition, recent high consequence incidents, including the 2009 failure in Palm City, Florida and the 2010 failure in San Bruno, California, have been caused by longitudinal seam failures.
The ANPRM listed questions for consideration and comment. The following are general comments received related to the topic as well as comments related to the specific questions:
1. Texas Pipeline Association and Texas Oil & Gas Association suggested that seam issues are best addressed through inspection, detection, remediation, and monitoring, based on specific segments, not a one-size-fits-all requirement.
PHMSA appreciates the comment and agrees that a one-size-fits-all requirement is not the best approach. Accordingly, PHMSA proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines, that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Verification of MAOP includes establishing and documenting MAOP if the pipeline segment: (1) Has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking and the pipeline segment is located in one of the following locations: (i) A high consequence area as defined in § 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
In addition, the proposed rule would allow operators to select from among several approaches to verify MAOP based on segment specific issues and limitations, such as pressure testing, pressure reduction based on historical operating pressure, and engineering critical assessment.
1. AGA, GPTC, and numerous pipeline operators opposed a requirement to pressure test all lines not previously tested. These commenters supported the more-limited testing mandated by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. AGA noted that Congress considered and rejected proposals for more extensive testing.
2. AGA, GPTC, Iowa Utilities Board, Iowa Association of Municipal Utilities, Texas Pipeline Association, Texas Oil & Gas Association, and several distribution pipeline operators objected to requiring pressure testing of distribution pipelines. The commenters argued that the impact of resulting service disruptions was overlooked. Pressure testing would necessitate disruptions of three to seven days for many distribution pipelines, sometimes involving service to an entire town. In some cases, establishing an alternate supply is not always possible. In addition, some in-service lines are not configured in a manner that would support testing. For these reasons, the commenters argued that the high costs to perform pressure tests were inappropriate absent some demonstration of actual risk. MidAmerican added a suggestion that such a requirement of this type be
3. INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas Association, and several pipeline operators opposed a blanket testing requirement for older pipelines. The commenters noted that more than sixty percent of in-service pipelines were installed prior to 1970, and have operated safely. INGAA argued that the objective of any action in this area should not be pressure testing, per se, but verification of fitness for service. INGAA noted that all of the listed pipe types are addressed in its Fitness for Service protocol, which would be more effective and efficient than a prescriptive test requirement. A number of additional pipeline operators supported INGAA's comments.
4. Accufacts recommended that all pipelines with at-risk seam anomalies be pressure tested to at least 90% SMYS, with priority given to lines operating under an MAOP established in accordance with 49 CFR 192.619(c).
5. Texas Pipeline Association and Texas Oil & Gas Association noted that pressure testing alone, is not sufficient to prove the integrity of pipelines subject to seam issues. The associations argued that verification must also consider any degradation mechanism present in the seam.
6. Dominion East Ohio supported a requirement to pressure test pipe susceptible to seam failure for which adequate test documentation does not exist.
7. Pipeline Safety Trust, California Public Utilities Commission, Commissioners of Wyoming County Pennsylvania, and an anonymous commenter supported requiring a pressure test for all pipelines not already tested to current requirements. The commenters argued that integrity management should have led to necessary testing but has not done so in all cases. They also noted that such a requirement would respond to an NTSB recommendation.
8. The Environmental Defense Fund (EDF) cautioned that any requirement for pressure testing should assure that the amount of gas blown down to the atmosphere is minimized. It noted that methane is a potent greenhouse gas, and uncontrolled blowdown of 182,000 miles of gas transmission pipeline would be approximately equivalent to the annual greenhouse gas release from 9-14 million autos.
PHMSA appreciates the information provided by the commenters. This NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Verification of MAOP includes establishing and documenting MAOP using one or more of the methods in § 192.624(c)(1) through (c)(6). With regard to the EDF comment regarding the environmental cost due to gas blow down during pressure testing, PHMSA considered this in the rule development. The proposed rulemaking is written to minimize pressure testing. The Integrity Verification Process allows MAOP verification through ILI and ECA. PHMSA believes operators will pressure test as a last resort because it is the costliest methodology. PHMSA estimates that the rule would result in approximately 1,300 miles of pipe being pressure tested. The gas release from controlled low volume release during pressure testing is much less than an uncontrolled high volume release as a result of rupture. The proposed rule is expected to prevent incidents, leaks, and other types of failures that might occur, thereby preventing future releases of greenhouse gases (GHG) to the atmosphere, thus avoiding additional contributions to global climate change. PHMSA estimated net GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on the estimated number of incidents averted and emissions from pressure tests and ILI upgrades.
1. INGAA, supported by a number of pipeline operators, argued that there is no evidence suggesting that subpart J test pressures are inadequate. INGAA added that there are circumstances in which additional tests to 1.25 times MAOP may be appropriate to verify fitness for service. This is consistent with ASME/ANSI B31.8S and addressed in its Fitness for Service protocol.
2. Texas Pipeline Association, Texas Oil & Gas Association, and Atmos argued that a pressure test at the time of construction is adequate. The associations further added that operating practices since part 192 became effective can also verify fitness for service, if primary test records are not available, particularly if MAOP is reduced.
3. AGA, GPTC, and a number of pipeline operators commented that any test to pressures greater than MAOP has some value. AGA noted that even tests to 1.1 times MAOP would identify the most severe defects that have the potential to adversely affect pipeline integrity.
4. MidAmerican suggested that a fitness for service evaluation should be allowed if there are service interruption issues and for pre-1970 pipelines. MidAmerican would allow testing for existing pipelines, to 1.1 or 1.25 times MAOP or to mill test pressures if they are less than would be required by subpart J.
5. An anonymous commenter argued that alternative minimum test pressures are not appropriate, since they provide no more information than successful operation at normal operating pressures.
6. Accufacts suggested that pipelines tested to lower pressures and that have been subject to aggressive operating cycles be considered for high-pressure testing. Accufacts would also require test pressures be recorded both in psig and percent SMYS.
PHMSA appreciates the information provided by the commenters. Following publication of the ANPRM, the NTSB issued its report on the San Bruno incident that included a recommendation for this issue (P-11-15). The NTSB recommended that PHMSA amend its regulations so that manufacturing- and construction-related defects can only be considered “stable” if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM proposes to revise the integrity management requirement in 192.917(e)(3) to allow the presumption of stable manufacturing and construction defects only if the pipe has been pressure tested to at least 1.25 times MAOP. In addition, PHMSA proposes to revise pressure test safety factors in § 192.619(a)(2)(ii) to correspond to at least 1.25 MAOP for newly installed pipelines.
1. INGAA and numerous pipeline operators noted that ILI tools can examine seam issues but the technology to identify and evaluate seam anomalies is still evolving. INGAA added that there are significant burdens associated
2. AGA reported that its discussions with ILI vendors have identified that ILI can detect seam issues but detection is dependent on many conditions and is not guaranteed.
3. Texas Pipeline Association and Texas Oil & Gas Association argued that ILI conducted using a multi-purpose tool can provide a seam assessment equivalent to pressure testing for detection of seam integrity issues, depending on anomaly characteristics and the ILI method used.
4. Northern Natural Gas commented that ILI can be used to detect seam anomalies. Analysis of anomalies is based on the log-secant method with consideration of toughness to determine the predicted failure pressure ratio. The response criteria can then be based on the failure pressure versus maximum allowable operating pressure, similar to wall loss. Northern noted that this is consistent with ASME/ANSI B31.8 and B31.8S.
5. Accufacts commented that ILI cannot, at present, reliably detect all seam anomalies.
PHMSA appreciates the information provided by the commenters. PHMSA proposes requirements in the rulemaking to address the use of ILI for seam integrity issues. This includes incorporating industry standard NACE SP0102-2010 into the regulations to provide better guidance for conducting integrity assessments with in-line inspection. In addition, for pipe segments subject to MAOP verification in new § 192.624, specific guidance is provided for analyzing crack stability when using engineering critical assessment in conjunction with inline inspection to address seam or other cracking issues.
1. INGAA and numerous pipeline operators noted that magnetic particle inspection is now being used by many operators when pipe with disbanded coating is exposed.
2. GPTC, Northern Natural Gas, and MidAmerican reported that there are other methods that are useful under some circumstances, such as x-ray or other forms of radiography and guided wave ultrasound.
3. Texas Pipeline Association, Texas Oil & Gas Association, and Atmos noted that radiography, ultrasonic testing (UT), and shear wave UT are now being tested.
4. AGA, supported by a number of its pipeline operator members, noted that operators must have the flexibility to select appropriate tools without prior PHMSA approval. AGA argued that technology is advancing rapidly and that PHMSA stifles advancement by requiring prior approval of new inspection tools. AGA argued that some requirements being imposed on the use of other technologies are effectively regulations imposed without formal rulemaking, citing limitations imposed on the use of guided wave ultrasound as an example.
5. Atmos recommended that PHMSA modify its regulations to allow operators to use appropriate methods to evaluate seam integrity without requiring approval as “other technology.”
6. Accufacts opined that pressure testing and cyclic monitoring and analysis are the only useful technologies currently available.
PHMSA appreciates the information provided by the commenters. PHMSA proposes requirements in the rulemaking to address the use of best available technology, including use of electromagnetic acoustic transducers (EMAT) or ultrasonic testing (UT) tools to assess seam integrity issues. In addition, proposed requirements include performing fracture mechanics modeling for failure stress pressure and cyclic fatigue crack growth analysis to assess crack or crack-like defects. These requirements would apply to any segment that required verification of MAOP.
1. INGAA and several pipeline operators argued that existing requirements are adequate and any verification beyond those requirements should rely on INGAA's Fitness for Service protocol. INGAA argued that its protocol is consistent with Section 23 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.
2. MidAmerican suggested any new requirements should focus on pipe with manufacturing and construction defects and should prioritize pipelines in Class 3 and 4 areas and HCAs. MidAmerican sees little benefit in testing other pipelines.
3. An anonymous commenter recommended additional unspecified requirements be applied to pipelines in Class 3 and 4 areas and HCAs.
4. The California Public Utilities Commission would apply pressure testing requirements to HCAs that are determined by the method described in paragraph 1 in the definition of HCA in § 192.903, as a minimum.
5. The Iowa Utilities Board and the Iowa Association of Municipal Utilities argued that class location is not a reasonable basis for determining where to apply pressure testing requirements, given that class location has no relationship to risk. These commenters noted that small-diameter, low-pressure lines could be Class 3, even with no structures intended for human occupancy within a potential impact radius.
6. The Commissioners of Wyoming County Pennsylvania would apply requirements to all transmission and gathering pipelines, including those in Class 1 locations.
7. Thomas Lael noted that all pipelines have been tested once, after construction.
PHMSA appreciates the information provided by the commenters. This NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Use of the MCA location criteria would apply to pipe segments where dwellings, occupied sites, or interstate highways, freeways, and expressways, and other principal 4-lane arterial roadways are located within the potential impact radius, but would not necessarily include all class 3 or 4 locations. Verification of MAOP includes establishing and documenting MAOP using one or more of the methods in 192.624(c)(1) through (c)(6). In addition, this NPRM proposes requirements for verification of pipeline material in new § 192.607 for existing onshore, steel, gas transmission pipelines that are located in an HCA or class 3 or class 4 locations.
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No comments were received in response to this question.
Underground storage facilities are comprised of wells and associated separation, compression, and metering facilities to inject and withdraw natural gas at high pressures from depleted hydrocarbon reservoirs and salt caverns. Pipelines that transport gas within a storage field are defined in § 192.3 as transmission pipelines and are regulated by PHMSA, while underground storage facilities including surface and subsurface well casing, tubing, and valves are not currently regulated under part 192. In the ANPRM, PHMSA provided a brief history of a 1992 accident that occurred in Brenham, Texas an involving underground storage facility. This incident involved an uncontrolled release of highly volatile liquids from a salt dome storage cavern that resulted in 3 fatalities, 21 people treated for injuries at area hospitals, and damages in excess of $9 million. Following the incident, the National Transportation Safety Board (NTSB) conducted an investigation that resulted in a recommendation for the Research and Special Programs Administration, the precursor to PHMSA, to initiate a rulemaking proceeding. Following a period of study, RSPA terminated that rulemaking. RSPA described this action in an Advisory Bulletin published in the
Since publication of the 1997 Advisory Bulletin, significant incidents have continued to occur involving underground gas storage facilities. The most significant incident occurred in 2001 near Hutchinson, Kansas. An uncontrolled release from an underground gas storage facility resulted in an explosion and fire, in which two people were killed. Many residents were evacuated from their homes and were not able to return for four months.
The Kansas Corporation Commission initiated enforcement action against the operator of the Hutchinson storage field as a result of safety violations associated with the accident. As part of this enforcement proceeding, it was concluded that the storage field was an interstate gas pipeline facility. Federal statutes provide that “[a] State authority may not adopt or continue in force safety standards for interstate pipeline facilities or interstate pipeline transportation” (49 U.S.C. 60104). There were, and remain, no federal safety standards against which enforcement could be taken. Therefore, the enforcement proceeding was terminated.
The ANPRM listed questions for consideration and comment. The following are general comments received related to this topic as well as comments related to the specific questions:
1. AGA, supported by a number of pipeline operators, suggested that any proceeding addressing gas storage be conducted under a docket separate from any pipeline requirements, arguing that the relevant engineering and regulatory concepts are vastly different.
2. The Kansas Department of Health and Environment (KDHE) noted that the ANPRM misstated the agency that took enforcement action in the case of the Kansas gas storage incident previously discussed. That action was taken by KDHE, and not the Kansas Corporation Commission, as stated.
3. Kansas Corporation Commission recommended that PHMSA work with the states to have Congress amend the Pipeline Safety Act to allow the states to regulate interstate and intrastate gas storage wellbores. KCC noted that current federal regulations undermine the ability of states to regulate gas storage facilities, as in the 2001 accident where Kansas attempted to take enforcement as a result of a serious incident but was precluded from doing so by pre-emption of federal regulations.
4. The Interstate Oil & Gas Compact Commission argued that states should be mandated to regulate gas storage wellbores, whether interstate or intrastate.
5. The Texas Pipeline Association and Texas Oil & Gas Association opposed new requirements, arguing that there has been no demonstration of undue risk or insufficiency of current regulations.
1. INGAA suggested that PHMSA develop high-level, performance-based guidelines that acknowledge and reflect existing applicable state rules to address regional and geologic variations in underground storage activity. Development of guidelines should follow PHMSA's current practice of stakeholder involvement leading to development of a consensus standard and its subsequent adoption into regulations. INGAA reported that it is committed to developing a standard under the auspices of the American Petroleum Institute (API), with work beginning in 2012. INGAA cautioned that it is important to understand, and clearly state, the scope of “gas storage,” which it contends begins at and includes the wing valve at the wellhead, the wellhead components, the well bore, and the “underground container” (
2. AGA suggested that PHMSA adopt federal performance standards, in conjunction with API. AGA argued that one-size-fits-all requirements are not appropriate in this area, since they would fail to recognize variations in wells and the geologic diversity of storage caverns and structures. AGA argued that no new requirements are needed governing maximum operating parameters and environmental conditions, since these are addressed adequately by existing federal and state certification and compliance programs related to gas storage facilities. AGA recommended that any new standards should be mandatory, but also recognize regional variations by state due to geologic and geographical diversity among storage fields. A number of pipeline operators supported AGA's comments.
3. INGAA, the Kansas Corporation Commission, and the Interstate Oil & Gas Compact Commission recommended that compliance with any new standards be mandatory, but that regulatory authority should be delegated to the states since PHMSA lacks relevant technical expertise. A number of pipeline operators supported this comment.
4. The Kansas Corporation Commission and the Interstate Oil & Gas Compact Commission recommended that any new standards cover all portions of a storage facility and that PHMSA enter into a memorandum of understanding with FERC regarding gas containment.
5. Southern Star Central Gas Pipeline agreed that the development of requirements for operation of gas storage facilities is appropriate but explicitly disagreed with Kansas Corporation Commission's suggestion that development be delegated to states.
6. GPTC, Nicor, Ameren Illinois, and Atmos argued that existing regulations are sufficient and that no new standards are needed. GPTC and Nicor added that if PHMSA elects to develop new requirements, they should be limited to facilities “affecting interstate or foreign commerce.” Atmos added that geology and circumstances vary considerably among gas storage facilities and states have the requisite expertise to regulate storage safety.
7. Texas Pipeline Association and Texas Oil & Gas Association argued that PHMSA lacks the expertise to regulate wellbores and therefore should not attempt to develop gas storage regulations.
8. FERC, NAPSR, Interstate Oil & Gas Compact Commission, Iowa Utilities Board, Kansas Corporation Commission, and Railroad Commission of Texas recommended that PHMSA seek statutory authority to confer jurisdiction over all gas storage facilities to the states. The commenters argued that states have expertise on local geology and storage fields and could therefore regulate in a fashion similar to that of production facilities. The commenters referred to PHMSA's Advisory Bulletin ADB 97-04 as a further basis for this recommendation. FERC further suggested that PHMSA delegate inspection and enforcement activities to states if statutory changes are not forthcoming.
9. The Alaska Department of Natural Resources recommended that PHMSA develop standards in consultation with the states.
10. The NTSB encouraged the development of gas storage regulations, noting that this was the subject of its recommendation P-93-9, which it closed as “unacceptable action,” after a rulemaking proceeding to regulate underground gas storage was terminated in 1997.
11. A private citizen suggested that there should be some level of regulation, as gas storage is currently insufficiently regulated.
12. NAPSR commented that, in many states, the agency familiar with gas storage issues is not responsible for regulation of pipeline safety. As a result, NAPSR stated that certification of additional state agencies may be required.
13. An anonymous commenter suggested that PHMSA should develop requirements applicable to piping within gas storage facilities. The commenter argued that caverns, well heads, casing, tubing, fresh water, and brine pumping are generally regulated by states.
14. ITT Exelis Geospatial Systems suggested that PHMSA consider requirements for leak detection, noting that their LIDAR system could serve this purpose.
1. AGA, INGAA, GPTC, Texas Pipeline Association, Texas Oil & Gas Association and numerous pipeline operators noted that FERC, EPA, and the states regulate various aspects of gas storage. Commenters reported that state regulations generally provide standards for wells and that EPA regulations provide standards for caverns. AGA described the aspects regulated by FERC, EPA, and the states and suggested provisions of each which might be considered for new PHMSA regulations. For example, it was recommended that a federal guideline be established to require a storage operator notification-review-and-approval process for third party wells encroaching on storage containers, which is a requirement some states currently have in place. Commenters reported that repaired wells must meet state standards for new wells and state requirements for abandonment vary. AGA indicated that interstate storage operators use state requirements as guidance in the absence of federal regulations.
2. The Kansas Department of Health and Environment, the Kansas Corporation Commission, the Railroad Commission of Texas, the Interstate Oil & Gas Compact Association, Ameren Illinois, and Atmos reported that states generally regulate gas storage. For example, in Texas, Statewide Rule 16 applies and KDHE submitted a copy of its gas storage regulations.
3. Texas Pipeline Association and Texas Oil & Gas Association noted that Texas requirements for gas storage are more similar to provisions that would govern production drilling and operations rather than pipeline operations.
1. AGA, INGAA, and numerous pipeline operators noted that varying approaches are used and argued that prescriptive standards would be inappropriate given that no one tool is applicable to all wells and well casings are not available for direct examination.
2. The Railroad Commission of Texas reported that its regulations require integrity testing every five years or after a well work over. Texas regulations also require periodic casing inspections and a pipeline integrity program.
3. Northern Natural Gas reported that it uses the same measures to monitor corrosion in its gas storage facilities as it does for its pipelines.
1. INGAA, AGA, the Texas Pipeline Association, the Texas Oil & Gas Association and numerous pipeline operators noted that state requirements reflect unique situations, welding is seldom used, pressure capacity is demonstrated by historical record, and casing requirements are customized for local geologic conditions. Welding, when used, is generally performed to procedures compliant with ASTM B31.8, part 192, and inspection is conducted to API-1104 criteria.
2. The Railroad Commission of Texas reported that Texas regulations are flexible to allow for site-specific decisions.
1. INGAA, AGA, and several pipeline operators reported that storage in salt domes generally requires emergency shutdown systems; these systems are generally not required for storage in depleted gas fields or aquifers but may be required depending on local site conditions. The commenters indicated that testing intervals are set in accordance with operator procedures and CP testing is based on an operator's local experience.
2. The Railroad Commission of Texas, the Texas Pipeline Association, and the Texas Oil & Gas Association reported that Texas' regulations require emergency shutdown systems and annual drills.
3. The Kansas Department of Health and Environment suggested that at least
4. Northern Natural Gas suggested that emergency shutoffs should only be required when the well is within 330 feet of a structure intended for human occupancy. Northern stated that intervals should be established for O&M activities and CP systems.
5. GPTC and Nicor expressed their opinion that no new regulations are needed in this area; decisions on emergency shutdown should be made based on local circumstances.
1. AGA, GPTC, and several pipeline operators reported that operators generally follow DOT regulations, where applicable, and industry good practices.
2. The NTSB commented that gas storage facility information should be made available to emergency responders, per its recommendation P-11-8.
3. The Railroad Commission of Texas, the Texas Pipeline Association, the Texas Oil & Gas Association, and Atmos reported that states establish standards in these areas through their regulations.
4. The Kansas Department of Health and Environment reported that these standards are specified in its regulations, and submitted a copy of its regulations as an attachment to its comments.
1. INGAA, supported by several of its member companies, noted that jurisdiction over gas storage facilities in interstate pipeline systems is federal.
2. AGA and several of its pipeline operator members suggested that federal standards could assure a degree of consistency, and uniform standards would promote integrity and safety. AGA opined that implementation of federal standards could be delegated to the states.
3. GPTC and Nicor opined that federal regulations are not needed; as states are not now precluded from regulating gas storage and many do so.
4. The Texas Pipeline Association, the Texas Oil & Gas Association, Atmos, Ameren Illinois, and Northern Natural Gas opined that effective state regulation is not now precluded. The commenters stated that state regulation in combination with applicable FERC and DOT requirements has been demonstrated to assure safety successfully.
5. The Kansas Department of Health and Environment and the Kansas Corporation Commission noted that state regulation of the safety of interstate gas storage facilities is currently precluded. When Kansas attempted to enforce its requirements following an accident at an interstate storage facility, it was prevented from doing so by a federal court on the basis of federal preemption. The agencies noted that lack of action by PHMSA or FERC on interstate gas storage facility safety precludes states from taking any action and leaves these facilities essentially unregulated.
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No comments were received in response to this question.
Since the publication of the ANPRM and the close of its comment period, Southern California Gas Company's (SoCal Gas) Aliso Canyon Natural Gas Storage Facility Well SS25 failed, causing a sustained and uncontrolled natural gas leak near Los Angeles, California. The failure, possibly from the downhole well casing, resulted in the relocation of more than 4,400 families according to the Aliso Canyon Incident Command briefing report issued on February 1, 2016. On January 6, 2016, California Governor Jerry Brown issued a proclamation declaring the Aliso Canyon incident a state emergency. On February 5, 2016, PHMSA issued an advisory bulletin in the
The ANPRM requested comments regarding the addition of requirements for the management of change to provide a greater degree of control over this element of pipeline risk, particularly following changes to physical configuration or operational practices. Operation of a pipeline over an extended period without effective management of change, such as changes to pipeline systems (
1. INGAA and several of its pipeline operator members disagreed with the implication in the ANPRM that change management is not now addressed in regulations. They pointed out that § 192.911(k) and ASME/ANSI B31.8S (incorporated by reference) already address this subject. INGAA reported that its members are committed to clarifying and expanding the use of a formal “management of change” process, and to facilitating its consistent application as a key management system. INGAA expressed its belief that the full adoption of ASME/ANSI B31.8S will facilitate the widespread application of these principles. Dominion East Ohio Gas also noted that part 192 already contains a management of change process. In addition, Chevron noted that management of change programs are generally specific to the organizational, operational, and ownership structures of the company, and part 192 already addresses this subject.
2. A private citizen opined that management of change is necessarily an integral part of quality management systems and another private citizen supported management of change requirements, noting that accidents often result from changes to systems. The Alaska Department of Natural Resources also supported PHMSA's goal of establishing management of change requirements or guidelines.
PHMSA appreciates the information provided by the commenters. PHMSA agrees management of change is currently addressed in § 192.911(k). However, because of its importance, and consistent with INGAA members' commitment to expanding use of formal MOC processes, PHMSA believes it is prudent to provide greater emphasis on MOC directly within the rule text.
Therefore, PHMSA proposes to clarify integrity management requirements for management of change by explicitly including aspects of an effective management of change process into the rule text to emphasize the current requirements. In addition, PHMSA also proposes to add a new subsection 192.13(d) that would apply to onshore gas transmission pipelines, and require that an evaluation must be performed to evaluate and mitigate, as necessary, the risk to the public and environment as an integral part of managing pipeline design, construction, operation, maintenance and integrity, including management of change. The new paragraph would also articulate the general requirements for a management of change process, consistent with Section 192.911(k).
1. AGA, supported by several of its members, and several transmission pipeline operators questioned why this question was in the ANPRM, noting that management of change requirements are already promulgated in § 192.911(k). GPTC added that § 192.909 also addresses this subject.
2. INGAA reported that Section 11 of ASME/ANSI B31.8S is the industry standard in this area, and all of the considerations in this question are included in operators' management of change processes. Several pipeline operators supported this comment.
3. Atmos reported that it is not aware of any standards used by the industry to guide management of change processes. Atmos does not have a formal management of change process, except in its integrity management program, but expressed its conclusion that existing practices within the company contribute to its ability to manage change.
4. Texas Pipeline Association (TPA) reported that its members do not have formal management of change processes but comply with regulations that address proxy requirements (
5. California Public Utilities Commission reported that it is unaware of any pipeline industry standards in this area.
6. An anonymous commenter opined that most operators do not have management of change processes.
7. The NTSB recommended that PHMSA require operators of natural gas transmission and distribution pipelines and hazardous liquid pipelines to ensure that their control room operators immediately notify the relevant 911 emergency call centers of possible ruptures (Recommendation P-11-9).
8. TransCanada reported that it is committed to clarifying and expanding the use of a formal “management of change” process. TransCanada expressed its conclusion that the full adoption of ASME/ANSI B31.8S will facilitate the widespread application of management of change principles.
PHMSA appreciates the information provided by the commenters, which did not identify any standards beyond ASME/ANSI B31.8S, which is already invoked by part 192, and used by the pipeline industry to guide management processes including management of change. See response to the general comments for Topic L, above.
1. INGAA reported that Section 11 of ASME/ANSI B31.8S is based on OSHA's Process Safety Management (PSM) standards. INGAA noted that OSHA worked with industry in developing PSM standards that would identify potential threats and assure that mitigative actions were taken. Several pipeline operators supported INGAA's comments.
2. AGA and GPTC expressed their belief that there is no benefit in comparing standards with other industries, reiterating that §§ 192.909 and 192.911 and ASME/ANSI B31.8S already include management of change. Several pipeline operators supported AGA's comments.
3. The Texas Pipeline Association and the Texas Oil & Gas Association reported that their members are aware of standards used in other industries but do not believe they are appropriate or applicable to the pipeline industry.
4. The Iowa Association of Municipal Utilities expressed its conclusion that OSHA standards are complicated and would be unduly costly for small municipal utilities.
5. Accufacts noted that transportation pipelines are specifically excluded from OSHA regulation; however, this does not prevent PHMSA from incorporating elements of 29 CFR 1910.119 into the
6. Atmos reported that it has no experience with standards used in other industries but noted that OSHA standards appear to be directed toward situations where processes interact such that a change in one process affects a second or third process.
7. Ameren Illinois suggested that standards from other industries would need to be studied to determine if they are applicable to the pipeline industry.
8. An anonymous commenter suggested that the OSHA standards are a good model for pipelines, as they are well written and thought out.
PHMSA appreciates the information provided by the commenters. See response to the general comments for Topic L, above.
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No comments were received in response to this question.
The ANPRM requested comments on whether and how to impose requirements related to quality management systems. Quality management includes the activities and processes that an organization uses to achieve quality. These include formulating policy, setting objectives, planning, quality control, quality assurance, performance monitoring, and quality improvement.
Achieving quality is critical to gas transmission pipeline design, construction, and operations. PHMSA recognizes that pipeline operators strive to achieve quality, but our experience has shown varying degrees of success in accomplishing this objective among pipeline operators. PHMSA believes that an ordered and structured approach to quality management can help pipeline operators achieve a more consistent state of quality and thus improve pipeline safety.
PHMSA's pipeline safety regulations do not currently address process management issues such as quality management systems. Section 192.328 requires a quality assurance plan for the construction of pipelines intended to operate at an alternative MAOP, but there is no similar requirement applicable to other pipelines. Quality assurance is generally considered to be an element of quality management. Important elements of quality management systems are their design and application to control (1) the equipment and materials used in new construction (
The ANPRM then listed questions for consideration and comment. The following are general comments received related to this topic as well as comments related to the specific questions:
1. MidAmerican suggested that PHMSA work with the committees for ASME/ANSI B31.8 and B31.8S to address these topics more fully, if PHMSA believes more is needed. MidAmerican opined that a general rule addressing quality management systems would divert resources and adversely affect safety, if applied to this already heavily-regulated industry.
2. The Alaska Department of Natural Resources supported quality management systems and suggested that pipeline operators should apply such standards to their contractors.
3. A private citizen supported quality management systems, noting that this is an area that would be difficult to regulate but might be an element in incentive programs.
1. INGAA opined that achieving consistent quality materials, construction and management is an appropriate focus for the INGAA Foundation, which has sponsored and will continue to sponsor workshops on this subject. INGAA reported that the Foundation plans to publish five relevant White Papers in 2012 and its Integrity Management—Continuous Improvement team is currently working on guidelines. INGAA also noted that there are elements of a quality management system in ASME/ANSI B31.8S, already incorporated by reference, including quality assurance/quality control, management of change, communication and performance measurement, Standards, specifications, and procedures governing pipe and appurtenances form part of a pipeline quality management system. INGAA cited ISO (9001:2008/29001:2010) and API (Spec Q1) quality management standards as references that are available for operator use. INGAA further noted that API published Spec Q2 in December 2011. Several pipeline operators supported INGAA's comments.
2. AGA, GPTC, Nicor, Atmos, the Texas Pipeline Association, and the Texas Oil & Gas Association suggested that part 192, taken as a whole, is essentially a quality management system. AGA provided a summary listing of part 192 requirements that assure quality. A number of additional pipeline operators supported AGA's comments.
3. Ameren Illinois reported that it has a quality assurance program for pipeline construction that includes building alliances with excavators and other elements.
4. Paiute and Southwest Gas reported that their practices beyond compliance with part 192 requirements include operator qualification (OQ) for construction, an internal quality assurance group, root cause analysis of events, and quality control verification of OQ.
5. MidAmerican reported that it has no formal quality management system but applies standards to assure quality processes. In particular, ASME/ANSI B31.8 and B31.8S and ANSI/ISO/ASQ Q9004-2000 were used to guide its company quality programs. MidAmerican also has a contractor oversight program.
6. An anonymous commenter opined that most operators have a quality management system, often incorporated into their SCADA system, to satisfy customers or end user requirements. The commenter suggested that some of these systems have only recently been modified to address internal corrosion mechanisms, often identified as part of operators' integrity management programs.
1. INGAA, supported by a number of its pipeline operator members, asserted that no new requirements are appropriate at this time. INGAA noted that much work is ongoing in this area and it may be appropriate to adopt some standards (
2. AGA, GPTC, the Texas Pipeline Association, the Texas Oil & Gas Association, Oleksa and Associates, and numerous pipeline operators expressed an opinion that new quality assurance requirements are not needed. These commenters view part 192 as quality assurance requirements and argue that a new programmatic requirement would not be beneficial.
3. TransCanada opined that quality management systems need to be adopted throughout the entire industry and embraced by operators and contractors alike, arguing that this would provide a more consistent level of quality throughout the industry. TransCanada opined that the INGAA Foundation is the appropriate venue in which to develop guidelines.
4. Northern Natural Gas opined that the existing process, which includes PHMSA/State inspections, is adequate.
5. A private citizen commented that quality management systems should be required to improve pipeline safety, including documentation, investigations, validation, audits/inspections, change management, training, and quality/management oversight.
6. An anonymous commenter opined that no new requirements are needed, arguing that most operators have such systems.
1. INGAA reported that most of its members apply quality management principles, including requiring contractors conform to specified requirements, though the approach varies from operator to operator. INGAA acknowledged, however, that “[t]here is room to establish a more structured approach to QMS for operators and construction contractors” to assure more consistency. A number of pipeline operators supported INGAA's comments.
2. AGA reported that transmission operators have the means to assure contractor work quality and that most LDC operators impose operator qualification (OQ) and other specific requirements on their construction contractors.
3. The Texas Pipeline Association and the Texas Oil & Gas Association encouraged PHMSA not to adopt requirements for operators to train construction personnel. The associations expressed concerns over potential liability and their preference for a performance-based standard.
4. Ameren Illinois, Atmos, and MidAmerican reported that they apply operator qualification (OQ) requirements on their contractors.
5. Northern Natural Gas, Paiute, and Southwest Gas reported that they do not require contractors to have formal QMS but do require conformance to various standards.
6. Oleksa and Associates reported its experience that operators require construction contractors to meet the same standards as their employees.
7. GPTC, Nicor, and an anonymous commenter suggested that compliance with construction regulations contribute to QMS through requirements for specifications and inspections.
8. NAPSR, the Texas Pipeline Association, and the Texas Oil & Gas Association suggested that operator qualification (OQ) requirements be applied to construction, since this would apply formal QMS to the full range of construction and operation.
1. INGAA and a number of pipeline operators suggested that several standards could be used as general references, including ISO 9001:2008 (Quality Management Systems), ISO 29001:2010 (Oil and Gas) and API Spec Q1 (Oil and Gas). INGAA opined that compliance with these standards should not be required, and added that additional standards, white papers, and guidance are under development.
2. The AGA, GPTC, Nicor, and Ameren Illinois opposed new requirements in this area. AGA opined that part 192 is already “saturated” with this type of requirement. A number of additional pipeline operators supported AGA's comments.
3. The NTSB recommended improvement to PHMSA's drug and alcohol requirements, citing their recommendations P-11-12 & 13.
4. A private citizen suggested that, by extrapolating from the practices of a pipeline operator with a good safety record. The commenter stated that useful references include the Baldrige Performance Excellence Program and Quality Management Standard ISO 9000.
1. INGAA reported that quality management systems have been demonstrated to reduce risk and opined that the keys to a successful QMS are simplicity, empowerment, accountability and ease of implementation. A number of pipeline operators supported INGAA's comments.
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No comments were received in response to this question.
PHMSA appreciates the information provided by the commenters. PHMSA does not propose additional rulemaking for this topic at this time. PHMSA will review the comments received on the ANPRM and will consider them in future rulemaking.
The ANPRM requested comments regarding proposed changes to part 192 regulations that would eliminate provisions that exempt pipelines from pressure test requirements to establish MAOP. Federal pipeline safety regulations were first established with the initial publication of part 192 on August 19, 1970 (35 FR 13248). Gas transmission pipelines had existed for many years prior to this, some dating to as early as 1920. Many of these older pipelines had operated safely for years at pressures higher than would have been allowed under the new regulations. It was concluded that a required reduction in the operating pressure of these pipelines would not have resulted in a material increase in safety. Therefore, a provision was included in the regulations (§ 192.619(c)) that allowed pipelines to
Many gas transmission pipelines continue to operate in the United States under an MAOP established in accordance with § 192.619(c). Some of these pipelines operate at stress levels higher than 72 percent specified minimum yield strength (SMYS), the highest level generally allowed for more modern gas transmission pipelines. Some pipelines operate at greater than 80 percent SMYS, the alternate MAOP allowed for some pipelines by regulations adopted October 17, 2008 (72 FR 62148). Under these regulations, operators who seek to operate their pipelines at up to 80 percent SMYS (in Class 1 locations) voluntarily accept significant additional requirements applicable to design, construction, and operation of their pipeline that are intended to assure quality and safety at these higher operating stresses. Pipelines that operate under an MAOP established in accordance with § 192.619(c) are subject to none of these additional requirements.
Part 192 also includes several provisions other than establishment of MAOP for which an accommodation was made in the initial part 192. These provisions allowed pipeline operators to use steel pipe that had been manufactured before 1970 and did not meet all requirements applicable to pipe manufactured after part 192 became effective (192.55); valves, fittings and components that did not contain all the markings required (192.63); and pipe which had not been transported under the standard included in the new part 192 (192.65, subject to additional testing requirements).
The ANPRM then listed questions for consideration and comment. The following are general comments received related to this topic as well as comments related to the specific questions:
1. INGAA and a number of pipeline operators opined that age alone is not an appropriate criterion for determining a pipeline's fitness for service. Old pipe that is well maintained operates safely and unfit pipe should be replaced regardless of age. INGAA suggested that fitness for service of pipe in HCAs should be evaluated using available records, if adequate, or through new testing. INGAA attached a white paper to its comments that described its Fitness for Service protocol. INGAA also cautioned that any requirement to reconfirm MAOP should be subject to a rigorous cost-benefit analysis, as hydrostatic testing is very expensive and could require outages of up to several weeks.
2. A private citizen suggested phasing out sub-standard or systems that pre-date regulatory requirements where public safety is concerned, implying that this has been done in other areas (citing elimination of radium dial watches and leaking underground storage tanks as examples).
3. A private citizen suggested that legacy facilities should be subject to a timetable to come into full compliance with current regulations, arguing that this would improve safety and knowledge of older facilities.
PHMSA appreciates the information provided by the commenters. NTSB recommended that regulatory exemptions be repealed. In addition, section 23 of the Act addressed gas transmission pipelines without records sufficient to validate MAOP. In response to these concerns, this NPRM proposes requirements for verification of maximum allowable operating pressure (MAOP) in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Verification of MAOP includes establishing and documenting MAOP if the pipeline MAOP was established in accordance with § 192.619(c), the grandfather clause. In addition, this NPRM proposes requirements for verification of pipeline material in accordance with new § 192.607 for existing onshore, steel, gas transmission pipelines that are located in an HCA or class 3 or class 4 locations.
N.1. Should PHMSA repeal provisions in part 192 that allow use of materials manufactured prior to 1970 and that do not otherwise meet all requirements in part 192?
1. INGAA, supported by several pipeline operators, suggested age, alone, should not be a criterion for determining fitness for service, noting some pre-regulation materials (
2. AGA, GPTC, and numerous pipeline operators noted it is illogical to storehouse pre-1970 materials for installation now. AGA indicated that it thus did not understand the purpose of the ANPRM question.
3. Iowa Utilities Board, NAPSR, Texas Pipeline Association, Texas Oil & Gas Association, Accufacts, Alaska Department of Natural Resources, Atmos, Commissioners of Wyoming County Pennsylvania, Professional Engineers in California Government, and an anonymous commenter encouraged repeal of this allowance. Some of these commenters would allow a specified time period for operators to come into compliance.
4. Thomas Lael and MidAmerican recommended operators be allowed to continue use of materials that have already been placed into service, arguing that they have been demonstrated safe through integrity management.
5. Ameren Illinois and Northern Natural Gas opposed repeal of this provision.
PHMSA appreciates the information provided by the commenters. As stated above, this NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). In addition, this NPRM proposes requirements for verification of pipeline material in accordance with new § 192.607 for existing onshore, steel, gas transmission pipelines that are located in an HCA or class 3 or class 4 locations.
1. INGAA and a number of pipeline operators opposed repeal of this exemption. INGAA suggested its Fitness for Service protocol be used to assure continued safety of old pipe.
2. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas Association and numerous pipeline operators commented that the wording of this question creates a false impression. There is no exemption for MAOP. Rather, the regulations establish requirements for determining MAOP and the only “exemption” is to a post-construction hydrostatic test, since the pipeline was in service at the time the regulations became effective.
3. AGA, supported by several of its pipeline operator members, contended the appropriate method for verifying
4. Accufacts, Texas Pipeline Association, and Texas Oil & Gas Association opposed requiring all pre-1970 pipelines to reduce MAOP, if necessary, to a pressure that would impose stresses no greater than 72 percent SMYS. Accufacts noted this pipe is still safe at its current operating pressure if it is managed properly, but suggested a possible focus on interactive threats that might make seam welds unstable.
5. Ameren Illinois opposed modifying MAOP requirements for pre-1970 pipelines.
6. NAPSR, the NTSB, and Professional Engineers in California Government supported repeal of exemptions applying to MAOP of pre-1970 pipelines. NAPSR added PHMSA should not allow any pipeline to operate at pressures above that which would impose stresses greater than 72 percent SMYS.
7. MidAmerican suggested use of a performance-based approach, which might include a fitness for service determination for pipe in Class 2, 3, or 4 areas or HCA.
8. Commissioners of Wyoming County Pennsylvania would support repeal of MAOP exemptions because pipeline infrastructure is aging and they see additional safety measures needed.
PHMSA appreciates the information provided by the commenters. As stated above, this NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Verification of MAOP includes establishing and documenting MAOP if the pipeline segment: (1) Has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking and the pipeline segment is located in one of the following locations: (i) A high consequence area as defined in § 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
(i) A high consequence area as defined in § 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
1. AGA and a number of pipeline operators opposed any requirement to pressure test all pipelines that have not been tested in accordance with subpart J, arguing Congress considered and rejected this approach in developing the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The commenters argue such a requirement would cripple the pipeline industry and support the alternative requirements included in the Act.
2. MidAmerican suggests a focus on pipe in Class 3 or 4 areas or HCAs. The company suggests no new requirements are needed if records are complete for pipe in these areas or it has been tested to 1.25 times MAOP. Otherwise, MidAmerican would subject such pipelines to a fitness for service determination.
3. The NTSB would require all pre-1970 pipelines to be pressure tested, including a spike test, citing their recommendation P-11-14.
4. Texas Pipeline Association and Texas Oil & Gas Association opposed a requirement to test all pipelines not previously subject to subpart J tests, arguing testing per the construction codes in effect when the pipelines were constructed and safe operating experience since then is adequate assurance of suitability.
5. Ameren Illinois reported the State of Illinois imposed pressure testing requirements before federal pipeline safety regulations were adopted in 1970.
6. Iowa Utilities Board and Iowa Association of Municipal Utilities recommended any new pressure test requirement be limited to pipeline segments in HCA and which operate at pressures where a rupture could occur (generally greater than 30 percent SMYS). These commenters argued the serious impacts of service interruptions pressure testing would be necessary for testing have not been appreciated and the cost for such testing of other pipelines would be unjustified absent any specific demonstration of risk.
7. Commissioners of Wyoming County Pennsylvania and Professional Engineers in California Government (PECG) would require pressure testing for pipelines not previously tested to subpart J requirements, since this would assure public safety. PECG would also require testing if adequate records of prior tests do not exist, noting California has experienced two failures to date of pipeline not adequately tested. PECG would also require all testing, modification, and replacement be observed by a certified inspector loyal to public safety interests.
8. An anonymous commenter would require subpart J testing but would allow schedule flexibility.
PHMSA appreciates the information provided by the commenters. This NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3). Verification of MAOP includes establishing and documenting MAOP using one or more of the methods in 192.624(c)(1) through (c)(6). In addition, this NPRM proposes requirements for verification of pipeline material in new § 192.607 for existing onshore, steel, gas transmission pipelines that are located in an HCA or class 3 or class 4 locations.
1. AGA and several pipeline operators opposed requiring hydrostatic tests for systemic issues, arguing it could potentially affect all pipelines. AGA noted Congress had considered and rejected this approach in developing the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. AGA supports the requirements in Section 23 of the Act. AGA further argued hold times in subpart J are excessive since defects that fail will likely do so in the first 30 minutes and urged PHMSA not to require any special testing for pipelines operating at less than 30 percent SMYS since they are likely to fail by leakage rather than rupture.
2. GPTC and Nicor opposed a blanket requirement for hydrostatic testing. They would test only in event of a demonstrated safety issue and only if a risk evaluation indicates testing is appropriate. For distribution operators, these commenters would treat any safety issues in distribution integrity management programs.
3. Atmos would not require pressure testing for systemic issues, arguing these are addressed adequately by subpart O.
4. Accufacts would require testing, focusing first on pipe in HCAs, at pressures greater than 1.1 times MAOP. Accufacts understands some operators are arguing for a 1.1 x MAOP test pressure and considers that to be insufficient.
5. MidAmerican would allow a risk-based alternative approach for problem pipe.
6. Texas Pipeline Association and Texas Oil & Gas Association would require assessments appropriate to a specific threat rather than a blanket requirement for pressure testing.
7. An anonymous commenter supported pressure testing for pipe subject to systemic issues.
PHMSA appreciates the information provided by the commenters. This NPRM proposes requirements for verification of MAOP in new § 192.624 for onshore, steel, gas transmission pipelines that are located in an HCA or MCA and meet any of the conditions in § 192.624(a)(1) through (a)(3).
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No comments were received in response to this question.
The ANPRM requested comments regarding modifying the regulations relative to gas gathering lines. In March 2006, PHMSA issued new safety requirements for “regulated onshore gathering lines.”
The 2006 rule defined onshore gas gathering lines based on the provisions in American Petroleum Institute Recommended Practice 80, “Guidelines for the Definition of Onshore Gas Gathering Lines,” (API RP 80), a consensus industry standard incorporated by reference. Additional regulatory requirements for determining the beginning and endpoints of gathering, modifying the application of API RP 80, were also imposed to improve clarity and consistency in their application.
In practice, however, the use of API RP 80, even as modified by the additional regulations, is difficult for operators to apply consistently to complex gathering system configurations. Enforcement of the current requirements has been hampered by the conflicting and ambiguous language of API RP 80, a complex standard that can produce multiple classifications for the same pipeline system, which can lead to the potential misapplication of the incidental gathering line designation under that standard. In addition, recent developments in the field of gas exploration and production, such as shale gas, indicate that the existing framework for regulating gas gathering lines may need to be expanded. Gathering lines are being constructed to transport “shale” gas that range from 4 to 36 inches in diameter with MAOPs up to 1480 psig, far exceeding the historical operating parameters (pressure and diameter). The risks considered during the development of the 2006 rule did not foresee gathering lines of these diameters and pressures.
Currently, according to 2011 annual reports submitted by pipeline operators, PHMSA only regulates about 8845 miles of Type A gathering lines, 5178 miles of Type B gathering lines, and about 6258 miles of offshore gathering lines, for a total of approximately 20,281 miles of regulated gas gathering pipelines. Gas gathering lines are currently not regulated if they are in Class 1 locations. Current estimates also indicate that there are approximately 132,500 miles of Type A gas gathering lines located in Class 1 areas (of which approximately 61,000 miles are estimated to be 8-inch diameter or greater), and approximately 106,000 miles of Type B gas gathering lines located in Class 1 areas. Also, there are approximately 2,300 miles of Type B gas gathering lines located in Class 2 areas, some of which may not be regulated in accordance with § 192.8(b)(2).
The ANPRM then listed questions for consideration and comment. The following are general comments received related to this topic as well as comments related to the specific questions:
1. Gas Processors Association (GPA) recommended PHMSA complete the study required by Section 21 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 before proposing any substantive regulations regarding gathering lines. The Association sees this as an essential pre-requisite and indicated it would establish a working group to work with PHMSA on the study. Following the study, GPA would then have PHMSA begin any rulemaking process with another ANPRM, focused on the issues to be addressed in changing regulation of gathering lines. Independent Petroleum Association of America, American Petroleum Institute, Oklahoma Independent Petroleum Association, and Chevron agreed any change to gathering line regulations before the required report to Congress would be inconsistent with the Act.
2. Independent Petroleum Association of America, American Petroleum Institute, Oklahoma Independent Petroleum Association, and Chevron argued no change in the gathering line regulatory regime is justified. IPAA and API argued gathering lines can be regulated based only on actual, vs.
3. Atmos would require new gathering lines operating above 20 percent SMYS to meet requirements in § 192.9(c), and those below 20 percent SMYS § 192.9(d). These paragraphs are, respectively, requirements applicable to Type A and Type B gathering lines. The “type” of a gathering line is established in accordance with requirements in § 192.8, and is based on the pipe material and MAOP of the line. Atmos argued, however, that class location changes over time and determining applicable requirements for new gathering lines based on stress levels would provide for public safety without the problems or confusion that could result from subsequent class location changes.
4. Texas Pipeline Association and Texas Oil & Gas Association suggested PHMSA treat gathering lines under a separate docket and collect data under the current regulatory regime before making any changes. The associations suggested a delay in rulemaking of 3 to 5 years to accumulate data from recently-promulgated changes in reporting requirements. The associations argued changes made without gathering and reviewing that data could be found unnecessary and would divert resources from higher risk needs. Atmos agreed any rulemaking concerning gathering lines should be conducted under a separate docket due to the complexity of the issues involved.
5. Dominion East Ohio Gas argued it is too soon for wholesale changes to the new federal regulations applicable to gas gathering lines. The company suggested one proposed change would be to consider “Incidental Gathering” as defined in API RP 80.
6. NAPSR and Commissioners of Wyoming County Pennsylvania suggested PHMSA assert regulatory authority beginning at the wellhead or first metering point. They argued the regulatory gap that results from excluding production facilities from regulation produces risks, especially in areas where high-pressure wells are being drilled in urban areas. NAPSR further stated that PHMSA should consider short sections of pipeline downstream of processing, compression, and similar equipment to be a continuation of gathering. The functional name of a segment of pipeline is not important,
7. Commissioners of Wyoming County Pennsylvania recommended PHMSA regulate gathering lines in Class 1 areas. The Commissioners noted many new gathering lines, some operating at high pressures, are being constructed in Class 1 areas of the Marcellus Shale Region, and regulation of these lines is necessary to ensure public safety. The Commissioners noted Pennsylvania law gives the state's public utilities commission authority to regulate pipelines but requires that they be no more stringent than federal regulations.
8. The League of Women Voters of Pennsylvania would regulate gathering lines in the same manner as transmission and would further require that gas in pipelines of both types be odorized.
9. Pipeline Safety Trust would have PHMSA assure gathering lines are displayed on the National Pipeline Mapping System.
PHMSA appreciates the information provided by the commenters. The commenters are correct that the Act required several actions related to gas gathering lines including a requirement that a study to be conducted prior to issuing new rules. We would note, however, that PHMSA is only proceeding with the issuance of an NPRM proposing expanded requirements and needed clarity with regard to issues that had been identified prior to enactment of the Act. The study has been completed and submitted to Congress and placed on the docket. PHMSA invites public comment on the study, which will inform the final rule. In addition, recent developments in the field of gas exploration and production, such as shale gas, indicate that the existing framework for regulating gas gathering lines may need to be expanded. Gathering lines are being constructed to transport “shale” gas that range from 4 to 36 inches in diameter with MAOPs up to 1,480 psig, far exceeding the historical operating parameters of such lines.
Currently, according to 2011 annual reports submitted by pipeline operators, PHMSA only regulates about 8845 miles of Type A gathering lines, 5,178 miles of Type B gathering lines, and about 6,258 miles of offshore gathering lines, for a total of approximately 20,281 miles of regulated gas gathering pipelines. Gas gathering lines are currently not regulated if they are in Class 1 locations. Current estimates also indicate that there are approximately 132,500 miles of Type A gas gathering lines located in Class 1 areas, and approximately 106,000 miles of Type B gas gathering lines located in Class 1 areas. Also, there are approximately 2,300 miles of Type B gas gathering lines located in Class 2 areas, some of which may not be regulated in accordance with § 192.8(b)(2).
Moreover, enforcement of the current requirements has been hampered by the conflicting and ambiguous language of API RP 80, a complex standard that can produce multiple classifications for the same pipeline system because numerous factors are involved, including the locations of treatment facilities, processing plants, and compressors, the relative spacing of production fields, and the commingling of gas. This can lead to the potential misapplication of the incidental gathering line designation under that standard.
In this NPRM, PHMSA proposes to extend existing requirements for Type B gathering lines to Type A gathering lines in Class 1 locations, if the nominal diameter is 8” or greater.
1. AGA, GPTC, Texas Pipeline Association, Texas Oil & Gas Association, and several pipeline operators opposed requiring annual reports for unregulated gas gathering pipelines, arguing such a requirement would be unduly burdensome with no safety benefit. These commenters agreed incident reports for unregulated gathering lines could be useful as a means to determine the effectiveness of safety practices on these pipelines.
2. Gas Producers Association opposed expanding reporting requirements to Class 1 gathering pipelines. The Association noted gathering lines in other class locations are currently subject to reporting requirements and suggested there were other means for PHMSA to collect data on Class 1 lines without requiring burdensome reporting. In the specific case of safety-related condition reports, the Association argued requiring reporting is clearly premature, because the purpose of these reports is to highlight problems in which PHMSA may elect to become involved and PHMSA presently does not regulate these pipelines.
3. Texas Pipeline Association and Texas Oil & Gas Association would support requiring incidents to be reported for all gathering pipelines as a first step in collecting data to determine whether other changes are needed.
4. Atmos would support limited reporting for Class 1 gathering lines, to include incidents and total mileage.
5. NAPSR, Alaska Department of Natural Resources, Pipeline Safety Trust, and Commissioners of Wyoming County Pennsylvania would require operators of Class 1 gathering pipelines to submit reports, because these pipelines can affect public safety and should be held accountable.
PHMSA appreciates the information provided by the commenters. The comments provide varied support for requiring submission of annual, incident, and safety-related conditions reports by the operators of all gathering lines. PHMSA believes these reports would provide valuable information, combined with the results of the congressionally required study, to support evaluation of the effectiveness of safety practices on these pipelines and determination of any needed additional requirements beyond those proposed in this NPRM. Accordingly, PHMSA proposes to delete the exemption for reporting requirements for operators of unregulated onshore gas gathering lines.
1. AGA and several pipeline operators opposed a change to the definition of gathering lines, noting API RP-80, with restrictions as specified in current regulations, is a good working definition.
2. Independent Petroleum Association of America, American Petroleum Institute, Oklahoma Independent Petroleum Association, Atmos, and Chevron argued that API RP 80, as currently specified, is the appropriate means for defining gathering lines. They argued it is based on a pipeline's function rather than its location and changes could infringe on production facilities, regulation of which is precluded by statute.
3. Gas Processors Association opposed changing the definition of gathering line or extending regulation to lines in Class 1 areas. The Association noted excluding Class 1 lines from regulation is risk-based and expressed its interest in continuing the risk-based approach to regulation represented by the 2006 rule.
4. NAPSR, GPTC, Accufacts, Thomas Lael, and Nicor supported simplifying the definition of gathering lines. These commenters noted that API RP-80 is confusing. One commenter referred to its application as a “nightmare.” The definition in Texas regulations was suggested as one possible model.
5. Oklahoma Independent Petroleum Association strongly opposed changes to the definitions of gathering line or production facilities.
6. Texas Pipeline Association and Texas Oil & Gas Association would not change the definition of gathering lines at this time, arguing data gathering, a necessary first step, is not yet complete.
7. The State of Washington Citizens Advisory Committee and a private citizen urged changes to the definitions of gathering, transmission, and distribution pipelines, arguing that the current definitions are confusing and employ circular logic.
8. Pipeline Safety Trust would revise the definition of gathering in a manner that does not allow operators to choose whether their pipeline is gathering or not on the basis of where they decide to install equipment. PST noted there is significant overlap among pipeline types in size, operating pressure, and attendant risks.
9. Alaska Department of Natural Resources and Commissioners of Wyoming County Pennsylvania urged a revision to the definition of gathering lines, in light of shale gas development which, the commenters contended, produces risks approximately equivalent to those from transmission pipelines.
PHMSA appreciates the information provided by the commenters. Industry commenters opposed a change to the definition of gathering lines, whereas NAPSR and other commenters supported revision of the definition of gathering lines and classified API RP-80 as confusing. As discussed above, PHMSA believes revision of the definition of gathering lines is needed and also proposes a new definition for onshore production facility/operation. In addition, see response to question O.3 comments.
1. Independent Petroleum Association of America, American Petroleum Institute, Oklahoma Independent Petroleum Association, and Chevron were emphatic in declaring there are no difficulties in applying API RP-80. IPAA and API noted that significant difficulties among gathering lines made RP-80 difficult to develop.
2. AGA and a number of pipeline operators reported RP-80 is clear and there are no difficulties with its application.
3. Gas Processors Association would retain the RP-80 definition, at least until the study required by the Act is completed. GPA acknowledged that application of RP-80 has been difficult, but stated that it has been difficult to craft a simpler definition.
4. Texas Pipeline Association and Texas Oil & Gas Association reported application of RP-80 has been challenging. The associations opined this has resulted from complexities in gathering pipeline systems and confusion caused by PHMSA guidance and interpretations.
5. Accufacts, NAPSR, GPTC, and Nicor commented RP-80 is too complex, not understandable to the public, and subject to misuse by operators.
PHMSA appreciates the information provided by the commenters. Industry commenters stated there are no difficulties in applying the definitions contained in API RP 80, whereas Accufacts, NAPSR and other commenters contend that API RP 80 is too complex, not understandable, and subject to misuse. PHMSA enforcement of the current requirements has been hampered by the conflicting and ambiguous language of API RP 80, which is complex and can produce multiple classifications for the same pipeline system. In the 2006 rulemaking which incorporated by reference the API RP 80, PHMSA expressed reservations concerning the ability to effectively and consistently apply the document as written, echoing NAPSR's comments at the time. Additionally, in 2006, PHMSA imposed limiting regulatory language in part 192 in an attempt to curtail the potential for misapplication of the language contained in RP-80. These limitations and their intended application were discussed in great detail in the Supplemental Notice of Proposed Rulemaking [Docket No. RSPA-1998-4868; Notice 5]. Because of the ambiguous language and terminology in the RP-80,
1. Commissioners of Wyoming County Pennsylvania and 24 private citizens encouraged PHMSA to regulate gathering lines in Class 1 locations. The commenters noted many such pipelines will exist in shale gas areas, many of them large-diameter and operating at high pressures, and contended these pipelines currently are being ignored by federal and state regulators. They noted the pipeline that ruptured causing the San Bruno accident was operated at a pressure considerably lower than some gathering lines in shale gas areas.
2. AGA, GPTC, and a number of pipeline operators argued no new requirements are needed and the effectiveness of the 2006 changes to regulation needs to be reviewed first, in accordance with the Act.
3. Gas Processors Association, Texas Pipeline Association, and Texas Oil & Gas Association contended PHMSA must gather additional data on Class 1 gathering lines before deciding whether to regulate them, arguing that only a detailed study can determine whether new regulations are appropriate.
4. Oklahoma Independent Petroleum Association cautioned any regulatory change needs to be supported by science and a comprehensive cost-benefit analysis.
5. Independent Petroleum Association of America, American Petroleum Institute, Oklahoma Independent Petroleum Association, and Chevron argued any change in the regulatory regime for gathering lines is unjustified. The commenters contended such lines only operate at high pressures when new, that pressure decreases as wells deplete, and that the record shows these lines are safe.
6. A private citizen who operates an outdoor gear supply business in a shale gas region argued reduced use of recreational areas, caused by concerns over nearby pipelines, will adversely impact his and similar businesses.
7. Alaska Department of Natural Resources would establish risk-based safety requirements for gathering pipelines.
8. NAPSR would establish new, prescriptive requirements for large-diameter, high-pressure gathering lines.
9. Pipeline Safety Trust argued the composition of gas carried in many gathering lines leads to increased risk of corrosion and additional corrosion and testing requirements should thus be considered.
10. A private citizen, arguing for regulation of Class 1 gathering lines, noted experience has shown Class 1 locations change to Class 2 or 3 locations while the pipeline remains unchanged and, the commenter contended, unsafe.
11. Pipeline Safety Trust, Accufacts, and NAPSR would regulate gathering lines the same as transmission pipelines. PST would include integrity management requirements for lines operating at greater than 20 percent SMYS. NAPSR would impose IM if greater than 30 percent SMYS.
12. ITT Exelis Geospatial Systems contended that safety criteria applicable to a pipeline should be based on the specifications of the line.
PHMSA appreciates the information provided by the commenters. The comments provide varied opinions for establishing new, risk-based safety requirements for gas gathering lines in rural locations. Several comments recommended PHMSA gather additional data on gathering lines before deciding to issue revised regulations. PHMSA believes rulemaking should proceed now to address the identified issues with regulation of gathering lines. Therefore, PHMSA proposes to extend existing requirements for Type B gathering lines to Type A gathering lines in Class 1 locations, if the nominal diameter is 8″ or greater. Integrity management requirements would not be applied to gathering lines at this time.
1. The AGA, the GPTC, and a number of pipeline operators suggested that the piping mentioned in O.5 be considered as gathering. The commenters contended that this is clearly “incidental gathering” in API RP-80, particularly if below 20 percent SMYS, and that some agencies are presently treating this pipeline inappropriately as transmission pipeline.
2. Oleksa and Associates contended that the types of pipeline described in the question are “incidental gathering.” Oleksa argued that the length of these pipeline sections should not be the determining factor in their definition but, rather, risk elements and public safety impact should be afforded more importance.
3. The Gas Processors Association, the Texas Pipeline Association, and the Texas Oil & Gas Association would continue to treat these types of pipelines as gathering. They argued that this reflects the practical realities in the field regarding the ability to locate gathering-related equipment. GPA urged PHMSA to retain the concept of incidental gathering in any future change to the regulations, arguing this would continue a consistent regulatory approach to gathering pipelines.
4. The Independent Petroleum Association of America, the American Petroleum Institute, the Oklahoma Independent Petroleum Association, and Chevron contended that the safety record in the Barnett Shale area demonstrates further regulation of downstream pipelines and compression is not needed.
5. Commissioners of Wyoming County Pennsylvania would treat gathering lines as transmission lines, arguing that this would preclude the need to answer any of these questions.
6. The Delaware Solid Waste Authority (DSWA) argued for the continued treatment of the listed pipeline sections as part of gathering for landfill gas operations. DSWA noted that landfills may use intermediate compression to improve collection efficiency and may have pipe at pressure leading to flares etc.
7. Waste Management contended that piping that is an active part of a landfill gas collection and control system should be exempt from regulation as this piping is generally on landfill property and poses no risk to the public.
8. The National Solid Waste Management Association and Waste Management supported PHMSA's interpretation that pipelines operating at vacuum, such as landfill systems up to the compressor/blower should be unregulated.
PHMSA appreciates the information provided by the commenters. See PHMSA's response to Question O.3, above.
1. The AGA, the GPTC, and a number of pipeline operators contended that RP-80 makes clear that these pipelines are production piping and therefore regulation is prohibited. In addition, they argued that risk doesn't justify regulating these lines; the situation is similar to production and is already managed well. They also noted that landfill systems are generally constructed with non-corrosive materials. The commenters agreed that piping from landfills to transmission or distribution pipelines is gathering and should be regulated.
2. Oleksa and Associates contended that landfill pipelines are distribution pipelines, if they carry gas to end use customers.
3. The APGA argued that new requirements are appropriate, as landfill gas is different from natural gas. The APGA contended that application of current regulations often produces absurd results. APGA would add new requirements applicable to systems with high concentrations of hydrogen sulfide and allow systems with low concentrations to use current requirements.
4. The Delaware Solid Waste Authority argued that no new requirements are needed, because these systems operate at low pressures and existing requirements are sufficient.
5. NAPSR encouraged that PHMSA establish jurisdiction over and requirements for landfill gas systems, arguing that many operate as distribution pipelines. NAPSR also recommended that PHMSA develop requirements for odorizing landfill gas, since normal methods cannot be used.
6. The National Solid Waste Management Association and Waste Management argued that landfill gas lines under the control of a landfill operator or gas developer should remain unregulated because they pose minimal risk. They also contended that lines delivering landfill gas to distant users should also remain unregulated because they are mostly buried, are generally constructed of plastic pipe, and pose low risk due to low pressure, their dedicated nature, and lack of interconnects.
7. The National Solid Waste Management Association (NSWMA) noted that these pipelines are already regulated by the EPA and the states and argued that additional regulation would confer limited additional benefits. NSWMA argued that no requirements are needed to address internal corrosion, because these pipeline systems are generally constructed of plastic pipe and corrosive gas constituents are limited to prevent destruction of gas processing equipment. NSWMA suggested that PHMSA work with the EPA to obtain data on the landfill experience needed to support any future decision to regulate in this area.
8. Oleksa and Associates and the Delaware Solid Waste Authority would have PHMSA modify the regulations to clarify that pipe downstream of intermediate compression is unregulated, even if at pressure. They argued that the EPA has regulated such pipelines successfully and there is no safety case for applying part 192. DSWA further notes that most landfill pipeline is constructed of plastic pipe and not subject to internal corrosion.
9. Oleksa and Associates, the GPTC, Nicor, Waste Management, and the Delaware Solid Waste Authority would exempt landfill gas systems from requirements for odorization and odor sampling. They argued that there is a strong odor inherent to landfill gas, the sampling of which is not practical.
PHMSA appreciates the information provided by the commenters. PHMSA is not proposing rulemaking to address landfill gas systems at this time, but would note that a pipeline that transports landfill gas away from the landfill facility to another destination is transporting gas. PHMSA will consider comments on this aspect of Topic O in the future.
1. AGA, GPTC, and a number of pipeline operators commented that new requirements are not needed. They argued existing part 192 requirements are adequate for internal corrosion protection and unregulated gathering lines are rural and pose little risk.
2. AGA and a number of pipeline operators opposed a requirement for periodic cleaning of gathering lines. They noted existing lines are not configured to accommodate cleaning pigs and retrofitting them would be a major cost with no safety benefit.
3. Gas Producers Association noted internal corrosion is only one of many threats, existing regulations are adequate, and thus no new requirements are needed.
4. Texas Pipeline Association and Texas Oil & Gas Association opposed establishing internal corrosion requirements for gathering pipelines. The associations noted risk from IC is not prevalent for many gathering pipelines and suggested the need to collect data (
5. Accufacts would require, as a minimum, use of cleaning pigs and analysis of removed materials.
6. NAPSR, Alaska Department of Natural Resources, and Commissioners of Wyoming County Pennsylvania would enhance internal corrosion requirements and require periodic cleaning.
PHMSA appreciates the information provided by the commenters. The majority of comments do not support enhancement of requirements for internal corrosion control for gathering pipelines. PHMSA is not proposing rulemaking specifically to address the need for additional internal corrosion requirements for gathering lines at this time. However, the proposed requirements in subpart I applicable to transmission lines; except the requirements in §§ 192.461(f), 192.465(f), 192.473(c) and 192.478, would be applicable to regulated Type A onshore gathering lines.
1. The AGA and several pipeline operators suggested that PHMSA consider applying some IM requirements to Type A gathering lines, since these lines represent conditions and risks similar to transmission pipelines. They consider IM inappropriate for Type B gathering lines, since these lines pose low risk and operate at hoop stresses similar to distribution pipelines.
2. The Gas Producers Association, the Texas Pipeline Association, the Texas Oil & Gas Association, and Atmos argued that it would be inappropriate to apply integrity management requirements to gathering pipelines. They noted that IM is a risk-based approach and that there is no evidence that gathering pipelines pose a risk that justifies application of IM.
3. The GPTC and Nicor opined that extending some aspects of gas transmission IM to non-rural, metallic
4. The Commissioners of Wyoming County Pennsylvania would apply IM to all onshore gathering pipelines. They would also apply requirements applicable to Class 2 transmission pipelines to Class 1 gathering pipelines, arguing that Class 1 areas will grow and class location will change.
5. Accufacts and the Alaska Department of Natural Resources would apply IM to gathering lines. Accufacts suggested an initial focus on large-diameter, high-pressure lines, since these lines are subject to failure by rupture.
PHMSA appreciates the information provided by the commenters. PHMSA does not propose rulemaking to apply integrity management requirements to gathering lines at this time.
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No comments were received in response to this question.
Pipeline regulation prescribes requirements for the surveillance and periodic patrolling of the pipeline to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation, including unusual operating and maintenance conditions. The probable cause of the 2011 hazardous liquid pipeline accident resulting in a crude oil spill into the Yellowstone River near Laurel, Montana, is scouring at a river crossing due to flooding. This is a recent example of extreme weather that resulted in a pipeline incident. PHMSA has determined that additional regulations are needed to require, and establish standards for, the inspection of the pipeline and right-of-way for “other factors affecting safety and operation” following an extreme weather event such as a hurricane or flood, landslide, an earthquake, a natural disaster, or other similar event. The proposed rule would add a new paragraph (c) to section 192.613 to require such inspections, specify the timeframe in which such inspections should commence, and specify the appropriate remedial actions that must be taken to ensure safe pipeline operations. The new paragraph (c) would apply to onshore pipelines and their rights-of-way.
Section 5 of the Act identifies a technical correction amending Section 60109(c)(3)(B) of Title 49 of the United States Code to allow the Secretary of Transportation to extend the 7-year reassessment interval for an additional 6 months if the operator submits written notice to the Secretary justifying the need for the extension. PHMSA proposes to codify this statutory requirement.
Section 23 of the Act requires operators to report each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. PHMSA proposes to codify this statutory requirement.
Section 29 of the Act states that in identifying and evaluating all potential threats to each pipeline segment, an operator of a pipeline facility must consider the seismicity of the area. PHMSA proposes to codify this statutory requirement to explicitly reference seismicity for data gathering and integration, threat identification, and implementation of preventive and mitigative measures.
PHMSA is proposing to add explicit requirements for safety features on launchers and receivers associated with ILI, scraper and sphere facilities.
PHMSA is proposing to incorporate by reference consensus standards for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment.
Section 191.1 prescribes requirements for the reporting of incidents, safety-related conditions, and annual pipeline summary data by operators of gas pipeline facilities. Currently, onshore gas gathering pipelines are exempt from reporting, as specified in paragraph (b)(4) of this section. In March 2012, the Government Accountability Office (GAO) issued a report (GAO-12-388) that contained a recommendation for DOT to collect data on federally unregulated hazardous liquid and gas gathering pipelines. PHMSA has determined that the statute requires the collection of additional information about gathering lines and that these reports and the congressionally required study support evaluation of the effectiveness of safety practices on these pipelines. Furthermore, PHMSA has inquired into whether any additional requirements are needed beyond those proposed in this NPRM. Accordingly, the proposed rule would repeal the exemption for reporting requirements for operators of unregulated onshore gas gathering lines by deleting § 191.1(b)(4), adding a new § 191.1(c), and making other conforming editorial amendments. In addition, Section 23 of the Act requires PHMSA to promulgate rules that require operators to report each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. The proposed rule would amend 191.1 to include MAOP exceedances within the scope of part 191.
Section 23 of the Act requires operators to report each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. On December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which advised operators of their responsibility under Section 23 of the Act to report such exceedances. PHMSA proposes to revise § 191.23 to codify this requirement.
Section 23 of the Act requires operators to report each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the
Section 192.3 provides definitions for various terms used throughout part 192. In support of other regulations proposed in this NPRM, PHMSA is proposing to amend the definitions of “
The revised definition for “
The revised definition for “
With regard to the new terms “
With regard to the new terms “
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that an important aspect of compliance with this requirement is to assure that pipeline class location records are complete and accurate. The proposed rule would add a new paragraph § 192.5(d) to require each operator of transmission pipelines to make and retain for the life of the pipeline records documenting class locations and demonstrating how an operator determined class locations in accordance with this section.
Section 192.7 lists documents that are incorporated by reference in part 192. PHMSA proposes conforming amendments to § 192.7 in the rule text to reflect other changes proposed in this NPRM.
Section 192.8 defines the upstream and downstream endpoints of gas gathering pipelines. Recent developments in the field of gas exploration and production, such as shale gas, indicate that the existing framework for regulating gas gathering lines may no longer be appropriate. Gathering lines are being constructed to transport “shale” gas that range from 4 to 36 inches in diameter with MAOPs of up to 1480 psig, far exceeding the historical operating parameters of such lines.
Currently, according to the 2011 annual reports submitted by pipeline operators, PHMSA only regulates about 8,845 miles of Type A gathering lines, 5,178 miles of Type B gathering lines, and about 6,258 miles of offshore gathering lines, for a total of approximately 20,281 miles of regulated gas gathering pipelines. Gas gathering lines are currently not regulated if they are in Class 1 locations. Current estimates also indicate that there are approximately 132,500 miles of Type A gas gathering lines located in Class 1 areas (of which approximately 61,000 miles are estimated to be 8-inch diameter or greater), and approximately 106,000 miles of Type B gas gathering lines located in Class 1 areas. Also, there are approximately 2,300 miles of Type B gas gathering lines located in Class 2 areas, some of which may not be regulated in accordance with § 192.8(b)(2).
Moreover, enforcement of the current requirements has been hampered by the conflicting and ambiguous language of API RP 80, a complex standard that can produce multiple classifications for the same pipeline system. PHMSA has also identified a regulatory gap that permits the potential misapplication of the incidental gathering line designation under that standard. Consequently, to address these issues and gaps, the proposed rule would repeal the use of API RP 80 as the basis for determining regulated gathering lines and would establish a new definition for onshore production facility/operation and a
Section 192.9 identifies those portions of part 192 that apply to regulated gas gathering lines. For the same reasons discussed under § 192.8, above, the proposed rule would expand and clarify the requirements that apply to gathering lines. PHMSA proposes to extend existing regulatory requirements for Type B gathering lines to Type A gathering lines in Class 1 locations, if the nominal diameter of the line is 8″ or greater.
In addition, on August 20, 2014, the GAO released a report (GAO Report 14-667) to address the increased risk posed by new gathering pipeline construction in shale development areas. GAO recommended that a rulemaking be pursued for gathering pipeline safety that addresses the risks of larger-diameter, higher-pressure gathering pipelines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. Currently, Type A gathering lines are subject to the emergency planning requirements in § 192.615 and only include gathering lines in Class 2, 3, and 4 locations that have a Maximum Allowable Operating Pressure (MAOP) with a hoop stress of 20% or more for metallic pipe and MAOP of more than 125 psig for non-metallic pipe. Further, gathering lines that are located in Class 1 areas (
Section 192.13 prescribes general requirements for gas pipelines. PHMSA has determined that safety and environmental protection would be improved by generally requiring operators to evaluate and mitigate risks during all phases of the useful life of a pipeline as an integral part of managing pipeline design, construction, operation, maintenance and integrity, including management of change. This proposed rule would add a new paragraph (d) to establish a general clause requiring onshore gas transmission pipeline operators to evaluate and mitigate risks to the public and environment as part of managing pipeline design, construction, operation, maintenance, and integrity, including management of change. The new paragraph would also invoke the requirements for management of change as outlined in ASME/ANSI B31.8S, section 11, and explicitly articulate the requirements for a management of change process that are applicable to onshore gas transmission pipelines.
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that an important aspect of compliance with this requirement is to assure that records that demonstrate compliance with part 192 are complete and accurate. The proposed rule would add a new paragraph (e) that clearly articulates the requirements for records preparation and retention and requires that records be reliable, traceable, verifiable, and complete. Further, the proposed Appendix A would provide specific requirements for records retention for transmission pipelines.
In addition, conforming amendments to paragraphs (a) and (b) list the effective date of the proposed requirements for newly regulated onshore gathering lines.
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline material records are complete and accurate. The proposed rule would add a new § 192.67 to require each operator of transmission pipelines to make and retain for the life of the pipeline the original steel pipe manufacturing records that document tests, inspections, and attributes required by the manufacturing specification in effect at the time the pipe was manufactured.
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipe design records are complete and accurate. The proposed rule would add a new § 192.127 to require each operator of transmission pipelines to make and retain for the life of the pipeline records documenting pipe design to withstand anticipated external pressures and determination of design pressure for steel pipe.
The current pipeline safety regulations in 49 CFR 192.150 require that pipelines be designed and constructed to accommodate in-line inspection devices. Part 192 is silent on technical standards or guidelines for implementing requirements to assure pipelines are designed and constructed for ILI assessments. At the time these rules were promulgated, there was no consensus industry standard that addressed design and construction requirements for ILI. NACE Standard Practice, NACE SP0102-2010, “In-line Inspection of Pipelines,” has since been published and provides guidance in this area in Section 7. The incorporation of this standard into § 192.150 will promote a higher level of safety by establishing consistent standards for the design and construction of line pipe to accommodate ILI devices.
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline component records are complete and
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline welding records are complete and accurate. The proposed rule would add a new paragraph § 192.227(c) to require each operator of transmission pipelines to make and retain for the life of the pipeline records demonstrating each individual welder qualification in accordance with this section.
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of certain pipelines and to confirm the established MAOP of the pipelines. PHMSA has determined that compliance requires that pipeline qualification records are complete and accurate. The proposed rule would add a new paragraph § 192.285(e) to require each operator of transmission pipelines to make and retain for the life of the pipeline records demonstrating plastic pipe joining qualifications in accordance with this section.
Section 192.319 prescribes requirements for installing pipe in a ditch, including requirements to protect pipe coating from damage during the process. However, during handling, lowering, and backfilling, sometimes pipe coating is damaged, which can compromise its ability to protect against external corrosion. An example of the consequences of such damage occurred in 2011 on the Bison Pipeline, operated by TransCanada Northern Border Pipeline, Inc. In this case, the probable cause of the incident was attributed to latent coating and mechanical damage caused during construction, which subsequently caused the pipeline to fail. To help prevent recurrence of such incidents, PHMSA has determined that additional requirements are needed to verify that pipeline coating systems for protection against external corrosion are not damaged during the installation and backfill process. Accordingly, this proposed rule would add a new paragraph (d) to require that onshore gas transmission operators perform an above-ground indirect assessment to identify locations of suspected damage promptly after backfill is completed and remediate any moderate or severe coating damage. Mechanical damage is also detectable by these indirect assessment methods, since the forces that are able to mechanically damage steel pipe usually result in detectable coating defects. Paragraph (d) does not apply to gas gathering lines or distribution mains. In addition, paragraph (d) would require each operator of transmission pipelines to make and retain for the life of the pipeline records documenting the coating assessment findings and repairs.
Section 192.452 prescribes corrosion control requirements for regulated onshore gathering lines. PHMSA proposes conforming amendments to the rule text in paragraph (b) to reflect other changes proposed in this NPRM for gas gathering lines.
Section 192.461 prescribes requirements for protective coating systems. However, certain types of coating systems that have been used extensively in the pipeline industry can impede the process of cathodic protection if the coating disbonds from the pipe. The NTSB determined that this was a significant contributing factor in the major crude oil spill that occurred near Marshall, Michigan, in 2010. PHMSA has determined that additional requirements are needed to specify that coating should not impede cathodic protection and to ensure operators verify that pipeline coating systems for protection against external corrosion have not become compromised or damaged during the installation and backfill process. Accordingly, this proposed rule would amend paragraph (a)(4) to require that coating have sufficient strength to resist damage during installation and backfill, and add a new paragraph (f) to require that onshore gas transmission operators perform an above-ground indirect assessment to identify locations of suspected damage promptly after backfill is completed or anytime there is an indication that the coating might be compromised. It would also require prompt remediation of any moderate or severe coating damage.
Section 192.465 currently prescribes that operators monitor cathodic protection and take prompt remedial action to correct deficiencies indicated by the monitoring. The provisions in § 192.465 do not specify the remedial actions required to correct deficiencies and do not define “prompt.” To address this potential issue, the proposed rule would amend paragraph (d) to require that remedial action must be completed promptly, but no later than the next monitoring interval specified in § 192.465 or within one year, whichever is less. In addition, a new paragraph (f) is added to require onshore gas transmission operators to perform close-interval surveys if annual test station readings indicate cathodic protection is below the level of protection required in subpart I. Unless it is impractical to do so, close interval surveys must be completed with the protective current interrupted. Impracticality must be based on a technical reason, for example, a pipeline protected by direct buried sacrificial anodes (anodes directly connected to the pipeline), and not on cost impact. The proposed rule would also require each operator to take remedial action to correct any deficiencies indicated by the monitoring.
Interference currents can negate the effectiveness of cathodic protection systems. Section 192.473 prescribes general requirements to minimize the detrimental effects of interference currents. However, specific requirements to monitor and mitigate detrimental interference currents have not been prescribed in subpart I. In 2003, PHMSA issued advisory bulletin ADB-03-06 (68 FR 64189). The bulletin advised each operator of a natural gas transmission or hazardous liquid pipeline to determine whether new steel pipelines are susceptible to detrimental effects from stray electrical currents. Based on this evaluation, an operator should carefully monitor and take action to mitigate detrimental effects. The operator should give special attention to a new pipeline's physical location, particularly where that location may subject the new pipeline to stray currents from other underground facilities, including other pipelines or induced currents from electrical transmission lines, whether aboveground or underground. Operators were strongly encouraged to review their corrosion control programs and to have qualified corrosion personnel present during construction to identify, mitigate, and monitor any detrimental stray currents that might damage new
Section 192.477 prescribes requirements to monitor internal corrosion if corrosive gas is being transported. However, the existing rules do not prescribe that operators continually or periodically monitor the gas stream for the introduction of corrosive constituents through system changes, changing gas supply, upset conditions, or other changes. This could result in pipelines that are not monitored for internal corrosion, because an initial assessment did not identify the presence of corrosive gas. In September 2000, following the Carlsbad explosion, PHMSA issued Advisory Bulletin 00-02, dated 9/1/2000 (65 FR 53803). The bulletin advised owners and operators of natural gas transmission pipelines to review their internal corrosion monitoring programs and consider factors that influence the formation of internal corrosion, including gas quality and operating parameters. Pipeline operators continue to report incidents attributed to internal corrosion. Between 2002 and November 2012, 206 incidents have been reported that were attributed to internal corrosion. PHMSA has determined that additional requirements are needed to assure that operators effectively monitor gas stream quality to identify if and when corrosive gas is being transported and to mitigate deleterious gas stream constituents (
Section 192.485 prescribes requirements for remedial measures to address general corrosion and localized corrosion pitting in transmission lines. For such conditions it specifies that the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee Project PR 3-805 (RSTRENG). PHMSA has determined that additional requirements are needed to assure such calculations have a sound basis. The proposed rule would revise section 192.485(c) to specify that pipe and material properties used in remaining strength calculations must be documented in reliable, traceable, verifiable, and complete records. If such records are not available, pipe and material properties used in the remaining strength calculations must be based on properties determined and documented in accordance with § 192.607.
The current pipeline safety regulations in 49 CFR 192.921 and 192.937 require that operators assess the material condition of pipelines in certain circumstances (
• API STD 1163-2005, “In-Line Inspection Systems Qualification Standard.” This Standard serves as an umbrella document to be used with and complement the NACE and ASNT standards below, which are incorporated by reference in API STD 1163.
• NACE Standard Practice, NACE SP0102-2010, “In-line Inspection of Pipelines.”
• ANSI/ASNT ILI-PQ-2010, “In-line Inspection Personnel Qualification and Certification.”
The API standard is more comprehensive and rigorous than requirements currently incorporated into 49 CFR part 192. The incorporation of this standard into pipeline safety regulations will promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes and software utilized by the in-line inspection industry. The API standard addresses in detail each of the following aspects of ILI inspections, most of which are not currently addressed in the regulations:
• Systems qualification process
• Personnel qualification
• In-line inspection system selection
• Qualification of performance specifications
• System operational validation
• System Results qualification
• Reporting requirements
• Quality management system
The incorporation of this standard into pipeline safety regulations will promote a higher level of safety by establishing consistent standards for conducting ILI assessments of line pipe. The NACE standard covers in detail each of the following aspects of ILI assessments, most of which are not currently addressed in part 192 or in ASME B31.8S:
• Tool selection
• Evaluation of pipeline compatibility with ILI
• Logistical guidelines, which includes survey acceptance criteria and reporting
• Scheduling
• New construction (planning for future ILI in new lines)
• Data analysis
• Data management
• The NACE standard provides a standardized questionnaire and specifies that the completed questionnaire should be provided to the ILI vendor. The questionnaire lists relevant parameters and characteristics of the pipeline section to be inspected.
PHMSA believes that the consistency, accuracy and quality of pipeline in-line inspections would be improved by incorporating the consensus NACE standard into the regulations.
The NACE standard applies to “free swimming” inspection tools that are carried down the pipeline by the
The ANSI/ASNT standard provides for qualification and certification requirements that are not addressed by 49 CFR part 192. The incorporation of this standard into pipeline safety regulations will promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes and software utilized by the in-line inspection industry. The ANSI/ASNT standard addresses in detail each of the following aspects, which are not currently addressed in the regulations:
• Requirements for written procedures
• Personnel qualification levels
• Education, training and experience requirements
• Training programs
• Examinations (testing of personnel)
• Personnel certification and recertification
• Personnel technical performance evaluations
The proposed rule adds a new § 192.493 to require compliance with the requirements and recommendations of the three consensus standards discussed above when conducting in-line inspection of pipelines.
Section 192.503 prescribes the general test requirements for the operation of a new segment of pipeline, or returning to service a segment of pipeline that has been relocated or replaced. The proposed rule would add additional requirements to § 192.503(a)(1) to reflect other requirements for determination of MAOP. These include § 192.620 for alternative MAOP determination requirements and new § 192.624 for verification of MAOP for onshore, steel, gas transmission pipeline segments that: (1) Has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking and the pipeline segment is located in one of the following locations: (i) A high consequence area as defined in § 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
The NTSB recommended repealing § 192.619(c) and requiring that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test (recommendation P-11-14). Currently, part 192 does not contain any requirement for operators to conduct spike hydrostatic pressure tests. In response to the NTSB recommendation, this NPRM proposes requirements for verification of MAOP in new § 192.624, which requires that MAOP be established and documented for pipelines located in either an HCA or MCA meeting the conditions in § 192.624(a)(1) through (3) using one or more of the methods in § 192.624(c)(1) through (6). The pressure test method requires performance of a spike pressure test in accordance with new § 192.506 if the pipeline includes legacy pipe or was constructed using legacy construction techniques or if the pipeline has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a crack or crack-like defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking.
Section 192.517 prescribes the record requirements for each test performed under §§ 192.505 and 192.507. The proposed rule would revise § 192.517 to add the record requirements for § 192.506.
Section 192.605 prescribes requirements for the operator's procedural manual for operations, maintenance, and emergencies. Part 192 contains numerous requirements intended to protect pipelines from overpressure events. These include mandatory pressure relieving or pressure limiting devices, inspections and tests of such devices, establishment of maximum allowable operating pressure, and administrative requirements to not operate the pipeline at pressures that exceed the MAOP, among others. Implicit in the requirements of § 192.605 is the intent for operators to establish operational and maintenance controls and procedures to effectively implement these requirements and preclude operation at pressures that exceed MAOP. PHMSA expects that operator's procedures should already address this aspect of operations and maintenance, as it is a long-standing, critical aspect of safe pipeline operations. However, § 192.605 does not explicitly prescribe this aspect of the procedural controls. In addition, as a result of the San Bruno incident, Congress mandated in Section 23 of the Act that any exceedance of MAOP on a gas transmission pipeline be reported to PHMSA. As part of such reporting, the operator should inform PHMSA of the cause(s) of each exceedance. On December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which advised transmission operators of their responsibility under Section 23 of the Act to report exceedances of MAOP that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices (
Section 23 of the Act requires the Secretary of Transportation to require verification of records used to establish MAOP to ensure they accurately reflect the physical and operational characteristics of the pipelines and to confirm the established MAOP of the pipelines. PHMSA issued Advisory Bulletin 11-01 on January 10, 2011 (76 FR 1504) and Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822) to inform operators of this requirement. Operators have submitted information in their 2012 Annual Reports indicating that a portion of transmission pipeline segments do not have adequate records to establish MAOP or to accurately reflect the physical and operational characteristics of the pipeline. Therefore, PHMSA has determined that additional rules are needed to implement this requirement of the Act. Specifically, PHMSA has determined that additional rules are needed to require that operators conduct tests and other actions needed to understand the physical and operational characteristics for those segments where adequate records are not available, and to establish standards for performing these actions.
This issue was addressed in detail at the Integrity Verification Process workshop on August 7, 2013. Major issues that were discussed include the scope of information needed and the methodology for verifying material properties. The most difficult information to obtain, from a technical perspective, is the strength of the steel. Conventional techniques would include cutting out a piece of pipe and destructively testing it to determine yield and ultimate tensile strength. PHMSA proposes to address this in the rule by allowing new non-destructive techniques if they can be validated to produce accurate results for the grade and type of pipe being evaluated. Such techniques have already been successfully validated for some grades of pipe.
Another issue is the extremely high cost of excavating the pipeline in order to verify the material, and determining how much pipeline needs to be exposed and tested in order to have assurance of pipeline properties. PHMSA proposes to address this issue by specifying that operators take advantage of opportunities when the pipeline is exposed for other reasons, such as maintenance and repair, by requiring that material properties be verified whenever the pipe is exposed. Over time, pipeline operators will develop a substantial set of verified material data, which will provide assurance that material properties are reliably known for the entire population of inadequately documented segments. PHMSA proposes to require that operators continue this opportunistic material verification process until the operator has completed enough verifications to obtain high confidence that only a small percentage of inadequately documented pipe lengths have properties that are inconsistent with operators' past assumptions. The rule would specify the number of excavations required to achieve this level of confidence.
Lastly, PHMSA proposes criteria that would require material verification for higher risk locations. Therefore, the proposed rule would add requirements for verification of pipeline material in new § 192.607 for existing onshore, steel, gas transmission pipelines that are located in an HCA or a class 3 or class 4 location. PHMSA believes this approach appropriately addresses pipeline segment risk without extending the requirement to all pipelines where risk and potential consequences are not as significant, such as pipeline in remote rural areas.
Requirements are also included to ensure that the results of this process are documented in records that are reliable, traceable, verifiable, and complete that must be retained for the life of the pipeline.
Section 192.613 prescribes general requirements for continuing surveillance of the pipeline to determine and take action due to changes in the pipeline from, among other things, unusual operating and maintenance conditions. The 2011 hazardous liquid pipeline accident resulting in a crude oil spill into the Yellowstone River near Laurel, Montana was probably caused by scouring at a river crossing due to flooding. Based on recent examples of extreme weather events that did result, or could have resulted, in pipeline incidents, PHMSA has determined that additional requirements are needed to assure that operator procedures adequately address inspection of the pipeline and right-of-way for “other factors affecting safety and operation” following an extreme weather event such as a hurricane or flood, landslide, an earthquake, a natural disaster, or other similar event. The proposed rule would add a new paragraph (c) to require such inspections, specify the timeframe in which such inspections should commence, and specify the appropriate remedial actions must be taken to ensure safe pipeline operations. The new paragraph (c) would apply to both onshore transmission pipelines and their rights-of-way.
The NTSB issued its report on the San Bruno incident that included a recommendation (P-11-15) that PHMSA amend its regulations so that manufacturing and construction-related defects can only be considered “stable” if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the MAOP. This NPRM proposes to revise the test pressure factors in § 192.619(a)(2)(ii) to correspond to at least 1.25 MAOP for newly installed pipelines.
In addition, Section 23 of the Act requires verification of records to confirm the established MAOP of the pipelines. Operators have submitted information in their 2012 Annual Reports indicating that a portion of gas transmission pipeline segments do not have adequate records to establish MAOP. For pipelines without an adequately documented basis for MAOP, the proposed rule adds a new paragraph (e) to § 192.619 to require that certain onshore steel transmission pipelines that meet the criteria specified in § 192.624(a), and that do not have adequate records to establish MAOP, must establish and document MAOP in accordance with new § 192.624 using one or more of the methods in § 192.624(c)(1) through (6), as discussed in more detail below.
The proposed rule would also add a new paragraph (f) to explicitly require that records documenting tests, design, and other information necessary to establish MAOP be retained for the life of the pipeline.
Lastly, the rule would incorporate conforming changes to § 192.619(a) to reflect changes to gas gathering regulations proposed in §§ 192.8 and 192.9.
Section 23 of the Act requires verification of records used to establish MAOP for pipe in class 3 and class 4 locations and high-consequence areas in Class 1 and 2 locations to ensure they accurately reflect the physical and operational characteristics of the pipelines and to confirm the established MAOP of the pipelines. Operators have submitted information in their 2012 Annual Reports indicating that some gas transmission pipeline segments do not
As a result of its investigation of the San Bruno accident, NTSB issued two related recommendations. NTSB recommended that PHMSA repeal § 192.619(c) and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test (P-11-14). NTSB also recommended that PHMSA amend the Federal pipeline safety regulations so that manufacturing- and construction-related defects can only be considered stable if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the maximum allowable operating pressure (P-11-15).
The proposed rule would add a new § 192.624 to address these mandates and recommendations. The rule would require that operators re-establish and document MAOP for certain onshore steel transmission pipelines located in an HCA or MCA that meet one or more of the criteria specified in § 192.624(a). Those criteria include: (1) Has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking and the pipeline segment is located in one of the following locations: (i) A high consequence area as defined in § 192.903; (ii) a class 3 or class 4 location; or (iii) a moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
The methods specified in § 192.624 include the pressure test method. If the pipeline includes legacy pipe or was constructed using legacy construction techniques or the pipeline has experienced a reportable in-service incident, as defined in § 191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a crack or crack-like defect, a spike pressure test in accordance with new § 192.506 would be required. For modern pipe without the aforementioned risk factors, a pressure test in accordance with § 192.505 would be allowed.
Other methods to reestablish MAOP for pipe currently operating under § 192.619(c) would also be allowed. PHMSA has determined that the following methods would provide equal or greater effectiveness as a pressure test:
(i) De-rating the pipe segment such that the new MAOP is less than historical actual sustained operating pressure by using a safety factor of 0.80 times the sustained operating pressure (equivalent to a pressure test using gas or water as the test medium with a test pressure of 1.25 times MAOP). For segments that operate at stress levels of less than 30% SMYS a safety factor of 0.90 times sustained operating pressure is allowed (equivalent to a pressure test of 1.11 times MAOP), supplemented with additional integrity assessments, and preventive and mitigative measures specified in the proposed rule.
(ii) Replacement of the pipe, which would require a new pressure test that conforms with subpart J before being placed in service,
(iii) An in-line inspection and Engineering Critical Assessment process using technical criteria to establish a safety margin equivalent to that provided by a pressure test, or
(iv) Use of other technology that the operator demonstrates provides an equivalent or greater level of safety, provided PHMSA is notified in advance.
The proposed rule establishes requirements for pipelines operating at stress levels of less than 30% of SMYS based on technical information provided in Interstate Natural Gas Association of America/American Gas Association Final Report No. 13-180, “Leak vs. Rupture Thresholds for Material and Construction Anomalies,” December 2013. The report references a 2010 study by Kiefner & Associates, Inc. “Numerical Modeling and Validation for Determination of the Leak/Rupture Boundary for Low-Stress Pipelines” performed under contract to the Gas Technology Institute (GTI). The Kiefner/GTI report evaluated theoretical fracture models and supporting test data in order to define a possible leak-rupture threshold stress level. The report pointed out that “no evidence was found that a propagating ductile rupture could arise from an incident attributable to any one of these causes in a pipeline that is being operated at a hoop stress level of 30% of SMYS or less.” In addition, the INGAA/AGA report included a review of Kiefner & Associates, Inc. failure investigation reports, which concluded that all manufacturing related defects failing under the action of hoop stress alone failed as leaks if the hoop stress level was 30% SMYS or less except for one case out of 94 which failed at 27% of SMYS. The INGAA/AGA report states that a hydrostatic test to 1.25 times the MAOP is unnecessary to reasonably assure stability of pipe manufacturing construction related features in pipe meeting the following conditions: (1) Ductile fracture initiation is assured by showing that the pipe has an operating temperature above the brittle fracture initiation temperature; (2) interaction with in-service degradation mechanics such as selective seam weld corrosion or previous mechanical damage is absent; (3) hoop stress is 30% or less; (4) mill pressure testing was conducted at 60% SMYS or more, established by documented conformance to applicable pipe product specifications (
The above approach implements the regulatory mandate in the Act for segments in HCAs. In addition, the scope includes additional pipe segments in the newly defined moderate consequence areas. This approach is intended to address the NTSB recommendations and to provide increased safety in areas where a pipeline rupture would have a significant impact on the public or the environment. PHMSA does not propose to repeal 49 CFR 192.619(c) for segments located outside of HCAs or MCAs where the routine presence of persons is not expected.
The Engineering Critical Assessment process requires the conservative analysis of: Any in-service cracks, crack-like defects remaining in the pipe, or the largest possible crack that could remain in the pipe, including crack dimensions (length and depth) to determine the predicted failure pressure (PFP) of each defect; failure mode (ductile, brittle, or both) for the microstructure, location, type of defect, and operating conditions (which includes pressure cycling); and failure stress and crack growth analysis to determine the remaining life of the pipeline. An Engineering Critical Assessment must use techniques and procedures developed and confirmed through research findings provided by PHMSA, and other reputable technical sources for longitudinal seam and crack growth such as PHMSA's Comprehensive Study to Understand Longitudinal ERW Seam Research & Development study task reports: Battelle Final Reports (“Battelle's Experience with ERW and Flash Weld Seam Failures: Causes and Implications”—Task 1.4), Report No. 13-002 (“Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams”—Subtask 2.4), Report No. 13-021 (“Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue”—Subtask 2.5), and “Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1”—Task 4.5), which can be found on the internet at:
Section 23 requires pipeline operators to conduct a records verification for pipelines located in certain areas to ensure that the records accurately reflect the physical and operational characteristics of the pipelines and confirm the established MAOP. Congress further directed DOT to require the owner or operator to reconfirm a maximum allowable operating pressure for pipelines with insufficient records. This rule proposes methods for satisfying this direction from Congress. In analyzing the impact of the proposed methods, PHMSA determined that they would result in large cost savings ($2.67 billion over 15 years discounted at 7%, $3.67 billion discounted at 3%) relative to current regulatory requirements for pipelines with insufficient records in 49 CFR 192.107(b), The results of that action indicated that problems similar to those that contributed to the San Bruno incidents are more widespread than previously believed. As a result, the proposed rule would establish consistent standards by which operators would correct these issues in a way that is more cost effective than the current regulations would require (which could require more extensive destructive testing, pressure testing, and/or pipe replacement). PHMSA did not identify any significant adverse safety impacts from allowing operators to use the proposed methods instead of those in the current regulations. See section 4.1.2.3 in the regulatory impact analysis for the analysis of the cost savings.
PHMSA estimated the cost savings to operators associated with the Section 23(c) mileage. Existing regulatory requirements [§ 192.107(b)] related to bad or missing records would be more costly for operators to achieve compliance. Under existing regulations, in order for pipelines with insufficient records to maintain operating pressure, operators must excavate the pipeline at every 10 lengths of pipe (commonly referred to as joints) in accordance with section II-D of appendix B of part 192 (as specified in § 192.107(b)), do a cutout, determine material properties by destructive tensile test, and repair the pipe. The process is similar to doing a repair via pipe replacement. PHMSA developed a blended average for performing such a cutout material verification ($75,000) by reviewing typical costs to repair a small segment of pipe by pipe replacement. The blended average accounted for various pipe diameters and regional cost variance. PHMSA assumed each joint is 40 feet long; ten joints is 400 ft. The number of cutouts required by existing rules is therefore the miles subject to this requirement multiplied by 5,280/400.
The proposed rule would allow operators to perform a sampling program that opportunistically takes advantage of repairs and replacement projects to verify material properties at the same time. Over time, operators will collect enough information gain significant confidence in the material properties of pipe subject to this requirement. The proposed rule nominally targets conducting an average of one material documentation process per mile. In addition, operators would be allowed to perform nondestructive examinations, in lieu of cutouts and destructive testing, when the technology provides a demonstrable level of confidence in the result. PHMSA estimated that the incremental unit cost of adding material documentation activities to a repair or replacement activity would be approximately $17,000 per instance.
The proposed methods for addressing pipelines with insufficient records are exclusively applicable to HCA and all Class 3 and 4 locations. Therefore, if the proposed rule were in effect, operators would be able to use the new methods for addressing pipeline with insufficient records in HCA and all Class 3 and 4 locations, but they would be required to comply with existing (more expensive) requirements for addressing the same issue for pipelines located outside HCA and all Class 3 and 4 locations. Locations outside HCAs and all Class 3 and 4 are by definition lower risk, meaning if incidents occur, the consequences are expected to be smaller than HCA and all Class 3 and 4 locations. PHMSA is considering including provisions in the final rule that would enable operators to use the proposed methods for addressing pipelines with insufficient records in locations outside HCAs and all Class 3 and 4. To maintain flexibility, the proposed methods may be an option to existing requirements—as opposed to a replacement of those requirements. PHMSA requests comments on the impacts of allowing operators to use the new methods for addressing insufficient records beyond HCAs and all Class 3 and 4 locations. What safety risks, if any, should PHMSA consider? What are the potential cost savings?
Currently, part 192 does not contain any requirement for operators to conduct integrity assessments of onshore transmission pipelines that are not HCA segments as defined in § 192.903 and therefore not subject to subpart O;
Given this level of commitment, PHMSA has determined that it is appropriate to codify requirements that additional gas transmission pipelines have an integrity assessment on a periodic basis to monitor for, detect, and remediate deleterious pipeline defects and injurious anomalies. However, INGAA does not represent all pipeline operators subject to part 192. In addition, in order to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while minimizing the cost of identifying such locations, PHMSA proposes to base the requirements for identifying those locations on processes already being implemented by pipeline operators.
The proposed rule would add a new § 192.710 to require that pipeline segments in moderate consequence areas that can accommodate inspection by means of instrumented inline inspection tools (
Because significant non-HCA pipeline mileage has been previously assessed in conjunction with an assessment of HCA segments in the same pipeline, PHMSA also proposes to allow the use of those prior assessments for non-HCA segments to comply with the new § 192.710, provided that the assessment was conducted in conjunction with an integrity assessment required by subpart O.
The proposed rule would also require that the assessment required by new § 192.710 be conducted using the same methods as proposed for HCAs (see § 192.921, below).
Section 192.711 prescribes general requirements for repair procedures. For non-HCA segments, the existing rule requires that permanent repairs be made as soon as feasible. However, no specific repair criteria are provided and no specific timeframe or pressure reduction requirements are provided. PHMSA has determined that more specific repair criteria are needed for pipelines not covered under the integrity management rule. The proposed rule would amend paragraph (b)(1) of section 192.711 to require that specific conditions (
Section 192.713 prescribes requirements for the permanent repair of pipeline imperfection or damage that impairs the serviceability of pipe in a steel transmission line operating at or above 40 percent of SMYS. PHMSA has determined that more explicit requirements are needed to better identify criteria for the severity of imperfection or damage that must be repaired, and to identify the timeframe within which repairs must be made. Further, PHMSA has determined that such repair criteria should apply to any transmission pipeline not covered under subpart O, Integrity Management regulations. PHMSA believes that establishing these non-HCA segment repair conditions are important because, even though they are not within the defined high consequence locations, they could be located in populated areas and are not without consequence. For example, as reported by operators in the 2011 annual reports, while there are approximately 20,000 miles of gas transmission pipe in HCA segments, there are approximately 65,000 miles of pipe in Class 2, 3, and 4 populated areas. PHMSA believes it is prudent and appropriate to include criteria to assure the timely repair of injurious pipeline defects in non-HCA segments. These changes will ensure the prompt remediation of anomalous conditions, while allowing operators to allocate their resources to high consequence areas on a higher priority basis. The proposed rule would amend § 192.713 to establish immediate, two-year, and monitored conditions which the operator must remediate or monitor to assure pipeline safety. PHMSA proposes to use the same criteria as proposed for HCAs (see 192.933, below), except that conditions for which a one-year response is required in HCAs would require a two-year response in non-HCA segments. In addition, PHMSA proposes to prescribe more explicit requirements for
PHMSA has determined that more explicit requirements are needed for safety when performing maintenance activities that utilize launchers and receivers to insert and remove maintenance tools and devices. Such facilities are subjected to pipeline system pressures. Current regulations for hazardous liquid pipelines (part 195) have, since 1981, contained such safety requirements for scraper and sphere facilities (re: § 195.426). However, current regulations for gas pipelines (part 192) do not similarly require controls or instrumentation to protect against inadvertent breach of system integrity due to incorrect operation of launchers and receivers for in-line inspection tools, scraper, and sphere facilities. Accordingly, the proposed rule would add a new section § 192.750 to require a suitable means to relieve pressure in the barrel and either a means to indicate the pressure in the
Paragraph (k) of § 192.911 requires that integrity management programs include a management of change process as outlined in ASME/ANSI B31.8S, section 11. PHMSA has determined that specific attributes and features of the management of change process as currently specified in ASME/ANSI B31.8S, section 11, should be codified directly within the text of § 192.911(k). The proposed rule would amend paragraph (k) to specify that the features of the operator's management of change process must include the reason for change, authority for approving changes, analysis of implications, acquisition of required work permits, documentation, communication of change to affected parties, time limitations, and qualification of staff. These general attributes of change management are already required by virtue of being invoked by reference to ASME/ANSI B31.8S. However, PHMSA believes it will improve the visibility and emphasis on these important program elements to require them directly in the rule text.
Section 192.917 requires that integrity management programs for covered pipeline segments identify potential threats to pipeline integrity and use the threat identification in its integrity program. Included within this performance-based process are requirements to identify threats to which the pipeline is susceptible, collect data for analysis, and perform a risk assessment. Special requirements are included to address plastic pipe and particular threats such as third party damage and manufacturing and construction defects. Following the San Bruno accident, the NTSB recommended that Pacific Gas and Electric (PG&E) assess every aspect of its integrity management program, paying particular attention to the areas identified in the investigation, and implement a revised program that includes, at a minimum,
(1) a revised risk model to reflect the Pacific Gas and Electric Company's actual recent experience data on leaks, failures, and incidents;
(2) consideration of all defect and leak data for the life of each pipeline, including its construction, in risk analysis for similar or related segments to ensure that all applicable threats are adequately addressed;
(3) a revised risk analysis methodology to ensure that assessment methods are selected for each pipeline segment that address all applicable integrity threats, with particular emphasis on design/material and construction threats; and
(4) an improved self-assessment that adequately measures whether the program is effectively assessing and evaluating the integrity of each covered pipeline segment (NTSB recommendation P-11-29).
In addition, the NTSB recommended that PG&E conduct threat assessments using the revised risk analysis methodology incorporated in its integrity management program, as recommended in Safety Recommendation P-11-29, and report the results of those assessments to the California Public Utilities Commission and the Pipeline and Hazardous Materials Safety Administration (NTSB recommendation P-11-30). PHMSA has also analyzed the issues the NTSB identified in the investigation related to information analysis and risk assessment. PHMSA held a workshop on July 21, 2011 to address perceived shortcomings in the implementation of integrity management risk assessment processes and the information and data analysis (including records) upon which such risk assessments are based. PHMSA sought input from stakeholders on these issues and has determined that additional clarification and specificity is needed for existing performance-based rules. These clarifications define and emphasize the specific functions that are required for risk assessment and effective risk management.
These aspects of integrity management have been an integral part of PHMSA's expectations for integrity management since the inception of the program. As specified in § 192.907(a), PHMSA expected operators to start with a framework, which would evolve into a more detailed and comprehensive program, and that the operator must continually improve its integrity management program, as it learned more about the process and about the material condition of its pipelines through integrity assessments.
PHMSA elaborated on this philosophy in the notice of final rulemaking for subpart O (68 FR 69778):
The clarifications and additional specificity proposed in this NPRM (with respect to processes for implementing the threat identification, risk assessment, and preventive and mitigative measures program elements), reflect PHMSA's expectation regarding the degree of progress operators should be making, or should have made, during the first 10 years of the integrity management program.
The current integrity management rule invokes ASME/ANSI B31.8S by reference to require that operators implement specific attributes and features of the threat identification, data analysis, and risk assessment process. PHMSA has determined that those specific attributes and features of the threat identification, data analysis, and risk assessment processes as currently specified in ASME/ANSI B31.8S, section 11, should be codified within the text of § 192.917. While continuing to incorporate the industry standard by reference, the proposed rule would amend § 192.917 to insert certain critical features of the industry standard (ASME/ANSI B31.8S) directly into the body of the Federal regulation. Specifically, PHMSA proposes to specify several pipeline attributes that must be included in pipeline risk assessments and to explicitly require that operators integrate analyzed information, and ensure that data be verified and validated to the maximum extent practical. PHMSA also acknowledges that objective, documented data is not always available or obtainable. To the degree that subjective data from subject matter experts must be used, PHMSA proposes to require that an operator's program include specific features to compensate for subject matter expert bias.
In addition, PHMSA proposes to clarify the performance-based risk assessment aspects of the IM rule to specify that operators perform risk assessments that are adequate to evaluate the effects of interacting threats; determine additional preventive and mitigative measures needed, analyze how a potential failure could affect high consequence areas, including the consequences of the entire worst-case incident scenario from initial failure to incident termination; identify the contribution to risk of each risk factor, or each unique combination of risk factors that interact or simultaneously contribute to risk at a common location, account for, and compensate for, uncertainties in the
Lastly, PHMSA proposes to revise the criteria in § 192.917(e)(3) and (4) for addressing the threat of manufacturing and construction defects and concluding that latent defects are stable as recommended in NTSB recommendation P-11-15.
Section 192.921 requires that pipelines subject to integrity management rules have an integrity assessment. Current rules allow the use of in-line inspection, pressure testing in accordance with subpart J, direct assessment for the threats of external corrosion, internal corrosion, and stress corrosion cracking, and other technology that the operator demonstrates provides an equivalent level of understanding of the condition of the pipeline. Following the San Bruno accident, PHMSA has determined that baseline assessment methods should be clarified to emphasize in-line inspection and pressure testing over direct assessment. At San Bruno, PG&E relied heavily on direct assessment under circumstances for which direct assessment was not effective. Further, ongoing research and industry response to the ANPRM is beginning to indicate that stress corrosion cracking direct assessment is not as effective, and does not provide an equivalent understanding of pipe conditions with respect to SCC defects, as ILI or hydrostatic pressure testing at test pressures that exceed those test pressures required by subpart J (
The current rule merely indicates that in-line inspection (ILI) is an accepted assessment method. The regulations are currently silent on a number of issues that significantly impact the quality and effectiveness of ILI assessment results. Such considerations are described in ASME/ANSI B31.8S, but limited guidance is provided. As discussed above, the proposed rule strengthens guidance in this area by adding a new § 192.493 to require compliance with the requirements and recommendations of API STD 1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2010 when conducting in-line inspection of pipelines. Section 192.921(a)(1) would be revised to require compliance with § 192.493 instead of ASME B31.8S for baseline ILI assessments for covered segments. In addition, a person qualified by knowledge, training, and experience would be required to analyze the data obtained from an internal inspection tool to determine if a condition could adversely affect the safe operation of the pipeline, and must explicitly consider uncertainties in reported results (including, but not limited to, tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies.
GWUT has been in use by pipeline operators for several years. Previously, operators were required by § 192.921(a)(4) to submit a notification to PHMSA as an “other technology” assessment method, in order to use GWUT. In 2007, PHMSA developed guidelines for how it would evaluate notifications for use of GWUT. These guidelines have been effectively used for seven years, and PHMSA has gained confidence that GWUT can be effectively used to assess the integrity of short segments of pipe. PHMSA proposes to incorporate these guidelines into a new Appendix F, which would be invoked in § 192.921. Therefore, notification for use of GWUT would no longer be required.
ASME B31.8S, Section 6.1, describes both excavation and direct
PHMSA proposes to clarify its requirements to explicitly add excavation and direct
PHMSA also proposes that mandatory integrity assessments proposed for non-HCA segments (see § 192.710, above) could also use these assessment methods.
As discussed in the changes to §§ 192.927 and 192.929 below, the proposed rule would incorporate by reference NACE SP0206-2006, “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas,” for addressing ICDA and NACE SP0204-2008, “Stress Corrosion Cracking Direct Assessment,” for addressing SCCDA. Sections 192.923(b)(2) and (b)(3) would be revised to require compliance with these standards.
Internal corrosion (IC) is a degradation mechanism in which steel pipe loses wall thickness due to corrosion initiating on the inside surface of the pipe. IC is one of several threats that can impact pipeline integrity. IM regulations in 49 CFR part 192 require that pipeline operators assess covered pipe segments periodically to detect degradation from threats that their analyses have indicated could affect the segment. Not all covered segments are subject to an IC threat, but some are. IC direct assessment (ICDA) is an assessment technique that can be used to address this threat for gas pipelines. ICDA involves evaluation and analysis to determine locations at which a
Section 192.927 specifies requirements for gas transmission pipeline operators who use ICDA for IM assessments. The requirements in § 192.927 were promulgated before the NACE standard was published. They require that operators follow ASME/ANSI B31.8S provisions related to ICDA. PHMSA has reviewed the NACE standard and finds that it is more comprehensive and rigorous than either § 192.927 or ASME B31.8S in many respects. Some of the most important features in the NACE standard are:
• The NACE standard requires more direct examinations in most cases.
• The NACE standard encompasses the entire pipeline segment and requires that all inputs and outputs be evaluated.
• The NACE standard indirect inspection model is different than the Gas Technology Institute (GTI) model currently referenced in § 192.927, but is considered to be equivalent or superior. Its range of applicability with respect to operating pressure is greater than the GTI model, thus allowing use of ICDA in pipelines with lower operating pressures and higher flow velocities.
• The NACE standard provides additional guidance on how to effectively determine areas to excavate for detailed examinations for internal corrosion.
The existing requirements in § 192.927 have one particular aspect that has proven problematic. The definition of regions and requirements for selection of direct examination locations in the regulations are tied to the covered segment. Covered segment boundaries are determined by population density and other consequence factors without regard to the orientation of the pipe and the presence of locations at which corrosive agents may be introduced or may collect and where internal corrosion would most likely be detected (
This proposed rule would require that operators perform two direct examinations within each covered segment the first time ICDA is performed. These examinations are in addition to those required to comply with the NACE standard practice. The additional examinations are consistent with the current requirement in § 192.927(c)(5)(ii) that operators apply more restrictive criteria when conducting ICDA for the first time and are intended to provide a verification, within the HCA, that the results of applying the NACE process for the ICDA are acceptable. Applying the NACE process requires a more precise knowledge of the pipeline's orientation (particularly slope) than operators may have in many cases. Conducting examinations within the HCA during the first application of ICDA will verify that application of the ICDA process provides adequate information about the covered segment. Operators who identify IC on these additional examinations, even though excavations at locations determined using the NACE process did not identify any, will know that improvements to their knowledge of pipeline orientation or other adjustments to their application of the NACE process to the covered segment will be needed for future uses of ICDA. § 192.927(b) and (c) are revised to address these issues.
Stress corrosion cracking (SCC) is a degradation mechanism in which steel pipe develops tight cracks through the combined action of corrosion and tensile stress (residual or applied). These cracks can grow or coalesce to affect the integrity of the pipeline. SCC is one of several threats that can impact pipeline integrity. IM regulations in 49 CFR part 192 require that pipeline operators assess covered pipe segments periodically to detect degradation from threats that their analyses have indicated could affect the segment, though not all covered segments are subject to an SCC threat. SCC direct assessment (SCCDA) is an assessment technique that can be used to address this threat.
Section 192.929 specifies requirements for gas transmission pipeline operators who use SCCDA for IM assessments. The requirements in § 192.929 were promulgated before NACE Standard Practice SP0204-2008 was published. They require that operators follow Appendix A3 of ASME/ANSI B31.8S. This appendix provides some guidance for conducting SCCDA, but is limited to SCC that occurs in high-pH environments. Experience has shown that pipelines also can experience SCC degradation in areas where the surrounding soil has a pH near neutral (referred to as near-neutral SCC). NACE Standard Practice SP0204-2008 addresses near-neutral SCC in addition to high-pH SCC. In addition, the NACE Standard provides technical guidelines and process requirements which are both more comprehensive and rigorous for conducting SCCDA than do § 192.929 or ASME/ANSI B31.8S.
The NACE standard provides additional guidance on:
• The factors that are important in the formation of SCC on a pipeline and what data should be collected;
• Additional factors, such as existing corrosion, which could cause SCC to form;
• Comprehensive data collection guidelines, including the relative importance of each type of data;
• Requirements to conduct close interval surveys of cathodic protection or other above-ground surveys to supplement the data collected during pre-assessment;
• Ranking factors to consider for selecting excavation locations for both near neutral and high pH SCC;
• Requirements on conducting direct examinations, including procedures for collecting environmental data, preparing the pipe surface for examination, and conducting Magnetic Particle Inspection (MPI) examinations of the pipe; and
• Post assessment analysis of results to determine SCCDA effectiveness and assure continual improvement.
NACE SP0204-2008 provides comprehensive guidelines on conducting SCCDA which are commensurate with the state of the art. It is more comprehensive in scope than Appendix A3 of ASME/ANSI B31.8S. PHMSA has concluded the quality and consistency of SCCDA conducted under IM requirements would be improved by requiring the use of NACE SP0204-2008. Revisions to § 192.929 are proposed to address these issues.
Section 192.933 specifies those injurious anomalies and defects which must be remediated, and the timeframe within which remediation must occur. PHMSA has determined that the existing rule has gaps, some injurious anomalies and defects are not identified in the rule as requiring remediation in a timely manner commensurate with their seriousness. The proposed rule would designate the following types of anomalies/defects as immediate
The methods specified in the IM rule to calculate predicted failure pressure are explicitly not valid if metal exceeds 80% of wall thickness. Corrosion affecting a longitudinal seam, especially associated with seam types that are known to be susceptible to latent manufacturing defects such as the failed pipe at San Bruno, and selective seam weld corrosion, are known time sensitive integrity threats. Stress corrosion cracking is listed in ASME/ANSI B31.8S as an immediate repair condition, which is not reflected in the current IM regulations. PHMSA proposes to add requirements to address these gaps.
With respect to SCC, PHMSA has incorporated repair criteria to address NTSB recommendation P-12-3 that resulted from the investigation of the Marshall, Michigan crude oil accident. From its investigation, the NTSB recommended that PHMSA revise § 195.452 to clearly state (1) when an engineering assessment of crack defects, including environmentally assisted cracks, must be performed; (2) the acceptable methods for performing these engineering assessments, including the assessment of cracks coinciding with corrosion with a safety factor that considers the uncertainties associated with sizing of crack defects; (3) criteria for determining when a probable crack defect in a pipeline segment must be excavated and time limits for completing those excavations; (4) pressure restriction limits for crack defects that are not excavated by the required date; and (5) acceptable methods for determining crack growth for any cracks allowed to remain in the pipe, including growth caused by fatigue, corrosion fatigue, or stress corrosion cracking as applicable (NTSB recommendation P-12-3). Although the recommendation was focused on part 195, the issue applies to gas pipelines regulated under part 192. PHMSA proposes to allow the use of engineering assessment to evaluate if SCC is significant (and thus categorized as an “immediate” condition), or not significant (and thus categorized as a “one-year” condition), but that an engineering assessment not be allowed to justify not remediating any known indications of SCC. Further, PHMSA proposes to adopt the definition of significant SCC from NACE SP0204-2008.
The current rule includes no explicit metal loss repair criteria for one-year conditions, other than one immediate condition. The rule does direct operators to use Figure 4 in ASME B31.8S to determine non-immediate metal loss repair criteria. PHMSA proposes to repeal the reference to Figure 4, and explicitly include selected metal loss repair conditions in the one-year criteria. These new criteria are consistent with similar criteria currently invoked in the hazardous liquid integrity management rule at 40 CFR 195.452(h). In addition, PHMSA proposes to incorporate safety factors commensurate with the class location in which the pipeline is located, to include predicted failure pressure less than or equal to 1.25 times MAOP for Class 1 locations, 1.39 times MAOP for Class 2 locations, 1.67 times MAOP for Class 3 locations, and 2.00 times MAOP for Class 4 locations in HCAs. Lastly, in response to the lessons learned from the Marshall, Michigan rupture, PHMSA proposes to include any crack or crack-like defect that does not meet the proposed immediate criteria, as a one year condition.
In addition, as a result of its investigation of the Marshall, Michigan crude oil spill, the NTSB recommended that PHMSA revise § 195.452(h)(2), the “discovery of condition,” to require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify the Pipeline and Hazardous Materials Safety Administration and provide an expected date when adequate information will become available (NTSB recommendation P-12-4). Although the recommendation was focused on part 195, the issue applies to gas pipelines regulated under part 192. Accordingly, PHMSA proposes to amend paragraph (b) of § 192.933 to require that operators notify PHMSA whenever the operator cannot obtain sufficient information to determine if a condition presents a potential threat to the integrity of the pipeline, within 180 days of completing the assessment.
Lastly, PHMSA proposes to require that pipe and material properties used in remaining strength calculations must be documented in reliable, traceable, verifiable, and complete records. If such records are not available, pipe and material properties used in the remaining strength calculations would be required to be based on properties determined and documented in accordance with § 192.607.
Section 192.935 requires an operator to take additional measures beyond those already required by part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area (HCA). An operator must conduct a risk analysis to identify the additional measures to protect the high consequence area and improve public safety. As discussed above, PHMSA proposes to amend § 192.917 to clarify the guidance for risk analyses operators use to evaluate and select additional preventive and mitigative measures. In addition, PHMSA has determined that some additional prescriptive preventive and mitigative measures are needed to assure that public safety is enhanced in HCAs and affords greater protections for HCAs. This proposed rule would expand the listing of example preventive and mitigative measures operators must consider, require that seismicity be analyzed to mitigate the threat of outside force damage, and would add specific enhanced measures for managing external corrosion and internal corrosion inside HCAs.
With respect to additional preventive and mitigative measures operators must consider, PHMSA proposes to specify that preventive and mitigative measures include (i) correction of the root causes of past incidents in order to prevent recurrence, (ii) adequate operations and maintenance processes, (iii) adequate resources for successful execution of safety related activities, (iv) additional right-of-way patrols, (v) hydrostatic tests in areas where material has quality issues or lost records, (vi) tests to determine material mechanical and chemical properties for unknown properties that are needed to assure integrity or substantiate MAOP evaluations including material property tests from removed pipe that is
Section 29 of the Act requires operators to consider seismicity when evaluating threats. Accordingly, PHMSA proposes to include seismicity of the area in evaluating preventive and mitigative measures with respect to the threat of outside force damage.
With respect to internal corrosion and external corrosion, PHMSA proposes to add new paragraphs (f) and (g) to § 192.935 to specify that an operator must enhance its corrosion control program in HCAs to provide additional protections from the threat of corrosion. More specifically, operators would be required to conduct periodic close-interval surveys, coating surveys, interference surveys, and gas-quality monitoring inside HCAs. The requirements would include specific minimum performance standards for these activities.
Lastly, to conform to the revised definition of “electrical survey,” the use of that term in § 192.935 would be replaced with “indirect assessment” to accommodate other techniques in addition to close-interval surveys.
Section 192.937 requires that operators continue to periodically assess HCA segments and periodically evaluate the integrity of each covered pipeline segment. PHMSA has determined that conforming amendments would be needed to implement, and be consistent with, the changes discussed above for §§ 192.917, 192.921, 192.933, and 192.935. The proposed rule would require that the continual process of evaluation and assessment implement and be consistent with data integration and risk assessment information in order to identify the threats specific to each HCA segment, including interacting threats, and the risk represented by these threats (§ 192.917), selection and use of assessment methods (§ 192.921), decisions about remediation (§ 192.933), and identify additional preventive and mitigative measures (§ 192.935) to avert or reduce threats to acceptable levels.
Section 192.939 specifies reassessment intervals for pipelines subject to integrity management requirements. Section 5 of the Act includes a technical correction that clarified that periodic reassessments must occur, at a minimum of once every 7 calendar years, but that the Secretary may extend such deadline for an additional 6 months if the operator submits written notice to the Secretary with sufficient justification of the need for the extension. PHMSA would expect that any justification, at a minimum, would need to demonstrate that the extension does not pose a safety risk. By this rulemaking, PHMSA intends to codify this technical correction. The proposed rule would implement this statutory requirement.
Section 192.941, among other requirements, specifies that, to address the threat of external corrosion on cathodically protected pipe in a HCA segment, an operator must perform an electrical survey (
As discussed under § 192.13, above, the proposed rule would more clearly articulate the requirements for records preparation and retention for transmission pipelines and to require that records be reliable, traceable, verifiable, and complete. New appendix A to part 192 provides specific requirements and records retention periods.
Appendix D to part 192 specifies requirements for cathodic protection of steel, cast iron & ductile pipelines. PHMSA has determined that this guidance needs to be updated to incorporate lessons learned since this appendix was first promulgated in 1971. The proposed rule would update appendix D accordingly by eliminating outdated guidance on cathodic protection and interpretation of voltage measurement to better align with current standards.
Appendix E to part 192 provides guidance for preventive and mitigative measures for HCA segment subject to subpart O. PHMSA proposes to make conforming edits to the language in this appendix to accommodate the revised definition of the term “electrical survey.” To conform to the revised definition of “electrical survey,” the use of that term in Appendix E would be replaced with “indirect assessment” to accommodate other techniques in addition to close-interval surveys.
As discussed under § 192.941 above, a new appendix F to part 192 is proposed to provide specific requirements and acceptance criteria for the use of GWUT as an integrity assessment method. Operators must apply all 18 criteria defined in Appendix F to use GWUT as an integrity assessment method. If an operator applied GWUT technology in a manner that does not conform to Appendix F, it would be considered “other technology” in §§ 192.710, 192.921, and 192. 937.
PHMSA currently incorporates by reference into 49 CFR parts 192, 193, and 195 all or parts of more than 60 standards and specifications developed and published by standard developing organizations (SDOs). In general, SDOs update and revise their published standards every 3 to 5 years to reflect modern technology and best technical practices.
The National Technology Transfer and Advancement Act of 1995 (Pub. L. 104-113) directs Federal agencies to use voluntary consensus standards in lieu of government-written standards whenever possible. Voluntary consensus standards are standards developed or adopted by voluntary bodies that develop, establish, or coordinate technical standards using agreed-upon procedures. In addition, Office of Management and Budget (OMB) issued OMB Circular A-119 to implement Section 12(d) of Public Law 104-113 relative to the utilization of consensus technical standards by
In accordance with the preceding provisions, PHMSA has the responsibility for determining, via petitions or otherwise, which currently referenced standards should be updated, revised, or removed, and which standards should be added to 49 CFR parts 192, 193, and 195. Revisions to incorporated by reference materials in 49 CFR parts 192, 193, and 195 are handled via the rulemaking process, which allows for the public and regulated entities to provide input. During the rulemaking process, PHMSA must also obtain approval from the Office of the Federal Register to incorporate by reference any new materials.
On January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90. Section 24 states: “Beginning 1 year after the date of enactment of this subsection, the Secretary may not issue guidance or a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge, on an Internet Web site.” 49 U.S.C. 60102(p).
On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to replace “1 year” with “3 years” and remove the phrases “guidance or” and “, on an Internet Web site.” This resulted in the current language in 49 U.S.C. 60102(p), which now reads as follows:
“Beginning 3 years after the date of enactment of this subsection, the Secretary may not issue a regulation pursuant to this chapter that incorporates by reference any documents or portions thereof unless the documents or portions thereof are made available to the public, free of charge.”
Further, the Office of the Federal Register issued a November 7, 2014, rulemaking (79 FR 66278) that revised 1 CFR 51.5 to require that agencies detail in the preamble of a proposed rulemaking the ways the materials it proposes to incorporate by reference are reasonably available to interested parties, or how the agency worked to make those materials reasonably available to interested parties. In relation to this proposed rulemaking, PHMSA has contacted each SDO and has requested a hyperlink to a free copy of each standard that has been proposed for incorporation by reference. Access to these standards will be granted until the end of the comment period for this proposed rulemaking. Access to these documents can be found on the PHMSA Web site at the following URL:
Consistent with the proposed amendments in this document, PHMSA proposes to incorporate by reference the following materials identified as follows:
• API Standard 1163-2005, “In-line Inspection Systems Qualification Standards.”—This Standard serves as an umbrella document to be used with and complement companion standards. NACE RP0102 Standard Recommended Practice, In-Line Inspections of Pipelines; and ASNT ILI-PQ In-Line Inspection Personnel Qualification & Certification all have been developed enabling service providers and pipeline operators to provide rigorous processes that will consistently qualify the equipment, people, processes and software utilized in the in-line inspection industry.
• NACE Standard Practice 0102-2010, “Inline Inspection of Pipelines.”—This standard is intended for use by individuals and teams planning, implementing, and managing ILI projects and programs. The incorporation of this standard into the Federal pipeline safety regulations would promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes, and software utilized by the ILI industry.
• NACE Standard Practice 0204-2008, “Stress Corrosion Cracking Direct Assessment.”—The standard practice for SCCDA presented in this standard addresses the situation in which a pipeline company has identified a portion of its pipeline as an area of interest with respect to SCC based on its history, operations, and risk assessment process and has decided that direct assessment is an appropriate approach for integrity assessment. This standard provides guidance for managing SCC by selecting potential pipeline segments, selecting dig sites within those segments, inspecting the pipe, collecting and analyzing data during the dig, establishing a mitigation program, defining the reevaluation interval, and evaluating the effectiveness of the SCCDA process.
• NACE Standard Practice 0206-2006, “International Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas.” This standard covers the NACE internal corrosion direct assessment (ICDA) process for normally dry natural gas pipeline systems. This standard is intended to serve as a guide for applying the NACE DG-ICDA process on natural gas pipeline systems that meet the feasibility requirements of Paragraph 3.3 of this standard.
• ANSI/ASNT ILI-PQ-2010, “In-line Inspection Personnel Qualification and Certification.” The ASNT standard provides for qualification and certification requirements that are not addressed in part 192. The incorporation of this standard into the Federal pipeline safety regulations would promote a higher level of safety by establishing consistent standards to qualify the equipment, people, processes, and software utilized by the ILI industry.
• Battelle's Experience with ERW and Flash Welding Seam Failures: Causes and Implications (Task 1.4). This report presents an evaluation of the database dealing with failures originating in electric resistance welds (ERW) and flash weld (FW) seam defects as quantified by Battelle's archives and the related literature.
• Battelle Memorial Institute, “Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams” (Subtask 2.4). This document presents an analysis of two known defect assessment methods in an effort to find suitable ways to satisfactorily predict the failure stress levels of defects in or adjacent to ERW or flash-welded line pipe seams.
• Battelle Final Report No. 13-021, “Predicting Times to Failures for ERW Seam Defects that Grow by Pressure Cycle Induced Fatigue (Subtask 2.5).” The work described in this report is part of a comprehensive study of ERW seam integrity and its impact on pipeline safety. The objective of this part of the work is to identify appropriate means for predicting the remaining lives of defects that remain after a seam integrity assessment and that may become enlarged by pressure-cycle-induced fatigue.
• Battelle Memorial Institute, “Final Summary Report and recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1” (Task 4.5).—This report summarizes work completed as part of a comprehensive project that resulted from a contract with Battelle, working with Kiefner and Associates (KAI) and Det Norske Veritas (DNV) as subcontractors, to address the concerns identified in NTSB recommendation (P-09-1) regarding the safety and performance of ERW pipe.
This proposed rule is published under the authority of the Federal Pipeline Safety Law (49 U.S.C. 60101
This proposed rule is a significant regulatory action under section 3(f) of Executive Order 12866 and, therefore, was reviewed by the Office of Management and Budget. This proposed rule is significant under the Regulatory Policies and Procedures of the Department of Transportation.
(44 FR 11034, February 26, 1979).
Executive Orders 12866 and 13563 require that proposed rules deemed “significant” include a Regulatory Impact Analysis, and that this analysis requires quantified estimates of the benefits and costs of the rule. PHMSA is providing the PRIA for this proposed rule simultaneously with this document, and it is available in the docket.
PHMSA estimates the total present value of benefits from the proposed rule to be approximately $3,234 to $3,738 million
The Regulatory Flexibility Act (RFA), as amended by the Small Business Regulatory Flexibility Fairness Act of 1996, requires Federal regulatory agencies to prepare an Initial Regulatory Flexibility Analysis (IFRA) for any proposed rule subject to notice-and-comment rulemaking under the Administrative Procedure Act unless the agency head certifies that the making will not have a significant economic impact on a substantial number of small entities. PHMSA has data on gas transmission pipeline operators affected by the proposed rule. However, PHMSA does not have data on currently unregulated gas gathering pipeline operators. Therefore, PHMSA prepared an IFRA which is available in the docket for the rulemaking.
PHMSA has analyzed this proposed rule according to the principles and criteria in Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Because this proposed rule would not significantly or uniquely affect the communities of the Indian tribal governments or impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.
Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide interested members of the public and affected agencies with an opportunity to comment on information collection and recordkeeping requests. PHMSA estimates that the proposals in this rulemaking will impact the information collections described below.
Based on the proposals in this rule, PHMSA will submit an information collection revision request to OMB for approval based on the requirements in this proposed rule. The information collection is contained in the pipeline safety regulations, 49 CFR parts 190 through 199. The following information is provided for each information collection: (1) Title of the information collection; (2) OMB control number; (3) Current expiration date; (4) Type of request; (5) Abstract of the information collection activity; (6) Description of affected public; (7) Estimate of total annual reporting and recordkeeping burden; and (8) Frequency of collection. The information collection burden for the following information collections are estimated to be revised as follows:
Total Annual Responses: 12,400.
Total Annual Burden Hours: 941,054.
2.
Total Annual Responses: 158.
Total Annual Burden Hours: 948.
3.
Total Annual Responses: 877.
Total Annual Burden Hours: 1,018,879.
4.
PHMSA is also revising the Gas Transmission and Gas Gathering Annual Report to collect additional information including mileage of pipe subject to the IVP and MCA criteria. Based on the proposed revisions, PHMSA estimates that an additional annual 500 reports to the current 1,440 reports will be submitted based on the required reporting of non-regulated gathering lines and gathering lines now subject to certain safety provisions. Further PHMSA estimates that the Annual report will require an additional 5 hours/report to the currently approved 42 hours due to collection of MCA data and IVP provisions. Therefore the overall burden allotted for the reporting of Gas annual reports will increase by 30,700 hours from 60,480 hours (42 hours*1,440 reports) to 91,180 hours (47 hours*1,940 reports).
As a result of the provisions mentioned above, the burden for this information collection will increase by 500 responses and 30,700 burden hours.
Total Annual Responses: 12,664.
Total Annual Burden Hours: 103,182
5.
Total Annual Responses: 920.
Total Annual Burden Hours: 920.
Requests for copies of these information collections should be directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline Safety (PHP-30), Pipeline Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE., Washington, DC 20590-0001, Telephone (202) 366-4595.
Comments are invited on:
(a) The need for the proposed collection of information for the proper performance of the functions of the agency, including whether the information will have practical utility;
(b) The accuracy of the agency's estimate of the burden of the revised collection of information, including the validity of the methodology and assumptions used;
(c) Ways to enhance the quality, utility, and clarity of the information to be collected; and
(d) Ways to minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other technological collection techniques.
Send comments directly to the Office of Management and Budget, Office of Information and Regulatory Affairs, Attn: Desk Officer for the Department of Transportation, 725 17th Street NW., Washington, DC 20503. Comments should be submitted on or prior to June 7, 2016.
An evaluation of Unfunded Mandates Reform Act (UMRA) considerations is performed as part of the Preliminary Regulatory Impact Assessment. The estimated costs to the States are approximately $1.3 million per year and are significantly less than the UMRA criterion of $151 million per year ($100 million, adjusted for inflation). The estimated costs to the private sector are in excess of the UMRA criterion of $151 million per year. A copy of the Preliminary Regulatory Impact Assessment is available for review in the docket.
PHMSA analyzed this proposed rule in accordance with section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), the Council on Environmental Quality regulations (40 CFR 1500-1508), and DOT Order 5610.1C, and has preliminarily determined this action will not significantly affect the quality of the human environment. The Environmental Assessment for this proposed action is in the docket.
PHMSA has analyzed this proposed rule according to Executive Order 13132 (“Federalism”). The proposed rule does not have a substantial direct effect on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government. This proposed rule does not impose substantial direct compliance costs on State and local governments. This proposed rule would not preempt state law for intrastate pipelines. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply.
This proposed rule is not a “significant energy action” under Executive Order 13211 (Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use). It is not likely to have a significant adverse effect on
Anyone may search the electronic form of all comments received for any of our dockets. You may review DOT's complete Privacy Act Statement in the
A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN number contained in the heading of this document can be used to cross-reference this action with the Unified Agenda.
Pipeline reporting requirements, Integrity Management, Pipeline safety, Gas gathering.
Incorporation by reference, Pipeline Safety, Fire prevention, Security measures.
In consideration of the foregoing, PHMSA proposes to amend 49 CFR parts 191 and 192 as follows:
49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, 60124, 60132, and 60139; and 49 CFR 1.97.
(a) This part prescribes requirements for the reporting of incidents, safety-related conditions, exceedances of maximum allowable operating pressure (MAOP), annual pipeline summary data, National Operator Registry information, and other miscellaneous conditions by operators of gas pipeline facilities located in the United States or Puerto Rico, including pipelines within the limits of the Outer Continental Shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). This part applies to offshore gathering lines and to onshore gathering lines, whether designated as “regulated onshore gathering lines” or not (as determined in § 192.8 of this chapter).
(b) * * *
(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9; or
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator.
(c) Sections 191.22(b) and 191.29 do not apply to gathering of gas—
(1) Through a pipeline that operates at less than 0 psig (0 kPa);
(2) Through an onshore pipeline that is not a regulated onshore gathering line (as determined in § 192.8 of this chapter); and
(3) Within inlets of the Gulf of Mexico, except for the requirements in § 192.612.
(a) * * **
(5) Any malfunction or operating error that causes the pressure of a distribution or gathering pipeline or LNG facility that contains or processes gas or LNG to rise above its maximum allowable operating pressure (or working pressure for LNG facilities) plus the margin (build-up) allowed for operation of pressure limiting or control devices.
(9) For transmission pipelines, each exceedance of the maximum allowable operating pressure that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices as specified in §§ 192.201, 192.620(e), and 192.739, as applicable.
(b) * * *
(4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline and any condition under paragraph (a)(9) of this section.
(a) Each report of a safety-related condition under § 191.23(a)(1) through (8) must be filed (received by the Associate Administrator, OPS) within five working days (not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to
(b) Each report of a maximum allowable operating pressure exceedance meeting the requirements of criteria in § 191.23(a)(9) for a gas transmission pipeline must be reported within five calendar days of the exceedance using the reporting methods and report requirements described in § 191.25(c).
(c) Reports may be filed by emailing information to
(1) Name, principal address, and operator identification number (OPID) of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person submitting the report.
(4) Name, job title, and business telephone number of person who determined that the condition exists.
(5) Date condition was discovered and date condition was first determined to exist.
(6) Location of condition, with reference to the State (and town, city, or county) or Offshore site, and as appropriate, nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline.
(7) Description of the condition, including circumstances leading to its discovery, any significant effects of the
(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up future corrective action, including the anticipated schedule for starting and concluding such action.
(c) This section does not apply to gathering lines.
49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 60116, 60118, 60137, and 60139; and 49 CFR 1.97.
The additions and revisions to read as follows:
(1) The inlet of 1st gas processing plant, unless the operator submits a request for approval to the Associate Administrator of Pipeline Safety that demonstrates, using sound engineering principles, that gathering extends to a further downstream plant other than a plant located on a transmission line and the Associate Administrator of Pipeline Safety approves such request;
(2) The outlet of gas treatment facility that is not associated with a processing plant or compressor station;
(3) Outlet of the furthermost downstream compressor used to facilitate delivery into a pipeline, other than another gathering line; or
(4) The point where separate production fields are commingled, provided the distance between the interconnection of the fields does not exceed 50 miles, unless the Associate Administrator of Pipeline Safety finds a longer separation distance is justified in a particular case (see § 190.9 of this chapter).
(5) Gathering may continue beyond the endpoints described in paragraphs (1) through (4) of this definition to the point gas is delivered into another pipeline, provided that it only does the following:
(i) It delivers gas into another gathering line;
(A) It does not leave the operator's facility surface property (owned or leased, not necessarily the fence line);
(B) It does not leave an adjacent property owned or leased by another pipeline operator's property—where custody transfer takes place; or
(C) It does not exceed a length of one mile, and it does not cross a state or federal highway or an active railroad; or
(ii) It transports gas to production or gathering facilities for use as fuel, gas lift, or gas injection gas.
(6) Pipelines that serve residential, commercial, or industrial customers that originate at a tap on gathering lines are not gathering lines; they are service lines and are commonly referred to as farm taps.
(1) Wrinkle bends;
(2) Miter joints exceeding three degrees;
(3) Dresser couplings;
(4) Non-standard fittings or field fabricated fittings (
(5) Acetylene welds;
(6) Bell and spigots; or
(7) Puddle welds.
(1) Low-Frequency Electric Resistance Welded (LF-ERW);
(2) Direct-Current Electric Resistance Welded (DC-ERW);
(3) Single Submerged Arc Welded (SSAW);
(4) Electric Flash Welded (EFW);
(5) Wrought iron;
(6) Pipe made from Bessemer steel; or
(7) Any pipe with a longitudinal joint factor, as defined in § 192.113, less than 1.0 (such as lap-welded pipe) or with a type of longitudinal joint that is unknown or cannot be determined, including pipe of unknown manufacturing specification.
(1) An outside area or open structure that is occupied by five (5) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive.) Examples include but are not limited to, beaches, playgrounds, recreational facilities, camping grounds, outdoor theaters, stadiums, recreational areas near a body of water, or areas outside a rural building such as a religious facility; or
(2) A building that is occupied by five (5) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive.) Examples include, but are not limited to, religious facilities, office buildings, community centers, general stores, 4-H facilities, or roller skating rinks.
(i) An amplitude greater than or equal to 1.5 times the wall thickness of the pipe, measured from peak to valley of the ripple; or
(ii) With ripples less than 1.5 times the wall thickness of the pipe and with a wrinkle length (peak to peak) to wrinkle height (peak to valley) ratio under 12.
(d) Records for transmission pipelines documenting class locations and demonstrating how an operator determined class locations in accordance with this section must be retained for the life of the pipeline.
The additions read as follows:
(b) * * *
(10) API STD 1163-2005, “In-Line Inspection Systems Qualification Standard,” 1st edition, August 2001, (API STD 1163), IBR approved for § 192.493.
(g) * * *
(2) NACE Standard Practice 0102-2010, “Inline Inspection of Pipelines,” Revised 2010, (NACE SP0102), IBR approved for §§ 192.150(a) and 192.493.
(3) NACE Standard Practice 0204-2008, “Stress Corrosion Cracking Direct Assessment,” Revised 2008, (NACE SP0204), Reaffirmed 2008, IBR approved for §§ 192.923(b)(3) and 192.929.
(4) NACE Standard Practice 0206-2006, “International Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas,” (NACE SP0206-2006), IBR approved for §§ 192.923(b)(2), 192.927(b), and 192.927(c).
(k) American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228, phone (800) 222-2768,
(1) ANSI/ASNT ILI-PQ-2010, “In-line Inspection Personnel Qualification and Certification,” 2010, (ANSI/ASNT ILI-PQ-2010), IBR approved for § 192.493.
(2) [Reserved]
(l) Battelle Memorial Institute, 505 King Avenue, Columbus, OH 43201, phone (800) 201-2011,
(1) Battelle's Experience with ERW and Flash Welding Seam Failures: Causes and Implications (Task 1.4), IBR approved for § 192.624(c) and (d).
(2) Battelle Memorial Institute, “Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams” (Subtask 2.4), IBR approved for § 192.624(c) and (d).
(3) Battelle Final Report No. 13-021, “Predicting Times to Failures for ERW Seam Defects that Grow by Pressure Cycle Induced Fatigue (Subtask 2.5), IBR approved for § 192.624(c) and (d).
(4) Battelle Memorial Institute, “Final Summary Report and recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1” (Task 4.5), IBR approved for § 192.624(c) and (d).
(a) Each operator must determine and maintain records documenting the beginning and endpoints of each gathering line it operates using the definitions of onshore production facility (or onshore production operation), gas processing facility, gas treatment facility, and onshore gathering line as defined in § 192.3 by
(b) Each operator must determine and maintain records documenting the beginning and endpoints of each regulated onshore gathering line it operates as determined in § 192.8(c) by
(c) For purposes of part 191 of this chapter and § 192.9, “regulated onshore gathering line” means:
(1) Each onshore gathering line (or segment of onshore gathering line) with a feature described in the second column that lies in an area described in the third column; and
(2) As applicable, additional lengths of line described in the fourth column to provide a safety buffer:
(c)
(d)
(1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines;
(2) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines;
(3) Carry out a damage prevention program under § 192.614;
(4) Establish a public education program under § 192.616;
(5) Establish the MAOP of the line under § 192.619;
(6) Install and maintain line markers according to the requirements for transmission lines in § 192.707;
(7) Conduct leakage surveys in accordance with § 192.706 using leak detection equipment and promptly repair hazardous leaks that are discovered in accordance with § 192.703(c); and
(8) For a Type A, Area 2 regulated onshore gathering line only, develop procedures, training, notifications, emergency plans and implement as described in § 192.615.
(e) If a regulated onshore gathering line existing on
(f) If, after
(a) No person may operate a segment of pipeline listed in the first column that is readied for service after the date in the second column, unless:
(1) The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this part; or
(2) The pipeline qualifies for use under this part according to the requirements in § 192.14.
(b) No person may operate a segment of pipeline listed in the first column that is replaced, relocated, or otherwise changed after the date in the second column, unless the replacement, relocation or change has been made according to the requirements in this part.
(d) Each operator of an onshore gas transmission pipeline must evaluate and mitigate, as necessary, risks to the public and environment as an integral part of managing pipeline design, construction, operation, maintenance, and integrity, including management of change. Each operator of an onshore gas transmission pipeline must develop and follow a management of change process, as outlined in ASME/ANSI B31.8S, section 11, that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary. A management of change process must include the following: reason for change, authority for approving changes, analysis of implications, acquisition of required work permits, documentation, communication of change to affected parties, time limitations, and qualification of staff.
(e) Each operator must make and retain records that demonstrate compliance with this part.
(1) Operators of transmission pipelines must keep records for the retention period specified in appendix A to part 192.
(2) Records must be reliable, traceable, verifiable, and complete.
(3) For pipeline material manufactured before
Each operator of transmission pipelines must acquire and retain for the life of the pipeline the original steel pipe manufacturing records that document tests, inspections, and attributes required by the manufacturing specification in effect at the time the pipe was manufactured, including, but not limited to, yield strength, ultimate tensile strength, and chemical composition of materials for pipe in accordance with § 192.55.
Each operator of transmission pipelines must make and retain for the life of the pipeline records documenting pipe design to withstand anticipated external pressures and loads in accordance with § 192.103 and determination of design pressure for steel pipe in accordance with § 192.105.
(a) Except as provided in paragraphs (b) and (c) of this section, each new
Each operator of transmission pipelines must acquire and retain records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this subpart. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi or greater must have records documenting the manufacturing specification in effect at the time of manufacture, including, but not limited to, yield strength, ultimate tensile strength, and chemical composition of materials.
(c) Records for transmission pipelines demonstrating each individual welder qualification in accordance with this section must be retained for the life of the pipeline.
(e) For transmission pipelines, records demonstrating plastic pipe joining qualifications in accordance with this section must be retained for the life of the pipeline.
18. In § 192.319, paragraph (d) is added to read as follows:
(d) Promptly after a ditch for a steel onshore transmission line is backfilled, but not later than three months after placing the pipeline in service, the operator must perform an assessment to ensure integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG). The operator must repair any coating damage classified as moderate or severe (voltage drop greater than 35% for DCVG or 50 dBμv for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by reference, see § 192.7) within six months of the assessment. Each operator of transmission pipelines must make and retain for the life of the pipeline records documenting the coating assessment findings and repairs.
(b)
(a) * * *
(4) Have sufficient strength to resist damage due to handling (including but not limited to transportation, installation, boring, and backfilling) and soil stress; and
(f) Promptly, but no later than three months after backfill of an onshore transmission pipeline ditch following repair or replacement (if the repair or replacement results in 1,000 feet or more of backfill length along the pipeline), conduct surveys to assess any coating damage to ensure integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG). Remediate any coating damage classified as moderate or severe (voltage drop greater than 35% for DCVG or 50 dBμv for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by reference, see § 192.7) within six months of the assessment.
(d) Each operator must promptly correct any deficiencies indicated by the inspection and testing provided in paragraphs (a), (b) and (c) of this section. Remedial action must be completed promptly, but no later than the next monitoring interval in § 192.465 or within one year, whichever is less.
(f) For onshore transmission lines, where any annual test station reading (pipe-to-soil potential measurement) indicates cathodic protection levels below the required levels in Appendix D of this part, the operator must determine the extent of the area with inadequate cathodic protection. Close interval surveys must be conducted in both directions from the test station with a low cathodic protection (CP) reading at a minimum of approximately five foot intervals. Close interval surveys must be conducted, where practical based upon geographical, technical, or safety reasons. Close interval surveys required by this part must be completed with the protective current interrupted unless it is impractical to do so for technical or safety reasons. Remediation of areas with insufficient cathodic protection levels or areas where protective current is found to be leaving the pipeline must be performed in accordance with paragraph (d) of this section. The operator must confirm restoration of adequate cathodic protection by close interval survey over the entire area.
(c) For onshore gas transmission pipelines, the program required by paragraph (a) of this section must include:
(1) Interference surveys for a pipeline system to detect the presence and level of any electrical stray current. Interference surveys must be taken on a periodic basis including, when there are current flow increases over pipeline segment grounding design, from any co-located pipelines, structures, or high voltage alternating current (HVAC) power lines, including from additional generation, a voltage up rating, additional lines, new or enlarged power substations, new pipelines or other structures;
(2) Analysis of the results of the survey to determine the cause of the interference and whether the level could impact the effectiveness of cathodic protection; and
(3) Implementation of remedial actions to protect the pipeline segment from detrimental interference currents
(a) For onshore transmission pipelines, each operator must develop and implement a monitoring and mitigation program to identify potentially corrosive constituents in the gas being transported and mitigate the corrosive effects. Potentially corrosive constituents include but are not limited to: carbon dioxide, hydrogen sulfide, sulfur, microbes, and free water, either by itself or in combination. Each operator must evaluate the partial pressure of each corrosive constituent by itself or in combination to evaluate the effect of the corrosive constituents on the internal corrosion of the pipe and implement mitigation measures.
(b) The monitoring and mitigation program in paragraph (a) of this section must include:
(1) At points where gas with potentially corrosive contaminants enters the pipeline, the use of gas-quality monitoring equipment to determine the gas stream constituents;
(2) Product sampling, inhibitor injections, in-line cleaning pigging, separators or other technology to mitigate the potentially corrosive gas stream constituents;
(3) Evaluation twice each calendar year, at intervals not to exceed 7
(c) If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked at least twice each calendar year, at intervals not exceeding 7
(d) Each operator must review its monitoring and mitigation program at least twice each calendar year, at intervals not to exceed 7
(c) Under paragraphs (a) and (b) of this section, the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G (incorporated by reference,
When conducting in-line inspection of pipelines required by this part, each operator must comply with the requirements and recommendations of API STD 1163,
(a) * * *
(1) It has been tested in accordance with this subpart and § 192.619, 192.620, or 192.624 to substantiate the maximum allowable operating pressure; and
(a) Each segment of an existing steel pipeline that is operated at a hoop stress level of 30% of specified minimum yield strength or more and has been found to have integrity threats that cannot be addressed by other means such as in-line inspection or direct assessment must be strength tested by a spike hydrostatic pressure test in accordance with this section to substantiate the proposed maximum allowable operating pressure.
(b) The spike hydrostatic pressure test must use water as the test medium.
(c) The baseline test pressure without the additional spike test pressure is the test pressure specified in § 192.619(a)(2), 192.620(a)(2), or 192.624, whichever applies.
(d) The test must be conducted by maintaining the pressure at or above the baseline test pressure for at least 8 hours as specified in § 192.505(e).
(e) After the test pressure stabilizes at the baseline pressure and within the first two hours of the 8-hour test interval, the hydrostatic pressure must be raised (spiked) to a minimum of the lesser of 1.50 times MAOP or 105% SMYS. This spike hydrostatic pressure test must be held for at least 30 minutes.
(f) If the integrity threat being addressed by the spike test is of a time-dependent nature such as a cracking threat, the operator must establish an appropriate retest interval and conduct periodic retests at that interval using the same spike test pressure. The appropriate retest interval and periodic tests for the time-dependent threat must be determined in accordance with the methodology in § 192.624(d).
(g)
(1) Descriptions of the technology or technologies to be used for all tests, examinations, and assessments;
(2) Procedures and processes to conduct tests, examinations, and assessments, perform evaluations, analyze defects and flaws, and remediate defects discovered;
(3) Data requirements including original design, maintenance and operating history, anomaly or flaw characterization;
(4) Assessment techniques and acceptance criteria;
(5) Remediation methods for assessment findings;
(6) Spike hydrostatic pressure test monitoring and acceptance procedures, if used;
(7) Procedures for remaining crack growth analysis and pipe segment life analysis for the time interval for additional assessments, as required; and
(8) Evidence of a review of all procedures and assessments by a subject matter expert(s) in both metallurgy and fracture mechanics.
(a) Each operator must make, and retain for the useful life of the pipeline, a record of each test performed under §§ 192.505, 192.506, and 192.507. The record must contain at least the following information:
(b) * * *
(5) Operating pipeline controls and systems and operating and maintaining pressure relieving or pressure limiting devices, including those for starting up and shutting down any part of the pipeline, so that the MAOP limit as prescribed by this part cannot be exceeded by more than the margin (build-up) allowed for operation of pressure relieving devices or pressure-limiting or control devices as specified in § 192.201, 192.620(e), 192.731, 192.739, or 192.743, whichever applies.
(a)
(1) The pipeline is located in a High Consequence Area as defined in § 192.903
(2) The pipeline is located in a class 3 or class 4 location.
(b)
(c)
(1) For line pipe and fittings, records must document diameter, wall thickness, grade (yield strength and ultimate tensile strength), chemical composition, seam type, coating type, and manufacturing specification.
(2) For valves, records must document either the applicable standards to which the component was manufactured, the manufacturing rating, or the pressure rating. For valves with pipe weld ends, records must document the valve material grade and weld end bevel condition to ensure compatibility with pipe end conditions;
(3) For flanges, records must document either the applicable standards to which the component was manufactured, the manufacturing rating, or the pressure rating, and the material grade and weld end bevel condition to ensure compatibility with pipe end conditions;
(4) For components, records must document the applicable standards to which the component was manufactured to ensure pressure rating compatibility.
(d)
(1) Develop and implement procedures for conducting non-destructive or destructive tests, examinations, and assessments for line pipe at all above ground locations.
(2) Develop and implement procedures for conducting destructive tests, examinations, and assessments for buried line pipe at all excavations associated with replacements or relocations of pipe segments that are removed from service.
(3) Develop and implement procedures for conducting non-destructive or destructive tests, examinations, and assessments for buried line pipe at all excavations associated with anomaly direct examinations,
(i) The operator must define a separate population of undocumented or inadequately documented pipeline segments for each unique combination of the following attributes: wall thicknesses (within 10 percent of the smallest wall thickness in the population), grade, manufacturing process, pipe manufacturing dates (within a two year interval) and construction dates (within a two year interval).
(ii) Assessments must be proportionally spaced throughout the pipeline segment. Each length of the pipeline segment equal to 10 percent of the total length must contain 10 percent of the total number of required excavations,
(A) 150 excavations; or
(B) If the segment is less than 150 miles, a number of excavations equal to the population's pipeline mileage (
(iii) At each excavation, tests for material properties must determine diameter, wall thickness, yield strength, ultimate tensile strength, Charpy v-notch toughness (where required for failure pressure and crack growth analysis), chemical properties, seam type, coating type, and must test for the presence of stress corrosion cracking, seam cracking, or selective seam weld corrosion using ultrasonic inspection, magnetic particle, liquid penetrant, or other appropriate non-destructive examination techniques. Determination of material property values must
(iv) If non-destructive tests are performed to determine strength or chemical composition, the operator must use methods, tools, procedures, and techniques that have been independently validated by subject matter experts in metallurgy and fracture mechanics to produce results that are accurate within 10% of the actual value with 95% confidence for strength values, within 25% of the actual value with 85% confidence for carbon percentage and within 20% of the actual value with 90% confidence for manganese, chromium, molybdenum, and vanadium percentage for the grade of steel being tested.
(v) The minimum number of test locations at each excavation or above-ground location is based on the number of joints of line pipe exposed, as follows:
(A) 10 joints or less: one set of tests for each joint.
(B) 11 to 100 joints: one set of tests for each five joints, but not less than 10 sets of tests.
(C) Over 100 joints: one set of tests for each 10 joints, but not less than 20 sets of tests.
(vi) For non-destructive tests, at each test location, a set of material properties tests must be conducted at a minimum of five places in each circumferential quadrant of the pipe for a minimum total of 20 test readings at each pipe cylinder location.
(vii) For destructive tests, at each test location, a set of materials properties tests must be conducted on each circumferential quadrant of a test pipe cylinder removed from each location, for a minimum total of four tests at each location.
(viii) If the results of all tests conducted in accordance with paragraphs (d)(3)(i) and (ii) of this section verify that material properties are consistent with all available information for each population, then no additional excavations are necessary. However, if the test results identify line pipe with properties that are not consistent with existing expectations based on all available information for each population, then the operator must perform tests at additional excavations. The minimum number of excavations that must be tested depends on the number of inconsistencies observed between as-found tests and available operator records, in accordance with the following table:
(ix) The tests conducted for a single excavation according to the requirements of paragraphs (d)(3)(iii) through (vii) of this section count as one sample under the sampling requirements of paragraphs (d)(3)(i), (ii), and (viii) of this section.
(4) For mainline pipeline components other than line pipe, the operator must develop and implement procedures for establishing and documenting the ANSI rating and material grade (to assure compatibility with pipe ends).
(i) Materials in compressor stations, meter stations, regulator stations, separators, river crossing headers, mainline valve assemblies, operator piping, or cross-connections with isolation valves from the mainline pipeline are not required to be tested for chemical and mechanical properties.
(ii) Verification of mainline material properties is required for non-line pipe components, including but not limited to, valves, flanges, fittings, fabricated assemblies, and other pressure retaining components appurtenances that are:
(A) 2-inch nominal diameter and larger; or
(B) Material grades greater than 42,000 psi (X-42); or
(C) Appurtenances of any size that are directly installed on the pipeline and cannot be isolated from mainline pipeline pressures.
(iii) Procedures for establishing material properties for non-line pipe components where records are inadequate must be based upon documented manufacturing specifications. Where specifications are not known, usage of manufacturer's stamped or tagged material pressure ratings and material type may be used to establish pressure rating. The operator must document the basis of the material properties established using such procedures.
(5) The material properties determined from the destructive or non-destructive tests required by this section cannot be used to raise the original grade or specification of the material, which must be based upon the applicable standard referenced in § 192.7.
(6) If conditions make material verification by the above methods impracticable or if the operator chooses to use “other technology” or “new technology” (alternative technical evaluation process plan), the operator must notify PHMSA at least 180 days in advance of use in accordance with paragraph § 192.624(e) of this section. The operator must submit the alternative technical evaluation process plan to the Associate Administrator of Pipeline Safety with the notification and must obtain a “no objection letter” from the Associate Administrator of Pipeline Safety prior to usage of an alternative evaluation process.
(c) Following an extreme weather event such as a hurricane or flood, an earthquake, landslide, a natural disaster, or other similar event that has the likelihood of damage to infrastructure, an operator must inspect all potentially affected onshore transmission pipeline facilities to detect conditions that could adversely affect the safe operation of that pipeline.
(1)
(2)
(3)
(i) Reducing the operating pressure or shutting down the pipeline;
(ii) Modifying, repairing, or replacing any damaged pipeline facilities;
(iii) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-way;
(iv) Performing additional patrols, surveys, tests, or inspections;
(v) Implementing emergency response activities with Federal, State, or local personnel; or
(vi) Notifying affected communities of the steps that can be taken to ensure public safety.
(a) * * *
(2) The pressure obtained by dividing the pressure to which the segment was tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the following table:
(3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part:
(4) The pressure determined by the operator to be the maximum safe pressure after considering material records, including material properties verified in accordance with § 192.607, and the history of the segment, particularly known corrosion and the actual operating pressure.
(e) Notwithstanding the requirements in paragraphs (a) through (d) of this section, onshore steel transmission pipelines that meet the criteria specified in § 192.624(a) must establish and document the maximum allowable operating pressure in accordance with § 192.624 using one or more of the following:
(1) Method 1: Pressure Test—Pressure test in accordance with § 192.624(c)(1)(i) or spike hydrostatic pressure test in accordance with § 192.624(c)(1)(ii), as applicable;
(2) Method 2: Pressure Reduction—Reduction in pipeline maximum allowable operating pressure in accordance with § 192.624(c)(2);
(3) Method 3: Engineering Critical Assessment—Engineering assessment and analysis activities in accordance with § 192.624(c)(3);
(4) Method 4: Pipe Replacement—Replacement of the pipeline segment in accordance with § 192.624(c)(4);
(5) Method 5: Pressure Reduction for Segments with Small PIR and Diameter—Reduction of maximum allowable operating pressure and other preventive measures for pipeline segments with small PIRs and diameters, in accordance with § 192.624(c)(5); or
(6) Method 6: Alternative Technology—Alternative procedure in accordance with § 192.624(c)(6).
(f) Operators must maintain all records necessary to establish and document the MAOP of each pipeline as long as the pipe or pipeline remains in service. Records that establish the pipeline MAOP, include, but are not limited to, design, construction, operation, maintenance, inspection, testing, material strength, pipe wall thickness, seam type, and other related data. Records must be reliable, traceable, verifiable, and complete.
(a)
(1) The pipeline segment has experienced a reportable in-service incident, as defined in § 191.3 of this chapter, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a cracking-related defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking and the pipeline segment is located in one of the following locations:
(i) A high consequence area as defined in § 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
(2) Pressure test records necessary to establish maximum allowable operating pressure per subpart J for the pipeline segment, including, but not limited to, records required by § 192.517(a), are not reliable, traceable, verifiable, and complete and the pipeline is located in one of the following locations:
(i) A high consequence area as defined in § 192.903; or
(ii) A class 3 or class 4 location
(3) The pipeline segment maximum allowable operating pressure was established in accordance with § 192.619(c) before
(i) A high consequence area as defined in § 192.903;
(ii) A class 3 or class 4 location; or
(iii) A moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
(b)
(1) The operator must develop and document a plan for completion of all actions required by this section by
(2) The operator must complete all actions required by this section on at least 50% of the mileage of locations that meet the conditions of § 192.624(a) by
(3) The operator must complete all actions required by this section on 100% of the mileage of locations that meet the conditions of § 192.624(a) by
(4) If operational and environmental constraints limit the operator from meeting the deadlines in § 192.614(b)(2) and (3), the operator may petition for an extension of the completion deadlines by up to one year, upon submittal of a notification to the Associate Administrator of the Office of Pipeline Safety in accordance with paragraph (e) of this section. The notification must include an up-to-date plan for completing all actions in accordance with paragraph (b)(1) of this section, the reason for the requested extension, current status, proposed completion date, remediation activities outstanding, and any needed temporary safety measures to mitigate the impact on safety.
(c)
(1)
(ii) If the pipeline segment includes legacy pipe or was constructed using legacy construction techniques or the pipeline has experienced an incident, as defined by § 191.3 of this chapter, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, a construction-, installation-, or fabrication-related defect, or a crack or crack-like defect, including, but not limited to, seam cracking, girth weld cracking, selective seam weld corrosion, hard spot, or stress corrosion cracking, then the operator must perform a spike pressure test in accordance with § 192.506. The maximum allowable operating pressure will be equal to the test pressure specified in § 192.506(c) divided by the greater of 1.25 or the applicable class location factor in § 192.619(a)(2)(ii) or § 192.620(a)(2)(ii).
(iii) If the operator has reason to believe any pipeline segment may be susceptible to cracks or crack-like defects due to assessment, leak, failure, or manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph (d) of this section.
(2)
(i) Where the pipeline segment has had a class location change in accordance with § 192.611 and pipe material and pressure test records are not available, the operator must reduce the pipeline segment MAOP as follows:
(A) For segments where a class location changed from 1 to 2, from 2 to 3, or from 3 to 4, reduce the pipeline maximum allowable operating pressure to no greater than the highest actual operating pressure sustained by the pipeline during the 18 months preceding
(B) For segments where a class location changed from 1 to 3, reduce the pipeline maximum allowable operating pressure to no greater than the highest actual operating pressure sustained by the pipeline during the 18 months preceding
(ii) If the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects due to assessment, leak, failure, or manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph (d) of this section.
(iii) Future uprating of the segment in accordance with subpart K of this part is allowed if the maximum allowable operating pressure is established using Method 2 described in paragraph (c)(2) of this section.
(iv) If an operator elects to use Method 2 described in paragraph (c)(2) of this section, but desires to use a less conservative pressure reduction factor, the operator must notify PHMSA in accordance with paragraph (e) of this section no later than seven calendar days after establishing the reduced maximum allowable operating pressure.
(A) Descriptions of the operational constraints, special circumstances, or other factors that preclude, or make it impractical, to use the pressure reduction factor specified in § 192.624(c)(2);
(B) The fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis that complies with paragraph (d) of this section;
(C) Justification that establishing maximum allowable operating pressure by another method allowed by this section is impractical;
(D) Justification that the reduced maximum allowable operating pressure determined by the operator is safe based on analysis of the condition of the pipeline segment, including material records, material properties verified in accordance § 192.607, and the history of the segment, particularly known corrosion and leakage, and the actual operating pressure, and additional compensatory preventive and mitigative measures taken or planned.
(E) Planned duration for operating at the requested maximum allowable operating pressure, long term remediation measures and justification of this operating time interval, including fracture mechanics modeling for failure stress pressures and cyclic fatigue growth analysis and other validated forms of engineering analysis that have been reviewed and confirmed by subject matter experts in metallurgy and fracture mechanics.
(3)
(i)
(B) The ECA must analyze any cracks or crack-like defects remaining in the pipe, or that could remain in the pipe, to determine the predicted failure pressure (PFP) of each defect. The ECA must use the techniques and procedures in Battelle Final Reports (“Battelle's Experience with ERW and Flash Weld Seam Failures: Causes and Implications”—Task 1.4), Report No. 13-002 (“Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams”—Subtask 2.4), Report No. 13-021 (“Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue”—Subtask 2.5) and (“Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1”—Task 4.5) (incorporated by reference,
(C) The ECA must analyze any metal loss defects not associated with a dent including corrosion, gouges, scrapes or other metal loss defects that could remain in the pipe to determine the predicted failure pressure (PFP). ASME/ANSI B31G (incorporated by reference, see § 192.7) or AGA Pipeline Research Committee Project PR-3-805 (“RSTRENG,” incorporated by reference, see § 192.7) must be used for corrosion defects. Both procedures apply to corroded regions that do not penetrate the pipe wall over 80 percent of the wall thickness and are subject to the limitations prescribed in the equations procedures. The ECA must use conservative assumptions for metal loss dimensions (length, width, and depth). When determining PFP for gouges, scrapes, selective seam weld corrosion, crack-related defects, or any defect within a dent, appropriate failure criteria and justification of the criteria must be used. If SMYS or actual material yield and ultimate tensile strength is not known or not adequately documented by reliable, traceable, verifiable, and complete records, then the operator must assume grade A pipe or determine the material properties based upon the material documentation program specified in § 192.607.
(D) The ECA must analyze interacting defects to conservatively determine the most limiting PFP for interacting defects. Examples include but are not limited to, cracks in or near locations with corrosion metal loss, dents with gouges or other metal loss, or cracks in or near dents or other deformation damage. The ECA must document all evaluations and any assumptions used in the ECA process.
(E) The maximum allowable operating pressure must be established at the lowest PFP for any known or postulated defect, or interacting defects, remaining in the pipe divided by the greater of 1.25 or the applicable factor listed in § 192.619(a)(2)(ii) or § 192.620(a)(2)(ii).
(ii)
(iii)
(A) In lieu of the tools specified in paragraph § 192.624(c)(3)(i), an operator may use “other technology” if it is validated by a subject matter expert in metallurgy and fracture mechanics to produce an equivalent understanding of the condition of the pipe. If an operator elects to use “other technology,” it must notify the Associate Administrator of Pipeline Safety, at least 180 days prior to use, in accordance with paragraph (e) of this section and receive a “no objection letter” from the Associate Administrator of Pipeline Safety prior to its usage. The “other technology” notification must have:
(
(
(B) If the operator has information that indicates a pipeline includes segments that might be susceptible to hard spots based on assessment, leak, failure, manufacturing vintage history, or other information, then the ILI program must include a tool that can detect hard spots.
(C) If the pipeline has had a reportable incident, as defined in § 192.3, attributed to a girth weld failure since its most recent pressure test, then the ILI program must include a tool that can detect girth weld defects unless the ECA analysis performed in accordance with paragraph § 192.624(c)(3)(iii) includes an engineering evaluation program to analyze the susceptibility of girth weld failure due to lateral stresses.
(D) Inline inspection must be performed in accordance with § 192.493.
(E) All MFL and deformation tools used must have been validated to characterize the size of defects within 10% of the actual dimensions with 90% confidence. All EMAT or UT tools must have been validated to characterize the size of cracks, both length and depth, within 20% of the actual dimensions with 80% confidence, with like-similar analysis from prior tool runs done to ensure the results are consistent with the required corresponding hydrostatic test pressure for the segment being evaluated.
(F) Interpretation and evaluation of assessment results must meet the requirements of §§ 192.710, 192.713, and subpart O of this part, and must conservatively account for the accuracy and reliability of ILI, in-the-ditch examination methods and tools, and any other assessment and examination results used to determine the actual sizes of cracks, metal loss, deformation and other defect dimensions by applying the most conservative limit of the tool tolerance specification. ILI and in-the-ditch examination tools and procedures for crack assessments (length, depth, and volumetric) must have performance and evaluation standards confirmed for accuracy through confirmation tests for the type defects and pipe material vintage being evaluated. Inaccuracies must be accounted for in the procedures for evaluations and fracture mechanics models for predicted failure pressure determinations.
(G) Anomalies detected by ILI assessments must be repaired in accordance with applicable repair criteria in §§ 192.713 and 192.933.
(iv) If the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects due to assessment, leak, failure, or manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph § 192.624(d).
(4)
(5)
(i) Reduce the pipeline maximum allowable operating pressure to no greater than the highest actual operating pressure sustained by the pipeline during 18 months preceding
(ii) Conduct external corrosion direct assessment in accordance with § 192.925, and internal corrosion direct assessment in accordance with § 192.927;
(iii) Develop and implement procedures for conducting non-destructive tests, examinations, and assessments for cracks and crack-like defects, including but not limited to stress corrosion cracking, selective seam weld corrosion, girth weld cracks, and seam defects, for pipe at all excavations associated with anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, or any other reason for which the pipe segment is exposed, except for segments exposed during excavation activities that are in compliance with § 192.614;
(iv) Conduct monthly patrols in Class 1 and 2 locations, at an interval not to exceed 45 days; weekly patrols in Class 3 locations not to exceed 10 days; and semi-weekly patrols in Class 4 locations, at an interval not to exceed six days, in accordance with § 192.705;
(v) Conduct monthly, instrumented leakage surveys in Class 1 and 2 locations, at intervals not to exceed 45 days; weekly leakage surveys in Class 3 locations at intervals not to exceed 10 days; and semi-weekly leakage surveys in Class 4 locations, at intervals not to exceed six days, in accordance with § 192.706; and
(vi) Odorize gas transported in the segment, in accordance with § 192.625;
(vii) If the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects due to assessment, leak, failure, or manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph § 192.624(d).
(viii) Under Method 5 described in paragraph (c)(5) of this section, future uprating of the segment in accordance with subpart K of this part is allowed.
(6)
(i) Descriptions of the technology or technologies to be used for tests, examinations, and assessments, establishment of material properties, and analytical techniques, with like-similar analysis from prior tool runs done to ensure the results are consistent with the required corresponding hydrostatic test pressure for the segment being evaluated.
(ii) Procedures and processes to conduct tests, examinations, and assessments, perform evaluations, analyze defects and flaws, and remediate defects discovered;
(iii) Methodology and criteria used to determine reassessment period or need for a reassessment including references to applicable regulations from this part and industry standards;
(iv) Data requirements including original design, maintenance and operating history, anomaly or flaw characterization;
(v) Assessment techniques and acceptance criteria, including anomaly detection confidence level, probability of detection, and uncertainty of PFP quantified as a fraction of specified minimum yield strength;
(vi) If the operator has reason to believe any pipeline segment contains or may be susceptible to cracks or crack-like defects due to assessment, leak, failure, or manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph (d) of this section;
(vii) Remediation methods with proven technical practice;
(viii) Schedules for assessments and remediation;
(ix) Operational monitoring procedures;
(x) Methodology and criteria used to justify and establish the maximum allowable operating pressure; and
(xi) Documentation requirements for the operator's process, including records to be generated.
(d)
(i) For an assessment using a hydrostatic pressure test use a full size equivalent Charpy upper-shelf energy level of 120 ft-lb and a flow stress equal to the minimum specified ultimate tensile strength of the base pipe material. The purpose of using the high level of Charpy energy and flow stress (equal to the ultimate tensile strength) is for an operator to calculate the largest defects that could have survived a given level of hydrostatic test. The resulting maximum-size defects lead to the shortened predicted times to failure,
(ii) For ILI assessments unless actual ranges of values of strength and toughness are known, the analysis must use the specified minimum yield strength and the specified minimum ultimate tensile strength and Charpy toughness valves lower than or equal to: 5.0 ft-lb for body cracks; 1.0 ft-lb for ERW seam bond line defects such as cold weld, lack of fusion, and selective seam weld corrosion defects.
(iii) The sensitivity analysis to determine the time to failure for a crack must include operating history, pressure tests, pipe geometry, wall thickness, strength level, flow stress, and operating environment for the pipe segment being assessed, including at a minimum the role of the pressure-cycle spectrum.
(2) If actual material toughness is not known or not adequately documented for fracture mechanics modeling for failure stress pressure, the operator must use a conservative Charpy energy value to determine the toughness based upon the material documentation program specified in § 192.607; or use maximum Charpy energy values of 5.0 ft-lb for body cracks; 1.0 ft-lb for cold weld, lack of fusion, and selective seam weld corrosion defects as documented in Battelle Final Reports (“Battelle's Experience with ERW and Flash Weld Seam Failures: Causes and Implications”—Task 1.4), No. 13-002 (“Models for Predicting Failure Stress Levels for Defects Affecting ERW and Flash-Welded Seams”—Subtask 2.4), Report No. 13-021 (“Predicting Times to Failure for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue”—Subtask 2.5) and (“Final Summary Report and Recommendations for the Comprehensive Study to Understand Longitudinal ERW Seam Failures—Phase 1”—Task 4.5) (incorporated by reference,
(3) The analysis must account for metallurgical properties at the location being analyzed (such as in the properties of the parent pipe, weld heat affected zone, or weld metal bond line), and must account for the likely failure mode of anomalies (such as brittle fracture, ductile fracture or both). If the likely failure mode is uncertain or unknown, the analysis must analyze both failure modes and use the more conservative result. Appropriate fracture
(4) If the predicted remaining life of the pipeline calculated by this analysis is 5 years or less, then the operator must perform a pressure test in accordance with paragraph (c)(1) of this section or reduce the maximum allowable operating pressure of the pipeline in accordance with paragraph (c)(2) of this section to establish the maximum allowable operating pressure within 1-year of analysis;
(5) The operator must re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated by this analysis has expired, but within 15 years. The operator must determine and document if further pressure tests or use of other methods are required at that time. The operator must continue to re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated in the most recent evaluation has expired. If the analysis results show that a 50% remaining life reduction does not give a sufficient safety factor based upon technical evaluations then a more conservative remaining life safety factor must be used.
(6) The analysis required by this paragraph (d) of this section must be reviewed and confirmed by a subject matter expert in both metallurgy and fracture mechanics.
(e)
(1) Sending the notification to the Office of Pipeline Safety, Pipeline and Hazardous Material Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue SE., Washington, DC 20590-0001;
(2) Sending the notification to the Information Resources Manager by facsimile to (202) 366-7128; or
(3) Sending the notification to the Information Resources Manager by email to
(4) An operator must also send a copy to a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
(f)
(a)
(i) A class 3 or class 4 location; or
(ii) A moderate consequence area as defined in § 192.3 if the pipe segment can accommodate inspection by means of instrumented inline inspection tools (
(2) This section does not apply to a pipeline segment located in a high consequence area as defined in § 192.903.
(b)
(2)
(3)
(c)
(1) Internal inspection tool or tools capable of detecting corrosion, deformation and mechanical damage (including dents, gouges and grooves), material cracking and crack-like defects (including stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots, and any other threats to which the segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with § 192.493;
(2) Pressure test conducted in accordance with subpart J of this part. The use of pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms, manufacturing and related defect threats, including defective pipe and pipe seams, dents and other forms of mechanical damage;
(3) “Spike” hydrostatic pressure test in accordance with § 192.506;
(4) Excavation and
(5) Guided wave ultrasonic testing (GWUT) as described in appendix F;
(6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. Use of direct assessment is allowed only if the line is not capable of inspection by internal inspection tools and is not practical to assess (due to low operating pressures and flows, lack of inspection technology, and critical delivery areas such as hospitals and nursing homes) using the methods specified in paragraphs (d)(1) through (5) of this section. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in §§ 192.925, 192.927 or 192.929; or
(7) Other technology or technologies that an operator demonstrates can provide an equivalent understanding of the line pipe for each of the threats to which the pipeline is susceptible.
(8) For segments with MAOP less than 30% of the SMYS, an operator must assess for the threats of external and internal corrosion, as follows:
(i)
(A)
(B)
(
(
(ii)
(A) Conduct a gas analysis for corrosive agents at least twice each calendar year;
(B) Conduct periodic testing of fluids removed from the segment. At least once each calendar year test the fluids removed from each storage field that may affect a segment; and
(C) At least every seven (7) years, integrate data from the analysis and testing required by paragraphs (c)(8)(ii)(A) and (B) of this section with applicable internal corrosion leak records, incident reports, safety-related condition reports, repair records, patrol records, exposed pipe reports, and test records, and define and implement appropriate remediation actions.
(d)
(e)
(f)
(g)
(b) * * *
(1)
(a)
(b)
(c)
(1) Removed by cutting out and replacing a cylindrical piece of pipe; or
(2) Repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe.
(d)
(1)
(i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1.1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining strength calculation. These documents are incorporated by reference and available at the addresses listed in § 192.7(c). Pipe and material properties used in remaining strength calculations must be documented in reliable, traceable, verifiable, and complete records. If such records are not available, pipe and material properties used in the remaining strength calculations must be based on properties determined and documented in accordance with § 192.607.
(ii) A dent that has any indication of metal loss, cracking or a stress riser.
(iii) Metal loss greater than 80% of nominal wall regardless of dimensions.
(iv) An indication of metal-loss affecting a detected longitudinal seam, if that seam was formed by direct current or low-frequency or high frequency electric resistance welding or by electric flash welding.
(v) Any indication of significant stress corrosion cracking (SCC).
(vi) Any indication of significant selective seam weld corrosion (SSWC).
(vii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(2) Until the remediation of a condition specified in paragraph (d)(1) of this section is complete, an operator must reduce the operating pressure of the affected pipeline to the lower of:
(i) A level that restores the safety margin commensurate with the design factor for the Class Location in which the affected pipeline is located, determined using ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)) (“RSTRENG,” incorporated by reference, see § 192.7) for corrosion defects. Both procedures apply to corroded regions that do not penetrate the pipe wall over 80 percent of the wall thickness and are subject to the limitations prescribed in the equations procedures. When determining the predicted failure pressure (PFP) for gouges, scrapes, selective seam weld corrosion, crack-related defects, appropriate failure criteria and justification of the criteria must be used. If SMYS or actual material yield and ultimate tensile strength is not known or not adequately documented by reliable, traceable, verifiable, and complete records, then the operator must assume grade A pipe or determine the material properties based upon the material documentation program specified in § 192.607; or
(ii) 80% of pressure at the time of discovery, whichever is lower.
(3)
(i) A smooth dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than nominal pipe size (NPS) 12).
(ii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal or helical (spiral) seam weld.
(iii) A calculation of the remaining strength of the pipe shows a predicted failure pressure ratio (FPR) at the location of the anomaly less than or equal to 1.25 for Class 1 locations, 1.39 for Class 2 locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations. This calculation must adequately account for the uncertainty associated with the accuracy of the tool used to perform the assessment.
(iv) An area of corrosion with a predicted metal loss greater than 50% of nominal wall.
(v) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.
(vi) A gouge or groove greater than 12.5% of nominal wall.
(vii) Any indication of crack or crack-like defect other than an immediate condition.
(4)
(i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12) located between the 4 o'clock position and the 8 o'clock position (bottom 1/3 of the pipe).
(ii) A dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than nominal pipe size (NPS) 12), and engineering analyses of the dent demonstrate critical strain levels are not exceeded.
(e)
(f)
Any launcher or receiver used after
(k) A management of change process as required by § 192.13(d).
(a)
(1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking;
(2) Stable threats, such as manufacturing, welding/fabrication, or equipment defects;
(3) Time independent threats such as third party/mechanical damage, incorrect operational procedure, weather related and outside force, including consideration of seismicity, geology, and soil stability of the area; and
(4) Human error such as operational mishaps and design and construction mistakes.
(b)
(1) Integrate information about pipeline attributes and other relevant information, including, but not limited to:
(i) Pipe diameter, wall thickness, grade, seam type and joint factor;
(ii) Manufacturer and manufacturing date, including manufacturing data and records;
(iii) Material properties including, but not limited to, diameter, wall thickness, grade, seam type, hardness, toughness, hard spots, and chemical composition;
(iv) Equipment properties;
(v) Year of installation;
(vi) Bending method;
(vii) Joining method, including process and inspection results;
(viii) Depth of cover surveys including stream and river crossings, navigable waterways, and beach approaches;
(ix) Crossings, casings (including if shorted), and locations of foreign line crossings and nearby high voltage power lines;
(x) Hydrostatic or other pressure test history, including test pressures and test leaks or failures, failure causes, and repairs;
(xi) Pipe coating methods (both manufactured and field applied) including method or process used to apply girth weld coating, inspection reports, and coating repairs;
(xii) Soil, backfill;
(xiii) Construction inspection reports, including but not limited to:
(A) Girth weld non-destructive examinations;
(B) Post backfill coating surveys;
(C) Coating inspection (“jeeping”) reports;
(xiv) Cathodic protection installed, including but not limited to type and location;
(xv) Coating type;
(xvi) Gas quality;
(xvii) Flow rate;
(xviii) Normal maximum and minimum operating pressures, including maximum allowable operating pressure (MAOP);
(xix) Class location;
(xx) Leak and failure history including any in-service ruptures or leaks from incident reports, abnormal operations, safety related conditions (both reported and unreported) and failure investigations required by § 192.617, and their identified causes and consequences;
(xxi) Coating condition;
(xxii) CP system performance;
(xxiii) Pipe wall temperature;
(xxiv) Pipe operational and maintenance inspection reports, including but not limited to:
(A) Data gathered through integrity assessments required under this part, including but not limited to in-line inspections, pressure tests, direct assessment, guided wave ultrasonic testing, or other methods;
(B) Close interval survey (CIS) and electrical survey results;
(C) Cathodic protection (CP) rectifier readings;
(D) CP test point survey readings and locations;
(E) AC/DC and foreign structure interference surveys;
(F) Pipe coating surveys, including surveys to detect coating damage, disbonded coatings, or other conditions that compromise the effectiveness of corrosion protection, including but not limited to direct current voltage gradient or alternating current voltage gradient inspections;
(G) Results of examinations of exposed portions of buried pipelines (
(H) Stress corrosion cracking (SCC) excavations and findings;
(I) Selective seam weld corrosion (SSWC) excavations and findings;
(J) Gas stream sampling and internal corrosion monitoring results, including cleaning pig sampling results;
(xxv) Outer Diameter/Inner Diameter corrosion monitoring;
(xxvi) Operating pressure history and pressure fluctuations, including analysis of effects of pressure cycling and instances of exceeding MAOP by any amount;
(xxvii) Performance of regulators, relief valves, pressure control devices, or any other device to control or limit operating pressure to less than MAOP;
(xxviii) Encroachments and right-of-way activity, including but not limited to, one-call data, pipe exposures resulting from encroachments, and excavation activities due to development or planned development along the pipeline;
(xxix) Repairs;
(xxx) Vandalism;
(xxxi) External forces;
(xxxii) Audits and reviews;
(xxxiii) Industry experience for incident, leak and failure history;
(xxxiv) Aerial photography;
(xxxv) Exposure to natural forces in the area of the pipeline, including seismicity, geology, and soil stability of the area; and
(xxxvi) Other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this part.
(2) Use objective, traceable, verified, and validated information and data as inputs, to the maximum extent practicable. If input is obtained from subject matter experts (SMEs), the operator must employ measures to adequately correct any bias in SME input. Bias control measures may include training of SMEs and use of outside technical experts (independent expert reviews) to assess quality of processes and the judgment of SMEs. Operator must document the names of all SMEs and information submitted by the SMEs for the life of the pipeline.
(3) Identify and analyze spatial relationships among anomalous information (
(4) Analyze the data for interrelationships among pipeline integrity threats, including combinations of applicable risk factors that increase the likelihood of incidents or increase the potential consequences of incidents.
(c)
(1) Analyze how a potential failure could affect high consequence areas, including the consequences of the entire worst-case incident scenario from initial failure to incident termination;
(2) Analyze the likelihood of failure due to each individual threat or risk factor, and each unique combination of threats or risk factors that interact or simultaneously contribute to risk at a common location;
(3) Lead to better understanding of the nature of the threat, the failure mechanisms, the effectiveness of currently deployed risk mitigation activities, and how to prevent, mitigate, or reduce those risks;
(4) Account for, and compensate for, uncertainties in the model and the data used in the risk assessment; and
(5) Evaluate the potential risk reduction associated with candidate risk reduction activities such as preventive and mitigative measures and reduced anomaly remediation and assessment intervals.
(d)
(e) * * *
(2)
(3)
(i) The segment has experienced an in-service incident, as described in § 192.624(a)(1);
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
(4)
(a)
(1) Internal inspection tool or tools capable of detecting corrosion, deformation and mechanical damage (including dents, gouges and grooves), material cracking and crack-like defects (including stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with § 192.493. A person qualified by knowledge, training, and experience must analyze the data obtained from an internal inspection tool to determine if a condition could adversely affect the safe operation of the pipeline. In addition, an operator must explicitly consider uncertainties in reported results (including, but not limited to, tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies;
(2) Pressure test conducted in accordance with subpart J of this part. An operator must use the test pressures specified in table 3 of section 5 of ASME/ANSI B31.8S to justify an extended reassessment interval in accordance with § 192.939. The use of pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms, manufacturing and related defect threats, including defective pipe
(3) “Spike” hydrostatic pressure test in accordance with § 192.506. The use of spike hydrostatic pressure testing is appropriate for threats such as stress corrosion cracking, selective seam weld corrosion, manufacturing and related defects, including defective pipe and pipe seams, and other forms of defect or damage involving cracks or crack-like defects;
(4) Excavation and
(5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in Appendix F;
(6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. Use of direct assessment is allowed only if the line is not capable of inspection by internal inspection tools and is not practical to assess using the methods specified in paragraphs (d)(1) through (5) of this section. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in § 192.925, 192.927, or 192.929; or
(7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with § 192.949 and receive a “no objection letter” from the Associate Administrator of Pipeline Safety. An operator must also notify the appropriate State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(b) * * *
(2) NACE SP0206-2006 and § 192.927 if addressing internal corrosion (ICDA).
(3) NACE SP0204-2008 and § 192.929 if addressing stress corrosion cracking (SCCDA).
(b)
(c)
(1)
(2)
(3)
(i) Evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with § 192.933, if the condition is in a covered segment,
(ii) Expand the detailed examination program, whenever internal corrosion is discovered, to determine all locations that have internal corrosion within the ICDA region, and accurately characterize the nature, extent, and root cause of the internal corrosion. In cases where the internal corrosion was identified within the ICDA region but outside the covered segment, the expanded detailed examination program must also include at least two detailed examinations within each covered segment associated with the ICDA region, at the location within the covered segment(s) most likely to have internal corrosion. One location must be the low point (
(iii) Expand the detailed examination program to evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) in the operator's pipeline system with similar characteristics to the ICDA region in which the corrosion was found and remediate identified instances of internal corrosion in accordance with § 192.933 or § 192.713, as appropriate.
(4)
(i) Evaluating the effectiveness of ICDA as an assessment method for addressing internal corrosion and determining whether a covered segment should be reassessed at more frequent intervals than those specified in § 192.939. An operator must carry out this evaluation within a year of conducting an ICDA;
(ii) Validation of the flow modeling calculations by comparison of actual locations of discovered internal corrosion with locations predicted by the model (if the flow model cannot be validated, then ICDA is not feasible for the segment); and
(iii) Continually monitoring each ICDA region which contains a covered segment where internal corrosion has been identified by using techniques such as coupons or UT sensors or electronic probes, and by periodically drawing off liquids at low points and chemically analyzing the liquids for the presence of corrosion products. An operator must base the frequency of the monitoring and liquid analysis on results from all integrity assessments that have been conducted in accordance with the requirements of this subpart, and risk factors specific to the ICDA region. At a minimum, the monitoring frequency must be two times each calendar year, but at intervals not exceeding 7
(A) Conduct excavations of, and detailed examinations at, locations downstream from where the electrolyte might have entered the pipe to investigate and accurately characterize the nature, extent, and root cause of the corrosion, including the monitoring and mitigation requirements of § 192.478; or
(B) Assess the covered segment using ILI tools capable of detecting internal corrosion.
(5)
(i) Criteria an operator will apply in making key decisions (
(ii) Provisions that analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of § 192.933 may be limited to covered segments.
(a)
(b)
(1)
(i) The effects of a carbonate-bicarbonate environment, including the implications of any factors that promote the production of a carbonate-bicarbonate environment such as soil temperature, moisture, the presence or generation of carbon dioxide, and/or Cathodic Protection (CP).
(ii) The effects of cyclic loading conditions on the susceptibility and propagation of SCC in both high-pH and near-neutral-pH environments.
(iii) The effects of variations in applied CP such as overprotection, CP loss for extended periods, and high negative potentials.
(iv) The effects of coatings that shield CP when disbonded from the pipe.
(v) Other factors which affect the mechanistic properties associated with SCC including but not limited to historical and present-day operating pressures, high tensile residual stresses, flowing product temperatures, and the presence of sulfides.
(2)
(3)
(4)
(i) Removing the pipe with SCC, remediating the pipe with a Type B sleeve, hydrostatic testing in accordance with (b)(4)(ii), below, or by grinding out the SCC defect and repairing the pipe. If grinding is used for repair, the repair procedure must include: Nondestructive testing for any remaining cracks or other defects; measuring remaining wall thickness; and the remaining strength of the pipe at the repair location must be determined using ASME/ANSI B31G or RSTRENG and must be sufficient to meet the design requirements of subpart C of this part. Pipe and material properties used in remaining strength calculations must be documented in reliable, traceable, verifiable, and complete records. If such records are not available, pipe and material properties used in the remaining strength calculations must be based on properties determined and documented in accordance with § 192.607.
(ii) Significant SCC must be mitigated using a hydrostatic testing program to a minimum test pressure equal to 105 percent of the specified minimum yield strength of the pipe for 30 minutes immediately followed by a pressure test in accordance with § 192.506, but not lower than 1.25 times MAOP. The test pressure for the entire sequence must be continuously maintained for at least 8 hours, in accordance with § 192.506 and must be above the minimum test factors in § 192.619(a)(2)(ii) or 192.620(a)(2)(ii), but not lower than 1.25 times maximum allowable operating pressure. Any test failures due to SCC must be repaired by replacement of the pipe segment, and the segment re-tested until the pipe passes the complete test without leakage. Pipe segments that have SCC present, but that pass the pressure test, may be repaired by grinding in accordance with paragraph (b)(4)(i) of this section.
(5)
(i) Evaluation of discovered crack clusters during the direct examination step in accordance with NACE RP0204-2008, sections 5.3.5.7, 5.4, and 5.5;
(ii) Conditions conducive to creation of the carbonate-bicarbonate environment;
(iii) Conditions in the application (or loss) of CP that can create or exacerbate SCC;
(iv) Operating temperature and pressure conditions including operating stress levels on the pipe;
(v) Cyclic loading conditions;
(vi) Mechanistic conditions that influence crack initiation and growth rates;
(vii) The effects of interacting crack clusters;
(viii) The presence of sulfides; and.
(ix) Disbonded coatings that shield CP from the pipe.
(a) * * *
(1)
(b)
(d) * * *
(1)
(i) Calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1.1 times the maximum allowable operating pressure at the location of the anomaly for any class location. Suitable
(ii) A dent that has any indication of metal loss, cracking, or a stress riser.
(iii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(iv) Metal loss greater than 80% of nominal wall regardless of dimensions.
(v) An indication of metal-loss affecting a detected longitudinal seam, if that seam was formed by direct current, low-frequency, or high frequency electric resistance welding or by electric flash welding.
(vi) Any indication of significant stress corrosion cracking (SCC).
(vii) Any indication of significant selective seam weld corrosion (SSWC).
(2)
(iii) A calculation of the remaining strength of the pipe shows a predicted failure pressure ratio at the location of the anomaly less than or equal to 1.25 for Class 1 locations, 1.39 for Class 2 locations, 1.67 for Class 3 locations, and 2.00 for Class 4 locations.
(iv) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.
(v) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.
(vi) A gouge or groove greater than 12.5% of nominal wall.
(vii) Any indication of crack or crack-like defect other than an immediate condition.
(a)
(b) * * *
(2)
(d) * * *
(3) Perform semi-annual, instrumented leak surveys (quarterly for unprotected pipelines or cathodically protected pipe where indirect assessments,
(f)
(1) Monitor for, and mitigate the presence of, deleterious gas stream constituents.
(2) At points where gas with potentially deleterious contaminants enters the pipeline, use filter separators or separators and continuous gas quality monitoring equipment.
(3) At least once per quarter, use gas quality monitoring equipment that includes, but is not limited to, a moisture analyzer, chromatograph, carbon dioxide sampling, and hydrogen sulfide sampling.
(4) Use cleaning pigs and sample accumulated liquids and solids, including tests for microbiologically induced corrosion.
(5) Use inhibitors when corrosive gas or corrosive liquids are present.
(6) Address potentially corrosive gas stream constituents as specified in § 192.478(a), where the volumes exceed these amounts over a 24-hour interval in the pipeline as follows:
(i) Limit carbon dioxide to three percent by volume;
(ii) Allow no free water and otherwise limit water to seven pounds per million cubic feet of gas; and
(iii) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet (16 ppm) of gas. If the hydrogen sulfide concentration is greater than 0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor injection program to address deleterious gas stream constituents, including follow-up sampling and quality testing of liquids at receipt points.
(7) Review the program at least semi-annually based on the gas stream experience and implement adjustments to monitor for, and mitigate the presence of, deleterious gas stream constituents.
(g)
(1) Control electrical interference currents that can adversely affect cathodic protection as follows:
(i) As frequently as needed (such as when new or uprated high voltage alternating current power lines greater than or equal to 69 kVA or electrical substations are co-located near the pipeline), but not to exceed every seven years, perform the following:
(A) Conduct an interference survey (at times when voltages are at the highest values for a time period of at least 24-hours) to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected;
(B) Analyze the results of the survey to identify locations where interference currents are greater than or equal to 20 Amps per meter squared; and
(C) Take any remedial action needed within six months after completing the survey to protect the pipeline segment from deleterious current. Remedial action means the implementation of measures including, but not limited to, additional grounding along the pipeline to reduce interference currents. Any location with interference currents greater than 50 Amps per meter squared must be remediated. If any AC interference between 20 and 50 Amps per meter squared is not remediated, the operator must provide and document an engineering justification.
(2) Confirm the adequacy of external corrosion control through indirect assessment as follows:
(i) Periodically (as frequently as needed but at intervals not to exceed seven years) assess the adequacy of the cathodic protection through an indirect method such as close-interval survey, and the integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG).
(ii) Remediate any damaged coating with a voltage drop classified as moderate or severe (IR drop greater than 35% for DCVG or 50 dBµv for ACVG) under section 4 of NACE RP0502-2008 (incorporated by reference, see § 192.7).
(iii) Integrate the results of the indirect assessment required under paragraph (g)(2)(i) of this section with the results of the most recent integrity assessment required by this subpart and promptly take any needed remedial actions no later than 6 months after assessment finding.
(iv) Perform periodic assessments as follows:
(A) Conduct periodic close interval surveys with current interrupted to confirm voltage drops in association with integrity assessments under sections §§ 192.921 and 192.937 of this subpart.
(B) Locate pipe-to-soil test stations at half-mile intervals within each covered segment, ensuring at least one station is within each high consequence area, if practicable.
(C) Integrate the results with those of the baseline and periodic assessments for integrity done under sections §§ 192.921 and 192.937 of this subpart.
(3) Control external corrosion through cathodic protection as follows:
(i) If an annual test station reading indicates cathodic protection below the level of protection required in subpart I of this part, complete assessment and remedial action, as required in § 192.465(f), within 6 months of the failed reading or notify each PHMSA pipeline safety regional office where the pipeline is in service and demonstrate that the integrity of the pipeline is not compromised if the repair takes longer than 6 months. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and
(ii) Remediate insufficient cathodic protection levels or areas where protective current is found to be leaving the pipeline in accordance with paragraph (g)(3)(i) of this section, including use of indirect assessments or direct examination of the coating in areas of low CP readings unless the reason for the failed reading is determined to be a short to an adjacent foreign structure, rectifier connection or power input problem that can be remediated and restoration of adequate cathodic protection can be verified. The operator must confirm restoration of adequate corrosion control by a close interval survey on both sides of the affected test stations to the adjacent test stations.
(b)
(c)
(1) Internal inspection tool or tools capable of detecting corrosion, deformation and mechanical damage (including dents, gouges and grooves), material cracking and crack-like defects (including stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with § 192.493. A person qualified by knowledge, training, and experience must analyze the data obtained from an assessment performed under paragraph (b) of this section to determine if a condition could adversely affect the safe operation of the pipeline. In addition, an operator must explicitly consider uncertainties in reported results (including, but not limited to, tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying tool performance) in identifying and characterizing anomalies.
(2) Pressure test conducted in accordance with subpart J of this part.
(3) “Spike” hydrostatic pressure test in accordance with § 192.506. The use of spike hydrostatic pressure testing is appropriate for threats such as stress corrosion cracking, selective seam weld corrosion, manufacturing and related defects, including defective pipe and pipe seams, and other forms of defect or damage involving cracks or crack-like defects.
(4) Excavation and
(5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in Appendix F;
(6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. Use of direct assessment is allowed only if the line is not capable of inspection by internal inspection tools and is not practical to assess using the methods specified in paragraphs (c)(1) through (5) of this section. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with the applicable requirements specified in § 192.925, 192.927, or 192.929;
(7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with § 192.949 and receive a “no objection letter” from the Associate Administrator of Pipeline Safety. An operator must also notify the appropriate State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(8) Confirmatory direct assessment when used on a covered segment that is scheduled for reassessment at a period longer than seven years. An operator using this reassessment method must comply with § 192.931.
(a)
(b) * * *
(1)
(2)
Appendix A summarizes the part 192 records retention requirements. As required by § 192.13(e), records must be readily retrievable and must be reliable, traceable, verifiable, and complete.
I.
A.
(1) A negative (cathodic) voltage across the structure electrolyte boundary of at least 0.85 volt, with reference to a saturated copper-copper sulfate reference electrode, often referred to as a half cell. Determination of this voltage must be made in accordance with sections II and IV of this appendix.
(2) A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix.
B.
(1) Except as provided in paragraphs B(2) and (3) of this section, a minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix.
(2) Notwithstanding the minimum criteria in paragraph B(1) of this section, if aluminum is cathodically protected at voltages in excess of 1.20 volts as measured with reference to a copper-copper sulfate reference electrode, in accordance with section II of this appendix, the aluminum may suffer corrosion resulting from the build-up of alkali on the metal surface. A voltage in excess of 1.20 volts may not be used unless previous test results indicate no appreciable corrosion will occur in the particular environment.
(3) Since aluminum may suffer from corrosion under high pH conditions, and since application of cathodic protection tends to increase the pH at the metal surface, careful investigation or testing must be made before applying cathodic protection to stop pitting attack on aluminum structures in environments with a natural pH in excess of 8.
C.
D.
II.
III.
IV.
A. Except as provided in paragraphs B and C of this section, negative (cathodic) voltage must be measured between the structure surface and a saturated copper-copper sulfate reference electrode contacting the electrolyte.
B. Other standard reference electrodes may be substituted for the saturated copper-copper sulfate electrode. Two commonly used reference electrodes are listed below along with their voltage equivalent to −0.85 volt as referred to a saturated copper-copper sulfate reference electrode:
(1) Saturated KCL calomel half cell:−0.78 volt.
(2) Silver-silver chloride reference electrode used in sea water: −0.80 volt.
C. In addition to the standard reference electrode, an alternate metallic material or structure may be used in place of the saturated copper-copper sulfate reference electrode if its potential stability is assured and if its voltage equivalent referred to a saturated copper-copper sulfate reference electrode is established.
This appendix defines criteria which must be properly implemented for use of Guided Wave Ultrasonic Testing (GWUT) as an integrity assessment method. Any application of GWUT that does not conform to these criteria is considered “other technology” as described by §§ 192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which OPS must be notified 180 days prior to use in accordance with § 192.921(a)(7) or 192.937(c)(7). GWUT in the “Go-No Go” mode means that all indications (wall loss anomalies) above the testing threshold (a maximum of 5% of cross sectional area (CSA) sensitivity) be directly examined, in-line tool inspected, pressure tested or replaced prior to completing the integrity assessment on the cased carrier pipe.
I.
II.
III.
IV.
A. The detection sensitivity threshold determines the ability to identify a cross sectional change. The maximum threshold sensitivity cannot be greater than 5% of the cross sectional area (CSA).
B. The locations and estimated CSA of all metal loss features in excess of the detection threshold must be determined and documented.
C. All defect indications in the “Go-No Go” mode above the 5% testing threshold must be directly examined, in-line inspected, pressure tested, or replaced prior to completing the integrity assessment.
V.
VI.
VII.
A. The Distance Amplitude Correction curve accounts for coating, pipe diameter, pipe wall and environmental conditions at the assessment location. The DAC curve must be set for each inspection as part of establishing the effective range of a GWUT inspection.
B. DAC curves provide a means for evaluating the cross sectional area change of reflections at various distances in the test range by assessing signal to noise ratio. A DAC curve is a means of taking apparent attenuation into account along the time base of a test signal. It is a line of equal sensitivity along the trace which allows the amplitudes of signals at different axial distances from the collar to be compared.
VIII.
IX.
X.
A. Coatings can have the effect of attenuating the signal. Their thickness and condition are the primary factors that affect the rate of signal attenuation. Due to their variability, coatings make it difficult to predict the effective inspection distance.
B. Several coating types may affect the GWUT results to the point that they may reduce the expected inspection distance. For
XI.
XII.
XIII.
A. There is no industry standard for qualifying GWUT service providers. Pipeline operators must require all guided wave service providers to have equipment-specific training and experience for all GWUT equipment operators which includes training for:
(1) Equipment operation;
(2) Field data collection; and
(3) Data interpretation on cased and buried pipe.
B. Only individuals who have been qualified by the manufacturer or an independently assessed evaluation procedure similar to ISO 9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7 Eligibility; and 10 Certification), as specified above, may operate the equipment.
C. A Senior level GWUT equipment operator with pipeline specific experience must provide onsite oversight of the inspection and approve the final reports. A senior level GWUT equipment operator must have additional training and experience, including but not limited to training specific to cased and buried pipe, with a quality control program which conforms to section 12 of ASME B31.8S.
D. Training and experience minimums for senior level GWUT equipment operators:
(1) Equipment Manufacturer's minimum qualification for equipment operation and data collection with specific endorsements for casings and buried pipe
(2) Training, qualification and experience in testing procedures and frequency determination
(3) Training, qualification and experience in conversion of guided wave data into pipe features and estimated metal loss (estimated cross-sectional area loss and circumferential extent)
(4) Equipment Manufacturer's minimum qualification with specific endorsements for data interpretation of anomaly features for pipe within casings and buried pipe.
XIV.
XV.
XVI.
XVII.
The use of GWUT in the “Go-No Go” mode requires that all indications (wall loss anomalies) above the testing threshold (5% of CSA sensitivity) be directly examined (or replaced) prior to completing the integrity assessment on the cased carrier pipe. If this cannot be accomplished then alternative methods of assessment (such as hydrostatic pressure tests or ILI) must be utilized.
XVIII.
Internal Revenue Service (IRS), Treasury.
Final and temporary regulations.
This document contains temporary regulations that address transactions that are structured to avoid the purposes of sections 7874 and 367 of the Internal Revenue Code (the Code) and certain post-inversion tax avoidance transactions. These regulations affect certain domestic corporations and domestic partnerships whose assets are directly or indirectly acquired by a foreign corporation and certain persons related to such domestic corporations and domestic partnerships. The text of the temporary regulations also serves as the text of the proposed regulations set forth in the notice of proposed rulemaking on this subject in the Proposed Rules section of this issue of the
Regarding the regulations under sections 304, 367, and 7874, Shane M. McCarrick or David A. Levine, (202) 317-6937; regarding the regulations under sections 956 and 7701(l), Rose E. Jenkins, (202) 317-6934 (not toll-free numbers).
This document contains regulations to address transactions commonly referred to as inversions and certain tax avoidance transactions related to inversions. An inversion may take many forms but has been generally described as a transaction that results in a domestic parent corporation of a multinational group being replaced with a foreign parent corporation. Staff of the Joint Committee on Taxation, General Explanation of Tax Legislation Enacted in the 108th Congress (JCS-5-05) (May 31, 2005) (the JCT Explanation), at 342. An inversion is typically accompanied or followed by certain transactions that are intended “to remove income from foreign operations from the U.S. taxing jurisdiction.” Id. In addition, the “corporate group may derive further advantage from the inverted structure by reducing U.S. tax on U.S.-source income through various earnings stripping or other transactions.” Id.
Section 7874 and the regulations thereunder and § 1.367(a)-3(c) (concerning outbound transfers of domestic stock) are intended to address inversions. As described in Part II.F of this Background section, section 7874 generally applies to a transaction if three conditions are satisfied. When these conditions are satisfied, section 7874 either prevents the use of certain tax attributes to reduce the U.S. federal income tax owed on certain income or gain (inversion gain) recognized in transactions intended to remove foreign operations from the U.S. taxing jurisdiction, or treats the new foreign parent corporation as a domestic corporation for all purposes of the Code. As described in Part II.B.1 of this Background section, in certain inversions, § 1.367(a)-3(c) causes a United States person that is a shareholder of the domestic parent corporation to recognize gain (but not loss) on the exchange of its stock in the domestic corporation.
On September 22, 2014, the Department of the Treasury (Treasury Department) and the IRS issued Notice 2014-52, 2014-42 I.R.B. 712 (the 2014 notice), which announced the intention to issue regulations described therein to address certain transactions structured to avoid the purposes of section 7874 and § 1.367(a)-3(c) and certain post-inversion tax avoidance transactions. On November 19, 2015, the Treasury Department and the IRS issued Notice 2015-79, 2015-49 I.R.B. 775 (the 2015 notice), which announced the intention to issue regulations described therein to address certain additional transactions structured to avoid the purposes of section 7874 and § 1.367(a)-3(c) and certain additional post-inversion tax avoidance transactions. This document contains temporary regulations under sections 304, 367, 956, 7701(l), and 7874 of the Code.
The temporary regulations include the rules described in the two notices. Part I of the Explanation of Provisions section of this preamble explains the regulations addressing certain transactions structured to avoid the purposes of section 7874. Part II of the Explanation of Provisions section of this preamble explains the regulations addressing certain post-inversion tax avoidance transactions. In addition, the temporary regulations set forth new rules that address issues that were not discussed in either notice: (i) Rules for identifying a foreign acquiring corporation when a domestic entity acquisition involves multiple steps (described in Part I.A of the Explanation of Provisions section of this preamble); (ii) rules that disregard stock of the foreign acquiring corporation that is attributable to certain prior domestic entity acquisitions (described in Part I.B.3 of the Explanation of Provisions section of this preamble); (iii) rules that require a controlled foreign corporation (CFC) to recognize all realized gain upon certain transfers of assets described in section 351 that shift the ownership of those assets to a related foreign person that is not a CFC (described in Part II.B.3 of the Explanation of Provisions section of this preamble); and (iv) rules clarifying the definition of group income for purposes of the substantial business activities test (described in Part I.D.2 of the Explanation of Provisions section of this preamble). The temporary regulations also contain the rules described in Notice 88-108, 1988-2 C.B. 445; Notice 2008-91, 2008-43 I.R.B. 1001; Notice 2009-10, 2009-5 I.R.B. 419; and Notice 2010-12, 2010-4 I.R.B. 326, concerning the short-term obligation exception from United States property for purposes of section 956.
In addition, the temporary regulations provide a new definitions section under § 1.7874-12T that defines terms commonly used in certain of the regulations under sections 367(b), 956, 7701(l), and 7874. It is expected that future guidance projects will conform the nomenclature used in other portions of the existing section 7874 regulations with the nomenclature used in § 1.7874-12T.
The applicability dates for the rules that previously were announced in the 2014 notice and the 2015 notice are consistent with the dates previously announced. Thus, the rules described in the 2014 notice that address transactions that are structured to avoid the purposes of section 7874 apply to acquisitions completed on or after September 22, 2014, and the rules described in the 2015 notice that address transactions that are structured to avoid the purposes of section 7874 apply to acquisitions completed on or
The new rules included in the temporary regulations, including any changes to rules described in the 2014 notice and the 2015 notice, generally apply to acquisitions or post-inversion tax avoidance transactions completed on or after April 4, 2016. In addition, and consistent with the announcement in the 2014 notice, the new rule described in Part II.B.3 of the Explanation of Provisions section of this preamble that reduces post-inversion tax benefits (by requiring a CFC to recognize all realized gain upon certain section 351 transfers) applies only if the inversion transaction was completed on or after September 22, 2014. However, no inference is intended as to the treatment of transactions described in the temporary regulations and this preamble under the law that applied before the applicability date of these regulations. The IRS may, where appropriate, challenge transactions, including those described in the temporary regulations and this preamble, under applicable Code or regulatory provisions or judicial doctrines.
Comments were received on the 2014 notice. One comment was received on the 2015 notice, but the comment was received after these temporary regulations had been substantially developed such that the Treasury Department and the IRS did not have time to fully consider the comment. The Treasury Department and the IRS will include this comment in the administrative record for the notice of proposed rulemaking on this subject in the Proposed Rules section of this issue of the
Section 304(a)(1) generally provides that, for purposes of sections 302 and 303, if one or more persons are in control of each of two corporations and, in return for property, one of the corporations (acquiring corporation) acquires stock in the other corporation (issuing corporation) from the person (or persons) so in control, then (unless section 304(a)(2) applies) the property shall be treated as a distribution in redemption of the stock of the acquiring corporation.
Section 304(a)(2) provides that, for purposes of sections 302 and 303, if in return for property, one corporation acquires from a shareholder of another corporation stock in such other corporation, and the issuing corporation controls the acquiring corporation, then the property shall be treated as a distribution in redemption of the stock of the issuing corporation.
Section 304(b)(2) provides that, in the case of any acquisition to which section 304(a) applies, the determination of the amount that is a dividend (and the source thereof) shall be made as if the property were distributed by the acquiring corporation to the extent of its earnings and profits, and then by the issuing corporation to the extent of its earnings and profits.
Section 304(b)(5)(B) limits the earnings and profits taken into account under section 304(b)(2) when the acquiring corporation is foreign. Specifically, section 304(b)(5)(B) provides that no earnings and profits are taken into account for purposes of section 304(b)(2)(A) (and section 304(b)(2)(A) shall not apply) if more than 50 percent of the dividends arising from such acquisition (determined without regard to section 304(b)(5)(B)) would neither be subject to U.S. federal income tax for the taxable year in which the dividends arise, nor be included in the earnings and profits of a CFC.
The Staff of the Joint Committee on Taxation's technical explanation of section 304(b)(5)(B) provides:
The provision prevents the foreign acquiring corporation's E&P from permanently escaping U.S. taxation by being deemed to be distributed directly to a foreign person (
Staff of the Joint Committee on Taxation, Technical Explanation of the Revenue Provisions of the Senate Amendment to the House Amendment to the Senate Amendment to H.R. 1586, Scheduled for Consideration by the House of Representatives on August 10, 2010 (JCX-46-10) (August 10, 2010), at 28.
Section 304(b)(5)(C) provides that the Secretary shall prescribe such regulations as are necessary to carry out the purposes of section 304(b)(5).
Subject to certain exceptions, section 367(a)(1) generally provides that if a United States person transfers property to a foreign corporation in an exchange described in section 332, 351, 354, 356, or 361, the foreign corporation shall not be considered a corporation for purposes of determining the extent to which the United States person recognizes gain on the transfer. Section 1.367(a)-3(c) provides an exception to the general rule of section 367(a)(1) for certain transfers by a United States person of stock or securities of a domestic corporation (the U.S. target company) to a foreign corporation. This exception only applies, however, if the U.S. target company complies with the reporting requirements in § 1.367(a)-3(c)(6) and if the four conditions set forth in § 1.367(a)-3(c)(1)(i) through (iv) are satisfied. The condition set forth in § 1.367(a)-3(c)(1)(iv) requires the active trade or business test (as defined in § 1.367(a)-3(c)(3)) to be satisfied, the requirements of which include the substantiality test (as defined in § 1.367(a)-3(c)(3)(iii)). The substantiality test is satisfied if, at the time of the transfer, the fair market value of the transferee foreign corporation is at least equal to the fair market value of the U.S. target company. For this purpose, the fair market value of the transferee foreign corporation generally does not include assets acquired outside the ordinary course of business within the 36-month period preceding the exchange if they produce, or are held for the production of, passive income or are acquired for the principal purpose of satisfying the substantiality test.
Section 367(b)(1) provides that, in the case of an exchange described in section 332, 351, 354, 355, 356, or 361 in connection with which there is no transfer of property described in section 367(a)(1), a foreign corporation shall be considered to be a corporation except to the extent provided in regulations prescribed by the Secretary that are
Regulations under section 367(b) generally provide that, if the potential application of section 1248 cannot be preserved following the acquisition of the stock or assets of a foreign corporation (foreign acquired corporation) by another foreign corporation in an exchange subject to section 367(b), then certain exchanging shareholders of the foreign acquired corporation must include in income as a dividend the section 1248 amount attributable to the stock of the foreign acquired corporation exchanged. See § 1.367(b)-4(b). Under § 1.367(b)-2(c)(1), the section 1248 amount attributable to the stock of a foreign acquired corporation means the net positive earnings and profits (if any) that would have been attributable to such stock and includible in income as a dividend under section 1248 if the stock were sold by the exchanging shareholder.
Specifically, subject to certain exceptions, § 1.367(b)-4(b)(1)(i) requires a deemed dividend inclusion if the exchange satisfies two conditions. First, immediately before the exchange, the exchanging shareholder is either (i) a United States person that is a section 1248 shareholder with respect to the foreign acquired corporation, or (ii) a foreign corporation, and a United States person is a section 1248 shareholder with respect to such foreign corporation and the foreign acquired corporation. See § 1.367(b)-4(b)(1)(i)(A). Second, immediately after the exchange, either (i) the stock received by the exchanging shareholder is not stock in a CFC as to which the United States person described in the preceding sentence is a section 1248 shareholder, or (ii) the foreign acquiring corporation (for this purpose, as defined in § 1.367(b)-4(a)) or the foreign acquired corporation (in the case of an acquisition of the stock of the foreign acquired corporation) is not a CFC as to which the United States person is a section 1248 shareholder. See § 1.367(b)-4(b)(1)(i)(B).
Section 1.367(b)-4(c)(1) provides that a section 1248 amount included in income as a deemed dividend under § 1.367(b)-4(b) is not included as foreign personal holding company income (FPHCI) under section 954(c).
Section 954 defines foreign base company income (FBCI), which generally is income earned by a CFC that is taken into account in computing the amount that a United States shareholder (within the meaning of section 951(b)) of the CFC must include in income under section 951(a)(1)(A). FBCI includes FPHCI, as defined in section 954(c), which, in turn, generally includes dividends. Section 954(c)(1)(A). However, dividends generally are excluded from FPHCI if they are received from a related person that (i) is a corporation created or organized under the laws of the same foreign country under the laws of which the CFC is created or organized, and (ii) has a substantial part of its assets used in its trade or business located in that foreign country. Section 954(c)(3).
In addition, for certain taxable years, dividends received or accrued from another CFC that is a related person generally are excluded from the FPHCI of a CFC to the extent the dividends are attributable or properly allocable to income of the related person that is neither subpart F income nor income treated as effectively connected with the conduct of a trade or business in the United States. Section 954(c)(6). Section 103(b)(1) of the Tax Increase Prevention and Reconciliation Act of 2005 (Pub. L. 109-222, 120 Stat. 345) added section 954(c)(6), which applied to taxable years of foreign corporations beginning after December 31, 2005, and before January 1, 2009, and to taxable years of United States shareholders with or within which these taxable years of the foreign corporation ended. Subsequently, section 954(c)(6) was amended five times to extend its applicability. Section 304(a) of the Tax Extenders and Alternative Minimum Tax Relief Act of 2008 (Pub. L. 110-343, 122 Stat. 3765); section 751(a) of the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (Pub. L. 111-312, 124 Stat. 3296); section 323(a) of the American Taxpayer Relief Act of 2012 (Pub. L. 112-240, 126 Stat. 2313); section 135(a) of Tax Increase Prevention Act of 2014 (Pub. L. 113-295, 128 Stat. 4010); and section 144 of the Protecting Americans from Tax Hikes Act of 2015 (Pub. L. 114-113, 129 Stat. 2242). Currently, section 954(c)(6) applies to taxable years of foreign corporations beginning after December 31, 2005, and before January 1, 2020, and to taxable years of United States shareholders with or within which such taxable years of the foreign corporations end. Section 954(c)(6)(A) provides the Secretary with the authority to prescribe regulations as may be necessary or appropriate to carry out section 954(c)(6), including regulations as may be necessary or appropriate to prevent the abuse of its purposes.
Section 956 determines the amount that a United States shareholder of a CFC must include in gross income with respect to the CFC under section 951(a)(1)(B). This amount is determined, in part, based on the average amount of United States property held, directly or indirectly, by the CFC at the close of each quarter during its taxable year. Subject to certain exceptions, section 956(c) generally defines United States property to include stock and obligations of United States persons that are related to the CFC. Sections 956(c)(1)(B) and (C) and 956(c)(2)(F) and (L). The term “obligation” is defined in § 1.956-2T(d). Section 956(e) grants the Secretary authority to prescribe such regulations as may be necessary to carry out the purposes of section 956, including regulations to prevent the avoidance of section 956 through reorganizations or otherwise. In addition, section 956(d) grants the Secretary authority to prescribe regulations pursuant to which a CFC that is a pledgor or guarantor of an obligation of a United States person is considered to hold the obligation. Section 1.956-2(c) provides that a CFC that is a direct or indirect pledgor or guarantor of an obligation of a United States person is treated as holding the obligation. Section 3.01(a) of the 2014 notice discusses relevant legislative history of section 956.
Section 7701(l) grants the Secretary authority to issue regulations re-characterizing any multiple-party financing transaction as a transaction directly among any two or more of such parties where the Secretary determines that such re-characterization is appropriate to prevent avoidance of any tax imposed under the Code. Section 3.02(a) of the 2014 notice discusses relevant legislative history of section 7701(l).
Under section 7874, a foreign corporation (foreign acquiring corporation) generally is treated as a
The tax treatment of a domestic entity acquisition in which the EAG does not have substantial business activities in the relevant foreign country varies depending on the level of owner continuity. If the ownership percentage is at least 80, the foreign acquiring corporation is treated as a domestic corporation for all purposes of the Code pursuant to section 7874(b). If, instead, the ownership percentage is at least 60 but less than 80 (in which case the domestic entity acquisition is referred to in this preamble as an “inversion transaction”), the foreign acquiring corporation is respected as a foreign corporation, but, under section 7874(a)(1), the taxable income of the domestic entity and certain related United States persons (referred to as “expatriated entities” and defined in section 7874(a)(2)(A)) for any year that includes any portion of the applicable period shall in no event be less than the inversion gain of the entity for the taxable year. Section 7874(d)(1) defines the term “applicable period” as the period beginning on the first date properties are acquired as part of the domestic entity acquisition, and ending on the date that is 10 years after the last date properties are acquired as part of the domestic entity acquisition. In addition, section 7874(d)(2) generally provides that the term “inversion gain” means the income or gain recognized by reason of the transfer during the applicable period of stock or other properties by an expatriated entity, and any income received or accrued during the applicable period by reason of a license of any property by an expatriated entity, provided the transfer or license takes place as part of the domestic entity acquisition or, under subparagraph (B), after the domestic entity acquisition if the transfer or license is to a foreign related person. Section 7874(d)(2) provides that subparagraph (B) does not apply to property described in section 1221(a)(1) (generally, property that is inventory) in the hands of the expatriated entity.
Section 7874(d)(3) provides that the term “foreign related person” means, with respect to any expatriated entity, a foreign person that is (i) related (within the meaning of section 267(b) or 707(b)(1)) to the entity, or (ii) under the same common control (within the meaning of section 482) as the entity.
Section 7874(e)(2)(A) provides that, in the case of an expatriated entity that is a partnership, section 7874(a)(1) shall apply at the partner rather than the partnership level.
Under section 7874(c)(4), a transfer of properties or liabilities (including by contribution or distribution) is disregarded if the transfer is part of a plan a principal purpose of which is to avoid the purposes of section 7874. In addition, section 7874(c)(6) grants the Secretary authority to prescribe regulations as may be appropriate to determine whether a corporation is a surrogate foreign corporation, including regulations to treat stock as not stock. Finally, section 7874(g) grants the Secretary authority to provide regulations necessary to carry out section 7874, including regulations providing for such adjustments to the application of section 7874 as are necessary to prevent the avoidance of the purposes of section 7874, including the avoidance of such purposes through (i) the use of related persons, pass-through or other non-corporate entities, or other intermediaries, or (ii) transactions designed to have persons cease to be (or not become) members of expanded affiliated groups or related persons.
This Part I describes rules for (i) identifying domestic entity acquisitions and foreign acquiring corporations in certain multiple-step transactions; (ii) calculating the ownership percentage and, more specifically, disregarding certain stock of the foreign acquiring corporation for purposes of computing the denominator of the ownership fraction and, in addition, taking into account certain non-ordinary course distributions (NOCDs) made by a domestic entity for purposes of computing the numerator of the ownership fraction; (iii) determining when certain stock of a foreign acquiring corporation is treated as held by a member of the EAG; and (iv) determining when an EAG has substantial business activities in a relevant foreign country.
Section 1.7874-2(c) provides guidance on the types of transactions that constitute a direct or indirect acquisition by a foreign corporation of properties held directly or indirectly by a domestic entity and that therefore potentially result in a domestic entity acquisition. Section 1.7874-2(c)(1) sets forth a non-exclusive list of the types of transactions that generally result in an indirect acquisition of properties of a domestic entity. In addition, § 1.7874-2(c)(2) provides that when a foreign corporation acquires stock of another foreign corporation, which, in turn, directly or indirectly owns stock or a partnership interest in a domestic entity, the acquisition by the foreign corporation does not constitute an indirect acquisition of any properties held by the domestic entity. Absent § 1.7874-2(c)(2), the foreign corporation's acquisition of the stock of the other foreign corporation would be an indirect acquisition of properties of the domestic entity. However, because the domestic entity had a foreign parent before the acquisition, these types of transactions typically do not give rise to the policy concerns that motivated
Section 1.7874-2(f) provides a non-exclusive list of stock of a foreign corporation that is described in section 7874(a)(2)(B)(ii) (that is, stock of the foreign acquiring corporation held by former domestic entity shareholders or former domestic entity partners by reason of holding stock or partnership interests in the domestic entity; at times, referred to in this preamble as “by-reason-of stock”).
The Treasury Department and the IRS are concerned that taxpayers may take the position that certain transactions are not domestic entity acquisitions even though the transactions give rise to the policy concerns that motivated Congress to enact section 7874. This could occur, for example, when a foreign corporation (initial acquiring corporation) acquires substantially all of the properties held by a domestic entity (the initial acquisition) in a transaction that does not result in the initial acquiring corporation being treated as a domestic corporation under section 7874(b) (for example, because the ownership percentage is less than 80 or because the EAG purports to meet the substantial business activities exception in § 1.7874-3), and, pursuant to a plan that includes the initial acquisition (or a series of related transactions), another foreign corporation (subsequent acquiring corporation) acquires substantially all of the properties of the initial acquiring corporation (the subsequent acquisition). In these cases, a taxpayer may take the position that the form of the transactions is respected for U.S. federal income tax purposes and that § 1.7874-2(c)(2) prevents the subsequent acquiring corporation from being considered to have indirectly acquired the properties of the domestic entity pursuant to the subsequent acquisition. Under this position, although the initial acquisition would be a domestic entity acquisition and the initial acquiring corporation would be a foreign acquiring corporation, the subsequent acquisition would not be a domestic entity acquisition, and the subsequent acquiring corporation would not be a foreign acquiring corporation. Moreover, for purposes of computing the ownership percentage, a taxpayer may assert that former domestic entity shareholders do not hold stock of the subsequent acquiring corporation by reason of holding stock in the domestic entity and, instead, hold stock of the subsequent acquiring corporation only by reason of holding stock in the initial acquiring corporation.
In certain cases, these positions are contrary to the purposes of section 7874, including the purposes of (i) the third-country rule set forth in § 1.7874-9T (and described in Section B.4 of this Part I), if the subsequent acquiring corporation and the initial acquiring corporation are subject to tax as residents of different foreign countries, or (ii) the substantial business activities exception in § 1.7874-3 if the EAG has substantial business activities in the foreign country in which, or under the laws of which, the initial acquiring corporation is created or organized but does not have substantial business activities in the foreign country in which, or under the laws of which, the subsequent acquiring corporation is created or organized.
To address the concerns described in Section 2 of this Part I.A, the temporary regulations provide a rule (the multiple-step acquisition rule) that treats the subsequent acquisition as a domestic entity acquisition and the subsequent acquiring corporation as a foreign acquiring corporation. § 1.7874-2T(c)(4)(i). When the multiple-step acquisition rule applies, the temporary regulations treat stock of the subsequent acquiring corporation received, pursuant to the subsequent acquisition, in exchange for stock of the initial acquiring corporation described in section 7874(a)(2)(B)(ii) (that is, stock of the initial acquiring corporation that, as a result of the initial acquisition, is by-reason-of stock) as stock of the subsequent acquiring corporation held by reason of holding stock in the domestic entity. § 1.7874-2T(f)(1)(iv).
Further, if, pursuant to the same plan (or a series of related transactions), a foreign corporation directly or indirectly acquires substantially all of the properties held by a subsequent acquiring corporation in a transaction that occurs after the subsequent acquisition, the principles of the multiple-step acquisition rule apply to also treat the further acquisition as a domestic entity acquisition and the foreign corporation that made such acquisition as a foreign acquiring corporation. § 1.7874-2T(c)(4)(iii). For example, if, pursuant to a plan, a foreign corporation (F1) acquires substantially all of the properties held by a domestic corporation, followed by another foreign corporation (F2) acquiring substantially all of the properties held by F1, followed, in turn, by another foreign corporation (F3) acquiring substantially all of the properties held by F2, then the multiple-step acquisition rule also would treat F3's acquisition of F2's properties as a domestic entity acquisition and F3 as a foreign acquiring corporation. In such a case, the principles of the multiple-step acquisition rule would apply in a similar manner to treat stock of F3 as by-reason-of stock to the extent the F3 stock is received in exchange for F2 stock that is itself treated as by-reason-of stock under the multiple-step acquisition rule.
The multiple-step acquisition rule applies in a similar manner when the domestic entity is a domestic partnership.
These rules do not affect the application of section 7874 to the initial acquisition. As a result, section 7874 may apply to both the initial acquisition and the subsequent acquisition. In addition, and like other guidance under § 1.7874-2, the multiple-step acquisition rule applies solely for section 7874 purposes. Accordingly, this rule does not modify general tax principles (such as the step-transaction doctrine) or other rules or guidance that may apply to related transactions.
Under section 7874(c)(2)(B) (statutory public offering rule), stock of a foreign acquiring corporation that is sold in a public offering related to a domestic entity acquisition described in section 7874(a)(2)(B)(i) is excluded from the denominator of the ownership fraction. The statutory public offering rule furthers the policy that section 7874 is intended to curtail domestic entity acquisitions that “permit corporations and other entities to continue to conduct business in the same manner as they did prior to the inversion.” S. Rep. No. 192, 108th Cong., 1st. Sess., at 142 (2003); JCT Explanation, at 343.
Section 1.7874-4T modifies the statutory public offering rule. The preamble to § 1.7874-4T provides that “the IRS and the Treasury Department believe that stock of the foreign acquiring corporation transferred in exchange for certain property in a transaction related to the acquisition, but not through a public offering, presents the same opportunity to inappropriately reduce the ownership fraction.” TD 9654, published on January 17, 2014, in the
Section 2.03(b) of the 2015 notice provides that § 1.7874-4T will be clarified in certain respects. The temporary regulations implement these clarifications. Accordingly, with respect to the definition of nonqualified property, the temporary regulations clarify that avoidance property means any property (other than specified nonqualified property) acquired with a principal purpose of avoiding the purposes of section 7874, regardless of whether the transaction involves an indirect transfer of specified nonqualified property. See § 1.7874-4T(j),
In addition, the temporary regulations update the de minimis exception in § 1.7874-4T(d)(1) to reflect the passive assets rule (described in Section 2 of this Part I.B) and the NOCD rule (described in Section 5 of this Part I.B), and to also conform the exception to the de minimis exceptions in §§ 1.7874-7T(c) and 1.7874-10T(d).
Section 2.01(b) of the 2014 notice announced that future regulations would include a rule (the passive assets rule) that would exclude from the denominator of the ownership fraction stock of a foreign acquiring corporation that is attributable to certain passive assets, but only if, after the domestic entity acquisition and all related transactions are complete, more than 50 percent of the gross value of all foreign group property constitutes certain passive assets (referred to in the notice and temporary regulations as “foreign group nonqualified property”). See Section b of this Part I.B.2 for the definition of foreign group property and foreign group nonqualified property. The temporary regulations implement the passive assets rule described in the 2014 notice, subject to the modifications described in Section c of this Part I.B.2.
The 2014 notice provides that the amount of stock that will be excluded under the passive assets rule is equal to the product of (i) the value of the stock of the foreign acquiring corporation, other than stock that is described in section 7874(a)(2)(B)(ii) (that is, by-reason-of stock) and stock that is excluded from the denominator of the ownership fraction under either § 1.7874-1(b) (because it is held by a member of the EAG) or § 1.7874-4T(b) (because it is disqualified stock); and (ii) the foreign group nonqualified property fraction. The numerator of the foreign group nonqualified property fraction is the gross value of all foreign group nonqualified property, and the denominator is the gross value of all foreign group property. However, property received by the foreign acquiring corporation that gives rise to stock that is excluded from the ownership fraction under § 1.7874-4T(b) is excluded from both the numerator and the denominator of the foreign group nonqualified property fraction, as applicable.
In addition, the 2014 notice provides that the passive assets rule will incorporate the principles of § 1.7874-4T(h) (regarding the interaction of the EAG rules with the rule that excludes disqualified stock from the denominator of the ownership fraction) with respect to stock of the foreign acquiring corporation that is excluded under the passive assets rule.
The 2014 notice provides that foreign group property means any property (including property that gives rise to disqualified stock upon application of § 1.7874-4T) held by the EAG after the domestic entity acquisition and all transactions related to that acquisition are complete, other than the following property: (i) Property that is directly or indirectly acquired in the domestic entity acquisition and that, at the time of the domestic entity acquisition, was held directly or indirectly by the domestic entity; and (ii) to avoid double counting, stock or a partnership interest in a member of the EAG and an obligation described in § 1.7874-4T(i)(7)(iii)(A) (that is, an obligation of a member of the EAG).
With respect to foreign group nonqualified property, the 2014 notice provides that the term generally means foreign group property that is described in § 1.7874-4T(i)(7) other than property that gives rise to income described in section 1297(b)(2)(A) (the banking exception under the passive foreign investment company (PFIC) rules) or section 954(h) or (i) (subpart F exceptions for qualified banking or financing income and for qualified insurance income, respectively), determined by substituting the term “foreign corporation” for the term “controlled foreign corporation.” In addition, a special rule treats certain property (referred to as “substitute property”) that would not be foreign group nonqualified property under the general rule as foreign group nonqualified property if, in a transaction related to the acquisition, such property is acquired in exchange for other property that would be foreign group nonqualified property under the general rule.
Section 4.01(b)(i) of the 2015 notice modifies the general definition of foreign group nonqualified property to also exclude from that definition property that gives rise to income described in section 1297(b)(2)(B) (the PFIC insurance exception). Further, section 4.01(b)(ii) of the 2015 notice provides that the general definition of foreign group nonqualified property does not include property (i) held by a domestic corporation that is subject to tax as an insurance company under subchapter L, provided that the property
Section 1.7874-7T sets forth the passive assets rule as described in the 2014 notice and the 2015 notice, subject to certain modifications, in part, to address comments received.
A comment noted that certain rules described in the 2014 notice could cause section 7874 to apply to a domestic entity acquisition even though the former domestic entity shareholders or former domestic entity partners, as applicable, actually own no, or only a de minimis amount of, stock in the foreign acquiring corporation after the domestic entity acquisition. In the context of the passive assets rule this could occur, for example, if a foreign acquiring corporation, which holds only cash that does not give rise to disqualified stock under § 1.7874-4T, acquires the stock of the domestic entity in exchange for a portion of the cash and a small amount of stock of the foreign acquiring corporation. Because the foreign group property would be comprised entirely of the remaining cash held by the foreign acquiring corporation, 100 percent of the gross value of all foreign group property would constitute foreign group nonqualified property. Accordingly, absent a de minimis exception, all of the stock of the foreign acquiring corporation, other than stock described in section 7874(a)(2)(B)(ii) (that is, by-reason-of stock), would be excluded from the denominator of the ownership fraction pursuant to the passive assets rule, resulting in an ownership fraction of 100 percent. In response to the comment, and for reasons similar to the reasons for the de minimis exceptions in § 1.7874-4T and the NOCD rule (described in Section 5 of this Part I.B), the Treasury Department and the IRS have determined that there should be a de minimis exception to the passive assets rule.
Accordingly, § 1.7874-7T(c) provides a de minimis exception when two requirements are satisfied: (i) First, the ownership percentage—determined without regard to the application of the passive assets rule, § 1.7874-4T(b), and the NOCD rule (described in Section 5 of this Part I.B)—is less than five (by vote and value); and (ii) second, on the date that the domestic entity acquisition and all transactions related to the domestic entity acquisition are complete (the completion date), former domestic entity shareholders or former domestic entity partners, as applicable, in the aggregate, own (applying the attribution rules of section 318(a) with the modifications described in section 304(c)(3)(B)) less than five percent (by vote and value) of the stock of (or a partnership interest in) each member of the EAG.
The 2014 notice would treat property held by an EAG member as foreign group property regardless of whether the foreign acquiring corporation directly or indirectly owned an interest in the property. Thus, in cases in which the foreign acquiring corporation is not the common parent of the EAG, the 2014 notice could treat property as foreign group property even though the value of the property is not reflected in the value of the stock of the foreign acquiring corporation.
The Treasury Department and the IRS have concluded that foreign group property should not include property held by EAG members if the value of such property is not reflected in the value of the stock of the foreign acquiring corporation. In order to effectuate this policy, the temporary regulations limit foreign group property to property held by members of the “modified expanded affiliated group.” See § 1.7874-7T(f)(2) (defining foreign group property). When the foreign acquiring corporation is not the common parent corporation, the modified EAG is the EAG redetermined as if the foreign acquiring corporation were the common parent corporation. See § 1.7874-7T(f)(4) (defining modified expanded affiliated group).
In connection with this change, the temporary regulations also modify the definition of foreign group property provided in the 2014 notice to exclude only stock or partnership interests in members of the modified EAG and obligations of such members, since the issue of double-counting only arises with respect to those interests.
A comment questioned whether, for purposes of the more-than-50-percent threshold test, foreign group property should include certain nonqualified property (within the meaning of § 1.7874-4T(i)(7)) received by the EAG in a transaction related to the domestic entity acquisition. In particular, the comment noted that nonqualified property received by the EAG in such a transaction may (i) if received in exchange for stock of the foreign acquiring corporation, give rise to disqualified stock (within the meaning of § 1.7874-4T(c)) that is excluded from the denominator of the ownership fraction under § 1.7874-4T(b), and (ii) because such property is foreign group nonqualified property, increase the likelihood that the more-than-50-percent threshold will be exceeded and thus that additional stock of the foreign acquiring corporation will be excluded from the denominator of the ownership fraction under the passive assets rule.
The Treasury Department and the IRS have determined that the more-than-50-percent threshold test should apply without regard to whether all or a portion of the foreign group nonqualified property was received in a transaction related to the domestic entity acquisition. The more-than-50-percent threshold test is an on-off switch that is intended to determine whether, after the domestic entity acquisition and all related transactions are complete, a majority of the value of the stock of the foreign acquiring corporation is attributable to nonqualified property; other aspects of the passive assets rule coordinate its operation with the other anti-abuse rules under section 7874. Accordingly, the temporary regulations confirm that, for purposes of the more-than-50-percent threshold test, foreign group property includes nonqualified property that gives rise to disqualified stock that is excluded from the denominator of the ownership fraction pursuant to § 1.7874-4T(b). See § 1.7874-7T(f)(2). However, as is the case under the 2014 notice, § 1.7874-7T(b) does not exclude from the denominator of the ownership fraction any stock of the foreign acquiring corporation that is attributable to such property. See § 1.7874-7T(f)(3). Stock attributable to such property is instead excluded from the denominator of the ownership fraction under § 1.7874-4T(b).
A comment recommended providing a safe harbor to facilitate the valuation
After considering this comment, the Treasury Department and the IRS decline to provide such a safe harbor. A domestic entity acquisition is likely to be an infrequent occurrence for a foreign acquiring corporation. Furthermore, as a general matter, the value of foreign group property must be established in order to determine the amount of stock of the foreign acquiring corporation that must be provided in the domestic entity acquisition. Therefore, it should not be unduly burdensome to determine the aggregate gross value of foreign group property and foreign group nonqualified property.
A comment requested that the regulations clarify that the exclusions from the general definition of foreign group nonqualified property for certain property that gives rise to income described in section 954(h) or (i) apply regardless of whether section 954(h) or (i) sunset. However, section 128 of the Protecting Americans from Tax Hikes Act of 2015 (Pub. L. 114-113, 129 Stat. 2242) made sections 954(h) and (i) permanent. Therefore, this comment is no longer relevant and is not adopted.
Another comment requested that the Treasury Department and the IRS clarify that references in the regulations to section 954(h) or (i) or section 1297(b)(2)(A) or (B) incorporate the principles of any regulations or other guidance issued pursuant to those Code sections. In this regard, the Treasury Department and the IRS note that as a general matter, unless otherwise indicated, a reference in a regulation to a Code section implicitly includes any regulations or other guidance issued pursuant to that Code section. Accordingly, the comment is not adopted.
The 2014 notice did not explicitly address the treatment of partnerships under the passive assets rule. Similar to § 1.7874-4T(g), the temporary regulations provide that, if one or more members of an EAG (for this purpose, taking into account only members of the modified EAG as described in Section ii of this Part I.B.2.c) own, in the aggregate, more than 50 percent (by value) of the interests in a partnership, then, for purposes of the passive assets rule, the partnership is treated as a corporation that is a member of the EAG (deemed corporation rule). See § 1.7874-7T(d).
The temporary regulations implementing the passive assets rule do not include a rule analogous to that provided in § 1.7874-3(e)(1), which treats certain corporate partners of a partnership that owns stock of a foreign acquiring corporation as members of the EAG for purposes of applying the substantial business activities test. Such a rule is not necessary because, as described in Section ii of this Part I.B.2.c, assets that are upstream of the foreign acquiring corporation are not taken into account as foreign group property for purposes of applying the passive assets rule.
The Treasury Department and the IRS are concerned that a single foreign acquiring corporation may avoid the application of section 7874 by completing multiple domestic entity acquisitions over a relatively short period of time, in circumstances where section 7874 would otherwise have applied if the acquisitions had been made at the same time or pursuant to a plan (or series of related transactions). In these situations, the value of the foreign acquiring corporation increases to the extent it issues stock in connection with each successive domestic entity acquisition, thereby enabling the foreign acquiring corporation to complete another, potentially larger, domestic entity acquisition to which section 7874 will not apply. In some cases, a substantial portion of the value of a foreign acquiring corporation may be attributable to its completion of multiple domestic entity acquisitions over the span of just a few years, with that value serving as a platform to complete still larger subsequent domestic entity acquisitions that avoid the application of section 7874. That is, the ownership percentage determined with respect to a subsequent domestic entity acquisition may be less than 60, or less than 80, if the shares of the foreign acquiring corporation issued in prior domestic entity acquisitions are respected as outstanding (thus, included in the denominator but not the numerator) when determining the ownership fraction.
Section 7874 is intended to address transactions in which a domestic parent corporation of a multinational group is replaced with a foreign parent corporation while “permit[ting] corporations and other entities to continue to conduct business in the same manner as they did prior to the inversion.” S. Rep. No. 192, at 142 (2003); JCT Explanation, at 343. To further this policy, various rules under section 7874 exclude from the denominator of the ownership fraction stock of the foreign acquiring corporation that otherwise would inappropriately reduce the ownership fraction. For example, the statutory public offering rule of section 7874(a)(2)(B) excludes from the denominator of the ownership fraction stock of the foreign acquiring corporation that is sold for cash in a public offering related to the domestic entity acquisition. For the same reason, rules under §§ 1.7874-4T and 1.7874-7T exclude from the denominator of the ownership fraction certain stock of the foreign acquiring corporation that is transferred in exchange for, or otherwise attributable to, passive assets or other nonqualified property.
The Treasury Department and the IRS have concluded that it is not consistent with the purposes of section 7874 to permit a foreign acquiring corporation to reduce the ownership fraction for a domestic entity acquisition by including stock issued in connection with other recent domestic entity acquisitions. Moreover, the Treasury Department and the IRS do not believe that the application of section 7874 in these circumstances should depend on whether there was a demonstrable plan to undertake the subsequent domestic entity acquisition at the time of the prior domestic entity acquisitions. Therefore, and consistent with the policies underlying the other stock exclusion rules under section 7874, the Treasury Department and the IRS have determined that stock of the foreign acquiring corporation that was issued in connection with certain prior domestic entity acquisitions occurring within a 36-month look-back period should be excluded from the denominator of the ownership fraction.
To address these concerns, the temporary regulations provide a rule under section 7874(c)(6) and (g) that, for purposes of calculating the ownership percentage by value with respect to a domestic entity acquisition (the relevant domestic entity acquisition), excludes from the denominator of the ownership fraction stock of the foreign acquiring corporation attributable to certain prior domestic entity acquisitions. This rule (the multiple domestic entity
In general, the amount of foreign acquiring corporation stock that is excluded under the multiple domestic entity acquisition rule is based on the current value of the shares of foreign acquiring corporation stock that were issued in the prior domestic entity acquisition, adjusted to reflect intervening redemptions of stock as well as certain other changes in the capital structure of the foreign acquiring corporation. The Treasury Department and the IRS have determined that this approach, which takes into account subsequent fluctuations in value attributable to the prior domestic entity acquisition, best reflects the policies underlying section 7874, including the ownership fraction.
The temporary regulations provide a three-step process to determine the excluded amount for each prior domestic entity acquisition. First, the total number of shares of stock of the foreign acquiring corporation, within each separate share class (relevant share class), that was described in section 7874(a)(2)(B)(ii) as a result of the prior domestic entity acquisition (without regard to whether the 60 percent test of section 7874(a)(2)(B)(ii) was satisfied) must be calculated (total number of prior acquisition shares). For this purpose, it is not relevant whether a share is outstanding at the time of the relevant domestic entity acquisition.
Second, for each relevant share class, the total number of prior acquisition shares must be adjusted to account for redemptions (within the meaning of section 317(b)) of shares that occur during the redemption testing period (each such share, a redeemed share) and that are attributed, on a pro rata basis, to the prior acquisition shares. In general, the redemption testing period is the period beginning on the day after the completion date of the prior domestic entity acquisition and ending on the day prior to the completion date of the relevant domestic entity acquisition (the general redemption testing period). § 1.7874-8T(e)(1). The number of redeemed shares is then multiplied by the redemption fraction (such product, the allocable redeemed shares). § 1.7874-8T(d)(1). The numerator of the redemption fraction is generally the total number of prior acquisition shares, and the denominator is the sum of: (i) The number of outstanding shares of the foreign acquiring corporation stock as of the end of the last day of the redemption testing period, and (ii) the number of redeemed shares during the redemption testing period.
By ending the redemption testing period on the day prior to the completion date of the relevant domestic entity acquisition, shares issued on such completion date would not dilute the portion of a prior redemption that is allocated to the prior acquisition shares. However, to prevent other stock issuances that occur after a particular redemption from diluting the amount of allocable redeemed shares, a foreign acquiring corporation may establish a reasonable method for dividing the general redemption testing period into shorter periods (each such shorter period, a redemption testing period). § 1.7874-8T(e)(2). In these cases, to account for the fact that the total number of prior acquisition shares is reduced by the allocable redeemed shares for each redemption testing period, the numerator of the redemption fraction for a redemption testing period is the total number of prior acquisition shares less the sum of the number of allocable redeemed shares for prior redemption testing periods. § 1.7874-8T(d)(2)(i).
Finally, for each relevant share class, the total number of prior acquisition shares, reduced to take into account redemptions, is multiplied by the fair market value of a single share of stock of the relevant share class, as of the completion date of the relevant domestic entity acquisition (such product, an excluded amount). § 1.7874-8T(c). The total amount of stock of the foreign acquiring corporation excluded from the denominator of the ownership fraction is the sum of the excluded amounts computed separately with respect to each prior domestic entity acquisition and each relevant share class. § 1.7874-8T(b).
The temporary regulations also require appropriate adjustments to be made to take into account changes in a foreign acquiring corporation's capital structure to ensure that the amount of stock excluded under the multiple domestic entity acquisition rule properly reflects the value attributable to prior domestic entity acquisitions. See § 1.7874-8T(f).
The multiple domestic entity acquisition rule applies after taking into account the rule in § 1.7874-2(e). The rule in § 1.7874-2(e) applies when a foreign acquiring corporation completes two or more domestic entity acquisitions pursuant to a plan (or series of related transactions). In such a case, for purposes of section 7874(a)(2)(B)(ii), the acquisitions are treated as a single acquisition, and the domestic entities are treated as a single domestic entity. Thus, for example, if two acquisitions that would separately qualify as a relevant domestic entity acquisition and a prior domestic entity acquisition are subject to § 1.7874-2(e), they are treated as a single acquisition and, as a result, would not be subject to the multiple domestic entity acquisition rule. Similarly, if two acquisitions that would separately be treated as two prior domestic entity acquisitions are subject to § 1.7874-2(e), they are treated as a single prior domestic entity acquisition for purposes of applying the multiple domestic entity acquisition rule.
Section 2.02(b) of the 2015 notice announces that the Treasury Department and the IRS intend to issue regulations providing a rule (the third-country rule) that will apply to certain domestic entity acquisitions in which a domestic entity combines with an existing foreign corporation under a foreign parent corporation that is a tax resident of a “third country” (that is, a foreign country other than the foreign country of which the existing foreign corporation is subject to tax as a resident). The 2015 notice provides that the third-country rule will apply when four requirements are satisfied. First, in a transaction (referred to in the 2015 notice as a “foreign target acquisition” but in this preamble and the temporary regulations as a “foreign acquisition”) related to the domestic entity acquisition, the foreign acquiring corporation directly or indirectly acquires substantially all of the
When these requirements are satisfied, the 2015 notice provides that the third-country rule will exclude from the denominator of the ownership fraction stock of the foreign acquiring corporation held by former shareholders of the acquired foreign corporation by reason of holding stock in the acquired foreign corporation (based on the principles of section 7874(a)(2)(B)(ii), which describes by-reason-of stock).
Section 1.7874-9T sets forth the third-country rule as described in the 2015 notice, subject to certain modifications.
The temporary regulations replace the gross value requirement contained in the 2015 notice with a continuity of interest requirement (referred to as the “foreign ownership percentage”). See § 1.7874-9T(d)(3) and (4). In general, this requirement is satisfied if at least 60 percent of the stock (by vote or value) of the foreign acquiring corporation is held by former shareholders of the acquired foreign corporation by reason of holding stock in the acquired foreign corporation, as determined under the principles of section 7874(a)(2)(B)(ii), with certain modifications. § 1.7874-9T(e)(3) and (4). For this purpose, stock of the foreign acquiring corporation held by former domestic entity shareholders (or former domestic entity partners) is not taken into account. See § 1.7874-9T(e)(3)(i). Because a domestic entity acquisition is disregarded for this purpose, it does not dilute the foreign ownership percentage. The temporary regulations implement this modification by requiring that there be a covered foreign acquisition, generally defined as a transaction in which there is an acquisition of substantially all of the properties of a foreign corporation (that is, a foreign acquisition) and in which the foreign ownership percentage is at least 60. This modification aligns the requirements for the third-country rule with the principles of section 7874.
The temporary regulations generally retain the domestic entity ownership and tax residency requirements as described in the 2015 notice. However, the temporary regulations clarify the application of the tax residency requirement by providing that the tax residency of the foreign acquiring corporation is determined after the covered foreign acquisition and all related transactions, and that the tax residency of the acquired foreign corporation is determined before the covered foreign acquisition and all related transactions.
The 2014 notice announced that the Treasury Department and the IRS intend to include in future regulations under section 7874 a rule (the NOCD rule) that disregards certain distributions made by a domestic entity before being acquired by a foreign acquiring corporation that otherwise would reduce the numerator of the ownership fraction. Specifically, section 2.02(b) of the 2014 notice provides that, for purposes of applying section 7874(c)(4), NOCDs made by the domestic entity (including a predecessor) during the 36-month period ending on the completion date will be treated as part of a plan a principal purpose of which is to avoid the purposes of section 7874.
The 2014 notice defines NOCDs as the excess of all distributions made during a taxable year by the domestic entity with respect to its stock or partnership interests, as applicable, over 110 percent of the average of such distributions during the thirty-six month period immediately preceding such taxable year. The 2014 notice defines distribution, in relevant part, to mean any distribution, regardless of whether it is treated as a dividend or whether, for example, it qualifies under section 355.
Section 4.02(b) of the 2015 notice provides that the future regulations incorporating the NOCD rule will include a de minimis exception. The 2015 notice provides that this exception, similar to the de minimis exception in § 1.7874-4T(d)(1), will apply to an acquisition that satisfies two requirements. First, the ownership percentage—determined without regard to § 1.7874-4T(b) (which disregards certain stock of the foreign acquiring corporation received in exchange for nonqualified property), the passive assets rule, and the NOCD rule—must be less than five (by vote and value). Second, after the domestic entity acquisition and all transactions related to the acquisition are complete, former domestic entity shareholders or former domestic entity partners, as applicable, of the domestic entity, in the aggregate, must own (applying the attribution rules of section 318(a) with the modifications described in section 304(c)(3)(B)) less than five percent (by vote and value) of the stock of (or a partnership interest in) any member of the EAG.
The 2015 notice provides that, when a domestic entity acquisition satisfies the requirements of the de minimis exception, no distributions will be treated as NOCDs that are disregarded under the NOCD rule. The 2015 notice further provides, however, that even when a domestic entity acquisition satisfies the requirements of the de minimis exception, distributions that are part of a plan a principal purpose of which is to avoid the purposes of section 7874, determined without regard to the NOCD rule, will nevertheless be disregarded under section 7874(c)(4).
Further, the 2014 notice provides that § 1.367(a)-3(c) (concerning outbound transfers of stock or securities of a domestic corporation) will be modified to include a rule that incorporates the principles of the NOCD rule for purposes of the substantiality test, which, in general, requires that the value of the foreign acquiring corporation be equal to or greater than the value of the domestic target corporation.
Section 1.7874-10T sets forth the NOCD rule as described in the 2014 notice and the 2015 notice, subject to certain modifications, in part, to address comments received. Section 1.367(a)-3T(c)(3)(iii)(C) sets forth a similar rule for purposes of the substantiality test under § 1.367(a)-3(c).
i. In General
Section 1.7874-10T(b) generally provides that, for purposes of determining the ownership percentage by value, former domestic entity shareholders or former domestic entity partners, as applicable, are deemed to receive, by reason of holding stock or an interest in the domestic entity, an
The temporary regulations provide, consistent with the approach recommended in comments received, that the amount of a distribution (including with respect to property distributed in redemption of stock) is determined based on the value of the property distributed at the time of the distribution. See § 1.7874-10T(b). Accordingly, post-distribution fluctuations in the value of the stock or interests of the domestic entity, as applicable, or the value of the distributed property (for example, in the case of a spin-off), do not affect the amount of NOCD stock that is deemed received. A comment suggested additional guidance on valuing the stock of controlled corporations in spin-off transactions. The temporary regulations do not provide new guidance on this issue, which extends beyond the scope of the NOCD rule.
A comment generally recommended that, for purposes of determining the extent to which NOCD stock is deemed received, the NOCD rule should take into account the mix of stock and non-stock consideration provided by a foreign acquiring corporation. For example, if the foreign acquiring corporation acquires a domestic entity in exchange for 60 percent stock and 40 percent cash, the comment recommended that only 60 percent of the additional consideration deemed received under the NOCD rule would be treated as consisting of NOCD stock (with the remaining 40 percent of the additional consideration treated as consisting of cash and, to this extent, not increasing the ownership percentage). The same comment indicated that, under such an approach, additional guidance would be needed in certain cases in which a domestic entity had multiple classes of stock outstanding, particularly where the foreign acquiring corporation does not have a similar capital structure.
The NOCD rule is intended to address transactions in which a taxpayer elects to reduce its size by making distributions outside of the ordinary course to shareholders in order to reduce the amount of foreign acquiring stock that would have to be provided to such shareholders in a subsequent domestic entity acquisition. The Treasury Department and the IRS have determined that the mix of additional consideration that would have been provided in the subsequent domestic entity acquisition but for the NOCDs could differ from the mix of consideration that was actually provided in the domestic entity acquisition. This could occur, for example, due to limitations on the amount of cash that the foreign acquiring corporation was financially capable of providing. It is in fact this type of limitation that could motivate a domestic entity to make NOCDs in order to reduce the ownership percentage, rather than relying on cash consideration provided by the foreign acquiring corporation. In addition, the Treasury Department and the IRS have concluded that determining the hypothetical mix of consideration that would have been provided in the absence of NOCDs would give rise to significant administrative complexities. Accordingly, the temporary regulations do not adopt this comment, and, therefore, also do not provide guidance specific to cases where a domestic entity has, or had, multiple classes of stock outstanding.
A comment also requested clarification that the NOCD rule does not establish a safe harbor with respect to the application of section 7874(c)(4). Specifically, the comment requested clarification that, when a distribution is not disregarded under the NOCD rule, the distribution may nevertheless be disregarded under section 7874(c)(4) if, without regard to the NOCD rule, it was made with a principal purpose of avoiding the purposes of section 7874. The temporary regulations confirm that this is the case. See § 1.7874-10T(c). In addition, and also in response to a comment, the temporary regulations clarify that, when only a portion of a distribution is treated as an NOCD, the NOCD rule does not create a presumption that the remaining portion of the distribution was made with a principal purpose of avoiding the purposes of section 7874. See id. The remaining portion must be analyzed under section 7874(c)(4) in the same manner as any other distribution that is not treated as an NOCD.
Comments requested clarification regarding whether the NOCD rule could apply for purposes other than the ownership fraction. For example, the comments questioned whether property distributed as part of an NOCD could be considered held by the EAG for purposes of determining whether the EAG has substantial business activities in the relevant foreign country. The temporary regulations confirm that the NOCD rule applies only for purposes of determining the ownership percentage by value; it therefore does not apply for any other purpose, including, for example, the substantial business activities determination under § 1.7874-3 or the loss of control exception under § 1.7874-1(c)(3). Nevertheless, the scope of section 7874(c)(4), by its terms, is not limited to the ownership fraction and therefore may apply for other purposes under section 7874. See also, for example, § 1.7874-3(c), which provides anti-abuse rules pursuant to which certain items are not taken into account for purposes of the substantial business activities test, including items associated with properties or liabilities the transfer of which is disregarded under section 7874(c)(4).
Comments recommended narrowing the NOCD rule. For example, comments suggested that the NOCD rule should only create, either in all cases or at least with respect to section 355 distributions, a rebuttable presumption that a distribution identified as an NOCD under the rule is made with a principal purpose of avoiding the purposes of section 7874. Under this approach, if a taxpayer demonstrated that a distribution presumptively identified as an NOCD was not in fact made with a principal purpose of avoiding the purposes of section 7874, then the distribution would not be disregarded. A comment did note, though, that difficulties, uncertainties, and administrative burdens could arise under a rebuttable presumption approach. After considering the comments received, the Treasury Department and the IRS have determined that replacing the per se NOCD rule with a rebuttable presumption would give rise to significant uncertainty and administrative burden because the IRS would face significant challenges in ascertaining the purpose underlying each distribution. Accordingly, the temporary regulations do not adopt this approach.
A comment suggested that, if a non-rebuttable presumption is retained, the NOCD rule should be narrowed by other means, such as by (i) replacing the 36-month period during which
Other comments suggested that the regulations should exclude the following distributions from the NOCD rule because they ordinarily would not give rise to avoidance concerns: (i) Dividends or redemptions made pursuant to a policy that is carried out consistently for the 36-month period preceding the completion date; (ii) intercompany distributions by a controlled corporation to its corporate shareholder, before the latter distributes the former in a spin-off transaction; (iii) certain redemptions of preferred stock; and (iv) in the case of a domestic entity that is a domestic partnership, certain partnership distributions. These changes are not adopted in the temporary regulations because each type of distribution implicates the fundamental concern that it reduces the value of the domestic entity. Furthermore, the Treasury Department and the IRS have concluded that crafting an “angel list” of categories of distributions would make the NOCD rule more complex and in some cases could lead to inappropriate results. As an example of additional complexity, to produce symmetrical results, it would be necessary to distinguish these types of distributions from other distributions and exclude them not only from the look-back period, but also from the distribution history period (as described in Section iii of this Part I.B.5.b). Another comment suggested that aggregate distributions during a period be calculated by netting distributions against certain capital contributions. Although netting distributions against contributions could more accurately reflect any reduction in the value of the domestic entity, it would require additional rules to identify which contributions and distributions are appropriate to net, raising the same complexity concerns as the other comments. The Treasury Department and IRS also note that netting is not allowed in other settings, for example, in the excess distribution regime under section 1291 (which applies to passive foreign investment companies) and in § 1.7874-4T (which applies to domestic entity acquisitions). In particular, § 1.7874-4T does not allow for a foreign acquiring corporation to net the amount of disqualified stock, the issuance of which increases its value, against distributions it makes. In sum, the Treasury Department and the IRS have determined that the NOCD rule should operate as a bright-line rule, testing whether a domestic entity's value-decreasing distributions exceed a threshold amount. For this reason, and in response to a comment, the temporary regulations exclude from the definition of a distribution certain distributions described in sections 304 and 305 because they do not reduce the domestic entity's value. See § 1.7874-10T(h)(1)(i)(A) and (B).
The temporary regulations set forth five steps for determining the amount of NOCDs. The first step is to identify the look-back period, that is, the period during which distributions are subject to being disregarded under the NOCD rule. Under § 1.7874-10T(h)(4), the look-back period means the 36-month period ending on the completion date or, if shorter, the entire period starting with the formation date (described in § 1.7874-10T(h)(3) as the earliest of the dates that the domestic entity and any predecessor were created or organized) and ending on the completion date.
The next step is to divide the look-back period into look-back years. Although the 2014 notice contemplated using a taxable-year convention to determine a look-back year, a taxable-year convention may create undue complexity or uncertainty when—as noted in a comment—the completion date is not the last day of the domestic entity's taxable year, or when the domestic entity (or any predecessor) has a short taxable year. Because a 12-month convention more simply addresses these situations and thus provides for a more administrable NOCD rule, the Treasury Department and the IRS have determined that a 12-month convention should be used to determine a look-back year. Accordingly, the temporary regulations provide that a look-back year generally means any of the three consecutive 12-month periods that comprise the look-back period. See § 1.7874-10T(h)(5)(i). The temporary regulations also provide special rules for determining look-back years when the look-back period is less than 36 months. See § 1.7874-10T(h)(5)(ii) through (iv).
Once the look-back years have been determined, the distribution history period for each look-back year must be identified. The distribution history period for a look-back year generally means the 36-month period preceding the start of the look-back year. § 1.7874-10T(h)(2)(i). In response to a comment, the temporary regulations provide special rules for determining the distribution history period for a look-back year that is not preceded by 36 months of history. In particular, § 1.7874-10T(h)(2)(ii) provides that when the formation date is less than 36 months, but at least 12 months, before
Next, the NOCD threshold for each look-back year must be calculated. Except for a look-back year that does not have a distribution history period, the NOCD threshold for a look-back year means 110 percent of the sum of the distributions made during the distribution history period for that look-back year multiplied by a fraction. § 1.7874-10T(h)(7)(i). The numerator of the fraction is the number of days in the look-back year at issue, and the denominator of the fraction is the number of days in the distribution history period for that look-back year. Id. Thus, if a look-back year has a 36-month distribution history period, the NOCD threshold for that look-back year would be 110 percent of the distributions in the 36-month distribution history period, multiplied by 1/3 (simplified from 365/1095). Similarly, if a look-back year has only a 12-month distribution history period, then the NOCD threshold for that look-back year generally would be 110 percent of the distributions in the 12-month distribution history period, multiplied by 1 (simplified from 365/365). For a look-back year that does not have a distribution history period, the NOCD threshold is zero. § 1.7874-10T(h)(7)(ii).
The last step for determining the amount of NOCDs is to calculate, for each look-back year, the excess, if any, of all distributions made during the look-back year over the NOCD threshold for the look-back year. Under § 1.7874-10T(h)(6), the excess amounts constitute NOCDs.
One comment suggested an aggregate approach to determining NOCDs under which NOCDs would mean the excess of all distributions during the look-back period over 110 percent of the aggregate distributions made during the 36-month period preceding the look-back period. The approach described in the preceding paragraphs is generally consistent with the approach used in other areas of the Code. See, for example, sections 172(g)(3)(C) and 1291(b)(1). Moreover, for a domestic entity that has otherwise had a consistent distribution practice during the look-back period, the approach suggested by the comment would facilitate larger distributions than are intended to be permitted under the NOCD rule in the year preceding the domestic entity acquisition, the year in which abusive distributions are most likely. As a result, the Treasury Department and the IRS decline to adopt the recommendation.
In response to a comment, the temporary regulations provide that a corporation or partnership (relevant entity) is treated for all purposes of the NOCD rule—including for purposes of look-back year calculations, distribution history period calculations, and NOCD threshold calculations—as having made distributions that were made by a predecessor of the relevant entity (the predecessor rule). § 1.7874-10T(e). Under the predecessor rule, a domestic entity “inherits” distributions made by a predecessor (and, such a predecessor could also be a relevant entity that inherits distributions made by a predecessor with respect to it).
The predecessor rule serves two purposes. First, the predecessor rule prevents potential avoidance of the NOCD rule. For example, absent the predecessor rule, a domestic corporation that would be treated as having NOCDs under the NOCD rule might, in anticipation of a domestic entity acquisition, undergo a reorganization into a newly formed domestic corporation and take the position that the newly formed domestic corporation has no distributions to which the NOCD rule applies. In addition, upon the combination of two domestic corporations in a transaction before a domestic entity acquisition, the domestic corporations might, absent the predecessor rule, structure the combination such that the corporation with the more favorable distribution history serves as the surviving corporation. Although section 7874(c)(4) could apply to address these types of transactions even absent the predecessor rule, the Treasury Department and the IRS have determined that it is appropriate to specifically address these transactions through the predecessor rule.
Second, the predecessor rule increases the accuracy of NOCD calculations. That is, when two entities combine in a transaction that increases the value of the combined group (for example, in a transaction in which a substantial portion of the consideration issued by the acquiring entity consists of equity interests in the entity), the distribution-paying capacity of the combined group increases. As a result, the separate distribution histories of the entities should be combined pursuant to the predecessor rule because, otherwise, post-combination distributions (which are funded by the earnings of both entities) might be compared to an NOCD threshold that is inappropriately low (that is, an NOCD threshold that takes into account the distribution history of only the acquiring entity).
In response to comments, the temporary regulations provide guidance on the meaning of predecessor. In particular, the temporary regulations provide that an entity (tentative predecessor) is a predecessor of another entity (relevant entity) when two requirements are satisfied. First, the relevant entity must complete a predecessor acquisition, which occurs when a relevant entity directly or indirectly acquires substantially all of the properties held directly or indirectly by the tentative predecessor. See § 1.7874-10T(f)(1)(i) and (f)(2)(i). Second, after the predecessor acquisition and all related transactions are complete, at least 10 percent of the stock (or interests) in the relevant entity must be held by reason of holding stock (or interests) in the tentative predecessor. See § 1.7874-10T(f)(1)(ii) and (f)(3).
The second requirement generally ensures that only transactions that result in a meaningful increase in the value of the relevant entity result in the predecessor's history being inherited by the relevant entity. The second requirement also generally ensures that, before the predecessor acquisition, the fair market value of the tentative predecessor is greater than a de minimis portion of the fair market value of the relevant entity. Accordingly, and in response to a comment, the second requirement generally prevents a tentative predecessor from being a predecessor in cases in which the utility of the relevant entity inheriting the historic distributions of the tentative predecessor could be outweighed by the potentially complicated due diligence required to determine those historic distributions. On the other hand, the Treasury Department and the IRS determined that it is not appropriate to condition predecessor status on a tentative predecessor being larger in value than the relevant entity at the time of the predecessor acquisition, as was suggested by a comment. Such a narrow definition of predecessor would not appropriately reflect the second, accuracy-related purpose of the predecessor rule, which requires taking into account the increase in the
Under the temporary regulations, when there is a predecessor of a relevant entity, the relevant entity inherits the full amount of any distributions made by the predecessor before the predecessor acquisition. § 1.7874-10T(e)(1). The relevant entity also inherits the full amount of any transfer of money or other property to the former owners of the predecessor that is made in connection with the predecessor acquisition, to the extent the money or other property was directly or indirectly provided by the predecessor. See § 1.7874-10T(e)(2); see also § 1.7874-10T(h)(1)(iv).
A comment noted that, in cases in which a foreign corporation wishes to acquire only a portion of a domestic corporation's properties, different results may arise under the NOCD rule depending on how the parties structure the acquisition and related transactions. Consider, for example, a situation in which a domestic parent corporation (DP) owns two businesses, Business A ($600 fair market value) and Business B ($400 fair market value), and a foreign corporation (FA) wishes to acquire Business A in exchange for FA stock. Under one structure, DP could contribute Business B to a newly formed domestic corporation (DC) and then distribute the stock of DC to its shareholders, followed by FA acquiring all the stock of DP in exchange for $600 of FA stock. Under another structure, DP could contribute Business A to DC and then distribute the stock of DC to its shareholders, followed by FA acquiring all the stock of DC in exchange for $600 of FA stock. In the first scenario, because the $400 of value attributable to Business B was distributed by the domestic entity (DP), the NOCD rule would take into account the value of Business B. In the second scenario, however, the NOCD rule would not take into account the $400 of value of Business B, because the value of Business B was not distributed by the domestic entity (DC) and, moreover, DC would not inherit any portion of the distribution by DP of the DC stock. See § 1.7874-10T(f)(1) (defining a predecessor).
The comment explained that examples like the one in the preceding paragraph demonstrate that, if in certain cases the direction of a spin-off is respected for purposes of the NOCD rule, then transactions that are substantively the same could give rise to vastly different results under the NOCD rule depending on the direction of the spin-off. The comment noted that this could lead to abuse of the NOCD rule. The Treasury Department and the IRS agree with the concerns raised by the comment. As a result, the temporary regulations provide a special rule pursuant to section 7874(g) that, for purposes of the NOCD rule, creates parity between certain transactions regardless of the direction of a spin-off. See § 1.7874-10T(g).
The special rule in § 1.7874-10T(g) applies when a domestic corporation (domestic distributing corporation) distributes stock of another domestic corporation (controlled corporation) pursuant to a transaction described in section 355 and, immediately before the distribution, the value of the distributed stock represents more than 50 percent of the value of the domestic distributing corporation. When the special rule applies, the controlled corporation is deemed for purposes of the NOCD rule to have distributed the stock of the distributing corporation. The value of the deemed distribution is equal to the fair market value of the distributing corporation (but not taking into account the fair market value of the stock of the controlled corporation) on the date of the distribution.
The temporary regulations generally provide that, for purposes of the substantiality test in § 1.367(a)-3(c)(3)(iii)(A), the fair market value of the U.S. target company includes the aggregate value of NOCDs made by the U.S. target company. § 1.367(a)-3T(c)(3)(iii)(C). In this regard, NOCDs are calculated in the same manner as provided under § 1.7874-10T. See id. Thus, regardless of whether the transfer of stock of the U.S. target company is part of a domestic entity acquisition, the amount of NOCDs under § 1.367(a)-3T(c)(3)(iii)(C) is the same as the amount of NOCDs that would exist under § 1.7874-10T.
One comment recommended a de minimis exception should apply to the NOCD rule as applied for purposes of the section 367(a) substantiality test. The comment suggested that the exception could be based on a fixed dollar amount or percentage of the U.S. target company, perhaps conditioned on a requirement that the distribution not have been motivated by the substantiality test. The temporary regulations adopt the comment's recommendation to provide a de minimis exception, but do not adopt the comment's recommended formulation of the exception. Rather, because the Treasury Department and IRS have concluded that the NOCD rule should apply consistently under sections 367 and 7874, the temporary regulations provide that the NOCD rule under section 367 does not apply if the de minimis exception in § 1.7874-10T(d) would apply. See § 1.367(a)-3T(c)(3)(iii)(C).
In general, section 7874 is intended to apply to transactions in which a U.S. parent corporation of a multinational corporate group is replaced by a foreign parent corporation without a significant change in the ultimate ownership of the group. See H.R. Conf. Rep. No. 755, 108th Cong., 2d Sess., at 568 (2004). Congress intended the statutory EAG rule in section 7874(c)(2)(A) to prevent section 7874 from applying to certain transactions that do not give rise to inversion policy concerns. For example, section 7874 should not apply to transactions occurring within a group of corporations owned by the same common parent corporation before and after the transaction, such as the conversion of a wholly-owned domestic subsidiary into a new wholly-owned CFC. See JCT Explanation, at 344. In this regard, section 7874(c)(2)(A) provides that stock of a foreign acquiring corporation that is held by members of the EAG is not included in the numerator or the denominator of the ownership fraction (statutory EAG rule).
The application of the statutory EAG rule may not always lead to appropriate results, including when the domestic entity has minority shareholders. To address these cases, § 1.7874-1 provides two exceptions to the statutory EAG rule: The internal group restructuring exception and the loss-of-control exception (together with the statutory EAG rule, the EAG rules). See § 1.7874-1(c)(2) and (3), respectively. When either of these exceptions applies, stock of the foreign acquiring corporation held by members of the EAG is excluded from the numerator, but not the denominator, of the ownership fraction. In general, the internal group restructuring exception applies when the domestic entity and the foreign acquiring corporation are members of an affiliated group (generally based on an 80-percent vote-and-value requirement) with the same common parent both
Section 1.7874-5T addresses the effect on the numerator of the ownership fraction when former domestic entity shareholders or former domestic entity partners receive stock of the foreign acquiring corporation by reason of holding stock or a partnership interest in the domestic entity and then transfer that stock to another person. Specifically, § 1.7874-5T(a) provides that stock of the foreign acquiring corporation that is described in section 7874(a)(2)(B)(ii) (that is, by-reason-of stock) shall not cease to be so described as a result of any subsequent transfer of the stock by the former domestic entity shareholder or former domestic entity partner that received the stock, even if the subsequent transfer is related to the domestic entity acquisition described in section 7874(a)(2)(B)(i). The preamble to that regulation notes that the Treasury Department and the IRS continue to study the extent to which subsequent transfers of stock of the foreign acquiring corporation should be taken into account in applying the EAG rules. See TD 9654, published on January 17, 2014, in the
Section 2.03(b) of the 2014 notice provides a rule concerning the interaction of § 1.7874-5T and the EAG rules. Subject to two exceptions, the 2014 notice provides that certain stock, referred to as “transferred stock,” is not treated as held by a member of the EAG for purposes of applying the EAG rules. As a result, transferred stock generally is included in both the numerator and the denominator of the ownership fraction. See § 1.7874-5T(a). For this purpose, transferred stock is stock of a foreign acquiring corporation described in section 7874(a)(2)(B)(ii) (that is, by-reason-of stock) that is received by a former domestic entity shareholder or former domestic entity partner that is a corporation (transferring corporation), and, in a transaction (or series of transactions) related to the domestic entity acquisition, is subsequently transferred.
The 2014 notice also described two exceptions to this rule: The U.S.-parented group exception and the foreign-parented group exception. When either of these exceptions applies, transferred stock is treated as held by members of the EAG for purposes of applying the EAG rules. In these cases, transferred stock is excluded from the numerator of the ownership fraction and, depending on the application of § 1.7874-1(c), may be excluded from the denominator of the ownership fraction. See § 1.7874-1(b) and (c).
The U.S.-parented group exception applies if: (i) Before and after the domestic entity acquisition, the transferring corporation (or its successor) is a member of a U.S.-parented group, and (ii) after the domestic entity acquisition, both the person that holds the transferred stock after all related transfers of the transferred stock are complete and the foreign acquiring corporation are members of the U.S.-parented group referred to in (i).
The foreign-parented group exception applies if: (i) Before the domestic entity acquisition, the transferring corporation and the domestic entity are members of the same foreign-parented group, and (ii) after the domestic entity acquisition, the transferring corporation is a member of the EAG, or would be a member of the EAG absent the subsequent transfer of any stock of the foreign acquiring corporation by a member of the foreign-parented group in a transaction related to the domestic entity acquisition (but taking into account all other transactions related to such acquisition).
The 2014 notice defines a U.S.-parented group as an affiliated group that has a domestic corporation as the common parent corporation, and a foreign-parented group as an affiliated group that has a foreign corporation as the common parent corporation. For this purpose, the term “affiliated group” means an affiliated group as defined in section 1504(a) but without regard to section 1504(b)(3), except that section 1504(a) is applied by substituting the term “more than 50 percent” for the term “at least 80 percent” each place it appears. Finally, the 2014 notice provides that, except as provided in the foreign-parented group exception, all transactions related to the domestic entity acquisition must be taken into account for purposes of determining an EAG, a U.S.-parented group, and a foreign-parented group.
Section 1.7874-6T sets forth the rule concerning the interaction of § 1.7874-5T and the EAG rules, as described in the 2014 notice, subject to the modifications described in this Part I.C.3, in part, to address comments received.
In response to a comment, the Treasury Department and the IRS have determined that it is not necessary to limit the U.S.-parented group exception to cases in which the common parent after the domestic entity acquisition is the same as the common parent before the acquisition. Accordingly, under § 1.7874-6T, the U.S.-parented group exception applies if two requirements are satisfied. First, before the domestic entity acquisition, the transferring corporation must be a member of a U.S.-parented group. § 1.7874-6T(c)(1)(i). Second, after the domestic entity acquisition, each of the transferring corporation (or its successor), any person that holds transferred stock, and the foreign acquiring corporation must be members of a U.S.-parented group the common parent of which: (i) Before the domestic entity acquisition, was a member (including the parent) of the U.S.-parented group described in the first requirement; or (ii) is a corporation that was formed in a transaction related to the domestic entity acquisition, provided that, immediately after the corporation was formed (and without regard to any related transactions), the corporation was a member of the U.S.-parented group described in the first requirement. § 1.7874-6T(c)(1)(ii).
A comment asserted that certain restructurings undertaken by foreign-parented groups could inappropriately be subject to section 7874. The comment posited a circumstance that is a variation of Example 2 of section 2.03(b)(iv) of the 2014 notice, where FA, the foreign acquiring corporation, acquired all the stock of a domestic corporation (DT) from a foreign corporation (FT) pursuant to a reorganization described in section 368(a)(1)(F). Related to the reorganization, FA subsequently issued shares to an individual in exchange for nonqualified property (as defined in § 1.7874-4T(i)(7)), which prevented FA and FT from being members of the same expanded affiliated group, therefore resulting in an ownership fraction of 100 percent. The comment asserted that there was no policy reason for section 7874 to apply to this transaction and requested that all “foreign-to-foreign” reorganizations described in section 368(a)(1)(F) be excluded from the application of section 7874.
The Treasury Department and the IRS decline to adopt the comment at this
A comment noted that it is unclear how to identify transferred stock in certain cases. This may occur, for example, when a transferring corporation that receives stock of a foreign acquiring corporation described in section 7874(a)(2)(B)(ii) (that is, by-reason-of stock) also holds other stock of the foreign acquiring corporation that has the same terms as the by-reason-of stock (other stock) (by-reason-of stock and other stock, collectively, fungible stock), and in a transaction related to the domestic entity acquisition, subsequently transfers less than all of the fungible stock. Different results would arise in these cases depending on the extent to which the subsequently transferred stock is considered to consist of by-reason-of stock or other stock.
To address this concern, the temporary regulations provide that a pro rata portion of the subsequently transferred stock is treated as consisting of by-reason-of stock. See § 1.7874-6T(f)(2)(ii).
The temporary regulations modify the affiliate-owned stock rules in § 1.7874-1 to take into account the rules described in the 2014 notice. First, the temporary regulations provide that, subject to an exception, for purposes of §§ 1.7874-1 and 1.7874-1T, all transactions related to an acquisition are taken into account. See § 1.7874-1T(f). This rule is consistent with the general rule provided in § 1.7874-6T(e) and the general rule described in section 2.03(b)(i) of the 2014 notice.
Second, the temporary regulations modify the internal group restructuring exception to take into account § 1.7874-6T(c)(2). See § 1.7874-1T(c)(2)(iii).
Section 2.02(a) of the 2015 notice provides a rule (the subject-to-tax rule) that addresses domestic entity acquisitions in which a taxpayer asserts that its EAG has substantial business activities in the relevant foreign country when compared to the EAG's total business activities even though the foreign acquiring corporation is not subject to tax as a resident of the relevant foreign country. Under the subject-to-tax rule, an EAG cannot have substantial business activities in the relevant foreign country when compared to the EAG's total business activities unless the foreign acquiring corporation is subject to tax as a resident of the relevant foreign country.
The temporary regulations implement the subject-to-tax rule described in the 2015 notice without making any substantive changes. See § 1.7874-3T(b)(4). The requirement set forth in § 1.7874-3T(b)(4) is in addition to the three quantitative tests for group employees, group assets, and group income set forth in § 1.7874-3(b)(1) through (3).
Under § 1.7874-3, an EAG is considered to have substantial business activities in the relevant foreign country only if at least 25 percent of its group employees, group assets, and group income are located or derived in the relevant foreign country. In general, group income is gross income from transactions occurring in the ordinary course of business with unrelated customers, as determined consistently under either federal tax principles or as reflected in the EAG's financial statements. With respect to group income determined using the EAG's financial statements, a comment in response to final regulations issued under § 1.7874-3 (see TD 9720, published on June 4, 2015, in the
As stated in Section 1 of the 2014 notice, the Treasury Department and the IRS understand that certain inversion transactions are motivated in substantial part by the ability to engage in tax avoidance transactions after the inversion transaction that would not be possible in the absence of the inversion transaction. In order to reduce the tax benefits of certain post-inversion tax avoidance transactions, the 2014 notice announced that the Treasury Department and the IRS would issue regulations under sections 304(b)(5)(B), 367, 956(e), 7701(l), and 7874 of the Code. Furthermore, the 2015 notice announced additional rules to reduce the tax benefits of certain post-inversion tax avoidance transactions.
As described in section 3.01(a) of the 2014 notice, an inversion transaction may permit the new foreign parent of the inverted group, a group still principally comprised of United States shareholders and their CFCs, to avoid section 956 by accessing the untaxed earnings and profits of the CFCs without a current U.S. federal income tax to the United States shareholders. This is a result that the United States shareholders could not achieve before the inversion transaction. The ability of the new foreign parent to access deferred CFC earnings and profits would in many cases eliminate the need for the CFCs to pay dividends to the United States shareholders, thereby circumventing the purposes of section 956.
In order to prevent this avoidance of section 956, section 3.01(b) of the 2014 notice announces that future regulations will include a rule (the United States property rule) providing that, solely for purposes of section 956, any obligation or stock of a non-CFC foreign related person (generally, either the foreign
These temporary regulations include the rules described in the 2014 notice, with certain modifications, in part, to address comments received.
Section 1.956-2T(a)(4)(i) provides that, generally, for purposes of section 956 and § 1.956-2(a), United States property includes an obligation of a foreign person and stock of a foreign corporation if (A) the obligation or stock is held by a CFC that is an expatriated foreign subsidiary, (B) the foreign person or foreign corporation is a non-CFC foreign related person, and (C) the obligation or stock was acquired either during the applicable period or in a transaction related to the inversion transaction. A non-CFC foreign related person is defined as a foreign related person that is not itself an expatriated foreign subsidiary. See § 1.7874-12T(a)(16). The rule applies to obligations and stock acquired during the applicable period or in a transaction related to the inversion transaction, regardless of whether at the time of acquisition the obligation or stock would constitute United States property—that is, regardless of whether, at the time of acquisition, the expatriated foreign subsidiary was a CFC or an expatriated foreign subsidiary, and the non-CFC foreign related person was a non-CFC foreign related person. Rather, the rules apply when the requirements set forth in § 1.956-2T(a)(4)(i) are satisfied on the expatriated foreign subsidiary's relevant quarterly measuring date.
The Treasury Department and the IRS have determined that CFC acquisitions of stock or obligations of a prospective foreign acquiring corporation or its foreign affiliates in contemplation of an inversion transaction present the same repatriation concerns as such acquisitions undertaken after an inversion transaction. Accordingly, § 1.956-2T(a)(4)(i)(C)(
An expatriated foreign subsidiary generally is defined as a CFC with respect to which an expatriated entity is a United States shareholder. See § 1.7874-12T(a)(9)(i). However, consistent with the 2014 notice, the Treasury Department and the IRS have determined that the CFCs of a domestic subsidiary owned by a foreign acquiring corporation before an inversion transaction should not be subject to the section 956 rules described in this Part II.A, or the rules under sections 7701(l) and 367(b) described in Sections B.1, B.2, and B.3 of this Part II. Accordingly, consistent with the 2014 notice, § 1.7874-12T(a)(9)(ii) excludes from the definition of expatriated foreign subsidiary a CFC that was a member of the EAG on the completion date if the domestic entity was not a United States shareholder with respect to the CFC on or before the completion date. As a result of not being treated as expatriated foreign subsidiaries, these CFCs are not subject to the new rules described in this Part II.A. However, the stock and obligations of these CFCs generally are United States property when acquired by an expatriated foreign subsidiary during the applicable period because these CFCs constitute non-CFC foreign related persons within the meaning of these temporary regulations. In addition, the exclusion from the definition of expatriated foreign subsidiary does not apply to CFCs of the foreign acquiring corporation's legacy domestic group that are formed or acquired after the inversion transaction. See § 1.956-2T(a)(4)(iv),
The 2014 notice indicates that the term “expatriated entity” has the meaning provided in section 7874(a)(2)(A). Section 7874(a)(2)(A) defines an expatriated entity to include both the domestic entity and any United States person who is related (within the meaning of section 267(b) or 707(b)(1)) to the domestic entity. Comments questioned which entities are expatriated entities in certain cases, for example, when a domestic entity described in section 7874(a)(2)(B)(i) is transferred or ceases to exist. In response to these comments, these temporary regulations clarify that an expatriated entity means a domestic entity (which includes a successor to a domestic entity, whether domestic or foreign) and any United States person that, on any date on or after the completion date, is or was related (within the meaning of section 267(b) or 707(b)(1)) to the domestic entity. See § 1.7874-12T(a)(6) and (8). Thus, for example, an entity that is a domestic subsidiary of a foreign acquiring corporation on (and before) the completion date, is treated as an expatriated entity, while any CFCs owned by that domestic subsidiary on or before the completion date are not treated as expatriated foreign subsidiaries.
The 2014 notice also provides that an expatriated foreign subsidiary that is a pledgor or guarantor with respect to an obligation of a non-CFC foreign related person will be treated as holding the obligation, which would be United States property under the general rule of § 1.956-2T(a)(4)(i), to the same extent that it would be treated as holding the obligation if it were a pledgor or guarantor with respect to an obligation of a United States person under the principles of section 956(d) and § 1.956-2(c). Accordingly, these temporary regulations add § 1.956-2T(c)(5) to extend the pledge and guarantee rule in § 1.956-2(c) to apply to obligations of non-CFC foreign related persons. Under this rule, an expatriated foreign subsidiary that is (or is treated as) a pledgor or guarantor of an obligation of a non-CFC foreign related person is considered to hold the obligation for purposes of section 956. In addition to pledges or guarantees entered into or treated as entered into during the applicable period, the rule applies to pledges or guarantees entered into or treated as entered into in a transaction related to an inversion transaction provided they are entered into or treated as entered into on or after April 4, 2016.
In the description of the United States property rule in section 3.01(b) of the 2014 notice, the Treasury Department and the IRS requested comments on whether any exceptions under section 956(c)(2) or § 1.956-2 should apply to an obligation or stock of a non-CFC
The Treasury Department and the IRS have concluded that it is appropriate for these exceptions to apply to obligations of non-CFC foreign related persons as well as United States persons because they relate to ordinary business transactions. The exceptions in section 956(c)(2)(H) and (I) apply by their terms to obligations of non-CFC foreign related persons, and thus no rules need to be added to the regulations to extend their application. On the other hand, the exceptions in current section 956(c)(2)(C) and (J) apply only to obligations of United States persons. Accordingly, these temporary regulations add rules in § 1.956-2T(a)(4)(ii)(A) and (B), pursuant to which obligations of non-CFC foreign related persons are excluded from the definition of United States property to the same extent that obligations of United States persons are excluded from the definition of United States property under section 956(c)(2)(C) and (J). In addition, new § 1.956-2T(d)(2)(iii) excludes from the definition of United States property obligations of non-CFC foreign related persons that arise in connection with the provision of services by a CFC, based on the principles of the exception in § 1.956-2T(d)(2)(ii) (previously § 1.956-2T(d)(2)(i)(B)), which sets forth a similar exclusion for obligations of United States persons.
A comment also advocated for an additional exception for CFCs that are regularly engaged in a third-party lending business. Specifically, the comment suggested that loans made by a CFC to related parties in the ordinary course of the CFC's business should not be treated as United States property when the CFC is regularly engaged in the business of making loans to unrelated parties. Alternatively, the comment suggested a more limited exclusion for loans made pursuant to a binding commitment that predated the inversion transaction, or negotiations leading to it, such as loans made under a revolving line of credit that was established several years before the first negotiations leading to the inversion transaction. An exception akin to the exception suggested by the comment does not currently exist with respect to obligations of United States persons. The consideration of new exceptions to the definition of United States property is beyond the scope of this regulation. Furthermore, the exception from the definition of non-CFC foreign related person for other expatriated foreign subsidiaries ensures that CFCs of a newly inverted group that are in the business of lending to other CFCs of the group will not be subject to section 956 with respect to the loans.
The 2014 notice provides that the exception to the definition of obligation for certain short-term obligations announced in Notice 88-108 (the short-term obligation exception) would not apply to obligations of non-CFC foreign related persons. As discussed in more detail in Part III.B of this Explanation of Provisions section, Notice 88-108 announced an exception for obligations that are collected within 30 days, as long as the CFC does not have loans to related United States persons that would constitute United States property outstanding during the year for 60 or more days. A comment requested that the Treasury Department and the IRS reconsider this position because the concerns underlying the exception exist with respect to foreign-parented groups as well as U.S.-parented groups, and questioned the rationale for eliminating this exception in the context of an inversion transaction. The Treasury Department and the IRS are concerned that there is a heightened risk that taxpayers would take abusive positions in reliance on the short-term obligation exception announced in Notice 88-108 in post-inversion transaction structures, due to the fact that gaining access to the deferred foreign earnings of CFCs without paying U.S. federal income tax is often a stated goal of inversion transactions. Accordingly, these temporary regulations provide that the exception announced in Notice 88-108 applies only to obligations of United States persons. Therefore, this exception does not apply to an obligation of a non-CFC foreign related person that is treated as United States property pursuant to § 1.956-2T(a)(4)(i).
As described in the 2014 notice, after an inversion transaction, the inverted group may cause an expatriated foreign subsidiary to cease to be a CFC using certain transactions that do not give rise to U.S. federal income tax, so as to avoid U.S. federal income tax on the CFC's pre-inversion transaction earnings and profits. Additionally, even if the foreign acquiring corporation were to acquire less stock of an expatriated foreign subsidiary, such that the expatriated foreign subsidiary remained a CFC, it could nevertheless substantially dilute a United States shareholder's ownership of the CFC. As a result, the United States shareholder could avoid U.S. federal income tax on the CFC's pre-inversion transaction earnings and profits if, for example, the CFC later redeemed, on a non pro rata basis, its stock held by the foreign acquiring corporation.
In order to prevent the use of these transactions to avoid U.S. federal income tax, the 2014 notice announces that the Treasury Department and the IRS intend to issue regulations under section 7701(l) that will recharacterize specified transactions completed during the applicable period (the section 7701(l) recharacterization rule). A specified transaction is defined in section 3.02(e)(i) of the 2014 notice as a transaction in which stock in an expatriated foreign subsidiary (specified stock) is transferred (including by issuance) to a specified related person. A specified related person means a non-CFC foreign related person, a U.S. partnership that has one or more partners that is a non-CFC foreign related person, or a U.S. trust that has one or more beneficiaries that is a non-CFC foreign related person.
Section 3.02(e)(i)(A) of the 2014 notice provides that a specified transaction is recharacterized for all purposes of the Code, as of the date on which the specified transaction occurs, as an arrangement directly between the specified related person and one or more section 958(a) U.S. shareholders of the expatriated foreign subsidiary. A
The 2014 notice states that regulations will provide that, if an expatriated foreign subsidiary issues specified stock to a specified related person, the specified transaction will be recharacterized as follows: (i) The property transferred by the specified related person to acquire the specified stock (transferred property) will be treated as having been transferred by the specified related person to the section 958(a) U.S. shareholder(s) of the expatriated foreign subsidiary in exchange for instruments deemed issued by the section 958(a) U.S. shareholder(s) (deemed instrument(s)); and (ii) the transferred property or proportionate share thereof will be treated as having been contributed by the section 958(a) U.S. shareholder(s) (through intervening entities, if any, in exchange for equity in such entities) to the expatriated foreign subsidiary in exchange for stock in the expatriated foreign subsidiary. The 2014 notice states that similar principles will apply to recharacterize a specified transaction in which a shareholder transfers specified stock of the expatriated foreign subsidiary to a specified related person (such as a partnership in which a non-CFC foreign related person is a partner).
Section 3.02(e)(i)(B) of the 2014 notice explains that regulations will provide that a deemed instrument treated as issued in a specified transaction will have the same terms as the specified stock (other than the issuer). Accordingly, if a distribution is made with respect to specified stock of the expatriated foreign subsidiary, matching seriatim distributions with respect to stock will be treated as made by the expatriated foreign subsidiary (through intervening entities, if any) to the section 958(a) U.S. shareholder(s). The section 958(a) U.S. shareholder(s), in turn, will be treated as making payments with respect to the deemed instrument(s) to the specified related person(s). An expatriated foreign subsidiary will be treated as the paying agent of a section 958(a) U.S. shareholder of the expatriated foreign subsidiary with respect to the deemed instrument treated as issued by the section 958(a) U.S. shareholder to a specified related person.
The 2014 notice states that the regulations will not recharacterize a specified transaction in certain situations. If the specified transaction is a fast-pay arrangement that is recharacterized under § 1.7701(l)-3(c)(2), section 3.02(e)(i)(A) of the 2014 notice provides that the rules of § 1.7701(l)-3 will apply instead of the recharacterization provided in the 2014 notice. Furthermore, section 3.02(e)(i)(C) of the 2014 notice provides that a specified transaction will not be recharacterized if the specified stock was transferred by a shareholder of the expatriated foreign subsidiary and, under applicable U.S. federal income tax rules, the shareholder either is required to recognize and include in income all of the gain in the specified stock (including gain treated as a deemed dividend pursuant to section 964(e) or 1248(a) or characterized as a dividend pursuant to section 356(a)(2)) or has a deemed dividend included in income with respect to the specified stock under § 1.367(b)-4 (including by reason of the regulations described in the 2014 notice that apply to specified exchanges, described in Section 2.c.i of this Part II.B). The last exception described in the 2014 notice applies if (i) the expatriated foreign subsidiary is a CFC immediately after the specified transaction and all related transactions, and (ii) the amount of stock (by value) in the expatriated foreign subsidiary (and any lower-tier expatriated foreign subsidiary) that is owned, in the aggregate, directly or indirectly by the section 958(a) U.S. shareholders of the expatriated foreign subsidiary immediately before the specified transaction and any transactions related to the specified transaction does not decrease by more than 10 percent as a result of the specified transaction and any related transactions. The 2015 notice clarifies that the second prong of the exception is satisfied only if the percentage of stock (by value) (rather than the amount of stock (by value)) does not decrease by more than 10 percent.
Further, the 2014 notice states that regulations will provide that if a deemed dividend is included in a CFC's income under section 964(e) as a result of a specified transaction that is completed during the applicable period, the deemed dividend will not be excluded from foreign personal holding company income under section 954(c)(6) (to the extent in effect, and notwithstanding the rule described in Notice 2007-9, 2007-1 C.B. 401).
These temporary regulations implement the section 7701(l) recharacterization rule described in the 2014 notice, subject to certain modifications, in part, to address comments received. Under § 1.7701(l)-4T(b)(1), a specified transaction completed during the applicable period will be recharacterized in the manner described in § 1.7701(l)-4T(c), subject to the exceptions described in § 1.7701(l)-4T(b)(2).
The description of the specified transaction rules in section 3.02(e) of the 2014 notice provides that a “section 958(a) U.S. shareholder” means any United States shareholder of an expatriated foreign subsidiary that is related (within the meaning of section 267(b) or 707(b)(1)) to the specified related person or is under the same common control (within the meaning of section 482) as the specified related person. In order to more appropriately tailor the rules, these temporary regulations narrow the definition of the term “section 958(a) U.S. shareholder” to include only United States shareholders that are expatriated entities. See § 1.7701(l)-4T(f)(10).
If an expatriated foreign subsidiary issues specified stock to a specified related person, the specified transaction is recharacterized under § 1.7701(l)-4T(c)(2) in the manner described in the 2014 notice. Similar rules are provided in § 1.7701(l)-4T(c)(3) for a specified transaction arising from a transfer of specified stock by shareholders of the expatriated foreign subsidiary. In the 2014 notice, the Treasury Department and the IRS requested comments about the application of the recharacterization rules to transfers to partnerships that are specified related persons, as illustrated in Example 2 in section 3.02(e)(iii) of the notice. A comment suggested that the recharacterization described in the 2014 notice should not apply to transfers of specified stock to partnerships, and that, instead, a transferee partnership should be treated as a conduit, to the extent of its ownership of specified stock and any corresponding property contributed to the partnership. The comment suggested that the section 958(a) U.S. shareholder could be treated as directly owning the specified stock, or, alternatively, the items attributable to the specified stock could be tracked solely to the section 958(a) U.S. shareholder. Thus, under the proposed recast, each transferor to the partnership would be treated as
The Treasury Department and the IRS appreciate the complexity of the recharacterization described in the 2014 notice, as highlighted by the comment, but are concerned that the comment does not fully account for the treatment of distributions by the expatriated foreign subsidiary as received by its section 958(a) U.S. shareholder rather than the transferee partnership. After consideration of the comment's proposal, the Treasury Department and the IRS have determined that the recharacterization described in the 2014 notice better ensures that an expatriated foreign subsidiary that is transferred to a partnership that is a specified related person continues to be a CFC, while addressing the ancillary consequences of recharacterizing the transfer.
The expatriated foreign subsidiary stock that is deemed issued pursuant to the recharacterization is referred to in the regulations as “deemed issued stock,” and the specified stock actually issued pursuant to the specified transaction but disregarded pursuant to the recharacterization is referred to as “disregarded specified stock.” Because the instruments deemed issued by a section 958(a) U.S. shareholder have the same terms as the disregarded specified stock (other than the issuer), the Treasury Department and the IRS believe that the deemed instruments generally will be treated as equity for all purposes of the Code.
Section 1.7701(l)-4T(b)(2) sets forth three exceptions to the application of the rules in § 1.7701(l)-4T(c) to recharacterize a specified transaction. The first two exceptions are consistent with the exceptions described in the 2014 notice and the 2015 notice for fast-pay arrangements described in § 1.7701(l)-3(b) and transactions (including specified exchanges) in which an appropriate amount of gain is recognized. See Section 2.C of this Part II.B for a description of the rules applicable to specified exchanges.
The final exception applies when the expatriated foreign subsidiary is a CFC immediately after the specified transaction and any related transaction and there is only a
The
The temporary regulations provide a special rule to ensure that stock of a corporation that is directly or indirectly owned by a domestic corporation that is an expatriated entity is considered for purposes of the
Because the
The 2014 notice requested comments on whether an exception to the section 7701(l) recharacterization rule and the section 367(b) stock dilution rule (described in Section 2 of this Part II.B) is warranted where (i) a specified transaction is undertaken in order to integrate similar or complementary businesses and (ii) after the inversion transaction, the inverted group in fact does not exploit that form in order to avoid U.S. taxation on the expatriated foreign subsidiary's pre-inversion earnings and profits. In addition, the 2014 notice requested comments on the provisions that would be necessary to administer such an exception and on the types of transactions that would need to serve as “triggers” for denying the exception because taxpayers could use them to avoid tax on a CFC's pre-inversion earnings after a specified transaction. One comment recommended providing a business integration exception because foreign-parented multinational groups of corporations often engage in internal restructurings for business reasons. After consideration of the comment, the Treasury Department and the IRS have determined that a business integration exception would be very difficult to administer given the subjective nature of the determination, the difficulty of determining whether the taxpayer takes “exploitative” actions in subsequent taxable years, and the complexity of potentially having to apply the section 7701(l) recharacterization rule retroactively depending on these subsequent actions. Accordingly, the temporary regulations do not provide a business integration exception.
The rules in § 1.7701(l)-4T(d) address transactions that affect the ownership of stock of an expatriated foreign subsidiary after a specified transaction with respect to the expatriated foreign subsidiary has been recharacterized under § 1.7701(l)-4T(c)(2) or (3). As discussed in Section i of this Part II.B.1.b, a specified transaction that is recharacterized under the rules of § 1.7701(l)-4T(c) is recharacterized for all purposes of the Code as of the date that the specified transaction occurs. Although the recharacterization described in the 2014 notice generally applies for all purposes for all future tax years, the Treasury Department and the IRS considered whether to unwind the recharacterization when stock,
The specified transaction rules in § 1.7701(l)-4T are issued under the Secretary's regulatory authority in section 7701(l) to recharacterize multi-party financing arrangements to prevent the avoidance of tax, which is the same authority underlying the fast-pay arrangement rules in § 1.7701(l)-3. Although the two regulations serve a similar purpose, the technical rules that effectuate that purpose deviate due to differences in the underlying financing arrangements. The specified transaction rules set forth herein generally are concerned with the relationship of the expatriated foreign subsidiary to the expatriated entity, as well as the expatriated foreign subsidiary's status as a controlled foreign corporation, and thus generally are focused on abusive transactions that affect the direct and indirect ownership of the expatriated foreign subsidiary.
The 2014 notice states that rules similar to those described in § 1.7701(l)-3(c)(3)(iii) (concerning transfers of benefited stock) under the fast-pay regulations will apply to transactions affecting specified stock. In general, pursuant to § 1.7701(l)-3(c)(3)(iii)(A), the designation of stock as benefited stock continues upon transfer of the stock. Upon further consideration, the Treasury Department and the IRS have determined that it is not necessary for the specified transaction rules to maintain the connection between the instruments that are deemed issued pursuant to the recharacterization and the stock (specifically, the non-specified stock) that led to the application of the recharacterization rules, as occurs when § 1.7701(l)-3(c)(3)(iii) is applied to fast-pay stock, due to the differences in policy underlying the fast-pay regulations and these temporary regulations. Accordingly, a transfer of non-specified stock does not require an associated transfer of the deemed instruments as would be required under the rules in § 1.7701(l)-3(c)(3)(iii) for a transfer of benefited stock. See § 1.7701(l)-4T(d)(1).
However, the Treasury Department and the IRS determined that special rules are necessary to address direct and indirect transfers of stock of an expatriated foreign subsidiary (both disregarded specified stock and non-specified stock), including rules that generally terminate the recharacterization provided for in these temporary regulations. Transactions that occur after the specified transaction can affect the underlying ownership of the expatriated foreign subsidiary stock in such a way that the underlying need for the recharacterization rules ceases to exist. That is, there is no reason for the recharacterization rules to continue to apply when the reason for the rule ceases to apply; the rules need to apply only to the extent the relatedness that gave rise to the application of the rules continues to be present. In addition, transactions in which the inverted group no longer holds the expatriated foreign subsidiary create concerns about whether the taxpayer will have access to the information necessary to comply with the rules in these temporary regulations. In this circumstance, the administrative burden of maintaining the recharacterization is not justified.
Thus, the Treasury Department and the IRS have determined that it is appropriate, in certain circumstances, to unwind the recharacterization as a result of certain subsequent transactions that affect the ownership of the expatriated foreign subsidiary. The regulations provide that the recharacterization generally is fully unwound when an expatriated foreign subsidiary ceases to be a foreign related person. Specifically, § 1.7701(l)-4T(d)(2) provides that when a transaction causes an expatriated foreign subsidiary to cease to be a foreign related person, the recharacterization is fully unwound immediately before the transaction as follows: the section 958(a) U.S. shareholders are treated as redeeming their respective deemed instruments with the deemed issued stock in the expatriated foreign subsidiary, which, in turn, is “recapitalized” into the disregarded specified stock (which is the specified stock that was transferred in the specified transaction that gave rise to the application of § 1.7701-4T) in the hands of the specified related person.
In addition, the regulations provide for a similar pro-rata unwind when the expatriated foreign subsidiary continues to be a foreign related person after a direct or indirect transfer of disregarded specified stock of the expatriated foreign subsidiary, and, after the transfer, no portion of the disregarded specified stock is held by a foreign related person, a specified related person, or an expatriated entity. In such circumstances, § 1.7701(l)-4T(d)(3) provides that the recharacterization under § 1.7701(l)-4T(c)(2) or (3) is partially unwound as follows: The section 958(a) U.S. shareholders are treated as redeeming a proportionate amount of their respective deemed instruments with the deemed issued stock in the expatriated foreign subsidiary, which, in turn, is “recapitalized” into the disregarded specified stock (which is the specified stock that was transferred in the specified transaction that gave rise to the application of § 1.7701-4T) in the hands of the specified related person.
The regulations also provide a rule that applies when there is a direct transfer of disregarded specified stock, but the recharacterization is not unwound, because the transaction does not result in an unwind under the rules described earlier in this Part II.B.1.b.iii. In those circumstances, the transferor is treated as transferring the deemed instruments, in lieu of the disregarded specified stock, in exchange for the consideration that was received in exchange for the disregarded specified stock. See § 1.7701(l)-4T(d)(4).
Even if the rules described in this Part II.B.1.b.iii do not apply to unwind a recharacterization under the rules of § 1.7701(l)-4T(c)(2) or (3), an inverted group may choose to unwind the recharacterization by causing the expatriated foreign subsidiary to actually redeem all of its disregarded specified stock.
Under § 1.7701(l)-4T(e), and consistent with section 3.02(e)(i) of the 2014 notice, a deemed dividend that is included in a CFC's income under section 964(e) as a result of a specified transaction that is completed during the applicable period is not excluded from FPHCI under section 954(c)(6) (to the extent in effect and notwithstanding the rule described in Notice 2007-9). See Part III.C of this Explanation of Provisions section for a discussion of Notice 2007-9.
Section 3.02(e)(ii) of the 2014 notice provides a rule (the section 367(b) stock dilution rule) that addresses certain post-inversion transaction exchanges that dilute the interest of a United States shareholder in a CFC and, absent the rule, could allow the United States shareholder to avoid U.S. federal income tax on earnings and profits of the CFC that exist at the time of the exchange. Specifically, the section 367(b) stock dilution rule, as described in the 2014 notice, provides that when certain requirements are satisfied with
As explained in the 2014 notice, the section 367(b) stock dilution rule is subject to an exception. The exception applies to exchanges that satisfy the principles of the second exception described in section 3.02(e)(i)(C) of the 2014 notice (regarding specified transactions that do not decrease, in the aggregate, the section 958(a) U.S. shareholders' ownership of stock in an expatriated foreign subsidiary (or lower-tier expatriated foreign subsidiary) by more than 10 percent).
The 2014 notice also provides that § 1.367(b)-4(c)(1) (regarding the exclusion of a deemed dividend from foreign personal holding company income) does not apply to a deemed dividend that results from an exchange to which the section 367(b) stock dilution rule applies. Further, the 2014 notice provides that such a deemed dividend does not qualify for the exceptions from foreign personal holding company income provided by section 954(c)(3)(A)(i) or (6) (to the extent in effect).
The 2015 notice expands the consequences of being subject to the section 367(b) stock dilution rule. The 2015 notice provides that, when an exchanging shareholder is required under the section 367(b) stock dilution rule to include in income as a deemed dividend the section 1248 amount (if any) with respect to the stock exchanged, the exchanging shareholder must also, after taking into account any increase in basis provided in § 1.367(b)-2(e)(3)(ii) resulting from the deemed dividend, recognize all realized gain with respect to the stock that is not otherwise recognized. The 2015 notice explains that this result is necessary to prevent a United States shareholder of a CFC from potentially avoiding U.S. federal income tax on net unrealized built-in-gain in property held by the CFC at the time of the exchange of the stock of the CFC. See section 3.02(b) of the 2015 notice.
The 2015 notice also states that a conforming change will be made to the regulations described in section 3.02(e)(i) of the 2014 notice. Thus, as noted in Section 1.b.ii of this Part II.B, the first exception described in section 3.02(e)(i)(C) of the 2014 notice applies with respect to a transfer of specified stock only if, as a result of the transfer, all the gain in the specified stock is recognized.
The temporary regulations implement the section 367(b) stock dilution rule as described in the 2014 notice and the 2015 notice, subject to certain modifications. See § 1.367(b)-4T(e).
The section 367(b) stock dilution rule, as described in the 2014 notice, generally applies to an exchange when three requirements are satisfied. First, the exchanging shareholder must be described in § 1.367(b)-4(b)(1)(i)(A). Second, the exchange must occur pursuant to a transaction described in § 1.367(b)-4(a) in which the exchanging shareholder exchanges stock of an expatriated foreign subsidiary for stock in another foreign corporation. And third, the exchange must occur within the applicable period. The temporary regulations, as well as the remainder of this preamble, use the term “specified exchange” to describe any exchange that meets all three requirements and with respect to which the section 367(b) stock dilution rule thus generally applies. See § 1.367(b)-4T(e)(1) and (2).
The Treasury Department and the IRS have determined that it is appropriate to provide two new exceptions to the section 367(b) stock dilution rule. The first exception applies to specified exchanges in which the exchanging shareholder is neither an expatriated entity nor an expatriated foreign subsidiary. The temporary regulations incorporate this exception into the first requirement for an exchange to be a specified exchange. See § 1.367(b)-4T(e)(2)(i) (requiring, among other things, that the exchanging shareholder be an expatriated entity or an expatriated foreign subsidiary).
The second exception replaces the exception described in the 2014 notice, and is consistent with the exception for de minimis shifts in ownership provided in § 1.7701(l)-4T(b)(2)(iii) and discussed in Section 1.b.ii of this Part II.B. Accordingly, the second exception applies to specified exchanges when the expatriated foreign subsidiary is a CFC immediately after the specified exchange and there is only a de minimis shift of ownership of the stock of the acquired expatriated foreign subsidiary (and any lower-tier expatriated foreign subsidiary) to non-CFC foreign related persons. See § 1.367(b)-4T(e)(3).
Under the second exception, as in the de minimis exception with respect to the section 7701(l) recharacterization rule provided in § 1.7701(l)-4T(b)(2)(iii), to determine whether a specified exchange shifts ownership of stock of an acquired expatriated foreign subsidiary (or any lower-tier expatriated foreign subsidiary) to non-CFC foreign related persons, the temporary regulations generally compare the percentage of the stock (by value) of the corporation owned immediately before and immediately after the exchange by persons other than non-CFC foreign related persons. In the case of asset acquisitions, however, because the acquired expatriated foreign subsidiary does not exist after the exchange, the temporary regulations compare (i) the percentage of the stock (by value) of the transferee foreign corporation—which may be viewed as a successor of the acquired expatriated foreign subsidiary for purposes of the exception—owned immediately after the exchange by persons other than non-CFC foreign related persons to (ii) the percentage of the stock (by value) of the acquired expatriated foreign subsidiary owned immediately before the exchange by persons other than non-CFC foreign related persons. The rules concerning the determination of indirect ownership for this purpose are identical to those applicable for purposes of the de minimis exception from the section 7701(l) recharacterization rule, described in Section 1.b.ii of this Part II.B.
Further, as is generally the case throughout § 1.367(b)-4, judicial doctrines and principles, such as substance-over-form and the step-transaction doctrine, apply in determining whether the requirements of a specified exchange or the de minimis exception are satisfied. See also Rev. Rul. 83-23, 1983-1 C.B. 82.
As noted in Section 1.b.ii of this Part II.B, the 2014 notice requested comments on whether an exception to the section 7701(l) recharacterization rule discussed therein and the section 367(b) stock dilution rule is warranted for certain business integration transactions. For the reasons discussed with respect to the section 7701(l) recharacterization rule, the temporary regulations do not provide a business integration exception with respect to the section 367(b) stock dilution rule.
Consistent with section 3.02(e)(ii) of the 2014 notice, § 1.367(b)-4T(e)(4)
For reasons similar to those discussed in section 3.02(d) of the 2014 notice and section 3.02(b) of the 2015 notice, the Treasury Department and the IRS have determined that, upon a transfer by an expatriated foreign subsidiary of property (other than stock of another expatriated foreign subsidiary) to a transferee foreign corporation in certain section 351 exchanges, the expatriated foreign subsidiary should be required to recognize all realized gain in the property that is not otherwise recognized. Absent such a rule, the transfer could dilute a United States shareholder's indirect interest in the property and, as a result, could allow the United States shareholder to avoid U.S. federal income tax on realized gain that is not recognized at the time of the transfer. For example, under section 351, an expatriated foreign subsidiary could transfer appreciated intangible property to a transferee foreign corporation in connection with a transfer by a non-CFC foreign related person to the transferee foreign corporation. Realized gain in the transferred property that is not recognized at the time of the transfer would, when recognized by the transferee foreign corporation after the transfer, create earnings and profits that are attributable to gain that economically had accrued within the U.S. federal income tax system at the time of the transfer. Because the United States shareholder would own less than all the stock of the transferee foreign corporation, the United States shareholder could avoid U.S. federal income tax on such earnings and profits, particularly if the transferee foreign corporation is not a CFC.
The temporary regulations provide a rule (the section 367(b) asset dilution rule) that applies when an expatriated foreign subsidiary transfers specified property to a foreign transferee corporation in an exchange described in section 351 that occurs within the applicable period. § 1.367(b)-4T(f)(1). When the section 367(b) asset dilution rule applies, the expatriated foreign subsidiary must recognize all realized gain (but not loss) with respect to the specified property that is not otherwise recognized, unless an exception applies. § 1.367(b)-4T(f)(1). For this purpose, specified property means any property other than stock of a lower-tier expatriated foreign subsidiary. § 1.367(b)-4T(g)(5).
Similar to the section 367(b) stock dilution rule, the section 367(b) asset dilution rule contains an exception that applies to transfers in which there is only a de minimis shift of ownership of the specified property to non-CFC foreign related persons. See § 1.367(b)-4T(f)(2). For purposes of the exception, the temporary regulations use ownership of stock of the expatriated foreign subsidiary immediately before the exchange as a proxy for ownership of specified property immediately before the exchange, and, similarly, use ownership of stock of the transferee foreign corporation immediately after the exchange as a proxy for ownership of specified property immediately after the exchange.
Section 3.03(b) of the 2014 notice explains how taxpayers may be engaging in certain transactions following an inversion transaction that reduce the earnings and profits of a CFC to facilitate repatriation of cash and other property of the CFC. The Treasury Department and the IRS understand that taxpayers may interpret section 304(b)(5)(B) to not apply when more than 50 percent of the dividend arising upon application of section 304 is sourced from the domestic corporation, even though, for example, pursuant to an income tax treaty there may be no (or a reduced rate of) U.S. withholding tax imposed on a dividend sourced from the domestic corporation. Under this position, the dividend sourced from earnings and profits of the CFC would never be subject to U.S. federal income tax.
To address the concerns described in Section a of this Part II.B.4, section 3.03(b) of the 2014 notice provides rules (the section 304 rules) that apply for purposes of section 304(b)(5)(B). In particular, the section 304 rules provide that the determination of whether more than 50 percent of the dividends that arise under section 304(b)(2) is subject to tax or includible in the earnings and profits of a CFC is made by taking into account only the earnings and profits of the acquiring corporation (and therefore excluding the earnings and profits of the issuing corporation). The section 304 rules also provide that if a partnership, option (or similar interest), or other arrangement, is used with a principal purpose of avoiding the application of the rule described in section 3.03(b) of the 2014 notice (for example, to treat a transferor as a CFC), then the partnership, option (or similar interest), or other arrangement will be disregarded for purposes of applying the rule. Further, the section 304 rules provide that these rules apply without regard to whether an inversion transaction has occurred.
Section 1.304-7T sets forth regulations implementing the section 304 rules as described in the 2014 notice.
A comment requested that the regulations clarify that a dividend is “subject to tax” if it is reportable in the income of a U.S. person, even if that income is not currently burdened with tax because of the U.S. person's tax attributes. The Treasury Department and the IRS decline to adopt the comment at this time because the narrow scope of § 1.304-7T concerns taking into account only the earnings and profits of the acquiring corporation, for purposes of making the 50 percent determination discussed in Section b of this Part II.B.4.
Section 7874(a)(1), together with section 7874(e)(1) (which prevents the use of certain credits to offset U.S. federal income tax on inversion gain), ensures that an expatriated entity generally pays current U.S. federal income tax with respect to inversion gain. These rules are intended to ensure that an appropriate “toll charge” is paid on transactions that accompany or follow an inversion transaction and are designed to “remove income from foreign operations from the U.S. taxing jurisdiction.” See H.R. Conf. Rep. No. 755, at 568, 574 (2004); JCT Explanation, at 342, 345.
Section 3.01(b) of the 2015 notice announces that the Treasury Department and the IRS intend to issue regulations that will provide a rule (the inversion gain rule) to address certain indirect transfers by an expatriated entity that, absent the rule, could have the effect of removing foreign earnings from the U.S. taxing jurisdiction while
The inversion gain rule also provides that, if a partnership that is a foreign related person transfers or licenses property, a partner of the partnership is treated as having transferred or licensed its proportionate share of that property, as determined under the rules and principles of sections 701 through 777, for purposes of determining inversion gain.
Section 1.7874-11T sets forth the inversion gain rule as described in the 2015 notice, subject to the following modification. In response to a comment, § 1.7874-11T(b)(1) provides that inversion gain includes amounts treated as a dividend under section 78 with respect to foreign taxes deemed to be paid by an expatriated entity under section 902(a) or 960(a)(1).
As noted in Part I of the Background section of this preamble, the temporary regulations provide a new definitions section, § 1.7874-12T, that defines certain terms commonly used in §§ 1.367(b)-4T, 1.956-2T, 1.7701(l)-4T, 1.7874-2, 1.7874-2T, and 1.7874-6T through 1.7874-11T. The Treasury Department and the IRS anticipate, in the future, updating other portions of the section 7874 regulations to conform those sections with the nomenclature used in § 1.7874-12T.
A comment noted that certain rules in the 2014 notice apply to inversion transactions, defined as acquisitions in which the foreign acquiring corporation is treated as a surrogate foreign corporation under section 7874(a)(2). The comment further noted that a transaction is not an inversion transaction if the substantial business activities requirement in section 7874(a)(2)(B)(iii) is not satisfied, but requested that this point be clarified in regulations.
The Treasury Department and the IRS believe that the definition of an inversion transaction, defined in the temporary regulations as a domestic entity acquisition in which the foreign acquiring corporation is treated as a surrogate foreign corporation under section 7874(a)(2)(B), taking into account section 7874(a)(3), is clear. If the substantial business activities requirement in section 7874(a)(2)(B)(iii) is not satisfied, the foreign acquiring corporation is not a surrogate foreign corporation, and the acquisition therefore is not an inversion transaction. Accordingly, this comment is not adopted.
On September 16, 1988, the Treasury Department and the IRS issued Notice 88-108, which announced that regulations would be issued under section 956 that would exclude from the definition of the term “obligation” for purposes of section 956 obligations that are collected within 30 days, as long as the CFC does not have loans to related United States persons that would constitute United States property outstanding during the year for 60 or more days (the 30/60 day exception). Due to circumstances affecting liquidity in the United States during 2008, on October 4, 2008, the Treasury Department and the IRS issued Notice 2008-91, which announced that the 30/60 day exception would be expanded to exclude obligations that are collected within 60 days, as long as the CFC does not have loans outstanding to related United States persons that would constitute United States property during the year for 180 or more days (the 60/180 day exception). A CFC could choose to apply either the 30/60 day exception or the 60/180 day exception in years in which the 60/180 day exception is applicable. Notice 2008-91 applies for the first two taxable years of a foreign corporation ending after October 3, 2008, but does not apply to taxable years of a foreign corporation beginning after December 31, 2009. On January 14, 2009, the Treasury Department and the IRS issued Notice 2009-10, which extends the application of the regulations described in Notice 2008-91 to a third taxable year in certain cases. On December 28, 2009, the Treasury Department and the IRS issued Notice 2010-12, which extends the application of Notice 2008-91 to the taxable year of the CFC that immediately follows the last taxable year of the CFC to which the regulations described in Notice 2008-91 otherwise could apply.
These temporary regulations set forth the exceptions to the definition of obligation that were announced in Notice 88-108 and Notice 2008-91, as modified by Notice 2009-10 and Notice 2010-12. Section 1.956-2T(d)(2)(iv) provides the short-term obligation exception described in Notice 88-108, and § 1.956-2T(d)(2)(v) provides the alternative short-term obligation exception described in Notice 2008-91, Notice 2009-10 and Notice 2010-12. For the years in which § 1.956-2T(d)(2)(v) is applicable, CFCs can choose to apply either paragraph (iv) or paragraph (v) of § 1.956-2T(d)(2).
As noted in Part II.A.2.b of this Explanation of Provisions section, the exceptions in § 1.956-2T(d)(2)(iv) and (v) apply only to obligations of United States persons, and thus do not apply to an obligation of a non-CFC foreign related person that is treated as United States property pursuant to § 1.956-2T(a)(4)(i).
The rules in § 1.956-2T(d)(2)(iv) described in this Part III.B that were described in Notice 88-108 apply to obligations held on or after September 16, 1988, and the rules in § 1.956-2T(d)(2)(v) apply to the first three taxable years of a foreign corporation ending after October 3, 2008, other than taxable years of a foreign corporation beginning on or after January 1, 2011, as well as the fourth taxable year of a foreign corporation, if any, when the foreign corporation's third taxable year (including any short taxable year) ended after October 3, 2008, and on or before December 31, 2009.
On January 11, 2007, the Treasury Department and the IRS issued Notice 2007-9, which provided guidance under section 954(c)(6) and announced that regulations under section 954(c)(6) that incorporated the guidance provided in the notice would be issued. In particular, Notice 2007-9 announced that gains treated as dividends under section 964(e) would be included among dividends eligible for the exclusion from FPHCI in section 954(c)(6). In the 2014 notice, the Treasury Department and the IRS announced that, notwithstanding Notice 2007-9, a deemed dividend included in a CFC's income under section 964(e) as a result
Notice 88-108, 1988-2 C.B. 446 is obsolete as of April 4, 2016.
Notice 2008-91, 2008-43 I.R.B. 1001 is obsolete as of April 4, 2016.
Notice 2009-10, 2009-5 I.R.B. 419 is obsolete as of April 4, 2016.
Notice 2010-12, 2010-4 I.R.B. 326 is obsolete as of April 4, 2016.
Notice 2014-52, 2014-42 I.R.B. 712 is obsolete as of April 4, 2016.
Notice 2015-79, 2015-49 I.R.B. 775 is obsolete as of April 4, 2016.
IRS Revenue Procedures, Revenue Rulings, notices, and other guidance cited in this document are published in the Internal Revenue Bulletin (or Cumulative Bulletin) and are available from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, or by visiting the IRS Web site at
Certain IRS regulations, including this one, are exempt from the requirements of Executive Order 12866, as supplemented and reaffirmed by Executive Order 13563. Therefore, a regulatory assessment is not required. It has been determined that sections 553(b) and (d) of the Administrative Procedure Act (5 U.S.C. chapter 5) do not apply to these regulations. For applicability of the Regulatory Flexibility Act (5 U.S.C. chapter 6), refer to the cross-referenced notice of proposed rulemaking published elsewhere in this issue of the
The principal authors of these regulations are Rose E. Jenkins, David A. Levine, and Shane M. McCarrick of the Office of Associate Chief Counsel (International). However, other personnel from the Treasury Department and the IRS participated in their development.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is amended as follows:
26 U.S.C. 7805 * * *
Section 1.304-7T also issued under 26 U.S.C. 304(b)(5)(C).
Section 1.367(b)-4T also issued under 26 U.S.C. 367(b) and 954(c)(6)(A).
Section 1.956-2T also issued under 26 U.S.C. 956(d) and 956(e).
Section 1.7701(l)-4T also issued under 26 U.S.C. 7701(l) and 954(c)(6)(A).
Section 1.7874-2T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-3T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-6T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-7T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-8T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-9T also issued under 26 U.S.C. 7874(c)(6) and (g).
Section 1.7874-10T also issued under 26 U.S.C. 7874(c)(4) and (g).
Section 1.7874-11T also issued under 26 U.S.C. 7874(g).
Section 1.7874-12T also issued under 26 U.S.C. 7874(g).
(a)
(b)
(c)
(d)
(1) FA is a foreign corporation that is not a controlled foreign corporation;
(2) FA wholly owns DT, a domestic corporation;
(3) DT wholly owns FS1, a controlled foreign corporation; and
(4) No portion of a dividend from FS1 would be treated as from sources within the United States under section 861.
(i)
(ii)
(i)
(ii)
(e)
(f)
The additions and revisions read as follows:
(c) * * *
(3) * * *
(iii) * * *
(B)
(C) [Reserved]. For further guidance, see § 1.367(a)-3T(c)(3)(iii)(C).
(11)
(ii) [Reserved]. For further guidance, see § 1.367(a)-3T(c)(11)(ii).
(a) through (c)(3)(iii)(B) [Reserved]. For further guidance, see § 1.367(a)-3(a) through (c)(3)(iii)(B).
(C)
(4) through (11)(i) [Reserved]. For further guidance, see § 1.367(a)-3(c)(4) through (c)(11)(i).
(ii)
(d) through (j) [Reserved]. For further guidance, see § 1.367(a)-3(d) through (j).
(k)
The additions and revisions read as follows:
(a) [Reserved]. For further guidance, see § 1.367(b)-4T(a).
(b) introductory text [Reserved]. For further guidance, see § 1.367(b)-4T(b) introductory text.
(1) * * *
(i) * * *
(C) [Reserved]. For further guidance, see § 1.367(b)-4T(b)(1)(i)(C).
(d) * * *
(1) [Reserved]. For further guidance, see § 1.367(b)-4T(d)(1).
(h) [Reserved]. For further guidance, see § 1.367(b)-4T(h).
(a)
(b)
(b)(1) through (b)(1)(i)(B) [Reserved]. For further guidance, see § 1.367(b)-4(b)(1) through (b)(1)(i)(B).
(C) The exchange is not a specified exchange to which paragraph (e)(1) of this section applies.
(b)(1)(ii) through (d) introductory text [Reserved]. For further guidance, see § 1.367(b)-4(b)(1)(ii) through (d) introductory text.
(1)
(2) [Reserved]. For further guidance, see § 1.367(b)-4(d)(2).
(e)
(i) Include in income as a deemed dividend the section 1248 amount attributable to the stock that it exchanges; and
(ii) After taking into account the increase in basis provided in § 1.367(b)-2(e)(3)(ii) resulting from the deemed dividend (if any), recognize all realized gain with respect to the stock that would not otherwise be recognized.
(2)
(i) Immediately before the exchange, the foreign acquired corporation is an expatriated foreign subsidiary and the exchanging shareholder is either an expatriated entity described in § 1.367(b)-4(b)(1)(i)(A)(
(ii) The stock received in the exchange is stock of a foreign corporation; and
(iii) The exchange occurs during the applicable period.
(3)
(i) Immediately after the exchange, the foreign acquired corporation (in the case of an acquisition of stock of the foreign acquired corporation) or the transferee foreign corporation (in the case of an acquisition of assets of the foreign acquired corporation) is a controlled foreign corporation;
(ii) The post-exchange ownership percentage with respect to the foreign acquired corporation (in the case of an acquisition of stock of the foreign acquired corporation) or the transferee foreign corporation (in the case of an acquisition of assets of the foreign acquired corporation) is at least 90 percent of the pre-exchange ownership percentage with respect to the foreign acquired corporation; and
(iii) The post-exchange ownership percentage with respect to each lower-tier expatriated foreign subsidiary of the foreign acquired corporation is at least 90 percent of the pre-exchange ownership percentage with respect to the lower-tier expatriated foreign subsidiary.
(4)
(5)
(ii)
(ii)
(A) Because the assets, rather than the stock, of FT1 (the foreign acquired corporation) are acquired, the requirement set forth in paragraph (e)(3)(i) of this section is satisfied if FS (the transferee foreign corporation) is a controlled foreign corporation immediately after the exchange. As stated in the facts, FS is a controlled foreign corporation immediately after the exchange.
(B) The requirement set forth in paragraph (e)(3)(ii) of this section is satisfied if the post-exchange ownership percentage with respect to FS is at least 90% of the pre-exchange ownership percentage with respect to FT1. Because USP, a domestic corporation that is an expatriated entity, directly owns 50 shares of FT stock immediately before the exchange, none of those shares are treated as indirectly owned by FP (a non-CFC foreign related person) for purposes of calculating the pre-exchange ownership percentage with respect to FT1. See paragraph (g)(1) of this section. Thus, for purposes of calculating the pre-exchange ownership percentage with respect to FT1, FP is treated as directly or indirectly owning 0%, or 0 of 50 shares, of the stock of FT1. Accordingly, the pre-exchange ownership percentage with respect to FT1 is 100 (calculated as 100% less 0%, the percentage of FT1 stock that non-CFC foreign related persons are treated as directly or indirectly owning immediately before the exchange). Consequently, for the requirement set forth in paragraph (e)(3)(ii) of this section to be satisfied, the post-exchange ownership percentage with respect to FS must be at least 90. Because USP, a domestic corporation that is an expatriated entity, directly owns 50 shares of FS stock immediately after the exchange, none of those shares are treated as indirectly owned by FP (a non-CFC foreign related person) for purposes of calculating the post-exchange ownership percentage with respect to FS. See paragraph (g)(1) of this section. Thus, for purposes of calculating the post-exchange ownership percentage with respect to FS, FP is treated as directly or indirectly owning 0%, or 0 of 90 shares, of the stock of FS. As a result, the post-exchange ownership percentage with respect to FS is 100 (calculated as 100% less 0%, the percentage of FS stock that non-CFC foreign related persons are treated as directly or indirectly owning immediately after the exchange). Therefore, because the post-exchange ownership percentage with respect to FS (100) is at least 90, the requirement set forth in paragraph (e)(3)(ii) of this section is satisfied.
(C) Because there is not a lower-tier expatriated foreign subsidiary of FT1, the requirement set forth in paragraph (e)(3)(iii) of this section does not apply.
(f)
(2)
(i) Immediately after the transfer, the transferee foreign corporation is a controlled foreign corporation; and
(ii) The post-exchange ownership percentage with respect to the transferee foreign corporation is at least 90 percent of the pre-exchange ownership percentage with respect to the expatriated foreign subsidiary.
(3)
(ii)
(ii)
(g)
(1)
(2) A
(3)
(4)
(5)
(6)
(7)
(ii)
(B)
(h)
(i)
The additions and revision read as follows:
(a) * * *
(4) [Reserved]. For further guidance, see § 1.956-2T(a)(4).
(c) * * *
(5) [Reserved]. For further guidance, see § 1.956-2T(c)(5).
(d) * * *
(2) [Reserved]. For further guidance, see § 1.956-2T(d)(2).
(f) [Reserved]
(g) [Reserved]
(h) [Reserved]
(i) [Reserved]. For further guidance, see § 1.956-2T(i).
The additions and revision read as follows:
(a)(1) through (3) [Reserved]. For further guidance, see § 1.956-2(a)(1) through (3).
(4)
(A) The obligation or stock is held by a controlled foreign corporation that is an expatriated foreign subsidiary, regardless of whether, when the obligation or stock was acquired, the acquirer was a controlled foreign corporation or an expatriated foreign subsidiary;
(B) The foreign person or foreign corporation is a non-CFC foreign related person, regardless of whether, when the obligation or stock was acquired, the foreign person or foreign corporation was a non-CFC foreign related person; and
(C) The obligation or stock was acquired—
(
(
(ii)
(A) Any obligation of a non-CFC foreign related person arising in connection with the sale or processing of property if the amount of the obligation at no time during the taxable year exceeds the amount that would be ordinary and necessary to carry on the trade or business of both the other party to the sale or processing transaction and the non-CFC foreign related person had the sale or processing transaction been made between unrelated persons; and
(B) Any obligation of a non-CFC foreign related person to the extent the principal amount of the obligation does not exceed the fair market value of readily marketable securities sold or purchased pursuant to a sale and repurchase agreement or otherwise posted or received as collateral for the obligation in the ordinary course of its business by a United States or foreign person which is a dealer in securities or commodities.
(iii)
(iv)
(A)
(B)
(A)
(B)
(A)
(B)
(A)
(B)
(b)(1) through (b)(1)(x) [Reserved]. For further guidance, see § 1.956-2(b)(1) through (b)(1)(x).
(b)(2) through (c)(4) [Reserved]. For further guidance, see § 1.956-2(b)(2) through (c)(4).
(5)
(ii)
(A) Applies regardless of whether, when the pledge or guarantee was entered into or treated as entered into, the controlled foreign corporation was a controlled foreign corporation or an expatriated foreign subsidiary, or a foreign person whose obligation is subject to the pledge or guarantee, or deemed pledge or guarantee, was a non-CFC foreign related person; and
(B) Applies to pledges or guarantees entered into, or treated pursuant to § 1.956-2(c)(2) as entered into—
(
(
(d)(1) [Reserved]. For further guidance, see § 1.956-2(d)(1).
(2)
(i) Any indebtedness arising out of the involuntary conversion of property
(ii) Any obligation of a United States person (as defined in section 957(c)) arising in connection with the provision of services by a controlled foreign corporation to the United States person if the amount of the obligation outstanding at any time during the taxable year of the controlled foreign corporation does not exceed an amount which would be ordinary and necessary to carry on the trade or business of the controlled foreign corporation and the United States person if they were unrelated. The amount of the obligations shall be considered to be ordinary and necessary to the extent of such receivables that are paid within 60 days;
(iii) Any obligation of a non-CFC foreign related person arising in connection with the provision of services by an expatriated foreign subsidiary to the non-CFC foreign related person if the amount of the obligation outstanding at any time during the taxable year of the expatriated foreign subsidiary does not exceed an amount which would be ordinary and necessary to carry on the trade or business of the expatriated foreign subsidiary and the non-CFC foreign related person if they were unrelated. The amount of the obligations shall be considered to be ordinary and necessary to the extent of such receivables that are paid within 60 days;
(iv) Unless a controlled foreign corporation applies the exception provided in paragraph (d)(2)(v) of this section with respect to the obligation, any obligation of a United States person (as defined in section 957(c)) that is collected within 30 days from the time it is incurred (a
(v) Unless a controlled foreign corporation applies the exception provided in paragraph (d)(2)(iv) of this section with respect to the obligation, any obligation of a United States person (as defined in section 957(c)) that is collected within 60 days from the time it is incurred (a
(h) [Reserved]
(i)
(2) Paragraphs (d)(2)(i) and (ii) of this section are effective June 14, 1988, with respect to investments made on or after June 14, 1988.
(3) Paragraph (d)(2)(iii) of this section applies to obligations acquired on or after April 4, 2016, but only if the inversion transaction was completed on or after September 22, 2014. For inversion transactions completed on or after September 22, 2014, however, taxpayers may elect to apply paragraph (d)(2)(iii) of this section to an obligation acquired on or after September 22, 2014, and before
(4) Paragraph (d)(2)(iv) of this section applies to obligations held on or after September 16, 1988.
(5) Paragraph (d)(2)(v) of this section applies to the first three taxable years of a foreign corporation ending after October 3, 2008, other than taxable years of a foreign corporation beginning on or after January 1, 2011, as well as the fourth taxable year of a foreign corporation, if any, when the foreign corporation's third taxable year (including any short taxable year) ended after October 3, 2008, and on or before December 31, 2009.
(j)
(a)
(b)
(2)
(i) That is a fast-pay arrangement that is recharacterized under § 1.7701(l)-3(c)(2);
(ii) In which the specified stock was transferred by a shareholder of the expatriated foreign subsidiary, and the shareholder either—
(A) Pursuant to § 1.367(b)-4T(e)(1), both—
(
(
(B) Included in gross income all of the gain recognized on the transfer of the specified stock (including gain included in gross income as a dividend pursuant to section 964(e), section 1248(a), or section 356(a)(2)); or
(iii) In which—
(A) Immediately after the specified transaction and any related transaction, the expatriated foreign subsidiary is a controlled foreign corporation;
(B) The post-transaction ownership percentage with respect to the expatriated foreign subsidiary is at least 90 percent of the pre-transaction ownership percentage with respect to the expatriated foreign subsidiary; and
(C) The post-transaction ownership percentage with respect to any lower-tier expatriated foreign subsidiary is at least 90 percent of the pre-transaction ownership percentage with respect to the lower-tier expatriated foreign subsidiary. See
(c)
(2)
(i) The transferred property is treated as having been transferred by the specified related person to the persons that were section 958(a) U.S. shareholders of the expatriated foreign subsidiary immediately before the specified transaction, in proportion to the stock of the expatriated foreign subsidiary owned by each section 958(a) U.S. shareholder, in exchange for deemed instruments in the section 958(a) U.S. shareholders; and
(ii) The transferred property treated as transferred to the section 958(a) U.S. shareholders pursuant to paragraph (c)(2)(i) of this section is treated as having been contributed by the section 958(a) U.S. shareholders (through intermediate entities, if any, in exchange for equity in the intermediate entities) to the expatriated foreign subsidiary in exchange for deemed issued stock in the expatriated foreign subsidiary. See
(3)
(i) The transferred property is treated as having been transferred by the specified related person to the persons that were section 958(a) U.S. shareholders of the expatriated foreign subsidiary immediately before the specified transaction, in proportion to the specified stock owned by each section 958(a) U.S. shareholder, in exchange for deemed instruments in the section 958(a) U.S. shareholders; and
(ii) To the extent the section 958(a) U.S. shareholders are not the transferring shareholders, the transferred property treated as transferred to the section 958(a) U.S. shareholders pursuant to paragraph (c)(3)(i) of this section is treated as having been contributed by the section 958(a) U.S. shareholders (through intermediate entities, if any, in exchange for equity in the intermediate entities) to the transferring shareholder in exchange for equity in the transferring shareholder. See
(4)
(ii)
(d)
(2)
(i) Each section 958(a) U.S. shareholder that is treated as owning deemed issued stock in the expatriated foreign subsidiary under paragraph (c)(2) or (3) of this section is treated as transferring the deemed issued stock (after the deemed issued stock is deemed to be transferred to the section 958(a) U.S. shareholder through intermediate entities, if any, in redemption of equity deemed issued by the intermediate entities pursuant to paragraph (c)(2) or (3) of this section) to the specified related person that is treated as holding the deemed instruments issued by the section 958(a) U.S. shareholder under paragraph (c)(2) or (3) of this section, in redemption of the deemed instruments; and
(ii) The deemed issued stock that is treated as transferred pursuant to paragraph (d)(2)(i) of this section is treated as recapitalized into the disregarded specified stock actually held by the specified related person, which immediately thereafter is treated as specified stock owned by the specified related person for all purposes of the Internal Revenue Code. See
(3)
(i) Each section 958(a) U.S. shareholder that is treated as owning all or a portion of the deemed issued stock in the expatriated foreign subsidiary is treated as transferring the deemed issued stock that is allocable to the transferred disregarded specified stock that is out-of-group transferred disregarded specified stock (after the deemed issued stock is deemed to be transferred to the section 958(a) U.S. shareholder through intermediate entities, if any, in redemption of equity deemed issued by the intermediate entities pursuant to paragraph (c)(2) or (3) of this section) to the specified related person that is treated as holding the deemed instruments allocable to the out-of-group transferred disregarded specified stock, in redemption of the deemed instruments that are allocable to the out-of-group transferred disregarded specified stock; and
(ii) The deemed issued stock that is treated as transferred pursuant to paragraph (d)(3)(i) of this section is treated as recapitalized into the disregarded specified stock actually held by the specified related person, which immediately thereafter is treated as specified stock owned by the specified related person for all purposes of the Internal Revenue Code. See
(4)
(5)
(ii)
(e)
(f)
(1)
(2)
(3)
(4)
(5)
(6) A
(7)
(8)
(9)
(10) A
(11)
(12)
(g)
(i)
(ii)
(B) FA's acquisition of the FT specified stock is recharacterized under paragraphs (c)(1) and (2) of this section as follows, with the result that FT continues to be a CFC:
(
(
(C) Under paragraph (c)(4)(i) of this section, any distribution with respect to the FT specified stock issued to FA will be treated as a distribution to DT, which, in turn, will be treated as making a matching distribution with respect to the deemed instruments that DT is treated as having issued to FA. Under paragraph (c)(4)(ii) of this section, FT is treated as the paying agent of DT with respect to the deemed instruments issued by DT to FA.
(i)
(ii)
(B) FA's acquisition of the FT specified stock is recharacterized under paragraphs (c)(1) and (2) of this section as follows, with the result that FT continues to be a CFC:
(
(
(
(C) Under paragraph (c)(4)(i) of this section, any distribution with respect to the FT specified stock issued to FA will be treated as a distribution to DT, which, in turn, will be treated as making a matching distribution with respect to the deemed instruments that DT is treated as having issued to FA. Under paragraph (c)(4)(ii) of this section, FT is treated as the paying agent of DT with respect to the deemed instruments issued by DT to FA.
(i)
(ii)
(B) However, the specified transaction is not recharacterized under paragraphs (c)(1) and (2) of this section because the exception in paragraph (b)(2)(iii) of this section applies. The exception applies because FT remains a controlled foreign corporation immediately after the specified transaction and any related transaction, and the post-transaction ownership percentage with respect to FT is 90% (90%/100%), or at least 90%, of the pre-transaction ownership percentage with respect to FT. The rule in paragraph (b)(2)(iii)(C) of this section does not apply because there is no lower-tier expatriated foreign subsidiary. Although FA (a non-CFC foreign related person) indirectly owns $4x of FT stock both immediately before and after the specified transaction and any related transaction, all of that stock is directly owned by DT (a domestic corporation that is a section 958(a) U.S. shareholder of FT), and as a result, under paragraph (f)(4) of this section, none of that stock is treated as directly or indirectly owned by FP for purposes of calculating the pre-transaction ownership percentage and the post-transaction ownership percentage with respect to FT. Accordingly, under paragraph (f)(8) of this section, the pre-transaction ownership percentage with respect to FT (100% less the percentage of stock (by value) in FT that, immediately before the specified transaction with respect to FT and any related transaction, is owned by non-CFC foreign related persons) is 100 (100% − 0%). Under paragraph (f)(9) of this section, the post-transaction ownership percentage with respect to FT (100% less the percentage of
(i)
(ii)
(B) However, the specified transaction is not recharacterized under paragraphs (c)(1) and (c)(3) of this section because the exception in paragraph (b)(2)(ii) of this section applies. The exception applies because DT recognizes and includes in income all of the gain (including any gain treated as a deemed dividend pursuant to section 1248(a)) with respect to the FT specified stock transferred to FA.
(i)
(ii)
(B) DT's transfer of the FT specified stock is recharacterized under paragraphs (c)(1) and (c)(3) of this section as follows, with the result that FT continues to be a CFC:
(
(
(C) Under paragraph (c)(4)(i) of this section, any distribution with respect to the FT specified stock transferred to FPRS will be treated as a distribution to DT, which, in turn, will be treated as making a matching distribution with respect to the deemed instruments that DT is treated as having issued to FPRS. Under paragraph (c)(4)(ii) of this section, FT is treated as the paying agent of DT with respect to the deemed instruments issued by DT to FPRS.
(i)
(ii)
(B) If FS had acquired only stock of FT and FT2, and had not acquired stock of FT3 in a related transaction, the specified transactions resulting from the acquisitions with respect to FT and FT2 would not have been recharacterized under paragraphs (c)(1) and (2) of this section, because the exception from recharacterization in paragraph (b)(2)(iii) of this section would have applied. FT and FT2 remain controlled foreign corporations (within the meaning of section 957) immediately after each specified transaction and any related transaction. Under paragraph (f)(9) of this section, the post-transaction ownership percentage with respect to each of FT, FT2, and FT3 (a lower-tier expatriated foreign subsidiary of FT and FT2) would have been 91% ((100% − 9%)/(100% − 0%)), or at least 90%, of the pre-transaction ownership percentage determined under paragraph (f)(8) of this section with respect to each of FT, FT2, and FT3 (100%).
(C) However, for the specified transactions with respect to FT, FT2, and FT3, the post-transaction ownership percentage determined under paragraph (f)(9) of this section with respect to FT3 (the lower-tier expatriated foreign subsidiary of FT and FT2), 100% less the percentage of stock (by value) in FT3 that, immediately after each of the specified transactions with respect to each of FT and FT2 and any related transaction, is owned by the non-CFC foreign related persons, is 82.81 (100%−(9%x50%x91%)−(9%x50%x91%)−9%). Accordingly, the post-transaction ownership percentage with respect to FT3 is 82.81% (82.81/(100%−0%)), which is less than 90%, of the pre-transaction ownership percentage determined under paragraph (f)(8) of this section with respect to FT3. Thus, the exception from recharacterization in paragraph (b)(2)(iii) of this section does not apply with respect to the specified transactions with respect to FT, FT2, or FT3.
(D) The specified transactions with respect to FT and FT2 are recharacterized under paragraphs (c)(1) and (2) of this section as follows:
(
(
(
(E) Under paragraph (c)(4)(i) of this section, any distribution with respect to the FT and FT2 specified stock issued to FS will be treated as a distribution to DT, which, in turn, will be treated as making a matching distribution with respect to the deemed instruments that DT is treated as having issued to FS. Under paragraph (c)(4)(ii) of this section, FT and FT2 are treated as the paying agents of DT with respect to the deemed instruments issued by DT to FS.
(F) The specified transaction with respect to FT3 is recharacterized under paragraphs (c)(1) and (2) of this section as follows:
(
(
(
(G) Under paragraph (c)(4)(i) of this section, any distribution with respect to the FT3 specified stock issued to FS will be treated as a distribution to DPRS, which, in turn, will be treated as making a matching distribution with respect to the deemed instruments that DPRS is treated as having issued to FS. Under paragraph (c)(4)(ii) of this section, FT3 is treated as the paying agent of DPRS with respect to the deemed instrument issued by DPRS to FS.
(i)
(ii)
(i)
(ii)
(i)
(ii)
(i)
(ii)
(i)
(ii)
(i)
(ii)
(i)
(ii)
(B) After the transfer, FT remains a foreign related person. Therefore, paragraph (d)(2) of this section does not apply. The disregarded specified stock of FT is not, as a result of the transfer, held by a person that is not a foreign related person, a specified related person, or an expatriated entity. Therefore, paragraph (d)(3) of this section does not apply. There has been no direct transfer of specified stock. Therefore, paragraph (d)(4) of this section also does not apply.
(C) Under paragraph (d)(1) of this section, the $6x of deemed issued stock treated as owned by DT as a result of the specified transaction in which FA acquired FT stock continues to be treated as owned by DT, and the $6x of deemed instruments treated as issued by DT to FA continue to be treated as owned by FA.
(h)
(i)
The additions and revision read as follows:
(c) * * *
(2) * * *
(iii) [Reserved]. For further guidance, see § 1.7874-1T(c)(2)(iii).
(f) [Reserved]. For further guidance, see § 1.7874-1T(f).
(h)
(2) [Reserved]. For further guidance, see § 1.7874-1T(h)(2).
(a) through (c)(2)(ii) [Reserved]. For further guidance, see § 1.7874-1(a) through (c)(2)(ii).
(iii)
(c)(3) through (e) [Reserved]. For further guidance, see § 1.7874-1(c)(3) through (e).
(f)
(g) through (h)(1) [Reserved]. For further guidance, see § 1.7874-1(g) through (h)(1).
(2)
(i)
The revisions and additions read as follows:
(a) [Reserved]. For further guidance, see § 1.7874-2T(a).
(b)
(b)(7) through (13) [Reserved]. For further guidance, see § 1.7874-2T(b)(7) through (13).
(c) * * *
(2) [Reserved]. For further guidance, see § 1.7874-2T(c)(2).
(4) [Reserved]. For further guidance, see § 1.7874-2T(c)(4).
(f) * * *
(1) introductory text [Reserved]. For further guidance, see § 1.7874-2T(f)(1) introductory text.
(iv) [Reserved]. For further guidance, see § 1.7874-2T(f)(1)(iv).
(k) * * *
(2) * * *
(l)
(2) [Reserved]. For further guidance, see § 1.7874-2T(l)(2).
(a)
(b) through (b)(6) [Reserved]. For further guidance, see § 1.7874-2(b) through (b)(6).
(7) A
(8) An
(9) An
(10) A
(11) A
(12)
(13)
(c) through (c)(1) [Reserved]. For further guidance, see § 1.7874-2(c) through (c)(1).
(2)
(3) [Reserved]. For further guidance, see § 1.7874-2(c)(3).
(4)
(ii)
(iii)
(d) through (f) introductory text [Reserved]. For further guidance, see § 1.7874-2(d) through (f) introductory text.
(1)
(f)(1)(i) through (f)(1)(iii) [Reserved]. For further guidance, see § 1.7874-2(f)(1)(i) through (iii).
(iv) Stock of a subsequent acquiring corporation received by a former initial acquiring corporation shareholder pursuant to a subsequent acquisition in exchange for, or with respect to, stock of an initial acquiring corporation that is held by reason of holding stock of, or a partnership interest in, a domestic entity.
(g) through (k)(2),
(ii)
(B) The DC1 acquisition is also an initial acquisition because it is a domestic entity acquisition that, pursuant to a plan that includes the F1 acquisition, occurs before the F1 acquisition (which, as described in paragraph (ii)(C) of this
(C) The F1 acquisition is a subsequent acquisition because it occurs, pursuant to a plan that includes the DC1 acquisition, after the DC1 acquisition and, pursuant to the F1 acquisition, F2 acquires 100 percent of the stock of F1 and therefore is treated under paragraph (c)(4)(ii) of this section (which applies the principles of section 7874(a)(2)(B)(i) with certain modifications) as indirectly acquiring substantially all of the properties held directly or indirectly by F1. Thus, F2 is the subsequent acquiring corporation.
(D) Under paragraph (c)(4)(i) of this section, the F1 acquisition is treated as a domestic entity acquisition, and F2 is treated as a foreign acquiring corporation. In addition, under paragraph (f)(1)(iv) of this section, the 70 shares of F2 stock received by Individual A (a former initial acquiring corporation shareholder) pursuant to the F1 acquisition in exchange for Individual A's F1 stock are stock of a foreign corporation that is held by reason of holding stock in DC1. As a result, those 70 shares are included in both the numerator and the denominator of the ownership fraction when applying section 7874 to the F1 acquisition.
(l) through (l)(1) [Reserved]. For further guidance, see § 1.7874-2(l) through (l)(1).
(2)
(m)
The revisions and additions read as follows:
(a) * * * Paragraph (b) of this section describes the general rule for determining whether the expanded affiliated group has substantial business activities in the relevant foreign country when compared to its total business activities.* * *
(b)
(4) [Reserved]. For further guidance, see § 1.7874-3T(b)(4).
(d) * * *
(10) [Reserved]. For further guidance, see § 1.7874-3T(d)(10).
(f)
(2) [Reserved]. For further guidance, see § 1.7874-3T(f)(2).
(a) through (b)(3) [Reserved]. For further guidance, see § 1.7874-3(a) through 1.7874-3(b)(3).
(4)
(c) through (d)(9) [Reserved]. For further guidance, see § 1.7874-3(c) through (d)(9).
(10) The term
(d)(11) through (f)(1) [Reserved]. For further guidance, see § 1.7874-3(d)(11) through (f)(1).
(2)
(g)
The revisions and additions read as follows:
(d) * * *
(1) * * *
(i) The ownership percentage described in section 7874(a)(2)(B)(ii), determined without regard to the application of paragraph (b) of this section and §§ 1.7874-7T(b) and 1.7874-10T(b), is less than five (by vote and value); and
(i) * * *
(6)
(7) * * *
(iv) Any other property acquired with a principal purpose of avoiding the purposes of section 7874, regardless of whether the transaction involves an indirect transfer of property described in paragraph (i)(7)(i), (ii), or (iii) of this section. See
(j) * * *
(9) FA, FMS, FS, and FT are tax residents in the same foreign country;
(10) For purposes of determining the ownership fraction, no shares of FA stock are excluded from the denominator pursuant to § 1.7874-7T(b); and
(11) For purposes of determining the ownership fraction, no shares of FA stock are received by former shareholders of DT pursuant to § 1.7874-10T(b).
* * *
(ii) * * * See also section 7874(c)(4). * * *
* * *
(ii) * * * Furthermore, even in the absence of paragraph (i)(7)(iv) of this section, the transfer of marketable securities to FT would be disregarded pursuant to section 7874(c)(4). * * *
(ii)
* * *
(ii) * * * However, without regard to the application of paragraph (b) of this section and §§ 1.7874-7T(b) and 1.7874-10T(b), the ownership percentage described in section
(k) * * *
(1) Except to the extent provided in this paragraph (k)(1) and paragraph (k)(2) of this section, this section applies to domestic entity acquisitions completed on or after September 17, 2009. Paragraphs (i)(6) and (i)(7)(iv) of this section apply to domestic entity acquisitions completed on or after November 19, 2015. Paragraph (d)(1)(i) of this section applies to domestic entity acquisitions completed on or after April 4, 2016. For domestic entity acquisitions completed on or after September 22, 2014, and before April 4, 2016, however, taxpayers may elect to apply paragraph (d)(1)(i) of this section. For domestic entity acquisitions completed before November 19, 2015, see paragraphs (i)(6) and (i)(7)(iv) of this section as contained in 26 CFR part 1 revised as of April 1, 2016.
(a)
(b)
(c)
(1)
(i) Before the domestic entity acquisition, the transferring corporation is a member of a U.S.-parented group.
(ii) After the domestic entity acquisition, each of the transferring corporation (or its successor), any person that holds transferred stock, and the foreign acquiring corporation are members of a U.S.-parented group the common parent of which—
(A) Before the domestic entity acquisition, was a member of the U.S.-parented group described in paragraph (c)(1)(i) of this section; or
(B) Is a corporation that was formed in a transaction related to the domestic entity acquisition, provided that, immediately after the corporation was formed (and without regard to any related transactions), the corporation was a member of the U.S.-parented group described in paragraph (c)(1)(i) of this section.
(2)
(i) Before the domestic entity acquisition, the transferring corporation and the domestic entity are members of the same foreign-parented group.
(ii) After the domestic entity acquisition, the transferring corporation—
(A) Is a member of the EAG; or
(B) Would be a member of the EAG absent one or more transfers (other than by issuance), in a transaction (or series of transactions) after and related to the domestic entity acquisition, of stock of the foreign acquiring corporation by one or more members of the foreign-parented group described in paragraph (c)(2)(i) of this section.
(d)
(2)
(e)
(f)
(1) A
(2)
(ii)
(3) A
(4) A
(g)
(ii)
(ii)
(ii)
(ii)
(iii)
(h)
(i)
(a)
(b)
(1) The value of the stock of the foreign acquiring corporation, other than stock that is described in section 7874(a)(2)(B)(ii) and stock that is excluded from the denominator of the ownership fraction under either § 1.7874-1(b) or § 1.7874-4T(b); and
(2) The foreign group nonqualified property fraction.
(c)
(1) The ownership percentage described in section 7874(a)(2)(B)(ii), determined without regard to the application of paragraph (b) of this section and §§ 1.7874-4T(b) and 1.7874-10T(b), is less than five (by vote and value); and
(2) On the completion date, former domestic entity shareholders or former domestic entity partners, as applicable, in the aggregate, own (applying the attribution rules of section 318(a) with the modifications described in section 304(c)(3)(B)) less than five percent (by vote and value) of the stock of (or a partnership interest in) each member of the expanded affiliated group.
(d)
(e)
(f)
(1)
(A) Property that gives rise to income described in section 954(h), determined—
(
(
(B) Property that gives rise to income described in section 954(i), determined by substituting the term “foreign corporation” for the term “controlled foreign corporation.”
(C) Property that gives rise to income described in section 1297(b)(2)(A) or (B).
(D) Property held by a domestic corporation that is subject to tax as an insurance company under subchapter L of chapter 1 of subtitle A of the Internal Revenue Code, provided that the property is required to support, or is substantially related to, the active conduct of an insurance business.
(ii)
(2)
(i) Property that is directly or indirectly acquired in the domestic entity acquisition;
(ii) Stock or a partnership interest in a member of the modified expanded affiliated group; and
(iii) An obligation of a member of the modified expanded affiliated group.
(3)
(i) The numerator of the fraction is the gross value of all foreign group nonqualified property, other than property received by the expanded affiliated group that gives rise to stock that is excluded from the ownership fraction under § 1.7874-4T(b).
(ii) The denominator of the fraction is the gross value of all foreign group property, other than property received by the expanded affiliated group that gives rise to stock that is excluded from the ownership fraction under § 1.7874-4T(b).
(4)
(i) When the foreign acquiring corporation is not the common parent corporation of the expanded affiliated group, the expanded affiliated group determined as if the foreign acquiring corporation was the common parent corporation.
(ii) When the foreign acquiring corporation is the common parent corporation of the expanded affiliated group, the expanded affiliated group.
(g)
(ii)
(ii)
(ii)
(h)
(i)
(a)
(b)
(c)
(1) The total number of prior acquisition shares, reduced by the sum of the number of allocable redeemed shares for all redemption testing periods; and
(2) The fair market value of a single share of stock of the relevant share class on the completion date of the relevant domestic entity acquisition.
(d)
(2)
(i) The numerator is the total number of prior acquisition shares, reduced by the sum of the number of allocable redeemed shares for all prior redemption testing periods.
(ii) The denominator is the sum of—
(A) The number of outstanding shares of the foreign acquiring corporation stock as of the end of the last day of the redemption testing period; and
(B) The number of redeemed shares during the redemption testing period.
(e)
(2)
(f)
(g)
(1) A
(2) A
(3)
(4) A
(ii)
(A) The ownership percentage described in section 7874(a)(2)(B)(ii) with respect to the domestic entity acquisition was less than five (by vote and value); and
(B) The fair market value of the stock of the foreign acquiring corporation that was described in section 7874(a)(2)(B)(ii) as a result of the domestic entity acquisition (without regard to whether the 60 percent test of section 7874(a)(2)(B)(ii) was satisfied) did not exceed $50 million, as determined on the completion date with respect to the domestic entity acquisition.
(5) A
(6) A
(h)
(ii)
(ii)
(ii)
(i)
(j)
(a)
(b)
(c)
(1) The foreign acquiring corporation completes a covered foreign acquisition pursuant to a plan (or series of related transactions) that includes the domestic entity acquisition.
(2) After the covered foreign acquisition and all related transactions are complete, the foreign acquiring corporation is not subject to tax as a resident in the foreign country in which the acquired foreign corporation was subject to tax as a resident before the covered foreign acquisition and all related transactions.
(3) The ownership percentage, determined without regard to the application of paragraph (b) of this section, is at least 60.
(d)
(1) A
(2) An
(3)
(4)
(e)
(1)
(2)
(i) The principles of § 1.7874-2(c)(1) (providing rules for determining whether there is an indirect acquisition of properties of a domestic entity), including § 1.7874-2(b)(5) (providing rules for determining the proportionate amount of properties indirectly acquired), apply by substituting the term “foreign” for “domestic” wherever it appears.
(ii) The principles of § 1.7874-2(c)(2) (regarding acquisitions of stock of a foreign corporation that owns a domestic entity) apply by substituting the term “domestic” for “foreign” wherever it appears.
(3)
(i) Stock of a foreign acquiring corporation described in section 7874(a)(2)(B)(ii) is not taken into account.
(ii) The principles of this section, section 7874(c)(2)(A), and §§ 1.7874-1, 1.7874-6T, 1.7874-8T, and 1.7874-10T do not apply.
(iii) The principles of § 1.7874-7T apply by, in addition to the exclusions listed in § 1.7874-7T(f)(2)(i) through (iii), also excluding from the definition of foreign group property any property held directly or indirectly by the acquired foreign corporation immediately before the foreign acquisition and directly or indirectly acquired in the foreign acquisition.
(4)
(5)
(f)
(ii)
(A) The FT acquisition is a foreign acquisition because, pursuant to the FT acquisition, FA (a foreign corporation) acquires 100 percent of the stock of FT and is thus treated as indirectly acquiring 100 percent of the properties held by FT (an acquired foreign corporation). See § 1.7874-2(c)(1) and paragraph (e)(2) of this section. Moreover, Individual B is treated as receiving 35 shares of FA stock by reason of holding stock in FT. See § 1.7874-2(f)(1)(i) and paragraph (e)(4) of this section. As a result, not taking into account the 65 shares of FA stock held by Individual A (a former domestic entity shareholder), 100 percent (35/35) of the stock of FA is held by reason of holding stock in FT and, thus, the foreign ownership percentage is 100. See paragraph (e)(3) of this section. Accordingly, the FT acquisition is a covered foreign acquisition. Therefore, because the FT acquisition occurs pursuant to a plan that includes the DT acquisition, the requirement set forth in paragraph (c)(1) of this section is satisfied.
(B) The requirement set forth in paragraph (c)(2) of this section is satisfied because, after the FT acquisition and all related transactions, the foreign country in which FA is subject to tax as a resident (Country Y) is different than the foreign country in which FT was subject to tax as a resident (Country X) before the FT acquisition and all related transactions.
(C) The requirement set forth in paragraph (c)(3) of this section is satisfied because, not taking into account paragraph (b) of this section, the ownership fraction is 65/100 and the ownership percentage is 65.
(D) Because the DT acquisition is a third-country transaction, the 35 shares of FA stock held by reason of holding stock in FT are excluded from the denominator of the ownership fraction. See paragraph (b) of this section. As a result, the ownership fraction is 65/65 and the ownership percentage is 100. The result would be the same if instead FA had directly acquired all of the properties held by FT in exchange for FA stock, for example, in a transaction that would qualify for U.S. federal income tax purposes as an asset reorganization under section 368.
(iii)
(iv)
(g)
(h)
(a)
(b)
(c)
(d)
(1) The ownership percentage described in section 7874(a)(2)(B)(ii), determined without regard to the application of paragraph (b) of this section and §§ 1.7874-4T(b) and 1.7874-7T(b), is less than five (by vote and value); and
(2) On the completion date, former domestic entity shareholders or former domestic entity partners, as applicable, in the aggregate, own (applying the attribution rules of section 318(a) with the modifications described in section 304(c)(3)(B)) less than five percent (by vote and value) of the stock of (or a partnership interest in) each member of the expanded affiliated group (within the meaning of § 1.7874-4T(i)(3)).
(e)
(1) A distribution made before the predecessor acquisition with respect to the predecessor; and
(2) A distribution made in connection with the predecessor acquisition to the extent the property distributed is directly or indirectly provided by the predecessor. See paragraph (h)(1)(iv) of this section.
(f)
(i) The relevant entity completes a predecessor acquisition; and
(ii) After the predecessor acquisition and all related transactions are complete, the tentative predecessor ownership percentage is at least 10.
(2)
(ii)
(iii)
(3)
(i) For purposes of determining the stock or partnership interests in a relevant entity held by reason of holding stock or partnership interests in the tentative predecessor, the principles of section 7874(a)(2)(B)(ii) and §§ 1.7874-2(f)(1)(i) through (iii) and 1.7874-5T apply.
(ii) For purposes of determining the stock or partnership interests in a relevant entity included in the numerator of the fraction used to compute the tentative predecessor ownership percentage, the rules of paragraph (f)(3)(i) of this section apply, and all the rules applicable to calculating the numerator of an ownership fraction with respect to a domestic entity acquisition apply, except that—
(A) The principles of section 7874(c)(2)(A) and §§ 1.7874-1 and 1.7874-6T do not apply; and
(B) The principles of paragraph (b) of this section do not apply.
(iii) For purposes of determining stock or partnership interests in a relevant entity included in the denominator of the fraction used to compute the tentative predecessor ownership percentage, the principles of section 7874(a)(2)(B)(ii) and all rules applicable to calculating the denominator of an ownership fraction with respect to a domestic entity acquisition apply, except that—
(A) The principles of section 7874(c)(2)(A) and §§ 1.7874-1 and 1.7874-6T do not apply; and
(B) The principles of §§ 1.7874-4T and 1.7874-7T through 1.7874-9T do not apply.
(g)
(h)
(1) A
(i) Any distribution made by a corporation with respect to its stock other than—
(A) A distribution to which section 305 applies;
(B) A distribution to which section 304(a)(1) applies; and
(C) Except as provided in paragraphs (h)(1)(iii) and (iv) of this section, a distribution pursuant to section 361(c)(1).
(ii) Any distribution by a partnership.
(iii) In the case of a domestic entity, a transfer of money or other property to the former domestic entity shareholders or former domestic entity partners that is made in connection with the domestic entity acquisition to the extent the money or other property is directly or indirectly provided by the domestic entity.
(iv) In the case of a predecessor, a transfer of money or other property to the former owners of the predecessor that is made in connection with the predecessor acquisition to the extent the money or other property is directly or indirectly provided by the predecessor.
(2)
(ii)
(iii)
(3)
(4)
(5)
(i) If the look-back period is 36 months, the three consecutive 12-month periods that comprise the look-back period.
(ii) If the look-back period is less than 36 months, but at least 24 months—
(A) The 12-month period that ends on the completion date;
(B) The 12-month period that immediately precedes the period described in paragraph (h)(5)(ii)(A) of this section; and
(C) The period, if any, that immediately precedes the period described in paragraph (h)(5)(ii)(B) of this section.
(iii) If the look-back period is less than 24 months, but at least 12 months—
(A) The 12-month period that ends on the completion date; and
(B) The period, if any, that immediately precedes the period described in paragraph (h)(5)(iii)(A) of this section.
(iv) If the look-back period is less than 12 months, the entire period, starting with the formation date, that ends on the completion date.
(6)
(7)
(i) If the look-back year has at least a 12-month distribution history period, 110 percent of the sum of all distributions made during the distribution history period multiplied by a fraction. The numerator of the fraction is the number of days in the look-back year and the denominator is the number of days in the distribution history period with respect to the look-back year.
(ii) If the look-back year has no distribution history period, zero.
(i)
(j)
(a)
(b)
(2)
(3)
(c)
(d)
(e)
—(i)
(ii)
(f)
(g)
(a)
(1) An
(2) The
(3) The
(4) A
(5) A
(6) A
(7) An
(8) An
(i) The domestic entity; and
(ii) A United States person that, on any date on or after the completion date, is or was related (within the meaning of section 267(b) or 707(b)(1)) to the domestic entity.
(9)
(ii)
(A) On the completion date, the foreign corporation was both a CFC and a member of the EAG; and
(B) On or before the completion date, the domestic entity was not a United States shareholder with respect to the foreign corporation.
(10) A
(11) A
(12) A
(13) A
(14) An
(15) An
(16) A
(17) The
(18) A
(i) A non-CFC foreign related person;
(ii) A domestic partnership in which a non-CFC foreign related person is a partner; and
(iii) A domestic trust of which a non-CFC foreign related person is a beneficiary.
(19) A
(20) A
(b)
(c)
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking.
This document contains proposed regulations under section 385 of the Internal Revenue Code (Code) that would authorize the Commissioner to treat certain related-party interests in a corporation as indebtedness in part and stock in part for federal tax purposes, and establish threshold documentation requirements that must be satisfied in order for certain related-party interests in a corporation to be treated as indebtedness for federal tax purposes. The proposed regulations also would treat as stock certain related-party interests that otherwise would be treated as indebtedness for federal tax purposes. The proposed regulations generally affect corporations that issue purported indebtedness to related corporations or partnerships.
Written or electronic comments and requests for a public hearing must be received by July 7, 2016.
Send submissions to: CC:PA:LPD:PR (REG-108060-15), Room 5203, Internal Revenue Service, P.O. Box 7604, Ben Franklin Station, Washington, DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG-108060-15), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC 20224 or sent electronically via the Federal eRulemaking Portal at
Concerning the proposed regulations under §§ 1.385-1 and 1.385-2, Eric D. Brauer, (202) 317-5348; concerning the proposed regulations under §§ 1.385-3 and 1.385-4, Raymond J. Stahl, (202) 317-6938; concerning submissions of comments or requests for a public hearing, Regina Johnson, (202) 317-5177 (not toll-free numbers).
The collection of information contained in this notice of proposed rulemaking has been submitted to the Office of Management and Budget in accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)). Comments on the collection of information should be sent to the Office of Management and Budget, Attn: Desk Officer for the Department of the Treasury, Office of Information and Regulatory Affairs, Washington, DC 20503, with copies to the Internal Revenue Service, Attn: IRS Reports Clearance Officer, SE:W:CAR:MP:T:T:SP, Washington, DC 20224. Comments on the collection of information should be received by June 7, 2016. Comments are specifically requested concerning:
Whether the proposed collection of information is necessary for the proper performance of the functions of the IRS, including whether the information will have practical utility;
The accuracy of the estimated burden associated with the proposed collection of information;
How the quality, utility, and clarity of the information to be collected may be enhanced;
How the burden of complying with the proposed collection of information may be minimized, including through the application of automated collection techniques or other forms of information technology; and
Estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information.
The collection of information in this proposed regulation is in
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a valid control number assigned by the Office of Management and Budget.
As described further in this preamble, courts historically have analyzed whether an interest in a corporation should be treated as stock or indebtedness for federal tax purposes by applying various sets of factors to the facts of a particular case. In 1969, Congress enacted section 385 to authorize the Secretary of the Treasury (Secretary) to prescribe such regulations as may be necessary or appropriate to determine whether an interest in a corporation is to be treated as stock or indebtedness for purposes of the Code. Because no regulations are currently in effect under section 385, the case law that developed before the enactment of section 385 has continued to evolve and to control the characterization of an interest in a corporation as debt or equity.
Section 385(a), as originally enacted as part of the Tax Reform Act of 1969 (Pub. L. 91-172, 83 Stat. 487), authorizes the Secretary to prescribe such regulations as may be necessary or appropriate to determine whether an interest in a corporation is treated as stock or indebtedness for purposes of the Code.
Section 385(b) provides that the regulations prescribed under section 385 shall set forth factors that are to be taken into account in determining in a particular factual situation whether a debtor-creditor relationship exists or a corporation-shareholder relationship exists. Under section 385(b), those factors may include, among other factors, the following: (1) Whether there is a written unconditional promise to pay on demand or on a specified date a sum certain in money in return for an adequate consideration in money or money's worth, and to pay a fixed rate of interest; (2) whether there is subordination to or preference over any indebtedness of the corporation; (3) the ratio of debt to equity of the corporation; (4) whether there is convertibility into the stock of the corporation; and (5) the relationship between holdings of stock in the corporation and holdings of the interest in question.
In enacting section 385(a) and (b), Congress authorized the Secretary to prescribe targeted rules to address particular factual situations, stating:
In view of the uncertainties and difficulties which the distinction between debt and equity has produced in numerous situations . . . the committee further believes that it would be desirable to provide rules for distinguishing debt from equity in the variety of contexts in which this problem can arise. The differing circumstances which characterize these situations, however, would
The provision also specifies certain factors which may be taken into account in these [regulatory] guidelines. It is not intended that only these factors be included in the guidelines or that, with respect to a particular situation, any of these factors must be included in the guidelines, or that any of the factors which are included by statute must necessarily be given any more weight than other factors added by regulations.
Congress amended section 385 in 1989 and 1992. In 1989, the Omnibus Budget Reconciliation Act of 1989 (Pub. L. 101-239, 103 Stat. 2106) amended section 385(a) to expressly authorize the Secretary to issue regulations under which an interest in a corporation is to be treated as in part stock and in part indebtedness. This amendment also provides that any regulations so issued may apply only with respect to instruments issued after the date on which the Secretary or the Secretary's delegate provides public guidance as to the characterization of such instruments (whether by regulation, ruling, or otherwise).
In 1992, Congress added section 385(c) to the Code as part of the Energy Policy Act of 1992 (Pub. L. 102-486, 106 Stat. 2776). Section 385(c)(1) provides that the issuer's characterization (as of the time of issuance) as to whether an interest in a corporation is stock or indebtedness shall be binding on such issuer and on all holders of such interest (but shall not be binding on the Secretary). Section 385(c)(2) provides that, except as provided in regulations, section 385(c)(1) shall not apply to any holder of an interest if such holder on his return discloses that he is treating such interest in a manner inconsistent with the initial characterization of the issuer. Section 385(c)(3) authorizes the Secretary to require such information as the Secretary determines to be necessary to carry out the provisions of section 385(c), including the information necessary for the Secretary to determine how the issuer characterized an interest as of the time of issuance.
Congress added section 385(c) in response to issuers and holders characterizing a corporate instrument inconsistently. H.R. Rep. No. 102-716, at 3 (1992). For example, a corporate issuer may designate an instrument as indebtedness for federal tax purposes and deduct as interest the amounts paid on the instrument, while a corporate holder may treat the instrument as stock for federal tax purposes and claim a dividends received deduction with respect to the amounts paid on the instrument.
There are no regulations currently in effect under section 385. On March 24, 1980, the Department of the Treasury (Treasury Department) and the IRS published a notice of proposed rulemaking (LR-1661) in the
The Treasury Department and the IRS have not previously published any regulations regarding the 1989 amendment to section 385(a), which authorizes the Secretary to issue regulations that treat an interest in a corporation as indebtedness in part or as stock in part. In addition, no regulations have been published with respect to the 1992 addition of section 385(c) authorizing the Secretary to require information related to an issuer's initial characterization of an interest for federal tax purposes or to affect the ability of a holder to treat an interest inconsistent with the initial treatment of the issuer.
In the absence of regulations under section 385, the pre-1969 case law has continued to evolve and control the characterization of an interest as debt or equity for federal tax purposes. Under that case law, courts apply inconsistent sets of factors to determine if an interest should be treated as stock or indebtedness, subjecting substantially similar fact patterns to differing analyses. The result has been a body of case law that perpetuates the “uncertainties and difficulties which the distinction between debt and equity has produced” and with which Congress expressed concern when enacting section 385.
(1) the intent of the parties; (2) the identity between creditors and shareholders; (3) the extent of participation in management by the holder of the instrument; (4) the ability of the corporation to obtain funds from outside sources; (5) the `thinness' of the capital structure in relation to debt; (6) the risk involved; (7) the formal indicia of the arrangement; (8) the relative position of the obligees as to other creditors regarding the payment of interest and principal; (9) the voting power of the holder of the instrument; (10) the provision of a fixed rate of interest; (11) a contingency on the obligation to repay; (12) the source of the interest payments; (13) the presence or absence of a fixed maturity date; (14) a provision for redemption by the corporation; (15) a provision for redemption at the option of the holder; and (16) the timing of the advance with reference to the organization of the corporation.
(1) the names given to the certificates evidencing the indebtedness; (2) The presence or absence of a fixed maturity date; (3) The source of payments; (4) The right to enforce payment of principal and interest; (5) participation in management flowing as a result; (6) the status of the contribution in relation to regular corporate creditors; (7) the intent of the parties; (8) `thin' or adequate capitalization; (9) identity of interest between creditor and stockholder; (10) source of interest payments; (11) the ability of the
Under this facts-and-circumstances analysis, as developed in the case law, no single fact or circumstance is sufficient to establish that an interest should be treated as stock or indebtedness.
Section 701 provides that a partnership as such shall not be subject to federal income tax, but that persons carrying on business as partners shall be liable for federal income tax only in their separate or individual capacities.
Section 1502 provides that the Secretary shall prescribe such regulations as the Secretary deems necessary in order that the federal tax liability of any affiliated group of corporations making a consolidated return and of each corporation in the group, both during and after the period of affiliation, may be returned, determined, computed, assessed, collected, and adjusted, in such manner as clearly to reflect the federal income tax liability and the various factors necessary for the determination of such liability, and in order to prevent avoidance of such tax liability. In prescribing such regulations, section 1502 authorizes the Secretary to prescribe rules that are different from the provisions of chapter 1 of subtitle A of the Code that would apply if such corporations filed separate returns.
Section 7701(l) provides that the Secretary may prescribe regulations recharacterizing any multiple-party financing transaction as a transaction directly among any two or more of such parties where the Secretary determines that such recharacterization is appropriate to prevent avoidance of any tax imposed by the Code.
Notice 2014-52, 2014-42 IRB 712 (Oct. 14, 2014), and Notice 2015-79, 2015-49 IRB 775 (Dec. 7, 2015), described regulations that the Treasury Department and the IRS intend to issue with respect to corporate inversions and related transactions. Notice 2014-52 and Notice 2015-79 also provided that the Treasury Department and the IRS expect to issue additional guidance to further limit the benefits of post-inversion tax avoidance transactions. The notices stated, in particular, that the Treasury Department and the IRS are considering guidance to address strategies that avoid U.S. tax on U.S. operations by shifting or “stripping” U.S.-source earnings to lower-tax jurisdictions, including through intercompany debt.
These proposed regulations under section 385 address whether an interest in a related corporation is treated as stock or indebtedness, or as in part stock or in part indebtedness, for purposes of the Code. While these proposed regulations are motivated in part by the enhanced incentives for related parties to engage in transactions that result in excessive indebtedness in the cross-border context, federal income tax liability can also be reduced or eliminated with excessive indebtedness between domestic related parties. Thus, the proposed rules apply to purported indebtedness issued to certain related parties, without regard to whether the parties are domestic or foreign. Nonetheless, the Treasury Department and the IRS also have determined that the proposed regulations should not apply to issuances of interests and related transactions among members of a consolidated group because the concerns addressed in the proposed regulations generally are not present when the issuer's deduction for interest expense and the holder's corresponding interest income offset on the group's consolidated federal income tax return.
Section A of this Part VI addresses bifurcation of interests that are indebtedness in part but not in whole. Section B of this Part VI addresses documentation requirements for related-party indebtedness. Section C of this Part VI addresses distributions of debt instruments and similar transactions.
As previously noted, Congress amended section 385(a) in 1989 to authorize the issuance of regulations permitting an interest in a corporation to be treated as in part indebtedness and in part stock. The legislative history to the 1989 amendment explained that “there has been a tendency by the courts to characterize an instrument entirely as debt or entirely as equity.” H.R. Rep. No. 101-386, at 562 (1989) (Conf. Rep.). No regulations have been promulgated under the amendment, however, and this tendency by the courts has continued to the present day. Consequently, the Commissioner generally is required to treat an interest in a corporation as either wholly indebtedness or wholly equity.
This all-or-nothing approach is particularly problematic in cases where the facts and circumstances surrounding a purported debt instrument provide only slightly more support for characterization of the entire interest as indebtedness than for equity characterization, a situation that is increasingly common in the related-party context. The Treasury Department and the IRS have determined that the all-or-nothing approach frequently fails to reflect the economic substance of related-party interests that are in form indebtedness and gives rise to inappropriate federal tax consequences. Accordingly, the Treasury Department and the IRS have determined that the interests of tax administration would best be served if the Commissioner were able to depart from the all-or-nothing approach where appropriate to ensure that the provisions of the Code are applied in a manner that clearly reflects the income of related taxpayers. To that end, these proposed regulations would exercise the authority granted by section 385(a) to permit the Commissioner to treat a purported debt instrument issued between related parties as in part indebtedness and in part stock for federal tax purposes. However, the proposed regulations would not permit issuers and related holders to treat such an instrument in a manner inconsistent with the issuer's initial characterization. The proposed regulations described in
The proposed rule applies with respect to parties that meet a lower 50-percent threshold for relatedness than the threshold applicable with respect to other rules contained in these proposed regulations. This is because, as noted in Part VI of the Background section of this preamble, federal income tax liability can be reduced or eliminated by the introduction of excessive indebtedness between related parties, and this can be accomplished without special cooperation among the related parties and regardless of other transactions undertaken by the issuer or holder after issuance. In addition, a 50-percent relatedness threshold is consistent with other provisions used in subchapter C of the Code to identify a level of control or ownership that can warrant different federal tax consequences than those for less-related parties.
The proposed rule merely permits the Commissioner to treat a purported debt instrument as in part indebtedness and in part stock consistent with its substance. Moreover, the proposed regulations would not affect the authority of the Commissioner to disregard a purported debt instrument as indebtedness or stock, to treat a purported debt instrument as indebtedness or equity of another entity, or otherwise to treat a purported debt instrument in accordance with its substance.
The Treasury Department and the IRS recognize that authorizing the Commissioner to treat purported debt instruments issued among unrelated parties as indebtedness in part and stock in part could result in unnecessary uncertainty in the capital markets in the absence of detailed standards for the exercise of that authority. Similarly, any exercise of this authority with respect to related-party interests that are denominated as other than indebtedness would require more detailed guidance. Thus, the proposed rule does not apply in those contexts.
Related-party indebtedness, like indebtedness between unrelated persons, may be respected as indebtedness for federal tax purposes, but only if there is intent to create a true debtor-creditor relationship that results in bona fide indebtedness. While still subject to the same multifactor analysis used for characterizing interests issued between third parties, “courts have consistently recognized that transactional forms between related parties are susceptible of manipulation and, accordingly, warrant a more thorough and discerning examination for tax characterization purposes.”
This scrutiny is warranted because there is typically less economic incentive for a related-party lender to impose discipline on the legal documentation and economic analysis supporting the characterization of an interest as indebtedness for federal tax purposes. While a lender typically carefully documents a loan to a third party borrower and decides whether and how much to lend based on that documentation and objective financial criteria, a related-party lender, especially one that directly or indirectly controls the borrower, may require only simple (or even no) legal documentation and may forgo any economic analysis that would inform the lender of the amount that the borrower could reasonably be expected to repay.
The absence of reasonable diligence by related-party lenders can have the effect of limiting the factual record that is available for additional scrutiny and thorough examination. Nonetheless, courts do not always require related parties to engage in reasonable financial analysis and legal documentation similar to that which business exigencies would incent third-parties in connection with lending to unrelated borrowers.
Historically, the absence of clear guidance regarding the documentation and information necessary to support debt characterization in the related-party context did not pose a significant obstacle, because the transactions presented by cases such as
Increasingly, this is no longer the case. Over time, the Treasury Department and the IRS have observed that business practices, structures, and activities between related parties have changed considerably. The Treasury Department and the IRS acknowledge that the size, activities, and financial complexity of corporations and their group structures have grown exponentially, and understand that these groups routinely include foreign entities, sometimes from multiple foreign jurisdictions, as well as federal tax-indifferent domestic members. The scope and complexity of intragroup transactions has grown commensurately. Examples include the transactions at issue in
As a result of these developments, it is increasingly problematic that there is a lack of guidance prescribing the information and documentation necessary to support the characterization of a purported debt instrument as indebtedness in the related-party context. The lack of such guidance, combined with the sheer volume of financial records taxpayers produce in the ordinary course of business, makes it difficult to identify the documents that will ultimately be required to support such a characterization, particularly with respect to whether a reasonable expectation of repayment is present at the time an interest is issued. The result can be either the inadvertent omission of necessary documents from disclosure
Finally, the dollar amounts at stake have often become increasingly significant. For example, the federal tax liability at issue in
To address these concerns, the Treasury Department and the IRS are proposing rules, under the authority granted in section 385(a) to prescribe regulations to determine whether an interest in a corporation is stock or indebtedness, that prescribe the nature of the documentation and information that must be prepared and maintained for a purported debt instrument issued by a corporation to a related party to be treated as indebtedness for federal tax purposes. The proposed regulations are intended to impose discipline on related parties by requiring timely documentation and financial analysis that is similar to the documentation and analysis created when indebtedness is issued to third parties. This requirement also serves to help demonstrate whether there was intent to create a true debtor-creditor relationship that results in bona fide indebtedness and also to help ensure that the documentation necessary to perform an analysis of a purported debt instrument is prepared and maintained. This approach is consistent with the long-standing view held by courts that the taxpayer has the burden of substantiating its treatment of an arrangement as indebtedness for federal tax purposes.
In general, the Treasury Department and the IRS have determined that timely preparation of documentation and financial analysis evidencing four essential characteristics of indebtedness are a necessary factor in the characterization of a covered interest as indebtedness for federal tax purposes. Those characteristics are: a legally binding obligation to pay, creditors' rights to enforce the obligation, a reasonable expectation of repayment at the time the interest is created, and an ongoing relationship during the life of the interest consistent with arms-length relationships between unrelated debtors and creditors. These characteristics are drawn from the case law and are consistent with the text of section 385(b)(1) and (5). While the proposed regulations do not intend to alter the general case law view of the importance of these essential characteristics of indebtedness, the proposed regulations do require a degree of discipline in the creation of necessary documentation, and in the conduct of reasonable financial diligence indicative of a true debtor-creditor relationship, that exceeds what is required under current law.
The proposed regulations make clear that the preparation and maintenance of this documentation and information are not dispositive in establishing that a purported debt instrument is indebtedness for federal tax purposes. Rather, these requirements are necessary to the conduct of the multi-factor analysis used in the
The Treasury Department and the IRS have identified three types of transactions between affiliates that raise significant policy concerns and that should be addressed under the Secretary's authority to prescribe rules for particular factual situations: (1) distributions of debt instruments by corporations to their related corporate shareholders; (2) issuances of debt instruments by corporations in exchange for stock of an affiliate (including “hook stock” issued by their related corporate shareholders); and (3) certain issuances of debt instruments as consideration in an exchange pursuant to an internal asset reorganization. Similar policy concerns arise when a related-party debt instrument is issued in a separate transaction to fund (1) a distribution of cash or other property to a related corporate shareholder; (2) an acquisition of affiliate stock from an affiliate; or (3) certain acquisitions of property from an affiliate pursuant to an internal asset reorganization. Accordingly, the proposed regulations treat related-party debt instruments issued in any of the foregoing transactions as stock, subject to certain exceptions.
Sections C.2 through C.5 of this Part VI describe in greater detail the purposes of the proposed regulations that apply to these types of transactions. Part IV of the Explanation of Provisions section of this preamble describes in detail the proposed regulations.
In
The court considered arguments by the government that the parent-subsidiary relationship warranted additional scrutiny in determining whether a debtor-creditor relationship was established in substance. In particular, the Commissioner argued that, because the issuer subsidiary was wholly-owned, “the sole stockholder [could] deal as it please[d] with the corporate entity it control[led]” and, as a result, the transaction could have been a sham.
In holding for the taxpayer, the Second Circuit determined that the debentures should be respected as indebtedness because the debentures were unambiguously denominated as debt, were issued by and to real taxable entities, and created real legal rights and duties between the parties.
Other courts have not given the same level of deference to the form of a transaction that the Second Circuit did in
Courts also have given weight to the lack of new capital investment when a closely-held corporation issues indebtedness to a controlling shareholder but receives no new investment in exchange.
In many contexts, a distribution of a debt instrument similar to the one at issue in
In light of these policy concerns, the proposed regulations treat a debt instrument issued in fact patterns similar to that in
Thus, any non-tax effects of a distribution of a debt instrument to an affiliate are often minimized or eliminated, allowing the related parties to obtain significant federal tax benefits at little or no cost. Accordingly, based on these considerations, the Treasury Department and the IRS have determined that in fact patterns similar to
The Treasury Department and the IRS have determined that the issuance of a related-party debt instrument to acquire stock of a related person is similar in many respects to a distribution of a debt instrument and implicates similar policy considerations. Recognizing the economic similarities between purchases of affiliate stock and distributions, Congress enacted section 304 and its predecessors to prevent taxpayers from acquiring affiliate stock to convert what otherwise would be a taxable dividend into a sale or exchange transaction.
Like distributions of debt instruments, issuances of debt instruments to acquire affiliate stock frequently have limited non-tax significance, particularly in relation to the significant federal tax benefits that are generated in the transaction. Such transactions do not change the ultimate ownership of the affiliate, and introduce no new operating capital to either affiliate. While the change in the direct ownership of the affiliate's stock may have some non-tax significance in certain circumstances, such as the harmonization of a group's corporate structure following an acquisition, other
Accordingly, the proposed regulations generally treat a debt instrument issued in exchange for affiliate stock as stock.
The proposed regulations also address certain debt instruments issued by an acquiring corporation as consideration in an exchange pursuant to an internal asset reorganization. Internal asset reorganizations can operate in a similar manner to section 304 transactions as a device to convert what otherwise would be a distribution into a sale or exchange transaction without having any meaningful non-tax effect. Congress noted this similarity in 1984 when it harmonized the control requirement for section 368(a)(1)(D) reorganizations with the control requirement in section 304.
Consider the following example: A foreign parent corporation (Parent) owns all of the stock of two U.S. subsidiaries, S1 and S2. In a transaction qualifying as a reorganization described in section 368(a)(1)(D), Parent transfers its stock in S1 to S2 in exchange for a note issued by S2, and S1 converts to a limited liability company. For federal tax purposes, S1 is treated as selling all of its assets to S2 in exchange for a debt instrument, and under section 356, Parent is treated as receiving the S2 debt instrument from S1 in a liquidating distribution with respect to Parent's S1 stock. This transaction has a similar effect (and tax treatment) as a section 304 transaction in which S2 issues a debt instrument to Parent in exchange for S1 stock, with the only difference being that S2 acquired the assets of S1 instead of the S1 stock and that Parent received the debt instrument as a result of the liquidation of S1.
This transaction introduces no new capital into the P group, and does not affect the ultimate ownership of the assets held by S1 or S2. Furthermore, S1 generally would not be required to recognize any built-in gain on the transfer of its assets to S2. Although this transaction entails a transfer of assets from S1 to S2, the tax costs (if any) and the non-tax consequences that result from this type of transaction among related parties are typically insignificant relative to the federal tax benefits obtained through the introduction of a related-party debt instrument. Accordingly, the proposed regulations treat a debt instrument issued by an acquiring corporation as consideration in an exchange pursuant to an internal asset reorganization as stock, consistent with the treatment of a debt instrument issued in a distribution or in exchange for affiliate stock.
The Treasury Department and the IRS have determined that the policy concerns implicated by the transactions described in Sections C.2 through C.4 of this Part VI are also present when a corporation issues a debt instrument with a principal purpose of funding certain related-party transactions. Specifically, the proposed regulations treat a debt instrument issued for property, including cash, as stock when the debt instrument is issued to an affiliate with a principal purpose of funding (1) a distribution of cash or other property to a related corporate shareholder, (2) an acquisition of affiliate stock from an affiliate, or (3) certain acquisitions of property from an affiliate pursuant to an internal asset reorganization.
Without these funding provisions, taxpayers that otherwise would have issued a debt instrument in a one-step transaction described in Sections C.2 through C.4 of this Part VI would be able to use multi-step transactions to avoid the application of these proposed regulations while achieving economically similar outcomes. For example, a wholly-owned subsidiary that otherwise would have distributed a debt instrument to its parent corporation in a distribution could, absent these rules, borrow cash from its parent and later distribute that cash to its parent in a transaction that is purported to be independent from the borrowing. Like the distribution of a note, this transaction, if respected, would result in an increase of related-party debt, but no new net investment in the operations of the subsidiary. The parent corporation would have effectively reshuffled its subsidiary's capital structure to obtain more favorable federal tax treatment for the subsidiary without affecting its control over the subsidiary. The similarity between these transactions indicates that they should be subject to similar tax treatment.
The Treasury Department and the IRS also have determined that a debt instrument should be subject to these funding rules regardless of whether the funding affiliate (the lender) is a party to the funded transaction. Otherwise, a corporation could, for example, borrow funds from a sister corporation and immediately distribute those funds to the common parent corporation. Issuances of debt instruments to an affiliate in order to fund a distribution of property, an acquisition of affiliate stock, or an acquisition of an affiliate's assets in a reorganization often would confer significant federal tax benefits without having a significant non-tax impact, regardless of whether the lender is also a party to the funded transaction. Accordingly, the proposed regulations treat as stock a debt instrument issued to an affiliate to fund one of the specified transactions regardless of whether the lender is a party to the funded transaction.
The proposed regulations provide guidance regarding substantiation of the treatment of certain interests issued between related parties as indebtedness for federal tax purposes, the treatment of certain interests in a corporation as in part indebtedness and in part stock, and the treatment of distributions of debt instruments and similar transactions that frequently have only limited non-tax effects. More specifically, the proposed regulations are set forth in four sections. First, proposed § 1.385-1 prescribes definitions and operating rules applicable to the regulations under section 385 generally, including a rule treating members of a consolidated group, as defined in § 1.1502-1(h), as one corporation. Proposed § 1.385-1(d) also provides that the Commissioner has the discretion to treat certain interests in a corporation for federal tax purposes as indebtedness in part and stock in part. Second, proposed § 1.385-2 addresses the documentation and information that taxpayers must prepare and maintain within required timeframes to substantiate the treatment of an interest issued between related parties as indebtedness for federal tax purposes. Such substantiation is necessary, but not sufficient, for a purported debt interest that is within the scope of these rules to be characterized as indebtedness; general federal income tax principles also apply in making such a determination. Third, if the application of proposed § 1.385-2 and
As previously discussed, the concerns addressed by the proposed regulations arise with respect to interests issued among related parties. The scope of the proposed regulations is therefore generally limited to purported indebtedness between members of an expanded group. Proposed § 1.385-1, which sets forth definitions generally applicable to the regulations proposed under section 385, defines the term
Through this definition of an expanded group, the application of the proposed regulations is limited to transactions between highly-related parties. Other rules, discussed in Section III.A (limiting the application of proposed § 1.385-2 to large taxpayers) and Section IV.C ($50 million threshold exception for proposed § 1.385-3) of this Explanation of Provisions limit the application of the proposed regulations to large taxpayers.
Proposed § 1.385-1 includes rules that prescribe the effects under the Code generally of an exchange of purported indebtedness for stock that is deemed to occur under the proposed regulations. Under those rules, on the date the indebtedness is recharacterized as stock, the indebtedness is deemed to be exchanged, in whole or in part, for stock with a value that is equal to the holder's adjusted basis in the portion of the indebtedness that is treated as equity under the regulations, and the issuer of the indebtedness is deemed to retire the same portion of the indebtedness for an amount equal to its adjusted issue price as of that date. This rule generally will prevent both the holder and issuer from realizing gain or loss from the deemed exchange other than foreign exchange gain or loss recognized by the issuer or the holder under section 988.
Proposed § 1.385-1 implements the statutory authority under section 385(a) to treat an instrument as part indebtedness and part stock by authorizing the Commissioner to treat certain instruments issued between related parties in this manner. Any such treatment will occur only in the event that the substance of the instrument is regarded for federal tax purposes and the instrument has met the documentation and information requirements in proposed § 1.385-2 (described subsequently in Section III), if applicable. In addition, the Commissioner is not required to treat such an interest as indebtedness in part and stock in part. For example, under the proposed regulations, if an analysis of a related-party interest that is documented as a $5 million debt instrument demonstrates that the issuer cannot reasonably be expected to repay more than $3 million of the principal amount as of the issuance of the interest, the Commissioner may treat the interest as part indebtedness ($3 million) and part stock ($2 million). The type of stock (for example, common stock or preferred stock, section 306 stock, stock described in section 1504(a)(4)) that the instrument will be treated as for federal tax purposes is determined by taking into account the terms of the instrument (for example, voting and conversion rights and rights relating to dividends, redemption, liquidation, and other distributions).
The Treasury Department and the IRS believe that this approach will facilitate the treatment of purported debt instruments issued between related parties in a manner that is more consistent with the substance of the underlying transaction.
Pursuant to section 385(c) and the regulatory authority granted the Secretary under section 385(c)(2), the issuer of the interest, the holder of the interest, and any other person relying on the characterization of the interest as indebtedness for federal tax purposes are all required to treat the interest consistent with the issuer's initial characterization. Thus, for example, a holder may not disclose on its return under section 385(c)(2) that it is treating an EGI, as later defined in Section III.A of this Explanation of Provisions, as indebtedness in part or stock in part if the issuer of the EGI treats the EGI as indebtedness. This approach eliminates cases in which members of the same expanded group take contrary positions as to the treatment of an EGI as indebtedness, stock, or indebtedness in part and stock in part.
The proposed regulations authorize the treatment of an interest as indebtedness in part and stock in part in the case of instruments issued in the form of debt between parties that are related, but at a lesser degree of relatedness than that required to include them in an expanded group. Under the proposed regulations, treatment as indebtedness in part and stock in part can apply to purported indebtedness between members of
As described in Part VI of the Background section of this preamble,
Proposed § 1.385-2 reflects the importance of contemporaneous documentation in identifying the rights, obligations, and intent of the parties to an instrument that is purported to be indebtedness for federal tax purposes. Such documentation is particularly important to the analysis of instruments issued between related parties. In recognition of this importance, the Treasury Department and the IRS are exercising authority granted under section 385(a) to treat the timely preparation and maintenance of such documentation as necessary factors to be taken into account in determining whether certain interests are properly characterized as stock or indebtedness. Accordingly, the proposed regulations first prescribe the nature of the documentation necessary to substantiate the treatment of related-party instruments as indebtedness and, second, require that such documentation be timely prepared and maintained. The proposed regulations further provide that, if the specified documentation is not provided to the Commissioner upon request, the Commissioner will treat the preparation and maintenance requirements as not satisfied and will treat the instrument as stock for federal tax purposes. The type of stock (for example, common stock or preferred stock, section 306 stock, stock described in section 1504(a)(4)) that the instrument will be treated as for federal tax purposes is determined by taking into account the terms of the instrument (for example, voting and conversion rights and rights relating to dividends, redemption, liquidation, and other distributions).
Satisfaction of the requirements of the proposed regulations does not establish that a related-party instrument is indebtedness. Rather, satisfaction of the proposed regulations acts as a threshold test for allowing the possibility of indebtedness treatment after the determination of an instrument's character is made under federal tax principles developed under applicable case law. If the requirements of the proposed regulations are not satisfied, the purported indebtedness would be recharacterized as stock. In such a case, any federal tax benefit claimed by the taxpayer with respect to the treatment of the interest as indebtedness will be disallowed.
Judicial doctrines that disregard transactions as having no substance continue to be applicable and are not affected by the proposed regulations. Accordingly, proposed § 1.385-2 applies only to interests the substance of which is potentially regarded as indebtedness for federal tax purposes. In addition, proposed § 1.385-2 does not limit the ability of the IRS to request information under any existing authorities, such as the rules under section 7602.
As discussed previously, these proposed regulations apply only to purported indebtedness issued among entities that are highly related. Several provisions of the proposed regulations combine to effect this limitation.
First, proposed § 1.385-2 provides rules only with respect to
Second, proposed § 1.385-2 only applies to applicable interests that are issued and held by members of an expanded group (
Third, proposed § 1.385-2 is intended to apply only to large taxpayer groups. Accordingly, an EGI is not subject to proposed § 1.385-2 unless the stock of any member of the expanded group is publicly traded, all or any portion of the expanded group's financial results are reported on financial statements with total assets exceeding $100 million, or the expanded group's financial results are reported on financial statements that reflect annual total revenue that exceeds $50 million. The proposed regulations provide guidance regarding the financial statement or statements that are to be used for purposes of determining the expanded group's assets and liabilities. In general, this determination is made by reference to a financial statement required to be filed with the Securities and Exchange Commission, a certified audited financial statement that is accompanied by the report of an independent certified public accountant (or in the case of a foreign entity, by the report of a similarly qualified independent professional) that is used for certain purposes, or a financial statement (other than a tax return) required to be provided to the federal, state, or foreign government or any federal, state, or foreign agency. Because this list represents a set of financial statements created for other purposes for persons outside the expanded group, these financial statements are expected to be sufficiently reliable for this purpose. In addition, to prevent the use of stale financial information, only applicable financial statements prepared within the three years of the EGI becoming subject to the proposed regulations are relevant for determining whether an EGI is subject to the proposed regulations under § 1.385-2.
The core of proposed § 1.385-2 is the guidance regarding the nature of the
The proposed regulations require that the prescribed documentation and information must be provided with respect to each category. Failure to provide the documentation and information upon request by the Commissioner will result in the Commissioner treating the requirements of this section as not satisfied. The four categories are more specifically described in the following four paragraphs.
1.
2.
3.
4.
In general, the documentation must be prepared no later than 30 calendar days after the date of the relevant event, which is generally the later of the date that the instrument becomes an EGI or the date that an expanded group member becomes an issuer with respect to an EGI. However, in the case of documentation of the debtor-creditor relationship, the regulations allow the documentation to be prepared up to 120 calendar days after the payment or relevant event occurred. This extended period is intended to avoid inadvertent failures to comply with the regulations that may be more likely in the case of events that occur during the life of an EGI. If an applicable instrument is not an EGI when issued, no documentation is required under the proposed regulations for any date before the date the applicable instrument becomes an EGI.
The proposed regulations provide special rules for determining the timeliness of documentation preparation in the case of certain revolving credit agreements and similar arrangements and cash pooling arrangements, generally looking to the documents pursuant to which the arrangements were established.
Under proposed § 1.385-2, the documentation and information in the four categories previously described must be maintained for all taxable years that the EGI is outstanding and until the period of limitations expires for any return with respect to which the federal tax treatment of the EGI is relevant. The proposed regulations do not otherwise specify where or in what manner such records must be kept. The Treasury Department and the IRS intend that taxpayers have flexibility to determine the manner in which the requirements of the proposed regulations are satisfied.
In general, proposed § 1.385-2 will apply to an applicable instrument at the time it becomes an EGI and thereafter. If an EGI that was characterized as stock under the rules of § 1.385-2 ceases to be an EGI, general federal tax principles will apply to determine its character at the time it ceases to be an EGI; if, under general federal tax principles, it is treated as indebtedness, the issuer is treated as issuing a new debt instrument to the holder in exchange for the EGI immediately before the transaction that causes the instrument to cease to qualify as an EGI.
If an applicable instrument is an EGI when issued, determinations under proposed § 1.385-2 are generally effective from the issuance date. If an applicable instrument was not an EGI when issued, proposed § 1.385-2 applies, and any resulting determination is generally effective, when the applicable instrument becomes an EGI. However, if an EGI originally treated as debt is later recharacterized as stock because the documentation and information cease to evidence an ongoing debtor-creditor relationship, the recharacterization will be effective as of the time that the facts and circumstances cease to evidence a debtor-creditor relationship.
Proposed § 1.385-1(e) provides that members of a consolidated group are treated as one corporation. Proposed § 1.385-2(c)(4)(ii) further provides that if an applicable instrument ceases to be an intercompany obligation and, as a result, becomes an EGI subject to the rules of proposed § 1.385-2, the applicable instrument is treated as becoming an EGI immediately after it ceases to be an intercompany obligation.
The proposed regulation includes a number of provisions that modify the general rules of § 1.385-2 in order to provide flexibility in appropriate circumstances or to prevent abuse. First, the requirements of proposed § 1.385-2 may be modified if a taxpayer's failure to comply with the requirements is attributable to reasonable cause. The principles of § 301.6724-1 (relating to
Second, to prevent abuse, proposed § 1.385-2 prohibits the affirmative use of the rules in the proposed regulations to support a particular characterization of an instrument. Thus, if a taxpayer fails to satisfy the requirements of proposed § 1.385-2 with a principal purpose of reducing the federal tax liability of any member of the expanded group, the rules of the proposed regulations do not apply.
Third, if an applicable instrument that is not an EGI is issued with a principal purpose of avoiding the purposes of proposed § 1.385-2, the applicable instrument is treated as an EGI and will be subject to the provisions of the proposed regulations. Such a situation could occur if, for example, an applicable interest was issued by an expanded group member to a trust held by members of the same expanded group.
The provisions of § 1.385-2 are proposed to be generally effective when the regulations are published as final regulations. Proposed § 1.385-2 would apply to any applicable instrument issued on or after that date, as well as to any applicable instrument treated as issued as a result of an entity classification election under § 301.7701-3 made on or after the date the regulations are issued as final regulations.
Proposed §§ 1.385-3 and 1.385-4 provide rules that treat as stock certain interests that otherwise would be treated as indebtedness for federal income tax purposes. Proposed § 1.385-3 applies to debt instruments that are within the meaning of section 1275(a) and § 1.1275-1(d), as determined without regard to the application of proposed § 1.385-3. Section 1275(a) and § 1.1275-1(d) generally define a debt instrument as any instrument or contractual arrangement that constitutes indebtedness under general principles of federal income tax law. Thus, the term
Specifically, proposed § 1.385-3 treats as stock certain debt instruments issued by one member of an expanded group to another member of the same group (expanded group debt instrument) in the circumstances described in Section B of this Part IV, unless an exception described in Section C of this Part IV applies. Detailed operating rules regarding the recharacterization (including with respect to partnerships) are discussed in Section D of this Part IV. A rule to prevent taxpayers from affirmatively using proposed §§ 1.385-3 and 1.385-4 is discussed in Section E of this Part IV. Section F of this Part IV discusses proposed § 1.385-4, which provides special rules to address the treatment of consolidated groups. The effective date of proposed §§ 1.385-3 and 1.385-4 is discussed in Section G of this Part IV.
To the extent proposed § 1.385-3 treats an interest as stock, the interest is treated as stock for all federal tax purposes. Consistent with the traditional case law debt-equity analysis, when a debt instrument is treated as stock under proposed § 1.385-3, the terms of the debt instrument (for example, voting rights or conversion features) are taken into account for purposes of determining the type of stock resulting from the recharacterization, including whether such stock is preferred stock or common stock.
Proposed § 1.385-3 provides three rules that treat an expanded group debt instrument as stock: a general rule, a funding rule, and an anti-abuse rule.
The general rule treats an expanded group debt instrument as stock to the extent it is issued by a corporation to a member of the corporation's expanded group (1) in a distribution; (2) in exchange for expanded group stock, other than in an exempt exchange (as defined later in this Section 1); or (3) in exchange for property in an asset reorganization, but only to the extent that, pursuant to the plan of reorganization, a shareholder that is a member of the issuer's expanded group immediately before the reorganization receives the debt instrument with respect to its stock in the transferor corporation. All or a portion of an issuance of a debt instrument may be described in more than one prong of the general rule without changing the result that follows from being described in a single prong.
For purposes of the first prong of the general rule, the term
The second prong of the general rule—addressing debt instruments issued in exchange for expanded group stock—applies regardless of whether the expanded group stock is acquired from a shareholder of the issuer of the expanded group stock, or directly from the issuer. For an illustration of this rule in a context where stock is not formally issued because it would be a “meaningless gesture,” see Example 11 in § 1.385-3(g)(3) of the proposed regulations.
For purposes of the second prong of the general rule, the term
The third prong of the general rule applies to asset reorganizations among corporations that are members of the same expanded group. An
The third prong of the general rule is limited to debt instruments distributed to shareholders pursuant to the reorganization, and does not apply to debt instruments exchanged for securities or other debt interests because, in that latter case, the newly issued debt instrument is exchanged for existing debt interests and thus no additional debt is incurred by the parties to the reorganization.
The funding rule treats as stock an expanded group debt instrument that is issued with a principal purpose of funding a transaction described in the general rule (principal purpose debt instrument). Specifically, a principal purpose debt instrument is a debt instrument issued by a corporation (funded member) to another member of the funded member's expanded group in exchange for property with a principal purpose of funding (1) a distribution of property by the funded member to a member of the funded member's expanded group, other than a distribution of stock pursuant to an asset reorganization that is permitted to be received without the recognition of gain or income under section 354(a)(1) or 355(a)(1) or, when section 356 applies, that is not treated as “other property” or money described in section 356; (2) an acquisition of expanded group stock, other than in an exempt exchange, by the funded member from a member of the funded member's expanded group in exchange for property other than expanded group stock; or (3) the acquisition of property by the funded member in an asset reorganization but only to the extent that, pursuant to the plan of reorganization, a shareholder that is a member of the funded member's expanded group immediately before the reorganization receives “other property” or money within the meaning of section 356 with respect to its stock in the transferor corporation.
Prongs (1) through (3) of the funding rule are referred to in this Section 2 as “distributions or acquisitions.” Proposed § 1.385-3(b)(3)(iii) provides that, if all or a portion of a distribution or acquisition by a funded member is described in more than one prong of the funding rule, the funded member is treated as engaging in only a single distribution or acquisition for purposes of applying the funding rule. The funding rule addresses transactions that, when viewed together, present similar policy concerns as the transactions that are subject to the general rule.
The first prong of the funding rule—addressing a distribution by a funded member—excludes a distribution of stock permitted to be received without the recognition of gain under section 355(a)(1) when the distribution is pursuant to an asset reorganization (that is, a divisive reorganization qualifying under section 368(a)(1)(D)), but does not exclude a distribution of stock that is permitted to be received without the recognition of gain under section 355(a)(1) when the transaction qualifies under section 355 without also qualifying as a reorganization (that is, a distribution of the stock of a controlled corporation without a related transfer of property by the distributing corporation to the controlled corporation pursuant to the plan of reorganization). The reason for this distinction is that the controlled corporation in a divisive reorganization described in section 368(a)(1)(D) acquires assets of the distributing corporation and, as described in Section B.2.b.v of this Part IV, is treated as a successor of the distributing corporation (and the distributing corporation is treated as a predecessor of the controlled corporation) for purposes of the funding rule. In contrast, when a distribution transaction qualifies under section 355 without also qualifying as a reorganization, the controlled corporation does not acquire assets from the distributing corporation as part of the transaction and the corporations are not treated as predecessor and successor of each other for purposes of the funding rule. Consistent with this approach, proposed § 1.385-3 does not treat a section 355 distribution that is part of a divisive reorganization as a distribution for purposes of the funding rule because the distributing corporation and the controlled corporation are both parties to the reorganization and are both treated as funded members to the extent of any prior debt instrument issued by the distributing corporation. For a further illustration of this rule, see Example 10 in § 1.385-3(g)(3) of the proposed regulations.
The determination as to whether a debt instrument is issued with a principal purpose of funding a distribution or acquisition is based on all of the facts and circumstances. A debt instrument may be treated as issued with such a principal purpose whether it is issued before or after a distribution or acquisition.
Proposed § 1.385-3 also establishes a non-rebuttable presumption that certain expanded group debt instruments are issued with a principal purpose of funding a distribution or acquisition by the funded member. Specifically, such a principal purpose is deemed to exist if the expanded group debt instrument is issued by the funded member during the period beginning 36 months before the funded member makes a distribution or acquisition and ending 36 months after the distribution or acquisition (the 72-month period). This per se rule does not create a safe harbor. Accordingly, a debt instrument issued outside the 72-month period may be treated as having a principal purpose of funding a distribution or acquisition, based on the facts and circumstances.
The Treasury Department and the IRS have determined that this non-rebuttable presumption is appropriate because money is fungible and because it is difficult for the IRS to establish the principal purposes of internal transactions. In the absence of a per se rule, taxpayers could assert that free cash flow generated from operations funded any distributions and acquisitions, while any debt instrument was incurred to finance the capital needs of those operations. Because taxpayers would be able to document the purposes of funding transactions accordingly, it would be difficult for the IRS to establish that any particular debt instrument was incurred with a principal purpose of funding a
An exception to this per se rule applies to ordinary course debt instruments. Proposed § 1.385-3(b)(3)(iv)(B)(
For purposes of applying the per se rule, proposed § 1.385-3(b)(3)(iv)(B)(
A second ordering rule in proposed § 1.385-3(b)(3)(iv)(B)(
An exception to these ordering rules applies when an acquisition of expanded group stock by issuance ceases to qualify for the exception from the funding rule described in Section C.3 of this Part IV. In that case, the acquisition of expanded group stock is treated as an acquisition that is subject to the funding rule on the date that the acquisition actually occurred, but debt instruments issued, and other distributions and acquisitions that occurred, prior to the date that the acquirer ceases to qualify for the exception are ordered without regard to the acquisition of expanded group stock that previously was excepted from the funding rule.
For a rule preventing the funding rule from treating a debt instrument issued on or after April 4, 2016 from being treated as funding a distribution or acquisition that occurred before April 4, 2016, see Section G of this Part IV.
Finally, the funding rule provides that references in the funding rule to the funded member include any predecessor or successor of such member. A
Proposed § 1.385-3(b)(4) also provides that a debt instrument is treated as stock if it is issued with a principal purpose of avoiding the application of the proposed regulations. In addition, other interests that are not debt instruments for purposes of proposed §§ 1.385-3 and 1.385-4 (for example, contracts to which section 483 applies or nonperiodic swap payments) are treated as stock if issued with a principal purpose of avoiding the application of proposed §§ 1.385-3 or 1.385-4.
Proposed § 1.385-3(b)(4) includes a non-exhaustive list of examples illustrating situations where the anti-abuse rule might apply. The anti-abuse rule may apply, for example, if a debt instrument is issued to, and later acquired from, a person that is not a member of the issuer's expanded group with a principal purpose of avoiding the application of the proposed regulations. In that situation, factors that may be taken into account in determining the presence or absence of a principal purpose of avoiding the application of the proposed regulations include the time period between the issuance of the debt instrument to the non-member and the acquisition of the debt instrument by a member of the issuer's expanded group, and whether there was a significant change in circumstances during that time period. For example, a change of control of the issuer group (for example, a cash acquisition of all of the stock of the ultimate parent company of the issuer) after the issuance and before the acquisition of the debt instrument that was not foreseeable when the debt instrument was issued to the non-member could indicate that the debt instrument was not issued with a principal purpose of avoiding the
Other examples of when the anti-abuse rule could apply include situations where, with a principal purpose of avoiding the application of proposed § 1.385-3: (i) A Debt instrument is issued to a person that is not a member of the issuer's expanded group and that person later becomes a member of the issuer's expanded group; (ii) a debt instrument is issued to an entity that is not taxable as a corporation for federal tax purposes (for example, a trust that is beneficially owned by an expanded group member); or (iii) a member of the issuer's expanded group is substituted as a new obligor or added as a co-obligor on an existing debt instrument. The anti-abuse rule also could apply to a debt instrument that is issued or transferred in connection with a reorganization or similar transaction with a principal purpose of avoiding the application of the proposed regulations. For a further illustration of this rule, see Example 18 in § 1.385-3(g)(3) of the proposed regulations.
Proposed § 1.385-3(b)(5) includes a rule to address a potential overlap between the general rule and the funding rule. This coordination rule provides that, to the extent all or a portion of a debt instrument issued in an asset reorganization is treated as stock under the third prong of the general rule (relating to a debt instrument issued for property in an asset reorganization), the distribution of the deemed stock to a shareholder in the asset reorganization is not also treated as a distribution or acquisition by the transferor corporation for purposes of the funding rule. This coordination rule addresses a specific potential overlap situation where a debt instrument is distributed to a shareholder pursuant to an asset reorganization and is characterized under the third prong of the general rule as an issuance of stock. When the issuance of the debt instrument is characterized under the general rule as an issuance of stock, the stock may be treated as non-qualified preferred stock for purposes of section 356. Nonqualified preferred stock received by a shareholder in a distribution is itself treated as “other property” for purposes of section 356. This overlap rule provides that, if the shareholder is deemed to receive nonqualified preferred stock in the asset reorganization, the distribution of the nonqualified preferred stock in the asset reorganization is not treated as a distribution or acquisition for purposes of the funding rule. For an illustration of this rule, see Example 8 in § 1.385-3(g)(3) of the proposed regulations.
Proposed § 1.385-3(c) provides three exceptions from the application of proposed § 1.385-3(b) for transactions that otherwise could result in a debt instrument being treated as stock.
As noted in Section B.2 of this Part IV, proposed § 1.385-3(c)(1) includes an exception pursuant to which distributions and acquisitions described in proposed § 1.385-3(b)(2) (the general rule) or proposed § 1.385-3(b)(3)(ii) (the funding rule) that do not exceed current year earnings and profits (as described in section 316(a)(2)) of the distributing or acquiring corporation are not treated as distributions or acquisitions for purposes of the general rule or the funding rule. For this purpose, distributions and acquisitions are attributed to current year earnings and profits in the order in which they occur.
A second exception provides that an expanded group debt instrument will not be treated as stock if, when the debt instrument is issued, the aggregate issue price of all expanded group debt instruments that otherwise would be treated as stock under the proposed regulations does not exceed $50 million (the threshold exception). If the expanded group's debt instruments that otherwise would be treated as stock later exceed $50 million, then all expanded group debt instruments that, but for the threshold exception, would have been treated as stock are treated as stock, rather than only the amount that exceeds $50 million. Thus, the threshold exception is not an exemption of the first $50 million of expanded group debt instruments that otherwise would be treated as stock under the proposed regulations, but rather is only intended to provide an exception from the application of proposed § 1.385-3 for taxpayers that have not exceeded the $50 million threshold. If the $50 million threshold subsequently is exceeded, the timing of the recharacterization of the relevant debt instrument as stock depends on when the debt instrument was issued. If the debt instrument ceases to qualify for the threshold exception after the taxable year of its issuance, the recharacterization is treated as occurring on the date that the threshold exception ceases to apply. If, on the other hand, the debt instrument ceases to qualify for the threshold exception during the same taxable year that the debt instrument is issued, the debt instrument is treated as stock as of the day that the debt instrument is issued. Once the $50 million threshold is exceeded, the threshold exception will not apply to any debt instrument issued by members of the expanded group for so long as any instrument that previously was treated as indebtedness solely because of the threshold exception remains outstanding, in order to prevent the $50 million limitation from refreshing after those instruments are treated as stock.
The threshold exception is applied after applying the exception for current year earnings and profits. For an illustration of the interaction of the threshold exception and the exception for current year earnings and profits, see Example 17 in § 1.385-3(g)(3) of the proposed regulations.
An acquisition of expanded group stock will not be treated as an acquisition described in the second prong of the funding rule if (i) the acquisition results from a transfer of property by a funded member (the transferor) to an issuer in exchange for stock of the issuer, and (ii) for the 36-month period following the issuance, the transferor holds, directly or indirectly, more than 50 percent of the total combined voting power of all classes of stock of the issuer entitled to vote and more than 50 percent of the total value of the stock of the issuer. For purposes of this exception, a transferor's indirect stock ownership is determined by applying the principles of section 958(a) without regard to whether an intermediate entity is foreign or domestic.
If the transferor ceases to meet the ownership requirement at any time during the 36-month period, the acquisition of expanded group stock will no longer qualify for the exception and will be treated as an acquisition described in the second prong of the funding rule. In this case, for purposes of applying the per se rule, the acquisition may be treated as having been funded by a debt instrument issued during the 72-month period determined with respect to the date of the acquisition (rather than the date that
The proposed regulations treat an issuer and a transferor as a successor and predecessor, respectively, for purposes of the funding rule to the extent of the value of the expanded group stock acquired from the issuer. However, for purposes of the per se rule, the issuer and transferor are only treated as successor and predecessor, respectively, with respect to a debt instrument issued by the transferor during the period beginning 36 months before the relevant issuance of expanded group stock and ending 36 months after such issuance. Proposed § 1.385-3(f)(11) further limits the effect of treating the issuer and transferor as successor and predecessor by providing that a distribution made by the issuer directly to the transferor is not treated as a distribution made by the transferor for purposes of applying the funding rule to a debt instrument of the transferor.
For an illustration of this exception, see Example 12 in § 1.385-3(g)(3) of the proposed regulations.
Proposed § 1.385-3(d) includes operating rules for determining when a debt instrument is treated as stock and for certain deemed exchanges required under the proposed regulations.
A debt instrument treated as stock under the general rule is treated as stock from the time when the debt instrument is issued. In addition, and in contrast to the funding rule, the treatment of a debt instrument as stock pursuant to the general rule may affect other aspects of the tax treatment of the transaction in which the debt instrument is issued. For example, a distribution of a debt instrument is treated as a distribution of stock for all federal tax purposes and, accordingly, is subject to section 305. Similarly, a debt instrument issued in exchange for expanded group stock is treated as an acquisition of expanded group stock in exchange for stock of the issuing corporation. Because stock of the issuing corporation is not treated as “property” within the meaning of section 317, such transactions would not, for example, be described in section 304(a)(1) or be subject to § 1.367(b)-10, both of which only apply to certain acquisitions of stock for property.
When the funding rule applies, a principal purpose debt instrument also is treated as stock from the time when the debt instrument is issued, but only to the extent it is issued in the same or a subsequent taxable year as the distribution or acquisition that the debt instrument is treated as funding. To the extent that a principal purpose debt instrument is issued in a taxable year preceding the taxable year in which the distribution or acquisition that it is treated as funding occurs, the debt instrument is respected as indebtedness until the date such distribution or acquisition occurs, at which time it is deemed to be exchanged (as described in Section D.2 of this Part IV) for stock. For these purposes, the relevant taxable year is the taxable year of the funded member. See Section C.3 of this Part IV for a discussion of the timing rule when the exception for funded acquisitions of subsidiary stock by issuance ceases to apply.
In contrast to transactions that are characterized under the general rule, when the funding rule applies, the tax treatment of the distribution or acquisition that the principal purpose debt instrument is treated as funding is never recharacterized under the proposed regulations. Accordingly, in the case of a section 301 distribution that triggers the application of the funding rule, section 301 will continue to apply to the distribution without regard to the fact that the debt instrument that is treated as funding the distribution is recharacterized as stock. Similarly, the application of section 304 to a funded acquisition of expanded group stock would not be affected by the fact that the debt instrument that is treated as funding the acquisition is recharacterized as stock under the funding rule.
For an additional timing rule addressing certain debt instruments issued on or after April 4, 2016 and before the date of publication in the
As described in Section D.1 of this Part IV, the funding rule can apply to treat a debt instrument as stock in a taxable year that is subsequent to the taxable year in which the debt instrument is issued. In addition, as described in Section C of this Part IV, when the $50 million threshold exception ceases to apply, all debt instruments of the expanded group issued in a prior taxable year that previously was treated as indebtedness because of the threshold exception is treated as stock on the date that the threshold exception ceases to apply. In those situations the deemed exchange rule described in Section B of Part II applies. This deemed exchange rule does not apply when a debt instrument that is treated as stock under proposed § 1.385-3 leaves the expanded group, as described in Section D.3 of this Part IV.
When a debt instrument that is treated as stock under proposed § 1.385-3 is transferred to a person that is not a member of the expanded group, or when the obligor with respect to such debt instrument ceases to be a member of the expanded group that includes the issuer, the interest ceases to be treated as stock. This is because proposed § 1.385-3 generally applies only to a debt instrument that is held by a member of an expanded group. For purposes of this rule, it should be noted that a debt instrument held by a partnership is considered held by its partners, as described in Section D.4 of this Part IV.
The proposed regulations provide that, immediately before a debt instrument that is treated as stock under proposed § 1.385-3 ceases to be held by a member of the expanded group, the expanded group issuer is deemed to issue a new debt instrument to the expanded group holder in exchange for the debt instrument that was treated as stock. The proposed regulations provide that this deemed issuance of the debt instrument is not itself subject to the general rule.
When a debt instrument treated as stock pursuant to the funding rule ceases to be treated as stock because it is no longer an expanded group debt instrument, all other debt instruments of the issuer that are not currently treated as stock are re-tested to determine whether other debt instruments are treated as funding the distribution or acquisition that previously was treated as funded by the debt instrument that ceases to be treated as stock pursuant to this rule. For an illustration of this rule, see Example 7 in § 1.385-3(g)(3) of the proposed regulations.
To prevent avoidance of these rules through the use of partnerships, proposed § 1.385-3(d)(5) takes an
If a debt instrument issued by a controlled partnership were to be recharacterized as equity in the controlled partnership, the resulting equity could give rise to guaranteed payments that may be deductible or gross income allocations to partners that would reduce the taxable income of the other partners that did not receive such allocations. Therefore, under the authority of section 7701(l) to recharacterize multiple-party financing transactions, proposed § 1.385-3(d)(5)(ii) provides that, when a debt instrument issued by a partnership is recharacterized, in whole or in part, under proposed § 1.385-3, the holder of the recharacterized debt instrument is treated as holding stock in the expanded group partner or partners rather than as holding a partnership interest in the controlled partnership. The partnership and its partners must make appropriate conforming adjustments to reflect the expanded group partner's treatment under the proposed regulations. Any such adjustments must be consistent with the purposes of these proposed regulations and must be made in a manner that avoids the creation of, or increase in, a disparity between the controlled partnership's aggregate basis in its assets and the aggregate bases of the partners' respective interests in the partnership. For an illustration of the rules applicable to controlled partnerships, see Examples 13, 14, and 15 in § 1.385-3(g)(3) of the proposed regulations.
Section 385(c)(1) provides that an issuer's characterization as of the time of issuance of an interest as debt or stock is binding on the issuer and on all holders of the interest. Section 385(c)(2) provides an exception to that rule if the holder discloses on its return that the holder is treating such interest in a manner that is inconsistent with such characterization. Section 385(c)(3) provides that the Secretary is authorized to require such information as the Secretary determines to be necessary to carry out the provisions of section 385(c). Under proposed § 1.385-3, a holder may be required to treat an interest as stock even though the issuer treated it as debt when it was issued. For example, a debt instrument may first be treated as a principal purpose debt instrument in a year that follows the year in which the debt instrument was issued. In that case, absent a regulatory provision to the contrary, the holder would be subject to the reporting requirement described in section 385(c)(2).
The Treasury Department and the IRS have determined that the characterization and reporting requirements in section 385(c) were not intended to apply when regulations under section 385 require an interest to be recharacterized after the issuer's initial characterization of that interest. Accordingly, the proposed regulations provide that section 385(c)(1) does not apply to a debt instrument to the extent that it is treated as stock under the proposed regulations.
Proposed § 1.385-3(d)(6) provides that a debt instrument issued by a disregarded entity that is treated as stock under proposed § 1.385-3 is treated as stock in the disregarded entity's owner rather than as an equity interest in the disregarded entity. Ordinarily, when a disregarded entity becomes an entity with more than one equity owner, the disregarded entity converts to a partnership.
Under proposed § 1.385-3(e), proposed §§ 1.385-3 and 1.385-4 do not apply to the extent a person enters into a transaction that otherwise would be subject to the proposed regulations with a principal purpose of reducing its federal tax liability or the federal tax liability of another person by disregarding the treatment of the debt instrument that would occur without regard to the proposed regulations.
As noted previously, the Treasury Department and the IRS have determined that a debt instrument between members of the same consolidated group does not raise the same federal tax concerns as a debt instrument between members of the same expanded (but not consolidated) group. Accordingly, proposed § 1.385-4 includes special rules, issued under the authority of section 1502, for applying § 1.385-3 to consolidated groups, including rules addressing the treatment of a debt instrument issued by one member of a consolidated group to another member of the same consolidated group (consolidated group debt instrument) and rules regarding the treatment of a debt instrument when it ceases to be a consolidated group debt instrument.
For purposes of proposed § 1.385-3, all members of a consolidated group are treated as one corporation. Accordingly, proposed § 1.385-3 does not apply to a consolidated group debt instrument. Thus, for example, the proposed regulations do not treat as stock a debt instrument that is issued by one member of a consolidated group to another member of the consolidated group in a distribution. The proposed regulations define a consolidated group
As a result of treating all members of a consolidated group as one corporation for purposes of applying proposed § 1.385-3, a debt instrument issued to or by one member of a consolidated group generally is treated as issued to or by all members of the same consolidated group. Thus, a debt instrument issued by one consolidated group member to a member of its expanded group that is not a member of its consolidated group may be treated under the funding rule as funding a distribution or acquisition by another member of that consolidated group, even though that other consolidated group member was not the issuer and thus was not funded directly. Similarly, a debt instrument issued by one consolidated group member to another consolidated group member is treated as stock under the general rule when the debt instrument is distributed by the holder to a member of the expanded group that is not a member of the same consolidated group, regardless of whether the issuer itself distributed the debt instrument. For an illustration of this rule, see Example 1 in proposed § 1.385-4(d)(3).
Proposed § 1.385-4 includes rules addressing debt held or issued by a consolidated group member that leaves a consolidated group, but continues to be a member of the expanded group (such corporation, a
Generally, any consolidated group debt instrument that is issued or held by the departing member and that is not treated as stock solely by reason of the rule treating all members of a consolidated group as one corporation (exempt consolidated group debt instrument) is deemed to be exchanged for stock immediately after the departing member leaves the group. Any consolidated group debt instrument issued or held by a departing member that is not an exempt consolidated group debt instrument (non-exempt consolidated group debt instrument) is treated as indebtedness unless and until the non-exempt consolidated group debt instrument is treated as a principal purpose debt instrument under proposed §§ 1.385-3(b)(3)(ii) and 1.385-3(d)(1) as a result of a distribution or acquisition described in proposed § 1.385-3(b)(3)(ii) that occurs after the departure. However, solely for purposes of applying the 72-month period under the per se funding rule, the debt instrument is treated as having been issued when it was first treated as a consolidated group debt instrument.
When a member of a consolidated group transfers a consolidated group debt instrument to an expanded group member that is not a member of the consolidated group, the debt instrument is treated as issued by the issuer of the debt instrument (which is treated as one corporation with the transferor of the debt instrument) to the transferee expanded group member on the date of the transfer. For purposes of proposed § 1.385-3, the consequences of the transfer are determined in a manner that is consistent with treating a consolidated group as one corporation. Thus, for example, the sale of a consolidated group debt instrument to an expanded group member that is not a member of the consolidated group is treated as an issuance of the debt instrument to the transferee expanded group member in exchange for property. To the extent the debt instrument is treated as stock upon being transferred, the debt instrument is deemed to be exchanged for stock immediately after the debt instrument is transferred outside of the consolidated group. For an illustration of this rule, see Examples 1 and 2 in § 1.385-4(d)(3) of the proposed regulations.
Sections 1.385-3 and 1.385-4 are proposed to apply to any debt instrument issued on or after April 4, 2016 and to any debt instrument issued before April 4, 2016 as a result of an entity classification election made under § 301.7701-3 that is filed on or after April 4, 2016. However, when §§ 1.385-3(b) and 1.385-3(d)(1)(i) through (d)(1)(v), or § 1.385-4 of the proposed regulations, otherwise would treat a debt instrument as stock prior to the date of publication in the
In addition, for purposes of determining whether a debt instrument is a principal purpose debt instrument described in proposed § 1.385-3(b)(3)(iv), a distribution or acquisition described in proposed § 1.385-3(b)(3)(ii) that occurs before April 4, 2016, other than a distribution or acquisition that is treated as occurring before April 4, 2016 as a result of an entity classification election made under § 301.7701-3 that is filed on or after April 4, 2016, is not taken into account.
IRS Revenue Procedures, Revenue Rulings notices, and other guidance cited in this document are published in the Internal Revenue Bulletin (or Cumulative Bulletin) and are available from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402, or by visiting the IRS Web site at
Executive Orders 13563 and 12866 direct agencies to assess costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has been designated a “significant regulatory action” under section 3(f) of Executive Order 12866 and designated as economically significant. Accordingly, the rule has been reviewed by the Office of Management and Budget. A regulatory assessment for this proposed rule is available in the docket for this rulemaking on
Pursuant to the Regulatory Flexibility Act (5 U.S.C. Chapter 6), it is hereby certified that the proposed regulations will not have a significant economic impact on a substantial number of small entities. Accordingly, an initial regulatory flexibility analysis is not required. The Commissioner and the courts historically have analyzed whether an interest in a corporation should be treated as stock or indebtedness for federal tax purposes by applying various sets of factors to the facts of a particular case. Proposed § 1.385-1 provides that in connection with determining whether an interest in a corporation should be treated as stock or indebtedness for federal tax purposes,
To facilitate the federal tax analysis of an interest in a corporation, taxpayers are required to substantiate their classification of an interest as stock or indebtedness for federal tax purposes. Proposed § 1.385-2 provides documentation requirements to substantiate the treatment of certain related-party instruments as indebtedness. First, these rules apply only to debt instruments in form issued within expanded groups of corporations and other entities. Second, proposed § 1.385-2 only applies to expanded groups if the stock of a member of the expanded group is publicly traded, or financial statements of the expanded group or its members show total assets exceeding $100 million or annual total revenue exceeding $50 million. Because the rules are limited to large expanded groups, they will not affect a substantial number of small entities.
Proposed § 1.385-3 provides rules that treat as stock certain interests in a corporation that are held by a member of the corporation's expanded group and that otherwise would be treated as indebtedness for federal tax purposes. Proposed § 1.385-4 provides rules regarding the application of proposed § 1.385-3 to members of a consolidated group. Proposed § 1.385-3 includes multiple exceptions that limit its application. In particular, the threshold exception provides that an expanded group debt instrument will not be treated as stock under proposed § 1.385-3 if, when the debt instrument is issued, the aggregate issue price of all expanded group debt instruments that otherwise would be treated as stock under proposed § 1.385-3 does not exceed $50 million. The threshold exception also governs the application of proposed § 1.385-3 rules to members of a consolidated group described in proposed § 1.385-4. Although it is possible that the classification rules in proposed §§ 1.385-3 and 1.385-4 could have an effect on small entities, the threshold exception makes it unlikely that a substantial number of small entities will be affected by proposed §§ 1.385-3 and 1.385-4. Pursuant to section 7805(f) of the Code, these regulations have been submitted to the Chief Counsel for Advocacy of the Small Business Administration for comment on their impact on small business.
Before the proposed regulations are adopted as final regulations, consideration will be given to any written (a signed original and eight copies) or electronic comments that are submitted timely to the IRS. The Treasury Department and the IRS request comments on all aspects of the proposed rules, including comments on the clarity of the proposed rules and how they can be made more administrable. In addition, comments are requested on: (1) Other instruments that should be subject to the proposed regulations, including other types of applicable instruments that are not indebtedness in form that should be subject to proposed § 1.385-2 and the documentation requirements that should apply to such applicable instruments; (2) whether special rules are warranted for cash pools, cash sweeps, and similar arrangements for managing cash of an expanded group; (3) the rule addressing deemed exchanges of an EGI and a debt instrument; (4) the application of these rules to any entity with respect to a year in which the entity is not a U.S. person (as defined in section 7701(a)(30)), is not required to file a U.S. tax return, and is not a CFC or a controlled foreign partnership, but in a later year becomes one of the foregoing; (5) whether certain indebtedness commonly used by investment partnerships, including indebtedness issued by certain “blocker” entities, implicate similar policy concerns as those motivating the proposed regulations, such that the scope of the proposed regulations should be broadened; (6) whether guidance is needed under section 909 to the extent a U.S. equity hybrid instrument arises solely by reason of the application of proposed § 1.385-3; and (7) the treatment of controlled partnerships in proposed § 1.385-3 and the collateral consequences of the recharacterization and any corresponding adjustments, including the treatment of a partner's proportionate share of partnership assets or debt instruments, of treating a debt instrument issued by a controlled partnership as stock in its expanded group partners, including a situation in which a recharacterization results in a partnership owning stock of an expanded group partner. Specifically, the Treasury Department and the IRS request comments on how to apply proposed § 1.385-3 when expanded group partners make distributions subject to the funding rule with respect to some, but not all, partnership debt instruments; when one or more, but not all, expanded group partners make a distribution subject to the funding rule with respect to part or all of their share of the partnership debt instrument; and how to address such distributions when a controlled partnership has one or more partners that are not expanded group members. The Treasury Department and the IRS also request comments on whether the objective rules in proposed § 1.385-3(d)(5) have the potential to be manipulated, including by selectively locating debt instruments in order to achieve results that are contrary to the purposes of these regulations, and, if so, whether the anti-abuse rule in proposed § 1.385-3(b)(4) or the rule prohibiting the affirmative use of these rules by taxpayers in proposed § 1.385-3(e) are sufficient to address these concerns.
More generally, the Treasury Department and the IRS request comments on whether additional guidance is necessary regarding the manner by which issuers and holders notify the Secretary of the intended federal tax treatment of an interest in a corporation.
The Treasury Department and the IRS are aware that the issuance of preferred equity by a controlled partnership to an expanded group member may give rise to similar concerns as debt instruments of a controlled partnership issued to an expanded group member, and that controlled partnerships may, in some cases, issue preferred equity with a principal purpose of avoiding the application of § 1.385-3 of the proposed regulations. The Treasury Department and the IRS are considering rules that would treat preferred equity in a controlled partnership as equity in the expanded group partners, based on the principles of the aggregate approach used in proposed § 1.385-3(d)(5). Comments are requested regarding the recharacterization of preferred equity in those circumstances. Until any such guidance is issued, the IRS intends to closely scrutinize, and may challenge when the regulations become effective, transactions in which a controlled partnership issues preferred equity to an expanded group member and, within the relevant 72-month period, one or more expanded group partners in the controlled partnership engage in a transaction described in § 1.385-3(b)(3)(ii) of the proposed regulations.
Finally, regarding the request for comments on whether guidance is needed under section 909 when a U.S. equity hybrid instrument arises solely by reason of the application of § 1.385-3: the application of proposed § 1.385-
The principal authors of these regulations are Eric D. Brauer of the Office of Associate Chief Counsel (Corporate) and Raymond J. Stahl of the Office of Associate Chief Counsel (International). However, other personnel from the Treasury Department and the IRS participated in their development.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is proposed to be amended as follows:
26 U.S.C. 7805 * * *
(a)
(b)
(1)
(2)
(3)
(A) Without regard to paragraphs (1) through (8) of section 1504(b);
(B) By substituting “directly or indirectly” for “directly” in section 1504(a)(1)(B)(i); and
(C) By substituting “or” for “and” in section 1504(a)(2)(A).
(ii)
(4)
(5)
(c)
(d)
(2)
(e)
(f)
(a)
(2)
(A) The stock of any member of the expanded group is traded on (or subject to the rules of) an established financial market within the meaning of § 1.1092(d)-1(b);
(B) On the date that an applicable instrument first becomes an EGI, total assets exceed $100 million on any applicable financial statement, or
(C) On the date that an applicable instrument first becomes an EGI, annual total revenue exceeds $50 million on any applicable financial statement.
(ii)
(3)
(4)
(i)
(B)
(ii)
(iii)
(iv)
(A) A financial statement required to be filed with the Securities and Exchange Commission (the Form 10-K or the Annual Report to Shareholders);
(B) A certified audited financial statement that is accompanied by the report of an independent certified public accountant (or in the case of a foreign entity, by the report of a similarly qualified independent professional) that is used for—
(
(
(
(C) A financial statement (other than a tax return) required to be provided to the Federal, state, or foreign government or any Federal, state, or foreign agency.
(b)
(ii)
(2)
(i)
(ii)
(iii)
(iv)
(B)
(v)
(A)-(B)
(3)
(ii)
(A) For documentation and information described in paragraphs (b)(2)(i) and (b)(2)(ii) of this section (relating to issuer's unconditional obligation to repay and establishment of holder's creditor's rights), the relevant date is the date on which a member of the expanded group becomes an issuer of a new or existing EGI, without regard to any subsequent deemed issuance of the EGI under § 1.1001-3. In the case of an applicable instrument that becomes an EGI subsequent to issuance, including an intercompany obligation, as defined in § 1.1502-13(g)(2)(ii), that ceases to be an intercompany obligation, the relevant date is the day on which the applicable instrument becomes an EGI.
(B) For documentation and information described in paragraph (b)(2)(iii) of this section (relating to reasonable expectation of issuer's repayment), the relevant dates are the dates on which a member of the expanded group becomes an issuer with respect to an EGI and any later date on which an issuance is deemed to occur under § 1.1001-3 and any subsequent relevant date that occurs under the special rules in paragraph (b)(3)(iii) of this section. In the case of an applicable instrument that becomes an EGI subsequent to issuance, the relevant date is the day on which the applicable instrument becomes an EGI and any relevant date after the date that the applicable instrument becomes an EGI.
(C) For documentation and information described in paragraph (b)(2)(iv)(A) of this section (relating to payments of principal and interest), each date on which a payment of interest or principal is due, taking into account all additional time permitted under the terms of the EGI before there is (or holder can declare) an event of default for nonpayment, is a relevant date.
(D) For documentation and information described in paragraph (b)(2)(iv)(B) of this section (relating to events of default and similar events), each date on which an event of default, acceleration event or similar event occurs under the terms of the EGI is a relevant date. For example, if the terms of the EGI require the issuer to maintain certain financial ratios, any date on which the issuer fails to maintain the specified financial ratio (and such failure results in an event of default under the terms of the EGI) is a relevant date.
(E) In the case of an applicable instrument that becomes an EGI subsequent to issuance, no date before the applicable instrument becomes an EGI is a relevant date.
(iii)
(A)
(B)
(4)
(c)
(2)
(ii)
(3)
(ii)
(4)
(ii)
(5)
(6)
(ii)
(d)
(e)
(f)
(a)
(b)
(2)
(i) In a distribution;
(ii) In exchange for expanded group stock, other than in an exempt exchange; or
(iii) In exchange for property in an asset reorganization, but only to the extent that, pursuant to the plan of reorganization, a shareholder that is a member of the issuer's expanded group immediately before the reorganization receives the debt instrument with respect to its stock in the transferor corporation.
(3)
(ii)
(A) A distribution of property by the funded member to a member of the funded member's expanded group, other than a distribution of stock pursuant to an asset reorganization that is permitted to be received without the recognition of gain or income under section 354(a)(1) or 355(a)(1) or, when section 356 applies, that is not treated as “other property” or money described in section 356;
(B) An acquisition of expanded group stock, other than in an exempt exchange, by the funded member from a member of the funded member's expanded group in exchange for property other than expanded group stock; or
(C) An acquisition of property by the funded member in an asset reorganization but only to the extent that, pursuant to the plan of reorganization, a shareholder that is a member of the funded member's expanded group immediately before the reorganization receives “other property” or money within the meaning of section 356 with respect to its stock in the transferor corporation.
(iii)
(iv)
(B)
(
(
(
(v)
(vi)
(4)
(5)
(c)
(2)
(3)
(d)
(i)
(ii)
(iii)
(iv)
(v)
(2)
(3)
(4)
(5)
(ii)
(6)
(e)
(f)
(1)
(2)
(3)
(4)
(5)
(i) Section 361(a) or (b) applies to the transferor of the expanded group stock and the stock is not transferred by issuance; or
(ii) Section 1032 or § 1.1032-2 applies to the transferor of the expanded group stock and the stock is distributed by the transferee pursuant to the plan of reorganization.
(6)
(7)
(8)
(9)
(ii)
(10)
(11)
(ii)
(g)
(i) FP is a foreign corporation that owns 100 percent of the stock of USS1, a domestic corporation, 100 percent of the stock of USS2, a domestic corporation, and 100 percent of the stock of FS, a foreign corporation;
(ii) USS1 owns 100 percent of the stock of DS, a domestic corporation, and CFC, which is a controlled foreign corporation within the meaning of section 957;
(iii) At the beginning of Year 1, FP is the common parent of an expanded group comprised solely of FP, USS1, USS2, FS, DS, and CFC (the FP expanded group);
(iv) The FP expanded group has more than $50 million of debt instruments described in paragraph (c)(2) of this section at all times;
(v) No issuer of a debt instrument has current year earnings and profits described in section 316(a)(2);
(vi) All notes are debt instruments described in paragraph (f)(3) of this section;
(vii) No notes are eligible for the ordinary course exception described in paragraph (b)(3)(iv)(B)(
(viii) Each entity has as its taxable year the calendar year;
(ix) PRS is a partnership for federal income tax purposes;
(x) No corporation is a member of a consolidated group, as defined in § 1.1502-1(h);
(xi) No domestic corporation is a United States real property holding corporation within the meaning of section 897(c)(2); and
(xii) Each note is issued with adequate stated interest (as defined in section 1274(c)(2)).
(2)
(3)
(ii)
(ii)
(B) Because USS1 Note is treated as stock for federal tax purposes when it is issued by USS1, pursuant to section § 1.367(b)-10(a)(3)(ii) (defining property for purposes of § 1.367(b)-10) there is no potential application of § 1.367(b)-10(a) to USS1's acquisition of the FP stock.
(C) Because paragraph (b)(2) of this section treats USS1 Note as stock for federal tax purposes when it is issued by USS1, USS1 Note is not treated as indebtedness for purposes of applying paragraph (b)(3) of this section.
(ii)
(B) Because USS1 Note is treated as stock for federal tax purposes when it is issued by USS1, USS1 Note is not treated as property for purposes of section 304(a) because it is not property within the meaning specified in
(C) Because USS1 Note is treated as stock for federal tax purposes when it is issued by USS1, USS1 Note is not treated as indebtedness for purposes of applying paragraph (b)(3) of this section.
(ii)
(ii)
(ii)
(B) Under paragraph (b)(3)(iv)(B)(
(ii)
(B) Under paragraph (d)(2) of this section, after USS1 Note A is deemed exchanged, USS1's other debt instruments that are not treated as stock as of Date D in Year 4 (USS1 Note B) are re-tested for purposes of paragraph (b)(3)(iv)(B) of this section to determine whether other USS1 debt instruments are treated as funding the $300x distribution by USS1 to FP on Date B in Year 2. USS1 Note B was issued by USS1 to FP within the 72-month period determined with respect to the $300x distribution. Under paragraph (b)(3)(iv)(B)(
(ii)
(B) Because DS2 Note is treated as stock when it is issued, section 355(a)(1) rather than section 356 may apply to FP on FP's receipt of DS2 Note. Alternatively, depending on the terms of DS2 Note and other factors, DS2 Note may be treated as non-qualified preferred stock that is not treated as stock pursuant to section 355(a)(3)(D). If DS2 Note is treated as non-qualified preferred stock, such stock would continue to be treated by FP as “other property” for purposes of section 356 under section 356(e). In that case, USS2's distribution of DS2 Note would be treated as “other property” described in section 356, and thus the distribution of DS2 note preliminarily would be described in paragraph (b)(3)(ii)(A) of this section. However, under paragraph (b)(5) of this section, because DS2 Note is treated as stock under paragraph (b)(2)(iii) of this section, USS2's distribution of DS2 Note to FP pursuant to the plan of reorganization is not also treated as a distribution or acquisition described in paragraph (b)(3)(ii) of this section that could cause USS2 Note to be a principal purpose debt instrument.
(C) USS2's distribution of $150x of actual DS2 stock is a distribution of stock pursuant to an asset reorganization that is permitted to be received by FP without recognition of gain under section 355(a)(1). Accordingly, USS2's distribution of the actual DS2 stock to FP is not a distribution of property by USS2 for purposes of paragraph (b)(3)(ii)(A) of this section.
(D) USS2's transfer of assets to DS2 in exchange for DS2 stock is not an acquisition described in paragraph (b)(3)(ii)(B) of this section because USS2's acquisition of DS2 stock is an exempt exchange. USS2's acquisition of DS2 stock is an exempt exchange described in paragraph (f)(5)(ii) of this section because USS2 and DS2 are both parties to a reorganization that is an asset reorganization, section 1032 applies to DS2, the transferor of the expanded group stock, and the DS2 stock is distributed by USS2, the transferee, pursuant to the plan of reorganization. Because USS2 has not made a distribution or acquisition that is treated as a distribution or acquisition for purposes of paragraph (b)(3)(ii) of this section, USS2 Note is not a principal purpose debt instrument.
(ii)
(B) Because the entire amount of USS2 Note is treated as funding DS2's $200x distribution to FP, under paragraph (b)(3)(iv)(B)(
(ii)
(B) USS2's exchange of assets for USS1 stock is not an acquisition described in paragraph (b)(3)(ii)(B) of this section because USS2's acquisition of USS1 stock is an exempt exchange. USS2's acquisition of USS1 stock is an exempt exchange described in paragraph (f)(5)(ii) of this section because USS1 and USS2 are both parties to a reorganization, section 1032 applies to USS1, the transferor of the expanded group stock, and the USS1 stock is distributed by USS2, the transferee, pursuant to the plan of reorganization.
(C) Because neither USS1 nor USS2 has made a distribution or acquisition described in paragraph (b)(3)(ii) of this section, USS2 Note is not a principal purpose debt instrument.
(ii)
(i)
(ii)
(B) CFC is a successor with respect to USS1 under paragraph (f)(11)(ii) of this section. For purposes of paragraph (b)(3)(iv)(B)(
(C) Under paragraph (f)(11)(ii) of this section, CFC's $20x cash distribution to USS1 on Date C in Year 2 is not taken into account for purposes of applying paragraph (b)(3) of this section to USS1 Note.
(D) On Date D in Year 3, CFC continues to be a successor to USS1 for purposes of applying the per se rule in paragraph (b)(3)(iv)(B) of this section. Accordingly, USS1 Note is a principal purpose debt instrument under paragraph (b)(3)(ii)(A) of this section that is deemed to be exchanged for stock on Date D in Year 3 under paragraph (d)(1)(ii) of this section. See § 1.385-1(c) for rules regarding the treatment of this deemed exchange.
(ii)
(B) Together CFC and FS own 100 percent of the interests in PRS capital and profits, such that PRS is a controlled partnership described in § 1.385-1(b)(1). Under paragraph (d)(5)(i) of this section, solely for purposes of this section, when X Corp issues X Note to PRS, proportionate shares of X Note are treated as issued to CFC and FS. Accordingly, for purposes of applying paragraph (b) of this section, in Year 1, 50 percent of X Note is treated as issued to CFC in a distribution and the other 50 percent of X Note is treated as issued to FS in a distribution. Therefore, under paragraphs (b)(2)(i) and (d)(1)(i) of this section, X Note is treated as stock beginning on Date A in Year 1. Under paragraph (d)(5)(i) of this section, CFC and FS are treated as holding X Note solely for purposes of this section. For all other federal tax purposes, X Note is treated as stock in X Corp that is held by PRS, and X Corp is treated as distributing its stock to its shareholder in a distribution that is subject to section 305.
(ii)
(B) Under paragraph (d)(5)(ii) of this section, CFC and FS are each treated as issuing $100x of stock to FP. Appropriate conforming adjustments must be made to CFC's and FS's interests in PRS to reflect the deemed treatment of PRS Note as stock issued by CFC and FS, which must be done in a manner that avoids the creation of, or increase in, a disparity between PRS's aggregate basis in its assets and the aggregate bases of CFC's and FS's respective interests in PRS. For example, reasonable and appropriate adjustments may occur when the following steps are deemed to occur on Date A in Year 1:
(
(
(
(
(ii)
(B) Under paragraph (d)(5)(ii) of this section, CFC and FS are each treated as issuing $100x of stock to FP. Appropriate conforming adjustments must be made to CFC's and FS's interests in PRS to reflect the deemed treatment of PRS Note as stock issued by CFC and FS, which must be done in a manner that avoids the creation of, or increase in, a disparity between PRS's aggregate basis in its assets and the aggregate bases of CFC's and FS's respective interests in PRS. For example, reasonable and appropriate adjustments may occur when the following steps are deemed to occur on Date C in Year 2:
(
(
(
(
(ii)
(ii)
(B) Because USS1 does not have earnings and profits described in section 316(a)(2) in Year 2, the exception in paragraph (c)(1) of this section does not apply to USS1 Note. Immediately after USS1 Note is issued to FP on Date B in Year 2, the aggregate adjusted issue price of outstanding debt instruments issued by members of the FP expanded group that would be subject to paragraph (b) of this section but for the application of paragraph (c)(2) of this section exceeds $50 million. Under paragraph (d)(1)(iii) of this section, CFC Note is deemed to be exchanged for stock on Date B in Year 2, when debt instruments of the FP expanded group cease to qualify for the threshold exception described in paragraph (c)(2) of this section. In addition, the threshold exception described in paragraph (c)(2) of this section does not apply to USS1 Note because, immediately after USS1 Note is issued, the aggregate adjusted issue price of outstanding debt instruments issued by members of the expanded group that would be subject to paragraph (b) of this section but for the application paragraph (c)(2) of this section exceeds $50 million. Accordingly, USS1 Note is treated as stock when it is issued on Date B in Year 2.
(C) Under paragraph (c)(1) of this section, for purposes of applying paragraphs (b)(2) and (b)(3) of this section to a member of an expanded group with respect to Year 3, the aggregate amount of any distributions or acquisitions by FS that are described in paragraphs (b)(2) or (b)(3)(ii) of this section are reduced by an amount equal to FS's current year earnings and profits described in section 316(a)(2) for Year 3, which is $35 million. Thus, $35 million of distributions or acquisitions by FS in Year 3 are not taken into account for purposes of applying paragraphs (b)(2) and (b)(3) of this section. The reduction is applied first against FS's $30 million cash distribution on Date C in Year 3 and second against FS's $19 million note distribution on Date E in Year 3. Accordingly, under paragraph (c)(1) of this section, FS Note A is not treated as stock under paragraph (b)(3) of this section. In addition, under paragraph (c)(1) of this section a portion of FS Note B equal to $5 million is not treated as stock under paragraph (b)(2) of this section.
(D) When FS Note B is issued in Year 3, CFC Note, which previously was treated as indebtedness solely because of paragraph (c)(2) of this section, remains outstanding. Accordingly, the threshold exception described in paragraph (c)(2) of this section does not apply to FS Note B. Accordingly, the remaining amount of FS Note B equal to $14 million after applying the exception under paragraph (c)(1) of this section is treated as stock under paragraph (b)(2) of this section.
(ii)
(h)
(2)
(3)
(a)
(b)
(i)
(ii)
(B)
(2)
(c)
(d)
(i) FP is a foreign corporation that owns 100 percent of the stock of USS1, a domestic corporation, and 100 percent of the stock of FS, a foreign corporation;
(ii) USS1 owns 100 percent of the stock of DS1, a domestic corporation;
(iii) DS1 owns 100 percent of the stock of DS2, a domestic corporation;
(iv) At the beginning of Year 1, FP is the common parent of an expanded group comprised solely of FP, USS1, FS, DS1, and DS2 (the FP expanded group);
(v) USS1, DS1, and DS2 are members of a consolidated group of which USS1 is the common parent (the USS1 consolidated group);
(vi) The FP expanded group has more than $50 million of debt instruments described in § 1.385-3(c)(2) at all times;
(vii) No issuer of a debt instrument has current year earnings and profits described in section 316(a)(2);
(viii) All notes are debt instruments described in § 1.385-3(f)(3) and therefore have satisfied any requirements under § 1.385-2, if applicable, and are respected as debt instruments under general federal tax principles;
(ix) No notes are eligible for the ordinary course exception described in § 1.385-3(b)(3)(iv)(B)(
(x) Each entity has as its taxable year the calendar year;
(xi) No domestic corporation is a United States real property holding corporation within the meaning of section 897(c)(2); and
(xii) Each note is issued with adequate stated interest (as defined in section 1274(c)(2)).
(2)
(3)
(ii)
(ii)
(ii)
(B) DS1 Note B is a non-exempt consolidated group debt instrument because DS1 Note B, which is issued in exchange for cash, would not be treated as stock even absent the application of § 1.385-1(e) because there have been no transactions described in § 1.385-3(b)(3)(ii) that would have been treated as funded by DS1 Note B in the absence of the application of § 1.385-1(e). Accordingly, under paragraph (b)(1)(ii)(A) of this section, DS1 Note B is not treated as stock when DS1 ceases to be a member of the USS1 consolidated group, provided there are no distributions or acquisitions described in § 1.385-3(b)(3)(ii) by DS1 that occur later in Year 4 (after Date C).
(ii)
(ii)
(e)
(2)
(3)
Employee Benefits Security Administration, Department of Labor
Final rule.
This document contains a final regulation defining who is a “fiduciary” of an employee benefit plan under the Employee Retirement Income Security Act of 1974 (ERISA or the Act) as a result of giving investment advice to a plan or its participants or beneficiaries. The final rule also applies to the definition of a “fiduciary” of a plan (including an individual retirement account (IRA)) under the Internal Revenue Code of 1986 (Code). The final rule treats persons who provide investment advice or recommendations for a fee or other compensation with respect to assets of a plan or IRA as fiduciaries in a wider array of advice relationships.
For Questions Regarding the Final Rule: Contact Luisa Grillo-Chope, Office of Regulations and Interpretations, Employee Benefits Security Administration (EBSA), (202) 693-8825. (Not a toll-free number). For Questions Regarding the Final Prohibited Transaction Exemptions: Contact Karen Lloyd, Office of Exemption Determinations, EBSA, 202-693-8824. (Not a toll free number). For Questions Regarding the Regulatory Impact Analysis: Contact G. Christopher Cosby, Office of Policy and Research, EBSA, 202-693-8425. (Not a toll-free number).
Under ERISA and the Code, a person is a fiduciary to a plan or IRA to the extent that the person engages in specified plan activities, including rendering “investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan . . . [.]” ERISA safeguards plan participants by imposing trust law standards of care and undivided loyalty on plan fiduciaries, and by holding fiduciaries accountable when they breach those obligations. In addition, fiduciaries to plans and IRAs are not permitted to engage in “prohibited transactions,” which pose special dangers to the security of retirement, health, and other benefit plans because of fiduciaries' conflicts of interest with respect to the transactions. Under this regulatory structure, fiduciary status and responsibilities are central to protecting the public interest in the integrity of retirement and other important benefits, many of which are tax-favored.
In 1975, the Department issued regulations that significantly narrowed the breadth of the statutory definition of fiduciary investment advice by creating a five-part test that must, in each instance, be satisfied before a person can be treated as a fiduciary adviser. This regulatory definition applies to both ERISA and the Code. The Department created the five-part test in a very different context and investment advice marketplace. The 1975 regulation was adopted prior to the existence of participant-directed 401(k) plans, the widespread use of IRAs, and the now commonplace rollover of plan assets from ERISA-protected plans to IRAs. Today, as a result of the five-part test, many investment professionals, consultants, and advisers
The Department has also sought to preserve beneficial business models for delivery of investment advice by separately publishing new exemptions from ERISA's prohibited transaction rules that would broadly permit firms to continue to receive many common types of fees, as long as they are willing to adhere to applicable standards aimed at ensuring that their advice is impartial and in the best interest of their customers. Rather than create a highly prescriptive set of transaction-specific exemptions, the Department instead is publishing exemptions that flexibly accommodate a wide range of current types of compensation practices, while minimizing the harmful impact of conflicts of interest on the quality of advice.
In particular, the Department is publishing a new exemption (the “Best Interest Contract Exemption”) that would provide conditional relief for common compensation, such as commissions and revenue sharing, that an adviser and the adviser's employing firm might receive in connection with
In order to protect the interests of the plan participants and beneficiaries, IRA owners, and plan fiduciaries, the exemption requires the Financial Institution to acknowledge fiduciary status for itself and its Advisers. The Financial Institutions and Advisers must adhere to basic standards of impartial conduct. In particular, under this standards-based approach, the Adviser and Financial Institution must give prudent advice that is in the customer's best interest, avoid misleading statements, and receive no more than reasonable compensation. Additionally, Financial Institutions generally must adopt policies and procedures reasonably designed to mitigate any harmful impact of conflicts of interest, and disclose basic information about their conflicts of interest and the cost of their advice. Level Fee Fiduciaries that receive only a level fee in connection with advisory or investment management services are subject to more streamlined conditions, including a written statement of fiduciary status, compliance with the standards of impartial conduct, and, as applicable, documentation of the specific reason or reasons for the recommendation of the Level Fee arrangements.
If advice is provided to an IRA investor or a non-ERISA plan, the Financial Institution must set forth the standards of fiduciary conduct and fair dealing in an enforceable contract with the investor. The contract creates a mechanism for IRA investors to enforce their rights and ensures that they will have a remedy for advice that does not honor their best interest. In this way, the contract gives both the individual adviser and the financial institution a powerful incentive to ensure advice is provided in accordance with fiduciary norms, or risk litigation, including class litigation, and liability and associated reputational risk.
This principles-based approach aligns the adviser's interests with those of the plan participant or IRA owner, while leaving the individual adviser and employing firm with the flexibility and discretion necessary to determine how best to satisfy these basic standards in light of the unique attributes of their business. The Department is similarly publishing amendments to existing exemptions for a wide range of fiduciary advisers to ensure adherence to these basic standards of fiduciary conduct. In addition, the Department is publishing a new exemption for “principal transactions” in which advisers sell certain investments to plans and IRAs out of their own inventory, as well as an amendment to an existing exemption that would permit advisers to receive compensation for extending credit to plans or IRAs to avoid failed securities transactions.
This broad regulatory package aims to require advisers and their firms to give advice that is in the best interest of their customers, without prohibiting common compensation arrangements by allowing such arrangements under conditions designed to ensure the adviser is acting in accordance with fiduciary norms and basic standards of fair dealing. The new exemptions and amendments to existing exemptions are published elsewhere in today's edition of the
Some comments urged the Department to publish yet another proposal before moving to publish a final rule. As noted elsewhere, the proposal published in the
To the extent the public comments were based on concerns about compliance and interpretive issues arising after publication of the final rule, the Department fully intends to support advisers, plan sponsors and fiduciaries, and other affected parties with extensive compliance assistance activities. The Department routinely provides such assistance following its issuance of highly technical or significant guidance. For example, the Department's compliance assistance Web page, at
After careful consideration of the issues raised by the written comments and hearing testimony and the extensive public record, the Department is adopting the final rule contained herein.
Specifically, paragraph (a)(1) of the final rule provides that person(s) render investment advice if they provide for a fee or other compensation, direct or indirect, certain categories or types of advice. The listed types of advice are—
• A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred, or distributed from the plan or IRA.
• A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, selection of investment account arrangements (
Paragraph (a)(2) establishes the types of relationships that must exist for such recommendations to give rise to fiduciary investment advice responsibilities. The rule covers: Recommendations by person(s) who represent or acknowledge that they are acting as a fiduciary within the meaning of the Act or the Code; advice rendered pursuant to a written or verbal agreement, arrangement, or understanding that the advice is based on the particular investment needs of the advice recipient; and recommendations directed to a specific advice recipient or recipients regarding the advisability of a particular investment or management decision with respect to securities or other investment property of the plan or IRA.
Paragraph (b)(1) describes when a communication, based on its context, content, and presentation, would be viewed as a “recommendation,” a fundamental element in establishing the existence of fiduciary investment advice. Paragraph (b)(1) provides that “recommendation” means a communication that, based on its content, context, and presentation, would reasonably be viewed as a suggestion that the advice recipient engage in or refrain from taking a particular course of action. The determination of whether a “recommendation” has been made is an objective rather than subjective inquiry. In addition, the more individually tailored the communication is to a specific advice recipient or recipients about, for example, a security, investment property, or investment strategy, the more likely the communication will be viewed as a recommendation. Providing a selective list of securities as appropriate for an advice recipient would be a recommendation as to the advisability of acquiring securities even if no recommendation is made with respect to any one security. Furthermore, a series of actions, directly or indirectly (
Paragraph (b)(2) sets forth non-exhaustive examples of certain types of communications which generally are not “recommendations” under that definition and, therefore, are not fiduciary communications. Although the proposal classified these examples as “carve-outs” from the scope of the fiduciary definition, they are better understood as specific examples of communications that are non-fiduciary because they fall short of constituting “recommendations.” The paragraph describes general communications and commentaries on investment products such as financial newsletters, which, with certain modifications, were identified as carve-outs under paragraph (b) of the 2015 Proposal, certain activities and communications in connection with marketing or making available a platform of investment alternatives that a plan fiduciary could choose from, and the provision of information and materials that constitute investment education or retirement education. With respect to investment education in particular, the final rule expressly describes in detail four broad categories of non-fiduciary educational information and materials, including (A) plan information, (B) general financial, investment, and retirement information, (C) asset allocation models, and (D) interactive investment materials. Additionally, in response to comments on the proposal, the final rule allows educational asset allocation models and interactive investment materials provided to participants and beneficiaries in plans to reference specific investment alternatives under conditions designed to ensure the communications are presented as hypothetical examples that help participants and beneficiaries understand the educational information and not as investment recommendations. The rule does not, however, create such a broad safe harbor from fiduciary status for such “hypothetical” examples in the IRA context for reasons described below.
Paragraph (c) describes and clarifies conduct and activities that the Department determined should not be considered investment advice activity, even if the communications meet the regulation's definition of “recommendation” and satisfy the criteria established by paragraph (a). As noted in the proposal, the regulation's general definition of investment advice, like the statute, sweeps broadly, avoiding the weaknesses of the 1975 regulation. At the same time, however, as the Department acknowledged in the proposal, the broad test could sweep in some relationships that are not appropriately regarded as fiduciary in nature and that the Department does not believe Congress intended to cover as fiduciary relationships. Thus, included in paragraph (c) is a revised version of the “counterparty” carve-out from the proposal that excludes from fiduciary investment advice communications in arm's length transactions with certain plan fiduciaries who are licensed financial professionals (broker-dealers, registered investment advisers, banks, insurance companies, etc.) or plan fiduciaries who have at least $50 million under management. Other exclusions in the final rule include a revised version of the swap transaction carve-out in the proposal, and an expanded version of the carve-out in the proposal for plan sponsor employees.
Because the proposal referred to all of the instances of non-fiduciary communications set forth in (b)(2) and
Except for minor clarifying changes, paragraph (d)'s description of the scope of the investment advice fiduciary duty, and paragraph (e) regarding the mere execution of a securities transaction at the direction of a plan or IRA owner, remained mostly unchanged from the 1975 regulation. Paragraph (f) also remains unchanged from the two prior proposals and articulates the application of the final rule to the parallel definitions in the prohibited transaction provisions of Code section 4975. Paragraph (g) includes definitions. Paragraph (h) describes the effective and applicability dates associated with the final rule, and paragraph (i) includes an express provision acknowledging the savings clause in ERISA section 514(b)(2)(A) for state insurance, banking, or securities laws.
In the Department's view, this structure is faithful to the remedial purpose of the statute, but avoids burdening activities that do not implicate relationships of trust.
As noted elsewhere, in addition to the final rule in this Notice, the Department is simultaneously publishing a new Best Interest Contract Exemption and a new Exemption for Principal Transactions, and revising other exemptions from the prohibited transaction rules of ERISA and the Code.
Tax-preferred retirement savings, in the form of private-sector, employer-sponsored retirement plans, such as 401(k) plans, and IRAs, are critical to the retirement security of most U.S. workers. Investment professionals play an important role in guiding their investment decisions. However, these professional advisers often are compensated in ways that create conflicts of interest, which can bias the investment advice that some render and erode plan and IRA investment results.
Since the Department issued its 1975 rule, the retirement savings market has changed profoundly. Individuals, rather than large employers, are increasingly responsible for their investment decisions as IRAs and 401(k)-type defined contribution plans have supplanted defined benefit pensions as the primary means of providing retirement security. Financial products are increasingly varied and complex. Retail investors now confront myriad choices of how and where to invest, many of which did not exist or were uncommon in 1975. These include, for example, market-tracking, passively managed and so-called “target-date” mutual funds; exchange traded funds (ETFs) (which may be leveraged to multiply market exposure); hedge funds; private equity funds; real estate investment trusts (both traded and non-traded); various structured debt instruments; insurance products that offer menus of direct or formulaic market exposures and guarantees from which consumers can choose; and an extensive array of derivatives and other alternative investments. These choices vary widely with respect to return potential, risk characteristics, liquidity, degree of diversification, contractual guarantees and/or restrictions, degree of transparency, regulatory oversight, and available consumer protections. Many of these products are marketed directly to retail investors via email, Web site pop-ups, mail, and telephone. All of this creates the opportunity for retail investors to construct and pursue financial strategies closely tailored to their unique circumstances—but also sows confusion and increases the potential for very costly mistakes.
Plan participants and IRA owners often lack investment expertise and must rely on experts—but are unable to assess the quality of the expert's advice or guard against conflicts of interest. Most have no idea how advisers are compensated for selling them products. Many are bewildered by complex choices that require substantial financial expertise and welcome advice that appears to be free, without knowing that the adviser is compensated through indirect third-party payments creating conflicts of interest or that opaque fees over the life of the investment will reduce their returns. The consequences are growing as baby boomers retire and move money from plans, where their employer has both the incentive and the fiduciary duty to facilitate sound investment choices, to IRAs, where both good and bad investment choices are more numerous and much advice is conflicted. These rollovers are expected to approach $2.4 trillion cumulatively from 2016 through 2020.
In the retail IRA marketplace, growing consumer demand for personalized advice, together with competition from online discount brokerage firms, has pushed brokers to offer more comprehensive guidance services rather than just transaction support. Unfortunately, their traditional compensation sources—such as brokerage commissions, revenue shared by mutual funds and funds' asset managers, and mark-ups on bonds sold from their own inventory—can introduce acute conflicts of interest. What is presented to an IRA owner as trusted advice is often paid for by a financial product vendor in the form of a sales commission or shelf-space fee, without adequate counter-balancing consumer protections to ensure that the advice is in the investor's best interest.
As part of the 2015 Proposal, the Department conducted an in-depth economic assessment of current market conditions and the likely effects of reform and conducted and published a detailed regulatory impact analysis, U.S. Department of Labor, Fiduciary Investment Advice Regulatory Impact Analysis, (Apr. 2015), pursuant to Executive Order 12866 and other applicable authorities. That analysis examined a broad range of evidence, including public comments on the 2010 Proposal; a growing body of empirical, peer-reviewed, academic research into the effect of conflicts of interest in advisory relationships; a recent study conducted by the Council of Economic Advisers, The Effects of Conflicted Investment Advice on Retirement Savings (Feb. 2015), at
The Department's regulatory impact analysis of its final rulemaking finds that conflicted advice is widespread, causing serious harm to plan and IRA investors, and that disclosing conflicts alone would fail to adequately mitigate the conflicts or remedy the harm. By extending fiduciary status to more advice and providing flexible and protective PTEs that apply to a broad array of compensation arrangements, the final rule and exemptions will mitigate conflicts, support consumer choice, and deliver substantial gains for retirement investors and economic benefits that more than justify its costs.
Advisers' conflicts of interest take a variety of forms and can bias their advice in a variety of ways. For example, advisers and their affiliates often profit more when investors select some mutual funds or insurance products rather than others, or engage in larger or more frequent transactions. Advisers can capture varying price spreads from principal transactions and product providers reap different amounts of revenue from the sale of different proprietary products. Adviser compensation arrangements, which often are calibrated to align their interests with those of their affiliates and product suppliers, often introduce serious conflicts of interest between advisers and retirement investors. Advisers often are paid substantially more if they recommend investments and transactions that are highly profitable to the financial industry, even if they are not in investors' best interests. These financial incentives sometimes bias the advisers' recommendations. Many advisers do not provide biased advice, but the harm to investors from those that do can be large in many instances and is large on aggregate.
Following such biased advice can inflict losses on investors in several ways. They may choose more expensive and/or poorer performing investments. They may trade too much and thereby incur excessive transaction costs. They may chase returns and incur more costly timing errors, which are a common consequence of chasing returns.
A wide body of economic evidence supports the Department's finding that the impact of these conflicts of interest on retirement investment outcomes is large and negative. The supporting evidence includes, among other things, statistical comparisons of investment performance in more and less conflicted investment channels, experimental and audit studies, government reports documenting abuse, and economic theory on the dangers posed by conflicts of interest and by the asymmetries of information and expertise that characterize interactions between ordinary retirement investors and conflicted advisers. In addition, the Department conducted its own analysis of mutual fund performance across investment channels and within variable annuity sub-accounts, producing results broadly consistent with the academic literature.
A careful review of the evidence, which consistently points to a substantial failure of the market for retirement advice, suggests that IRA holders receiving conflicted investment advice can expect their investments to underperform by an average of 50 to 100 basis points per year over the next 20 years. The underperformance associated with conflicts of interest—in the mutual funds segment alone—could cost IRA investors between $95 billion and $189 billion over the next 10 years and between $202 billion and $404 billion over the next 20 years.
While these expected losses are large, they represent only a portion of what retirement investors stand to lose as a result of adviser conflicts. The losses quantified immediately above pertain only to IRA investors' mutual fund investments, and with respect to these investments, reflect only one of multiple types of losses that conflicted advice produces. The estimate does not reflect expected losses from so-called timing errors, wherein investors invest and divest at inopportune times and underperform pure buy-and-hold strategies. Such errors can be especially costly. Good advice can help investors avoid such errors, for example, by reducing panic-selling during large and abrupt downturns. But conflicted advisers often profit when investors choose actively managed funds whose deviation from market results (
The quantified losses also omit losses that adviser conflicts produce in connection with IRA investments other than mutual funds. Many other products, including various annuity products, among others, involve similar or larger adviser conflicts, and these conflicts are often equally or more opaque. Many of these same products exhibit similar or greater degrees of complexity, magnifying both investors' need for good advice and their vulnerability to biased advice. As with mutual funds, advisers may steer investors to products that are inferior to, or costlier than, similar available products, or to excessively complex or costly product types when simpler, more affordable product types would be appropriate. Finally, the quantified losses reflect only those suffered by retail IRA investors and not those incurred by plan investors, when there is evidence that the latter suffer losses as well. Data limitations impede quantification of all of these losses, but there is ample qualitative and in some cases empirical evidence that they occur and are large both in instance and on aggregate.
Disclosure alone has proven ineffective to mitigate conflicts in advice. Extensive research has demonstrated that most investors have little understanding of their advisers' conflicts of interest, and little awareness of what they are paying via indirect channels for the conflicted advice. Even if they understand the scope of the advisers' conflicts, many consumers are not financial experts and therefore, cannot distinguish good advice or
This final rule and exemptions aim to ensure that advice is in consumers' best interest, thereby rooting out excessive fees and substandard performance otherwise attributable to advisers' conflicts, producing gains for retirement investors. Delivering these gains will entail some compliance costs,—mostly, the cost incurred by new fiduciary advisers to avoid prohibited transactions and/or satisfy relevant PTE conditions—but the Department has attempted to minimize compliance costs while maintaining an enforceable best interest standard.
The Department expects compliance with the final rule and exemptions to deliver large gains for retirement investors by reducing, over time, the losses identified above. Because of data limitations, as with the losses themselves, only a portion of the expected gains are quantified in this analysis. The Department's quantitative estimate of investor gains from the final rule and exemptions takes into account only one type of adviser conflict: the conflict that arises from variation in the share of front-end loads that advisers receive when selling different mutual funds that charge such loads to IRA investors. Published research provides evidence that this conflict erodes investors' returns. The Department estimates that the final rule and exemptions, by mitigating this particular type of adviser conflict, will produce gains to IRA investors worth between $33 billion and $36 billion over 10 years and between $66 and $76 billion over 20 years.
These quantified potential gains do not include additional potentially large, expected gains to IRA investors resulting from reducing or eliminating the effects of conflicts in IRA advice on financial products other than front-end-load mutual funds or the effect of conflicts on advice to plan investors on any financial products. Moreover, in addition to mitigating adviser conflicts, the final rule and exemptions raise adviser conduct standards, potentially yielding additional gains for both IRA and plan investors. The total gains to retirement investors thus are likely to be substantially larger than these particular, quantified gains alone.
The final exemptions include strong protections calibrated to ensure that adviser conflicts are fully mitigated such that advice is impartial. If, however, advisers' impartiality is sometimes compromised, gains to retirement investors consequently will be reduced correspondingly.
The Department estimates that the cost to comply with the final rule and exemptions will be between $10.0 billion and $31.5 billion over 10 years with a primary estimate of $16.1 billion, mostly reflecting the cost incurred by affected fiduciary advisers to satisfy relevant consumer-protective PTE conditions. Costs generally are estimated to be front-loaded, reflecting a substantial amount of one-time, start-up costs. The Department's primary 10-year cost estimate of $16.1 billion reflects the present value of $5.0 billion in first-year costs and $1.5 billion in subsequent annual costs. These estimates account for start-up costs in the first year following the final regulation's and exemptions' initial applicability. The Department understands that in practice some portion of these start-up costs may be incurred in advance of or after that year. These cost estimates may be overstated insofar as they generally do not take into account potential cost savings from technological innovations and market adjustments that favor lower-cost models. They may be understated insofar as they do not account for frictions that may be associated with such innovations and adjustments.
Just as with IRAs, there is evidence that conflicts of interest in the investment advice market also erode the retirement savings of plan participants and beneficiaries. For example, the U.S. Government Accountability Office (GAO) found that defined benefit pension plans using consultants with undisclosed conflicts of interest earned 1.3 percentage points per year less than other plans. Other GAO reports have found that adviser conflicts may cause plan participants to roll plan assets into IRAs that charge high fees or 401(k) plan officials to include expensive or underperforming funds in investment menus. A number of academic studies find that 401(k) plan investment options underperform the market, and at least one study attributes such underperformance to excessive reliance on funds that are proprietary to plan service providers who may be providing investment advice to plan officials that choose the investment options.
The final rule and exemptions' positive effects are expected to extend well beyond improved investment results for retirement investors. The IRA and plan markets for fiduciary advice and other services may become more efficient as a result of more transparent pricing and greater certainty about the fiduciary status of advisers and about the impartiality of their advice. There may be benefits from the increased flexibility that the final rule and related exemptions will provide with respect to fiduciary investment advice currently falling within the ambit of the 1975 regulation. The final rule's defined boundaries between fiduciary advice, education, and sales activity directed at independent fiduciaries with financial expertise may bring greater clarity to the IRA and plan services markets. Innovation in new advice business models, including technology-driven models, may be accelerated, and nudged away from conflicts and toward transparency, thereby promoting healthy competition in the fiduciary advice market.
A major expected positive effect of the final rule and exemptions in the plan advice market is improved compliance and the associated improved security of ERISA plan assets and benefits. Clarity about advisers' fiduciary status will strengthen the Department's ability to quickly and fully correct ERISA violations, while strengthening deterrence.
A large part of retirement investors' gains from the final rule and exemptions represents improvements in overall social welfare, as some resources heretofore consumed inefficiently in the provision of financial products and services are freed for more valuable uses. The remainder of the projected gains reflects transfers of existing economic surplus to retirement investors, primarily from the financial industry. Both the social welfare gains and the distributional effects can promote retirement security, and the distributional effects more fairly allocate a larger portion of the returns on retirement investors' capital to the investors themselves. Because quantified and additional unquantified investor gains from the final rule and exemptions comprise both welfare gains and transfers, they cannot be netted against estimated compliance costs to produce an estimate of net social welfare gains. Rather, in this case, the Department concludes that the final rule and exemptions' positive social welfare and distributional effects together justify their cost.
A number of comments on the Department's 2015 Proposal, including those from consumer advocates, some independent researchers, and some independent financial advisers, largely endorsed its accompanying impact analysis, affirming that adviser conflicts cause avoidable harm and that the
Many comments anticipating sharp increases in the cost of advice neglected the costs currently attributable to conflicted advice including, for example, indirect fees. Many exaggerated the negative impacts (and neglected the positive impacts) of recent overseas reforms and/or the similarity of such reforms to the 2015 Proposal. Many implicitly and without support assumed rigidity in existing business models, service levels, compensation structures, and/or pricing levels, neglecting the demonstrated existence of low-cost solutions and potential for investor-friendly market adjustments. Many that predicted that only wealthier investors would be served appeared to neglect the possibility that once the fixed costs of serving wealthier investors was defrayed, only the relatively small marginal cost of serving smaller investors would remain for affected firms to bear in order to serve these consumers.
The Department expects that, subject to some short-term frictions as markets adjust, investment advice will continue to be readily available when the final rule and exemptions are applicable, owing to both flexibilities built into the final rule and exemptions and to the conditions and dynamics currently evident in relevant markets, Moreover, recent experience in the United Kingdom suggests that potential gaps in markets for financial advice are driven mostly by factors independent of reforms to mitigate adviser conflicts. Commenters' conclusions that stem from an assumption that advice will be unavailable therefore are of limited relevance to this analysis. Nonetheless, the Department notes that these commenters' claims about the consequences of the rule would still be overstated even if the availability of advice were to decrease. Many commenters arguing that costlier advice will compromise saving exaggerated their case by presenting mere correlation (wealth and advisory services are found together) as evidence that advice causes large increases in saving. Some wrongly implied that earlier Department estimates of the potential for fiduciary advice to reduce retirement investment errors—when accompanied by very strong anti-conflict consumer protections—constituted an acknowledgement that conflicted advice yields large net benefits.
The negative comments that offered their own original analysis, and whose conclusions contradicted the Department's, also are generally unpersuasive on balance in the context of this present analysis. For example, these comments collectively neglected important factors such as indirect fees, made comparisons without adjusting for risk, relied on data that are likely to be unrepresentative, failed to distinguish conflicted from independent advice, and/or presented as evidence median results when the problems targeted by the 2015 Proposal and the proposal's expected benefits are likely to be concentrated on one side of the distribution's median.
In light of the Department's analysis, its careful consideration of the comments, and responsive revisions made to the 2015 Proposal, the Department stands by its analysis and conclusions that adviser conflicts are inflicting large, avoidable losses on retirement investors, that appropriate, strong reforms are necessary, and that compliance with this final rule and exemptions can be expected to deliver large net gains to retirement investors. The Department does not anticipate the substantial, long-term unintended consequences predicted in the negative comments.
In conclusion, the Department's analysis indicates that the final rule and exemptions will mitigate adviser conflicts and thereby improve plan and IRA investment results, while avoiding greater than necessary disruption of existing business practices. The final rule and exemptions will deliver large gains to retirement investors, reflecting a combination of improvements in economic efficiency and worthwhile transfers to retirement investors from the financial industry, and a variety of other economic benefits, which, in the Department's view, will more than justify its costs.
The following accounting table summarizes the Department's conclusions:
ERISA is a comprehensive statute designed to protect the rights and interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in the Act's imposition of stringent fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans, their participants, and beneficiaries.
The Code also protects individuals who save for retirement through tax-favored accounts that are not generally covered by ERISA, such as IRAs, through a more limited regulation of fiduciary conduct. Although ERISA's statutory fiduciary obligations of prudence and loyalty do not govern the fiduciaries of IRAs and other plans not covered by ERISA, these fiduciaries are subject to prohibited transaction rules under the Code. The statutory exemptions in the Code apply and the Department of Labor has been given the statutory authority to grant administrative exemptions under the Code.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, section 3(21)(A) of ERISA provides that a person is a fiduciary with respect to a plan to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or exercises any authority or control with respect to management or disposition of its assets; (ii) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan, or has any authority or responsibility to do so; or, (iii) has any discretionary authority or discretionary responsibility in the administration of such plan. Section 4975(e)(3) of the Code identically defines “fiduciary” for purposes of the prohibited transaction rules set forth in Code section 4975.
The statutory definition contained in section 3(21)(A) of ERISA deliberately casts a wide net in assigning fiduciary responsibility with respect to plan assets. Thus, “any authority or control” over plan assets is sufficient to confer fiduciary status, and any person who renders “investment advice for a fee or other compensation, direct or indirect” is an investment advice fiduciary, regardless of whether they have direct control over the plan's assets, and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated fiduciary responsibilities were enacted to ensure that plans can depend on persons who provide investment advice for a fee to make recommendations that are prudent, loyal, and untainted by conflicts of interest. In the absence of fiduciary status, persons who provide investment advice would neither be subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or tainted advice, no matter how egregious the misconduct or how substantial the losses. Plans, individual participants and beneficiaries, and IRA owners often are not financial experts and consequently must rely on professional advice to make critical investment decisions. The broad statutory definition, prohibitions on conflicts of interest, and core fiduciary obligations of prudence and loyalty all reflect Congress' recognition in 1974 of the fundamental importance of such advice to protect savers' retirement nest eggs. In the years since then, the significance of financial advice has become still greater with increased reliance on participant-directed plans and self-directed IRAs for the provision of retirement benefits.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c), defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of section 3(21)(A)(ii) of ERISA (the “1975 regulation”), and the Department of the Treasury issued a virtually identical regulation under the Code.
(c) Investment advice. (1) A person shall be deemed to be rendering “investment advice” to an employee benefit plan, within the meaning of section 3(21)(A)(ii) of the Employee Retirement Income Security Act of 1974 (the Act) and this paragraph, only if:
(i) Such person renders advice to the plan as to the value of securities or other property, or makes recommendation as to the advisability of investing in, purchasing, or selling securities or other property; and
(ii) Such person either directly or indirectly (
(A) Has discretionary authority or control, whether or not pursuant to agreement, arrangement or understanding, with respect to purchasing or selling securities or other property for the plan; or
(B) Renders any advice described in paragraph (c)(1)(i) of this section on a regular basis to the plan pursuant to a mutual agreement, arrangement or understanding, written or otherwise, between such person and the plan or a fiduciary with respect to the plan, that such services will serve as a primary basis for investment decisions with respect to plan assets, and that such person will render individualized investment advice to the plan based on the particular needs of the plan regarding such matters as, among other things, investment policies or strategy, overall portfolio composition, or diversification of plan investments.
40 FR 50842 (Oct. 31, 1975). The Department of the Treasury issued a virtually identical regulation, at 26 CFR 54.4975-9(c), which interprets Code section 4975(e)(3). 40 FR 50840 (Oct. 31, 1975). Under section 102 of Reorganization Plan No. 4 of 1978, the authority of the Secretary of the Treasury to interpret section 4975 of the Code has been transferred, with certain exceptions not here relevant, to the Secretary of Labor. References in this document to sections of ERISA should be read to refer also to the corresponding sections of the Code.
The market for retirement advice has changed dramatically since the Department promulgated the 1975 regulation. Perhaps the greatest change is the fact that individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. In 1975, private-sector defined benefit pensions—mostly large, professionally managed funds—covered over 27 million active participants and held assets totaling almost $186 billion. This compared with just 11 million active participants in individual account defined contribution plans with assets of just $74 billion.
These changes in the marketplace, as well as the Department's experience with the rule since 1975, support the Department's efforts to reevaluate and revise the rule through a public process of notice and comment rulemaking. As the marketplace for financial services has developed in the years since 1975, the five-part test now undermines, rather than promotes, the statute's text and purposes. The narrowness of the 1975 regulation allows advisers, brokers, consultants, and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly rely on paid advisers for impartial guidance, the regulation allows many advisers to avoid fiduciary status and disregard ERISA's fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers can steer customers to investments based on their own self-interest (
Instead of ensuring that trusted advisers give prudent and unbiased advice in accordance with fiduciary norms, the 1975 regulation erects a multi-part series of technical impediments to fiduciary responsibility. The Department is concerned that the specific elements of the five-part test—which are not found in the text of the Act or Code—work to frustrate statutory goals and defeat advice recipients' legitimate expectations. In light of the importance of the proper management of plan and IRA assets, it is critical that the regulation defining investment advice draws appropriate distinctions between the sorts of advice relationships that should be treated as fiduciary in nature and those that should not. The 1975 regulation does not do so. Instead, the lines drawn by the five-part test frequently permit evasion of fiduciary status and responsibility in ways that undermine the statutory text and purposes.
One example of the five-part test's shortcomings is the requirement that advice be furnished on a “regular basis.” As a result of the requirement, if a small plan hires an investment professional on a one-time basis for an investment recommendation on a large, complex investment, the adviser has no fiduciary obligation to the plan under ERISA. Even if the plan is considering investing all or substantially all of the plan's assets, lacks the specialized expertise necessary to evaluate the complex transaction on its own, and the consultant fully understands the plan's dependence on his professional judgment, the consultant is not a fiduciary because he does not advise the plan on a “regular basis.” The plan could be investing hundreds of millions of dollars in plan assets, and it could be the most critical investment decision the plan ever makes, but the adviser would have no fiduciary responsibility under the 1975 regulation. While a consultant who regularly makes less significant investment recommendations to the plan would be a fiduciary if he satisfies the other four prongs of the regulatory test, the one-time consultant on an enormous transaction has no fiduciary responsibility.
In such cases, the “regular basis” requirement, which is not found in the text of ERISA or the Code, fails to draw a sensible line between fiduciary and non-fiduciary conduct, and undermines the law's protective purposes. A specific example is the one-time purchase of a group annuity to cover all of the benefits promised to substantially all of a plan's participants for the rest of their lives when a defined benefit plan terminates or a plan's expenditure of hundreds of millions of dollars on a single real estate transaction with the assistance of a financial adviser hired for purposes of that one transaction. Despite the clear importance of the decisions and the clear reliance on paid advisers, the advisers would not be fiduciaries. On a smaller scale that is still immensely important for the affected individual, the “regular basis” requirement also deprives individual participants and IRA owners of statutory protection when they seek specialized advice on a one-time basis, even if the advice concerns the investment of all or substantially all of the assets held in their account (
Under the five-part test, fiduciary status can also be defeated by arguing that the parties did not have a
Similarly, there appears to be a widespread belief among broker-dealers that they are not fiduciaries with respect to plans or IRAs because they do not hold themselves out as registered investment advisers, even though they often market their services as financial or retirement planners. The import of such disclaimers—and of the fine legal distinctions between brokers and registered investment advisers—is often completely lost on plan participants and IRA owners who receive investment advice. As shown in a study conducted by the RAND Institute for Civil Justice for the Securities and Exchange Commission (SEC), consumers often do not read the legal documents and do not understand the difference between brokers and registered investment advisers, particularly when brokers adopt such titles as “financial adviser” and “financial manager.”
Even in the absence of boilerplate fine print disclaimers, however, it is far from evident how the “primary basis” element of the five-part test promotes the statutory text or purposes of ERISA and the Code. If, for example, a prudent plan fiduciary hires multiple specialized advisers for an especially complex transaction, it should be able to rely upon all of the consultants' advice,
In other respects, the current regulatory definition could also benefit from clarification. For example, a number of parties have argued that the regulation, as currently drafted, does not encompass paid advice as to the selection of money managers or mutual funds. Similarly, they have argued that the regulation does not cover advice given to the managers of pooled investment vehicles that hold plan assets contributed by many plans, as opposed to advice given to particular plans. Parties have even argued that advice was insufficiently “individualized” to fall within the scope of the regulation because the advice provider had failed to prudently consider the “particular needs of the plan,” notwithstanding the fact that both the advice provider and the plan agreed that individualized advice based on the plan's needs would be provided, and the adviser actually made specific investment recommendations to the plan. Although the Department disagrees with each of these interpretations of the 1975 regulation, the arguments nevertheless suggest that clarifying regulatory text would be helpful.
As noted above, changes in the financial marketplace have further enlarged the gap between the 1975 regulation's effect and the congressional intent as reflected in the statutory definition. With this transformation, plan participants, beneficiaries, and IRA owners have become major consumers of investment advice that is paid for directly or indirectly. Increasingly, important investment decisions have been left to inexpert plan participants and IRA owners who depend upon the financial expertise of their advisers, rather than professional money managers who have the technical expertise to manage investments independently. In today's marketplace, many of the consultants and advisers who provide investment-related advice and recommendations receive compensation from the financial institutions whose investment products they recommend. This gives the consultants and advisers a strong reason, conscious or unconscious, to favor investments that provide them greater compensation rather than those that may be most appropriate for the participants. Unless they are fiduciaries, however, these consultants and advisers are free under ERISA and the Code, not only to receive such conflicted compensation, but also to act on their conflicts of interest to the detriment of their customers. In addition, plans, participants, beneficiaries, and IRA owners now have a much greater variety of investments to choose from, creating a greater need for expert advice. Consolidation of the financial services industry and innovations in compensation arrangements have multiplied the opportunities for self-dealing and reduced the transparency of fees.
The absence of adequate fiduciary protections and safeguards is especially problematic in light of the growth of participant-directed plans and self-directed IRAs, the gap in expertise and information between advisers and the customers who depend upon them for guidance, and the advisers' significant conflicts of interest.
When Congress enacted ERISA in 1974, it made a judgment that plan advisers should be subject to ERISA's fiduciary regime and that plan participants, beneficiaries, and IRA owners should be protected from conflicted transactions by the prohibited transaction rules. More fundamentally, however, the statutory language was designed to cover a much broader category of persons who provide fiduciary investment advice based on their functions and to limit their ability to engage in self-dealing and other conflicts of interest than is currently reflected in the 1975 regulation's five-part test. While many advisers are committed to providing high-quality advice and always put their customers' best interests first, the 1975 regulation makes it far too easy for advisers in today's marketplace not to do so and to avoid fiduciary responsibility even when they clearly purport to give individualized advice and to act in the client's best interest, rather than their own.
On October 22, 2010, the Department published the 2010 Proposal in the
Under the 2010 Proposal, a paid adviser would have been treated as a fiduciary if the adviser provided one of the above types of advice and either: (1) Represented that he or she was acting as an ERISA fiduciary; (2) was already an ERISA fiduciary to the plan by virtue of having control over the management or disposition of plan assets, or by having discretionary authority over the administration of the plan; (3) was already an investment adviser under the Investment Advisers Act of 1940 (Advisers Act); or (4) provided the advice pursuant to an agreement, arrangement or understanding that the advice may be considered in connection with plan investment or asset management decisions and would be individualized to the needs of the plan, plan participant or beneficiary, or IRA owner. The 2010 Proposal also provided that, for purposes of the fiduciary definition, relevant fees included any direct or indirect fees received by the adviser or an affiliate from any source. Direct fees are payments made by the advice recipient to the adviser including transaction-based fees, such as brokerage, mutual fund or insurance sales commissions. Indirect fees are payments to the adviser from any source other than the advice recipient such as revenue sharing payments with respect to a mutual fund.
The 2010 Proposal included specific provisions for the following actions that the Department believed should not result in fiduciary status. In particular, a person would not have become a fiduciary by—
1. Providing recommendations as a seller or purchaser with interests adverse to the plan, its participants, or IRA owners, if the advice recipient reasonably should have known that the adviser was not providing impartial investment advice and the adviser had not acknowledged fiduciary status.
2. Providing investment education information and materials in connection with an individual account plan.
3. Marketing or making available a menu of investment alternatives that a plan fiduciary could choose from, and providing general financial information to assist in selecting and monitoring those investments, if these activities include a written disclosure that the adviser was not providing impartial investment advice.
4. Preparing reports necessary to comply with ERISA, the Code, or regulations or forms issued thereunder, unless the report valued assets that lack a generally recognized market, or served as a basis for making plan distributions.
In the preamble to the 2010 Proposal, the Department also noted that it had previously interpreted the 1975 regulation as providing that a recommendation to a plan participant on how to invest the proceeds of a contemplated plan distribution was not fiduciary investment advice. Advisory Opinion 2005-23A (Dec. 7, 2005). The Department specifically asked for comments as to whether the final rule should cover such recommendations as fiduciary advice.
The Department made special efforts to encourage the regulated community's participation in this rulemaking. The 2010 Proposal prompted a large number of comments and a vigorous debate. The Department received over 300 comment letters. A public hearing on the 2010 Proposal was held in Washington, DC on March 1 and 2, 2011, at which 38 speakers testified. In addition to an extended comment period, additional time for comments was allowed following the hearing. The transcript of that hearing was made available for additional public comment and the Department received over 60 additional comment letters. The Department also participated in many meetings requested by various interested stakeholders. Many of the comments concerned the Department's conclusions regarding the likely economic impact of the 2010 Proposal, if adopted. A number of commenters urged the Department to undertake additional analysis of expected costs and benefits particularly with regard to the 2010 Proposal's coverage of IRAs. After consideration of these comments and in light of the significance of this rulemaking to the retirement plan service provider industry, plan sponsors and participants, beneficiaries and IRA owners, the Department decided to take more time for review and to issue a new proposed regulation for comment. On September 19, 2011 the Department announced that it would withdraw the 2010 Proposal and propose a new rule defining the term “fiduciary” for purposes of section 3(21)(A)(ii) of ERISA and section 4975(e)(3)(B) of the Code.
On April 20, 2015, the Department published in the
The 2015 Proposal made many revisions to the 2010 Proposal, although it also retained aspects of that proposal's essential framework. Paragraph (a)(1) of the 2015 Proposal set forth the following types of advice, which, when provided in exchange for a fee or other compensation, whether directly or indirectly, and given under circumstances described in paragraph (a)(2), would be “investment advice” unless one of the “carve-outs” in paragraph (b) applied. The listed types of advice were—(i) a recommendation as to the advisability of acquiring, holding, disposing of, or exchanging securities or other property, including a recommendation to take a distribution of benefits or a recommendation as to the investment of securities or other property to be rolled over or otherwise distributed from the plan or IRA; (ii) a recommendation as to the management of securities or other property, including recommendations as to the management of securities or other property to be rolled over or otherwise distributed from the plan or IRA; (iii) an appraisal, fairness opinion, or similar statement whether verbal or written concerning the value of securities or other property if provided in connection with a specific transaction or transactions involving the acquisition, disposition, or exchange, of such securities or other property by the plan or IRA; or (iv) a recommendation of a person who is also going to receive a fee or other compensation to provide any of the types of advice described in paragraphs (i) through (iii) above.
As provided in paragraph (a)(2) of the 2015 Proposal, unless a carve-out applied, a category of advice listed in the proposal would constitute “investment advice” if the person providing the advice, either directly or indirectly (
The 2015 Proposal included several carve-outs for persons who do not represent that they are acting as ERISA fiduciaries, some of which were included in some form in the 2010 Proposal but many of which were not. Subject to specified conditions, these carve-outs covered—
(1) statements or recommendations made to a “large plan investor with financial expertise” by a counterparty acting in an arm's length transaction;
(2) offers or recommendations to plan fiduciaries of ERISA plans to enter into a swap or security-based swap that is regulated under the Securities Exchange Act or the Commodity Exchange Act;
(3) statements or recommendations provided to a plan fiduciary of an ERISA plan by an employee of the plan sponsor if the employee receives no fee beyond his or her normal compensation;
(4) marketing or making available a platform of investment alternatives to be selected by a plan fiduciary for an ERISA participant-directed individual account plan;
(5) the identification of investment alternatives that meet objective criteria specified by a plan fiduciary of an ERISA plan or the provision of objective financial data to such fiduciary;
(6) the provision of an appraisal, fairness opinion or a statement of value to an Employee Stock Ownership Plan
(7) information and materials that constitute “investment education” or “retirement education.”
The 2015 Proposal applied the same definition of “investment advice” to the definition of “fiduciary” in section 4975(e)(3) of the Code and thus applied to investment advice rendered to IRAs. “Plan” was defined in the proposal to mean any employee benefit plan described in section 3(3) of the Act and any plan described in section 4975(e)(1)(A) of the Code. For ease of reference the proposal defined the term “IRA” inclusively to mean any account described in Code section 4975(e)(1)(B) through (F), such as an individual retirement account described under Code section 408(a) and a health savings account described in section 223(d) of the Code.
Many of the differences between the 2015 Proposal and the 2010 Proposal reflect the input of commenters on the 2010 Proposal as part of the public notice and comment process. For example, some commenters argued that the 2010 Proposal swept too broadly by making investment recommendations fiduciary in nature simply because the adviser was a plan fiduciary for purposes unconnected with the advice or an investment adviser under the Advisers Act. In their view, such status-based criteria were in tension with the Act's functional approach to fiduciary status and would have resulted in unwarranted and unintended compliance issues and costs. Other commenters objected to the lack of a requirement for these status-based categories that the advice be individualized to the needs of the advice recipient. The 2015 Proposal incorporated these suggestions: An adviser's status as an investment adviser under the Advisers Act or as an ERISA fiduciary for reasons unrelated to advice were not explicit factors in the definition. In addition, the 2015 Proposal provided that unless the adviser represented that he or she is a fiduciary with respect to advice, the advice must be provided pursuant to a written or verbal agreement, arrangement, or understanding that the advice is individualized to, or that such advice is specifically directed to, the recipient for consideration in making investment or management decisions with respect to securities or other property of the plan or IRA.
Furthermore, under the 2015 Proposal, the carve-outs that treat certain conduct as non-fiduciary in nature were modified, clarified, and expanded in response to comments to the 2010 Proposal. For example, the carve-out for certain valuations from the definition of fiduciary investment advice was modified and expanded. Under the 2010 Proposal, appraisals and valuations for compliance with certain reporting and disclosure requirements were not treated as fiduciary investment advice. The 2015 Proposal additionally provided a carve-out from fiduciary treatment for appraisal and fairness opinions for ESOPs regarding employer securities. Although, the Department remained concerned about valuation advice concerning an Employee Stock Ownership Plan's (ESOP's) purchase of employer stock and about a plan's reliance on that advice, the Department concluded, at the time, that the concerns regarding valuations of closely held employer stock in ESOP transactions raised issues that were more appropriately addressed in a separate regulatory initiative. Additionally, the carve-out for valuations conducted for reporting and disclosure purposes was expanded to include reporting and disclosure obligations outside of ERISA and the Code, and was applicable to both ERISA plans and IRAs.
The Department took significant steps to give interested persons an opportunity to comment on the new proposal and proposed related exemptions. The 2015 Proposal and proposed related exemptions initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department held a public hearing in Washington, DC on August 10-13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to submit comments on the proposal and proposed related exemptions or transcript until September 24, 2015. A total of over 3,000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support of, and in opposition to, the proposed rule and proposed related exemptions.
Many comments throughout the rulemaking have emphasized the need to harmonize the Department's efforts with potential rulemaking and rulemaking activities under the Dodd-Frank Wall Street Reform and Consumer Protection Act, Pub. Law No. 111-203, 124 Stat. 1376 (2010) (Dodd-Frank Act), in particular, the SEC's standards of care for providing investment advice and the Commodity Futures Trading Commission's (CFTC) business conduct standards for swap dealers. In addition, some commenters questioned the adequacy of coordination with other agencies regarding IRA products and services in particular. They argued that subjecting SEC-regulated investment advisers and broker-dealers to a special set of ERISA rules for plans and IRAs could lead to additional costs and complexities for individuals who may have several different types of accounts at the same financial institution some of which may be subject only to the SEC rules, and others of which may be subject to both SEC rules and new regulatory requirements under ERISA.
Other commenters questioned the extent to which the Department had engaged with federal and state securities, insurance and banking regulators to ensure that regulatory regimes already in place would not be adversely affected. They expressed concern that subjecting parties to overlapping regulatory requirements from multiple oversight organizations would make compliance difficult and costly. One commenter asserted, however, that when service providers are subject to different legal standards of conduct, the easiest compliance approach is to meet the higher standard of care, which would benefit consumers, even outside the context of plans and IRAs.
In the course of developing the 2015 Proposal, the final rule, and the related prohibited transaction exemptions, the Department has consulted with staff of the SEC; other securities, banking, and insurance regulators, the U.S. Treasury Department's Federal Insurance Office, and FINRA, the independent regulatory authority of the broker-dealer industry, to better understand whether the rule and exemptions would subject investment advisers and broker-dealers who provide investment advice to requirements that create an undue compliance burden or conflict with their obligations under other federal laws. As part of this consultative process, SEC staff has provided technical assistance and information with respect to the agencies' separate regulatory provisions and responsibilities, retail investors, and the marketplace for investment advice. Some commenters argued that the SEC's regulation of advisers and brokers is sufficient. Other commenters noted, however, that plans and IRAs invest in more products than those regulated by the SEC alone, and asserted that the regulatory framework under ERISA and the Code was more protective of retirement investors. Some commenters also questioned the extent to which the SEC's disclosure framework would adequately protect retirement investors. Others thought the Department should coordinate with the SEC on the initiative and some advocated for a uniform fiduciary standard to lessen confusion about various standards of care owed to investors.
Commenters were also divided when it came to FINRA, with some commenters contending that FINRA sufficiently regulates brokers and that the Department should incorporate FINRA concepts or defer to FINRA and SEC regulation under the federal securities laws. Other commenters expressed concern about relying on FINRA and SEC regulations and guidance, in part, because FINRA's guidance would not be directly applicable to an array of ERISA investment advisers that are not subject to FINRA rules or SEC oversight.
In pursuing its consultations with other regulators, the Department aimed to avoid conflict with other federal laws and minimize duplicative provisions between ERISA, the Code and federal securities laws. However, the governing statutes do not permit the Department to make the obligations of fiduciary investment advisers under ERISA and the Code identical to the duties of advice providers under the securities laws. ERISA and the Code establish consumer protections for some investment advice that does not fall within the ambit of federal securities laws, and vice versa. Even if each of the relevant agencies were to adopt an identical definition of “fiduciary,” the legal consequences of the fiduciary designation would vary between agencies because of differences in the specific duties and remedies established by the different federal laws at issue. ERISA and the Code place special emphasis on the elimination or mitigation of conflicts of interest and adherence to substantive standards of conduct, as reflected in the prohibited transaction rules and ERISA's standards of fiduciary conduct. The specific duties imposed on fiduciaries by ERISA and the Code stem from legislative judgments on the best way to protect the public interest in tax-preferred benefit arrangements that are critical to workers' financial and physical health. The Department has taken great care to honor ERISA and the Code's specific text and purposes.
At the same time, the Department has worked hard to understand the impact of the 2015 Proposal and the final rule on firms subject to the federal securities and other laws, and to take the effects of those laws into account so as to appropriately calibrate the impact of the rule on those firms. The final rule reflects these efforts. In the Department's view, it neither undermines, nor contradicts, the provisions or purposes of the securities laws, but instead works in harmony with them. The Department has coordinated—and will continue to coordinate—its efforts with other federal agencies to ensure that the various legal regimes are harmonized to the fullest extent possible.
The Department has also consulted with the Department of the Treasury, particularly on the subject of IRAs. Although the Department has responsibility for issuing regulations and prohibited transaction exemptions under section 4975 of the Code, which applies to IRAs, the IRS maintains general responsibility for enforcing the tax laws. The IRS' responsibilities extend to the imposition of excise taxes on fiduciaries who participate in prohibited transactions.
The Department received comments from the North American Securities Administrators Association (NASAA), whose membership includes all U.S. state securities regulators. NASAA generally supported the proposal and the Department's goal of enhancing the standard of care available to retirement investors, including those who invest through IRAs. NASAA said the proposal is an important step in raising the standard of care available to retirement investors, and paves the way for additional regulatory initiatives to raise the standard of care for investors in general. NASAA asked that the Department include language in its final rule that explicitly acknowledges that state securities laws are not superseded or preempted and remain subject to the ERISA section 514(b)(2)(A) savings clause. NASAA also offered suggestions on individual substantive provisions of the proposal. For example, NASAA suggested the final rule prohibit pre-dispute binding arbitration agreements with respect to individual contract claims.
The National Association of Insurance Commissioners (NAIC) also submitted a comment stating that it recognizes that oversight of the retirement plans marketplace is a shared regulatory responsibility, and has been so for decades. The NAIC agreed that state insurance regulators, the DOL, SEC and FINRA, each have an important role in the administration and enforcement of standards for retirement plans and products within their jurisdiction. It said that state insurance regulators share the DOL's commitment to protect, educate and empower consumers as they make important decisions to provide for their retirement security. The NAIC noted that the states have acted to implement a robust set of consumer protection and education standards for annuity and insurance transactions, have extensive enforcement authority to examine companies, revoke producer and company licenses to operate, as well as to collect and analyze industry data, and have a strong record of protecting consumers, especially seniors, from inappropriate sales practices or unsuitable products. The NAIC pointed out that it is important that the approaches regulators take within their respective regulatory framework be as consistent as possible, and that it would carefully evaluate the stakeholder input on the proposal submitted during the
Comments were submitted by the National Conference of Insurance Legislators and the National Association of Governors suggesting further dialogue with the NAIC, insurance legislators, and other state officials to ensure the federal and state approaches to consumer protection in this area are consistent and compatible.
The Department carefully considered the comments that were submitted by interested state regulators, and had meetings during the comment period on the 2015 Proposal with NASAA staff and with the NAIC (including insurance commissioners and NAIC staff). The Department also received input on the interaction between state and federal regulation of investment advice from various groups and organizations that are subject to state insurance or securities regulations. The Department's obligation and overriding objective in developing regulations implementing ERISA (and the relevant prohibited transaction provisions in the Code) is to achieve the consumer protection objectives of ERISA and the Code. The Department believes the final rule reflects that obligation and objective while also reflecting that care was taken to craft the rule so that it does not require people subject to state banking, insurance or securities regulation to take steps that would conflict with applicable state statutory or regulatory requirements. The Department notes that ERISA section 514 expressly saves state regulation of insurance, banking, or securities from ERISA's express preemption provision. The Department agrees that it would be appropriate for the final rule to include an express provision acknowledging the savings clause in ERISA section 514(b)(2)(A) for state insurance, banking, and securities laws to emphasize the fact that those state regulators all have important roles in the administration and enforcement of standards for retirement plans and products within their jurisdiction. Accordingly, the final rule includes a new paragraph (i).
After carefully evaluating the full range of public comments and extensive record developed on the proposal, the final rule as described below amends the definition of investment advice in 29 CFR 2510.3-21 (1975) to replace the restrictive five-part test with a new definition that better comports with the statutory language in ERISA and the Code. Some commenters offered general support for, or opposition to, the Department's proposal to replace the 1975 regulation's five-part test. The Department did not attempt to separately identify or discuss these general comments in this Notice, although the preamble, in its entirety, addresses the reasons for undertaking this regulatory initiative and the rationales for the Department's specific regulatory choices. Most commenters, however, gave the Department feedback on the specific provisions of the proposal and whether they believed them to be preferable to the 1975 regulation.
Several commenters argued for withdrawal of the proposed rule stating that the proposal neither demonstrated a compelling need for regulatory action nor employed the least burdensome method to effect any necessary change. They believed that to make the rule and exemptions workable, such significant modifications were necessary that a second re-proposal was required. Some comments suggested that the Department should engage in extensive testing of the rule and exemptions before going final, for example, via focus groups or a negotiated rulemaking process. Some commenters complained that the Administrative Procedures Act requires that a decision to re-propose be based on the public record and that informal comments from the Department suggested that the Department had prejudged that issue before evaluating all the public comments. Another commenter disagreed and maintained that the proposal should be finalized since the Department had followed the proper regulatory process and no one, in testimony or comment, had made a credible argument for any change that is “material” enough to warrant a re-proposal. Moreover, a number of organizations also offered nearly unqualified support for the rule, and endorsed the Department's efforts in moving forward with the proposal. Although some organizations expressed concern about the rule's complexity and posited possible attendant high compliance costs and uncertain legal liabilities, they deemed these costs justified by moving to a higher standard for investors. Other commenters pointed to specific demographic groups and noted their need for the increased protections offered by the rule. One international organization articulated the hope that efforts in the United States may influence its government to similarly act to hold persons offering financial advice to a fiduciary duty. The Department believes it has engaged in sufficient public outreach to establish a valid and comprehensive public record as detailed above in discussions of the 2010 Proposal and the re-proposal in 2015 to substantiate promulgating a final rule at this time. In the Department's judgment, this final rulemaking, which follows a robust regulatory process, fulfills the Department's mission to protect, educate, and empower retirement investors as they face important choices in saving for retirement in their IRAs and employee benefit plans.
The final rule largely adopts the general structure of the 2015 Proposal but with modifications in response to commenters seeking changes or clarifications of certain provisions in the proposal. Similar to the proposal, the final rule in paragraph (a)(1) first describes the kinds of communications that would constitute investment advice. Then paragraph (a)(2) sets forth the types of relationships that must exist for such recommendations to give rise to fiduciary investment advice responsibilities. The rule covers: Recommendations by a person who represents or acknowledges that it is acting as a fiduciary within the meaning of the Act or the Code; advice rendered pursuant to a written or verbal agreement, arrangement or understanding that the advice is based on the particular investment needs of the advice recipient; and recommendations directed to a specific advice recipient or recipients regarding the advisability of a particular investment or management decision with respect to securities or other investment property of the plan or IRA. Paragraph (b)(1) describes when a communication based on its context, content, and presentation would be viewed as a “recommendation,” a fundamental element in establishing the existence of fiduciary investment advice. Paragraph (b)(2) sets forth examples of certain types of communications which are not “recommendations” under that definition. The examples include certain activities that were classified as “carve-outs” under the proposal, but which are better understood as not constituting investment “recommendations” in the first place. Paragraph (c) describes and clarifies conduct and activities that the Department determined should not be considered investment advice activity although they may otherwise meet the criteria established by paragraph (a). Thus, paragraph (c) includes communications and activities that were appropriately classified as “carve-outs” under the proposal. Paragraph (c) also
Under the final rule, whether a “recommendation” has occurred is a threshold issue and the initial step in determining whether investment advice has occurred. The 2015 Proposal included a definition of recommendation in paragraph (f)(1): “[A] communication that, based on its content, context, and presentation, would reasonably be viewed as a suggestion that the advice recipient engage in or refrain from taking a particular course of action.” The Department received a wide range of comments that asked that the final rule include a clearer statement of when particular communications rise to the level of covered investment “recommendations.” As described more fully below, the Department, in response, has added a new section to the regulation that is intended to clarify the standard for determining whether a person has made a “recommendation” covered by the final rule.
Paragraph (a) of the final rule states that a person renders investment advice with respect to moneys or other property of a plan or IRA described in paragraph (g)(6) of the final rule if such person provides the types of advice described in paragraphs (a)(1)(i) or (ii). The final rule revises and clarifies this provision from the 2015 Proposal in the manner described below. Specifically, paragraph (a)(1) of the final rule provides that person(s) provide investment advice if they provide for a fee or other compensation certain categories or types of investment recommendations. The listed types of advice are—
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred, or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services; selection of investment account arrangements (
The final rule thus maintains the general structure of the 2015 Proposal, but the operative text of the rule includes several changes to clarify the provisions. In addition, the Department reserves the possible coverage of appraisals, fairness opinions, and similar statements for a future rulemaking project.
In general, paragraph (a)(1)(i) covers recommendations regarding the investment of plan or IRA assets, including recommendations regarding the investment of assets that are being rolled over or otherwise distributed from plans to IRAs. Paragraph (a)(1)(ii) covers recommendations regarding investment management of plan or IRA assets. In response to comments that the term “management” should be clarified, the Department included text from the 1975 regulation and added additional examples to clarify the scope of the definition. In particular, the management recommendations covered by (a)(1)(ii) include recommendations on rollovers, distributions, and transfers from a plan or IRA, including recommendations on whether to take a rollover, distribution, or transfer; recommendations on the form of the rollover, distribution, or transfer; and recommendations on the insurance issuer or investment provider to receive the rollover, distribution or transfer. Some commenters expressed concern that advice providers could avoid fiduciary responsibility for recommendations to roll over plan assets, for example, to a mutual fund provider by not including in that recommendation any advice on how to invest the assets after they are rolled over. The revisions to paragraph (a)(1)(ii) are intended to make clear that such recommendations would be investment advice covered by the rule.
In addition, (a)(1)(ii) has been amended to include recommendations on the selection of persons to perform investment advice or investment management services. The proposal had contained a separate provision covering recommendations to hire investment advisers, but that provision has been merged into paragraph (a)(1)(ii) as one type of recommendation on management of investments. The Department may have contributed to some commenters' uncertainty about the breadth of the proposal and whether it covered recommendations of persons providing investment management services by setting forth the recommendation of fiduciary investment advisers as a separate provision of the rule, rather than as merely one example of a recommendation on investment management. The Department has always viewed the recommendation of persons to perform investment management services for plans or IRAs as investment advice. The final rule more clearly and simply sets forth the scope of the subject matter covered by the rule. Below is a more detailed discussion of various comments that relate to these changes.
Several commenters argued that the language of the proposal referring to advice regarding “moneys or other property” of the plan was sufficiently broad that it could be read to cover advice on purchasing insurance policies that do not have an investment component. Those commenters observed that such a reading of the proposal did not appear to be what the Department intended, and, moreover, asserted that a regulation defining “investment advice” as having such scope would likely exceed the Department's authority. Thus, they asked that the final rule confirm that advice as to the purchase of health, disability, and term life insurance policies to provide benefits to plan participants or IRA owners would not be fiduciary investment advice within the meaning of ERISA section 3(21)(A)(ii). Other commenters asked whether the rule would apply to 403(b) plans, SIMPLE-IRA plans, SEPs, fraternal benefit societies, and health savings accounts. Lastly, many commenters requested clarification as to whether and when traditional service
It was not the intent of the proposal to treat as fiduciary investment advice, advice as to the purchase of health, disability, and term life insurance policies to provide benefits to plan participants or IRA owners if the policies do not have an investment component. The Department believes it would depart from a plain and natural reading of the term “investment advice” to conclude that recommendations to purchase group health and disability insurance constitute investment advice. The definition of an “investment advice” fiduciary in ERISA itself, as adopted in 1974, uses the same terms as the proposal to define an investment advice fiduciary—a person that renders “investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan.” The Department's 1975 regulation implementing that definition similarly covers “investment advice” regarding “securities or other property.”
The Department is not aware of any substantial concern or confusion regarding whether the 1975 regulation covered recommendations to purchase health, disability, or term life insurance policies. Additionally, the Securities Exchange Act of 1934 in section 3(a)(35) uses the term “securities and other property” to define “investment discretion,” and the Investment Company Act of 1940 in section 2(a)(20) refers to “securities or other property” in defining an “investment adviser.” The Department does not believe that these statutory provisions have created the type of confusion that commenters attached to the Department's proposal. Thus, although there can be situations in which a person recommending group health or disability insurance, for example, effectively exercises such control over the decision that he or she is functionally exercising discretionary control over the management or administration of the plan within the meaning of the fiduciary definition in ERISA section 3(21)(A)(i) or section 3(21)(A)(iii), the Department does not believe that the definition of investment advice in ERISA's statutory text, the Department's 1975 regulation, or the prior proposals are properly interpreted or understood to cover a recommendation to purchase group health, disability, term life insurance or similar insurance policies that do not have an investment component.
As a result, and to expressly make this point, the Department has modified the final rule to make it clear that, in order to render investment advice with respect to moneys or other property of a plan or IRA, the adviser must make a recommendation with respect to the advisability of acquiring, holding, disposing or exchanging securities or other “investment” property. The Department similarly modified the final rule to make it clear that the covered recommendation must concern the management or manager of securities or other “investment” property to fall under that prong of the investment advice fiduciary definition. Further, the Department added new paragraph (g)(4) to define investment property as expressly not including health or disability insurance policies, term life insurance policies, or other assets to the extent that they do not include an investment component.
A few commenters argued that bank certificates of deposit (CDs) and other similar bank deposit accounts should not be treated as investments for purposes of the rule and communications regarding them should not be treated as investment advice because the purposes for which plan and IRA investors use them do not present the same concerns about conflicts of interest as other covered investment recommendations. The commenters also argued, similar to other commenters in other industries, that educational communications from bank branch personnel to customers about bank products will be impaired if possibly subject to ERISA rules governing fiduciary investment advice.
In the Department's view, the definition of investment property in paragraph (g)(4) should include bank CDs and similar investment products. The Department does not see any basis for differentiating advice regarding investments in CDs, including investment strategies involving CDs (
Many commenters questioned the application of the proposal in connection with recommendations of proprietary investment products. These commenters objected that the proposal would make recommending proprietary products on a commission basis a per se violation of ERISA's fiduciary duties and the fiduciary self-dealing prohibitions, and contended the proposal was flawed by a “bias” against proprietary products. Some of these commenters raised specific issues related to insurers marketing their own insurance products and contended that subjecting insurers to fiduciary investment advice duties would impede their ability to give participants and IRA owners guidance about lifetime income guarantees and other insurance features in their proprietary products. Commenters suggested that some mechanism, for example, a requirement to disclose potential conflicts of interest or a specific carve-out for proprietary and/or insurance products, was needed to ensure that affected providers can market purely proprietary investment products. These commenters argued that the potential for “conflict of interest” abuses is limited in the case of proprietary products because it is obvious to consumers that companies and their agents are marketing “their” products. Several other commenters, however, disagreed and argued that proprietary or affiliated investment products present substantial conflicts of interest resulting in biased advice that is detrimental to investors. These commenters argued that the Department should narrowly define provisions of the proposal designed to address advisers whose business involves proprietary or limited menu products to mitigate this potential conflict of interest.
A couple of commenters recommended that the Department consider these proprietary product issues in the context of fraternal benefit societies exempt from tax under section 503(c)(8) of the Code, including those engaged in religious and benevolent activities, suggesting that a carve-out or similar exception is needed to protect these not-for-profit organizations because their religious and benevolent activities have been funded in large part through the sale of insurance and financial products to fraternal lodge members.
The Department does not believe that it is appropriate for a rule defining fiduciary investment advice to provide special treatment for sales and marketing of proprietary products. The Department agrees that a person's status as a fiduciary investment adviser presents inherent conflicts with sales and marketing activities that restrict recommendations to only proprietary products. The fact that conflicts of interest may be inherent in the sale and marketing of proprietary products, in the Department's view, would not be a compelling basis for excluding those communications from a rule designed to protect consumers from just such conflicts of interest. Rather, the Department believes that the model reflected in the ERISA statutory structure is the way, at least in the retail market, to acknowledge and address the fact that providers of proprietary products will, in selling their products, engage in communications and activities that constitute fiduciary investment advice under the final rule.
Specifically, just as ERISA contains broadly protective rules and prohibited transaction restrictions with carefully crafted exemptions, including conditions designed to mitigate possible abuses, the Department believes a generally applicable definition of fiduciary investment advice focused on investment “recommendations,” coupled with carefully crafted exemptions from the prohibited transaction rules, is also the appropriate solution in this context. In addition, with respect to institutional investors and plan fiduciaries with financial expertise, the Department has included in the final rule a special provision under which sales communications and activities in arm's length transactions with such persons would not constitute fiduciary investment advice. Insurers and others selling proprietary products can rely on that provision when dealing with such financially sophisticated plan fiduciaries. The Best Interest Contract Exemption also specifically addresses advice concerning proprietary products, and provides a means for firms and advisers to recommend such products, while safeguarding retirement investors from the dangers posed by conflicts of interest.
With respect to fraternal benefit societies, the concerns raised by these commenters regarding the proposed rule largely mirrored the concerns raised by other sellers of proprietary products. The fact that an organization is exempt from tax under the Code or that it has an educational or charitable mission does not, in the Department's view, provide a basis for excluding investment advice provided to retirement investors by those organizations from fiduciary duties. Similarly, if fraternal benefit societies adopt business structures and compensation arrangements that present self-dealing concerns and financial conflicts of interest, the fact that revenues from sales may be used, in part, for religious and benevolent activities is not, in the Department's view, a basis for treating such sales differently from other sales under the prohibited transaction provisions of ERISA and the Code. Rather, those societies can avail themselves of the same provisions in the final rule and final exemptions as are available to other sellers of proprietary products.
Some commenters similarly argued that advisers to SIMPLE-IRA plans and SEPs should be excluded from coverage under the rule. However, such arrangements established or maintained by a private sector employer for its employees are “employee benefit plans” within the meaning of section 3(3) of ERISA, and, as such, are subject to the protections of the prohibited transaction rules. Such plans use IRAs as their investment and funding vehicles. In light of the fact that the 2015 Proposal covered investment advice with respect to the assets of employee benefit plans and IRAs, the Department does not see any basis for excluding employee benefit plans like SIMPLE-IRA plans and SEPs from the scope of the final rule. Nor is there any reason to believe that the small employers that rely upon such plans for the provision of benefits, and their employees, are any less in need of the rule's protections. The Department's authority to issue this rulemaking, including its application to IRAs is discussed more fully below.
With respect to 403(b) plans, because the final rule defines investment advice fiduciary for “plans” covered under Title I of ERISA or Code section 4975 (
Several commenters also asserted that it was unclear whether investment advice under the scope of the proposal would include the provision of information and plan services that traditionally have been performed in a non-fiduciary capacity. The Department agrees that actuaries, accountants, and attorneys, who historically have not been treated as ERISA fiduciaries for plan clients, would not become fiduciary investment advisers by reason of providing actuarial, accounting, and legal services. The Department does not believe anything in the 2010 or 2015 Proposals, or the final rule, suggested a different conclusion. Rather, in the Department's view, the provisions in the final rule defining investment advice make it clear that attorneys, accountants, and actuaries would not be treated as investment advice fiduciaries
Paragraph (a)(1)(i) and (ii) of the final rule specifically includes recommendations concerning the investment, management, or manager of securities or other investment property to be rolled over, transferred, or distributed from the plan or IRA, including recommendations how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred, or distributed from the plan or IRA and recommendations with respect whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made. The final rule thus supersedes the Department's position in Advisory Opinion 2005-23A (Dec. 7, 2005) that it is not fiduciary advice to make a recommendation as to distribution options even if accompanied by a recommendation as to where the distribution would be invested.
The comments on this issue tended to mirror the comments submitted on this same question the Department posed in its 2010 Proposal. Some commenters, mainly those representing consumers, stated that exclusion of recommendations on rollovers and benefit distributions from the final rule would fail to protect participant accounts from conflicted advice in connection with one of the most significant financial decisions that participants make concerning retirement savings. These comments particularly noted the critical nature of retirement and rollover decisions and the existence of incentives for advice and investment providers to steer plan participants into higher cost, subpar investments. Other commenters, mainly those representing financial services providers, argued that including such communications as fiduciary investment advice would significantly restrict the type of investment education that would be provided regarding rollover and plan distributions by employers and other plan service providers because of concerns about possible fiduciary liability and prohibited transactions. They argued that such potential fiduciary liability would disrupt the routine process that occurs when a worker leaves a job and contacts a financial services firm for help rolling over a 401(k) balance, and the firm explains the investments it offers and the benefits of a rollover. They also asserted that plan sponsors and plan service providers would stop assisting participants and beneficiaries with these important decisions, including recommendations to keep retirement savings in the plan or advice regarding lifetime income products and investment strategies. Some commenters claimed that the proposal would discourage or impede rollovers into IRAs or other vehicles that give them access to annuities and other lifetime income products that often are unavailable in their 401(k) plans. The commenters argued that such a result would conflict with the Department's recent guidance and initiatives designed to enhance the availability of lifetime income products in 401(k) and similar employer-sponsored defined contribution pension plans. Other commenters questioned the legal authority of the Department to classify rollover advice as fiduciary in nature. Others asked that the Department exclude rollover recommendations into IRAs when there is no accompanying recommendation on how to invest the funds once in the IRA. Other commenters asked for clarifications or broad exclusions in various specific circumstances, such as advice with respect to benefit distributions that are required by tax law such as required minimum distributions. Others asked that the principles of FINRA guidance on rollovers under Notice 13-45 be incorporated in the advice definition and suggested that compliance with the guidance could act as a safe harbor for rollover advice.
The Department continues to believe that decisions to take a benefit distribution or engage in rollover transactions are among the most, if not the most, important financial decisions that plan participants and beneficiaries, and IRA owners are called upon to make. The Department also continues to believe that advice provided at this juncture, even if not accompanied by a specific recommendation on how to invest assets, should be treated as investment advice under the final rule. The final rule thus adopts the provision in the proposal and supersedes Advisory Opinion 2005-23A. The advisory opinion failed to consider that advice to take a distribution of assets from a plan is actually advice to sell, withdraw, or transfer investment assets currently held in a plan. Thus, a distribution recommendation involves either advice to change specific investments in the plan or to change fees and services directly affecting the return on those investments. Even if the assets will not be covered by ERISA or the Code when they are moved outside the plan or IRA, the recommendation to change the plan or IRA investments is investment advice under ERISA and the Code. Thus, recommendations on distributions (including rollovers or transfers into another plan or IRA) or recommendations to entrust plan or IRA assets to a particular IRA provider would fall within the scope of investment advice in this regulation, and would be covered by Title I of ERISA, including the enforcement provisions of section 502(a). Further, in the Department's view, recommendations to take a distribution or rollover to an IRA and recommendations not to take a distribution or to keep assets in a plan should be treated the same in terms of evaluating whether the communication constitutes fiduciary investment advice.
The Department acknowledges commenters' concerns that some employers and service providers could restrict the type of investment education they provide regarding rollovers and plan distributions based on concerns about fiduciary liability. Accordingly, the final rule (like the 2015 Proposal) includes provisions that describe in detail the distinction between recommendations that are fiduciary investment advice and educational and informational materials. For example, the provisions specifically state that educational materials can describe the terms or operation of the plan or IRA, inform a plan fiduciary, plan participant, beneficiary, or IRA owner about the benefits of plan or IRA
To the extent that an individual adviser goes beyond providing education and gives investment advice in a particular case, the Department does not believe it is appropriate to broadly exempt those communications from fiduciary liability. Moreover, the Department believes that such an exemption would be especially inappropriate in cases where a service provider offers educational services that systematically exceed the boundaries of education. In such cases, when firms or individuals make specific investment recommendations to plan participants, they should adhere to basic fiduciary norms of prudence and loyalty, and take appropriate measures to protect plan participants and beneficiaries from the potential harm caused by conflicts of interest.
Comments from various sources also expressed concern about employers and plan sponsors becoming fiduciary investment advisers as a result of educational communications and activities designed to inform employees about plans, plan investments, distribution options, retirement planning, and similar subjects. In many cases, those comments were submitted by financial services companies that might be engaged by an employer as opposed to the employer itself.
In the Department's view, in the case of an employer or other plan sponsor, an employer or plan sponsor would not become an investment advice fiduciary merely because the employer or plan sponsor engaged a service provider to provide investment advice or because a service provider engaged to provide investment education crossed the line and provided investment advice in a particular case. On the other hand, whether the service provider renders fiduciary advice or non-fiduciary education, the final rule does not change the well-established fiduciary obligations that arise in connection with the selection and monitoring of plan service providers. These issues were discussed in the 1996 Interpretive Bulletin (IB 96-1) on investment education (that many commenters urged the Department to adopt in full as the final rule). Specifically, as pointed out in the preamble to the proposal, although IB 96-1 would be formally removed from the CFR and replaced by the final rule, paragraph (e) of IB 96-1 provides generalized guidance under sections 405 and 404(c) of ERISA with respect to the selection by employers and plan fiduciaries of investment educators and the limits of their responsibilities. Specifically, paragraph (e) states:
As with any designation of a service provider to a plan, the designation of a person(s) to provide investment educational services or investment advice to plan participants and beneficiaries is an exercise of discretionary authority or control with respect to management of the plan; therefore, persons making the designation must act prudently and solely in the interest of the plan participants and beneficiaries, both in making the designation(s) and in continuing such designation(s). See ERISA sections 3(21)(A)(i) and 404(a), 29 U.S.C. 1002 (21)(A)(i) and 1104(a). In addition, the designation of an investment adviser to serve as a fiduciary may give rise to co-fiduciary liability if the person making and continuing such designation in doing so fails to act prudently and solely in the interest of plan participants and beneficiaries; or knowingly participates in, conceals or fails to make reasonable efforts to correct a known breach by the investment advisor. See ERISA section 405(a), 29 U.S.C. 1105(a). The Department notes, however, that, in the context of an ERISA section 404(c) plan, neither the designation of a person to provide education nor the designation of a fiduciary to provide investment advice to participants and beneficiaries would, in itself, give rise to fiduciary liability for loss, or with respect to any breach of part 4 of Title I of ERISA, that is the direct and necessary result of a participant's or beneficiary's exercise of independent control. 29 CFR 2550.404c-1(d). The Department also notes that a plan sponsor or fiduciary would have no fiduciary responsibility or liability with respect to the actions of a third party selected by a participant or beneficiary to provide education or investment advice where the plan sponsor or fiduciary neither selects nor endorses the educator or adviser, nor otherwise makes arrangements with the educator or adviser to provide such services.
The Department explained in the preamble to the 2015 Proposal that, unlike the remainder of the IB 96-1, this text does not belong in the investment advice regulation, and since the principles articulated in paragraph (e) are generally understood and accepted, re-issuing the paragraph as a stand-alone IB does not appear necessary or appropriate.
Although not specifically raised by these comments, it is important to emphasize that ERISA section 404(c) and the Department's regulations thereunder do not limit the liability of fiduciary investment advisers for the provision of investment advice regardless of whether or not they provide that advice pursuant to a statutory or administrative exemption. In fact, the statutory exemption in ERISA section 408(b)(14) and the administrative exemptions being finalized with this rule generally require the fiduciary investment adviser to specifically assume and acknowledge fiduciary responsibility for the provision of investment advice. ERISA section 404(c) provides relief for acts which are the direct and necessary result of a participant's or beneficiary's exercise of control. Although a participant or beneficiary may direct a transaction in his or her account pursuant to fiduciary investment advice, that direction would not mean that any imprudence in the advice or self-dealing violation by the fiduciary investment adviser in connection with the advice was the direct and necessary result of the participant's action. Accordingly, section 404(c) of ERISA would not provide any relief from liability for a
Moreover, in the case of an employer or plan sponsor, neither the employer, plan sponsor, nor their employees ordinarily receive fees or other compensation in connection with the educational services and materials that they provide to plan participants and beneficiaries. Thus, even if they crossed the line from education to actual investment advice, the absence of a fee or other compensation would generally preclude a finding that the communication constituted fiduciary investment advice. It is important to note, however, that communications from the plan administrator or other person in a fiduciary capacity would be subject to ERISA's general prudence duties notwithstanding the fact that the communications may not result in the person also becoming a fiduciary under ERISA's investment advice provisions.
In response to the comments suggesting that the Department adopt FINRA Notice 13-45 as a safe harbor for communications on benefit distributions, the FINRA notice did not purport to define a line between education and advice. The final rule seeks to ensure that all investment advice to retirement investors adheres to fiduciary norms, particularly including advice as critically important as recommendations on how to manage a lifetime of savings held in a retirement plan and on whether to roll over plan accounts. Following FINRA and SEC guidance on best practices is a good way for advisers to look out for the interests of their customers, but it does not give them a pass from ERISA fiduciary status.
With respect to the tax code provisions regarding required minimum distributions, the Department agrees with commenters that merely advising a participant or IRA owner that certain distributions are required by tax law would not constitute investment advice. Whether such “tax” advice is accompanied by a recommendation that constitutes “investment advice” would depend on the particular facts and circumstances involved.
As in the 2015 Proposal, paragraph (a)(1)(ii) of the final rule provides that a recommendation as to the “management” of securities or other investment property is fiduciary investment advice. Some commenters contended this provision could be read very broadly and asked for clarification as to the scope of activities covered by the term. These commenters were concerned that “management” could be read as duplicative of paragraph (a)(1)(i) of the proposal, which concerned recommendations on the “investment” of plan or IRA assets. The Department also received comments seeking clarification regarding this provision's impact on, for example, foreign exchange transactions, the internal operation of stable value funds, and options trading. Others questioned whether the recommendation of a general investment strategy or recommending use of a class of investment products fall within the meaning of the term “management” of plan or IRA assets, even in cases where a particular product is not recommended.
The Department agrees that further clarification of the concept of “management” in the final rule would be helpful. Accordingly, the final rule includes text from the 1975 regulation that gives examples of “investment management” that the Department believes will clarify the difference between investment recommendations and investment management recommendations. Specifically, the final rule includes text that describes management of securities or other investment property, as including, among other things, recommendations on investment policies or strategies, portfolio composition, or recommendations on distributions, including rollovers, from a plan or IRA. The final rule also adds another example to make it clear that recommendations to move from commission-based accounts to advisory fee based accounts would be fiduciary investment advice under this provision. As explained above and more fully below, the final rule also includes recommendations on the selection of other persons to provide investment advice or investment management services in this provision rather than in a separate provision.
The new text is consistent with FINRA guidance that makes it clear that recommendations on investment strategy are subject to the federal securities laws' “suitability” requirements regardless of whether the recommendation results in a securities transaction or even references a specific security or securities. Specifically, FINRA explained this requirement in a set of FAQs on Rule 2111:
The rule explicitly states that the term “strategy” should be interpreted broadly. The rule would cover a recommended investment strategy regardless of whether the recommendation results in a securities transaction or even references a specific security or securities. For instance, the rule would cover a recommendation to purchase securities using margin or liquefied home equity or to engage in day trading, irrespective of whether the recommendation results in a transaction or references particular securities. The term also would capture an explicit recommendation to hold a security or securities. While a decision to hold might be considered a passive strategy, an explicit recommendation to hold does constitute the type of advice upon which a customer can be expected to rely. An explicit recommendation to hold is tantamount to a “call to action” in the sense of a suggestion that the customer stay the course with the investment. The rule would apply, for example, when an associated person meets with a customer during a quarterly or annual investment review and explicitly advises the customer not to sell any securities in or make any changes to the account or portfolio. . . . (footnotes omitted)
FINRA Rule 2111 (Suitability) FAQ (available at
Some commenters suggested that the concept of “management” covered only proxy voting, and pointed to the preamble to the 2010 Proposal which stated that the “management of securities or other property” would
With respect to the comments seeking clarification of this provision's application to foreign exchange transactions, the internal operation of stable value funds, and options trading, the Department does not believe there is a need for special clarification. For example, recommendations on foreign exchange transactions and options trading clearly can involve recommendations on investment policies or strategies and portfolio composition. Whether any particular communication rises to the level of a recommendation would depend, as with any other communication to a plan or IRA investor, on context, content, and presentation. Thus, merely explaining the general importance of maintaining a diversified portfolio or describing how options work would not generally meet the regulation's definition of a covered “recommendation.” But if, on the other hand, the adviser recommends that the investor change the composition of her portfolio or pursue an option strategy, the adviser makes a recommendation covered by the rule. Similarly, a recommendation to transition from a commissionable account to a fee-based account would constitute a recommendation on the management of assets covered by the rule, and compensation received as a result of that recommendation could be a prohibited transaction for which an exemption would be required. The impact of the final rule in this regard should largely be limited to retail retirement investors because, to the extent the communications involve sophisticated financial professional or large money managers, the final rule's provision that allows such communications to be excluded from fiduciary investment advice should address the commenters' request for clarification.
The proposal included paragraph (a)(1)(iv) that separately treated recommendations on the selection of investment advisers for a fee as fiduciary investment advice. In the Department's view, the current 1975 regulation already covered such advice, as well as recommendations on the selection of other persons providing investment management services. The Department continues to believe that such recommendations should be treated as fiduciary in nature but concluded that presenting such hiring recommendations as a separate provision may have created some confusion among commenters, as discussed above.
Many commenters expressed concern about the effect of the proposal's paragraph (a)(1)(iv) on a service or investment provider's solicitation efforts on its own (or an affiliate's) behalf to potential clients, including routine sales or promotion activity, such as the marketing or sale of one's own products or services to plans, participants, or IRA owners. These commenters argued that the provision in the proposal could be interpreted broadly enough to capture as investment advice nearly all marketing activity that occurs during initial conversations with plan fiduciaries or other potential clients associated with hiring a person who would either manage or advise as to plan assets. Service providers argued that the proposal could preclude them from being able to provide information and data on their services to plans, participants, and IRA owners, during the sales process in a non-fiduciary capacity. For example, commenters questioned whether the mere provision of a brochure or a sales presentation, especially if targeted to a specific market segment, plan size, or group of individuals, could be fiduciary investment advice under the 2015 Proposal based on the express or implicit recommendation to hire the service provider. Commenters stated that a similar issue exists in the distribution and rollover context regarding a sales pitch to participants about potential retention of an adviser to provide retirement investment services outside of the plan.
Many commenters were also concerned that the provision would treat responses to requests for proposal (RFP) as investment advice, especially in cases where the RFP requires some degree of individualization in the response or where specific representations were included about the quality of services being offered. For example, a service provider may include a sample fund line up or discuss specific products or services as part of its RFP presentation. Commenters argued that this or similar individualization should not trigger fiduciary status in an RFP context. A specific example of this issue is whether and how providers can respond to inquiries concerning the mapping of plan investments, in which case they often are asked to provide specific examples of alternative investments; a few commenters indicated that the Department should clarify application of the rule in this context. Other commenters stated that the proposed regulation conflates two separate acts—(i) the recommendation to hire the adviser and (ii) the recommendation to make particular investments or to pursue particular investment strategies. Some commenters said the proposal would create a fiduciary obligation for the adviser to tell the potential investor if some other adviser could provide the same services for lower fees, for example. They described such an obligation as unprecedented and not commercially viable.
Some other commenters argued that recommendations on the engagement of an adviser is not “investment” advice at all, and suggested that the final rule should be limited to an adviser's recommendation on investments and services. These commenters explained that plan fiduciaries commonly look to existing consultants, attorneys, and other professionals for referrals to other service providers, and that service
The Department continues to believe that the recommendation of another person to be entrusted with investment advice or investment management authority over retirement assets is often critical to the proper management and investment of those assets and should be fiduciary in nature. Recommendations of investment advisers or managers are no different than recommendations of investments that the plan or IRA may acquire and are often, by virtue of the track record or information surrounding the capabilities and strategies that are employed by the recommended fiduciary, inseparable from the types of investments that the plan or IRA will acquire. For example, the assessment of an investment fund manager or management is often a critical part of the analysis of which fund to pick for investing plan or IRA assets. That decision thus is clearly part of a prudent investment analysis, and advice on that subject is, in the Department's view, fairly characterized as investment advice. Failing to include such advice within the scope of the final rule carries the risk of creating a significant gap or loophole.
It was not the intent of the Department, however, that one could become a fiduciary merely by engaging in the normal activity of marketing oneself or an affiliate as a potential fiduciary to be selected by a plan fiduciary or IRA owner, without making an investment recommendation covered by (a)(1)(i) or (ii). Thus, the final rule was revised to state, as an example of a covered recommendation on investment management, a recommendation on the selection of “other persons” to provide investment advice or investment management services. Accordingly, a person or firm can tout the quality of his, her, or its own advisory or investment management services or those of any other person known by the investor to be, or fairly identified by the adviser as, an affiliate, without triggering fiduciary obligations.
However, the revision in the final rule does not, and should not be read to, exempt a person from being a fiduciary with respect to any of the investment recommendations covered by paragraphs (a)(1)(i) or (ii). The final rule draws a line between an adviser's marketing of the value of its own advisory or investment management services, on the one hand, and making recommendations to retirement investors on how to invest or manage their savings, on the other. An adviser can recommend that a retirement investor enter into an advisory relationship with the adviser without acting as a fiduciary. But when the adviser recommends, for example, that the investor pull money out of a plan or invest in a particular fund, that advice is given in a fiduciary capacity even if part of a presentation in which the adviser is also recommending that the person enter into an advisory relationship. The adviser also could not recommend that a plan participant roll money out of a plan into investments that generate a fee for the adviser, but leave the participant in a worse position than if he had left the money in the plan. Thus, when a recommendation to “hire me” effectively includes a recommendation on how to invest or manage plan or IRA assets (
Some commenters stated that it is common practice for some service providers, such as recordkeepers, to be asked by customers to provide a list of names of investment advisers with whom the recordkeepers have existing relationships (
With respect to the question about whether a general recommendation to hire “an adviser” would constitute fiduciary investment advice even if the recommendation did not identify any particular person or group of persons to engage, the Department does not intend to cover such a recommendation within the prong of the final rule that requires a recommendation of an unaffiliated person. While it is possible that such a communication could be presented in a way that constituted a recommendation regarding the management of securities or other investment property, it seems unlikely, in most circumstances, for such a general recommendation to result in the person's receipt of a fee or compensation that would give rise to a prohibited transaction requiring compliance with the conditions of an exemption.
There was also concern that recommendations of service providers who themselves are not fiduciary investment advisers or investment managers, for example, because of a carve-out under the proposal, may be considered fiduciary advice whereas the underlying activity of the recommended service provider would not. The Department did not intend the proposal to reach recommendations of persons to provide services that did not constitute fiduciary investment advice or fiduciary investment management services. Although the Department agrees that potential conflicts of interest may exist with respect to recommendations to hire non-fiduciary service providers (
After carefully reviewing the comments, the Department has concluded that the issues related to valuations are more appropriately addressed in a separate regulatory initiative. Therefore, unlike the proposal, the final rule does not address appraisals, fairness opinions, or similar statements concerning the value of securities or other property in any way. Consequently, in the absence of regulations or other guidance by the Department, appraisals, fairness opinions and other similar statements will not be considered fiduciary investment advice for purposes of the final rule.
Paragraph (a)(1)(iii) of the 2015 Proposal, like the 1975 regulation, which included advice as to “the value of securities or other property,” covered certain appraisals and valuation reports. However, it was considerably more focused than the 2010 Proposal. Responding to comments to the 2010 Proposal, the 2015 Proposal in paragraph (a)(1)(iii) covered only appraisals, fairness opinions, or similar statements that relate to a particular investment transaction. Under paragraph (b)(5)(iii), the proposal also expanded the 2010 Proposal's carve-out for general reports or statements of value provided to satisfy required reporting and disclosure rules under ERISA or the Code. In this manner, the proposal focused on instances where the plan or IRA owner is looking to the appraiser for advice on the market value of an asset that the investor is considering to acquire, dispose, or exchange. The proposal also contained a carve-out at paragraph (b)(5)(ii) specifically addressing valuations or appraisals provided to an investment fund (
Many commenters requested that the Department narrow the scope of this provision of the proposal, or alternatively, expand the carve-outs on valuations to clarify that routine or ministerial, non-discretionary valuation functions that are necessary and appropriate to plan administration or integral to the offering and reporting of investment products are not fiduciary advice. Commenters also requested an explanation of what was meant by “in connection with a specific transaction” and explained that many appraisals support fairness opinions that fiduciary investment managers render in connection with specific transactions. Some commenters asked that the Department remove valuations of all types from the definition of investment advice because, in their view, valuations and appraisals are conceptually different from investment advice in that they involve questions of fact as to what an investment “is” worth, rather than qualitative assessments of what investment “should” be held, how they “should” be managed, and who “should” be hired. Further these commenters believe that the Department had not established the abuse that it is attempting to curb with this provision. Other commenters suggest that the Department reserve the issue of valuations pending further study. Other commenters suggested that the Department make certain exceptions for valuations provided to ESOPs regardless of whether the valuation is conducted on a transactional basis or if independent plan fiduciaries engaged the valuation provider. Some others suggested that the current professional standards for appraisers are sufficient or that the Department should develop its own.
Other commenters agree with the Department that appraisal and valuation information is extremely important to plans when acquiring or disposing of assets. Some also expressed concern that valuations can steer participants toward riskier assets at the point of distribution.
It continues to be the Department's opinion that, in many transactions, a proper appraisal of hard-to-value assets is the single most important factor in determining the prudence of the transaction. Accordingly, the Department believes that employers and participants could benefit from the imposition of fiduciary standards on appraisers when they value assets in connection with investment transactions. The Department believes that this is particularly true in the employer security valuation context in which the Department has seen some extreme cases of abuse. In the case of closely-held companies, ESOP trustees typically rely on professional appraisers and advisers to value the stock, often do not proceed with a transaction in the absence of an appraisal, and sometimes engage in little or no negotiation over price. In these cases, the appraiser effectively determines the price the plan pays for the stock with plan assets. Unfortunately, in investigations and enforcement actions, the Department has seen many instances of improper ESOP appraisals—often involving most or all of a plan's assets—resulting in hundreds of millions of dollars in losses.
After carefully considering the comments, the Department is persuaded that ESOP valuations present special issues that should be the focus of a separate project. The Department also believes that piecemeal determinations as to inclusions or exclusions of particular valuations may produce unfair or inconsistent results. Accordingly, rather than single out ESOP appraisers for special treatment under the final rule, the Department has concluded that it is preferable to broadly address appraisal issues generally in a separate project so that it can ensure consistent treatment of appraisers under ERISA's fiduciary provisions. Given the common issues and problems appraisers face, it is quite likely that the comments and issues presented to the Department by ESOP appraisers will be relevant to other appraisers as well.
As provided in paragraph (a)(2) of the final rule, a person would be considered a fiduciary investment adviser in connection with a recommendation of a type listed paragraph (a)(1) of the final rule, if the recommendation is made either directly or indirectly (
(i) Represents or acknowledges that it is acting as a fiduciary within the meaning of the Act or Code with respect to the advice described in paragraph (a)(1);
(ii) Renders the advice pursuant to a written or verbal agreement, arrangement or understanding that the advice is based on the particular investment needs of the advice recipient; or
(iii) Directs the advice to a specific advice recipient or recipients regarding the advisability of a particular investment or management decision
As in the proposal, under paragraph (a)(2)(i) of the final rule, advisers who claim fiduciary status under ERISA or the Code are required to honor their words. They may not say they are acting as fiduciaries and later argue that the advice was not fiduciary in nature. Several commenters focused on the provision in the proposal covering investment recommendations “if the person providing the advice, either directly or indirectly (
The Department does not agree that the suggested changes are necessary or appropriate. In general, it has been the longstanding view of the Department that when an individual acts as an employee, agent or registered representative on behalf of an entity engaged to provide investment advice to a plan, that individual, as well as the entity, would be investment advice fiduciaries under the final rule. The Department's intent also is to ensure that persons holding themselves out as fiduciaries with respect to investment advice to retirement investors cannot deny their fiduciary status if a dispute subsequently arises, but rather must honor their words. There is no one formulation that must be used to trigger fiduciary status in this regard, but rather the question is whether the person was reasonably understood to hold itself out as a fiduciary with respect to communications with the plan or IRA investor. If a person or entity does not want investment-related communications to be treated as fiduciary in nature, it should exercise care not to suggest otherwise. Moreover, some of the suggested changes with respect to affiliates could encourage “bait and switch” tactics where a person encourages individuals to seek fiduciary investment advice from an affiliate, but then later claims those communications are not relevant unless expressly ratified by the person in direct communications with an advice recipient. This is particularly true given the interrelated nature of affiliated financial service companies and their operations, and the likelihood that ordinary retirement investors will not know the details of a corporate family's legal structure or draw fine lines between different segments of the same corporate family. On the other hand, the mere fact that an affiliate acknowledged its fiduciary status for purposes other than rendering advice (for example, as a trustee) would not constitute a representation or acknowledgement that the person was acting as a fiduciary “with respect to” that person's investment-related communications.
The proposal alternatively required that “the advice be rendered pursuant to a written or verbal agreement, arrangement or understanding that the advice is individualized to, or that such advice is specifically directed to, the advice recipient for consideration in making investment or management decisions with respect to the plan or IRA.” Commenters focused on several aspects of this provision. First, they argued that the “specifically directed” and “individualized” prongs were unclear, overly broad, and duplicative, because any advice that was individualized would also be specifically directed at the recipient. Second, they said it was not clear whether there had to be an agreement, arrangement, or understanding that advice was specifically directed to a recipient, and, if so, what would be required for such an agreement, arrangement or understanding to exist. They expressed concern about fiduciary status possibly arising from a subjective belief of a participant or IRA investor. And third, they requested modification of the phrase “for consideration,” believing the phrase was overly broad and set the threshold too low for requiring that recommendations be made for the purpose of making investment decisions. A number of other commenters explicitly endorsed the phrases “specifically directed,” and “individualized to,” believing that these are appropriate and straightforward thresholds to attach fiduciary status.
As explained in the preamble to the 2015 Proposal, the parties need not have a subjective meeting of the minds on the extent to which the advice recipient will actually rely on the advice, but the circumstances surrounding the relationship must be such that a reasonable person would understand that the nature of the relationship is one in which the adviser is to consider the particular needs of the advice recipient. 80 FR 21940. The Department agrees, however, that the provision in the proposal could be improved and clarified. The final rule changes this provision in two respects. First, the phrase “for consideration” has been removed from the provision. After reviewing the comments, the Department believes that clause as drafted was largely redundant to the provisions in paragraph (a)(1) of the proposal and that the final rule sets forth the subject matter areas to which a recommendation must relate to constitute investment advice. The final rule thus revises the condition to require that advice be “directed to” a specific advice recipient or recipients regarding the advisability of a particular investment or management decision.” Second, although the preamble to the proposal stated that the “specifically directed to” provision, like the individualized advice provision, required that there be an agreement, arrangement or understanding that advice was specifically directed to the recipient, the Department agrees that using that terminology for both the individualized advice prong and the specifically directed to prong serves no useful purpose for defining fiduciary investment advice. The point of the proposal's language concerning advice specifically directed to an individual was to distinguish specific investment recommendations to an individual from “recommendations made to the general public, or to no one in particular.” 75 FR 21940. Examples included general circulation newsletters, television talk show commentary, and remarks in speeches and presentations at conferences. The final rule now includes a new provision (paragraph (b)(2)) to make clear that such general communications generally are not advice because they are not recommendations within the meaning of the final rule. A showing that an adviser directed a specific investment recommendation to a specific person
As the Department indicated in the preamble to the proposed regulation, advisers should not be able to specifically direct investment recommendations to individual persons, but then deny fiduciary responsibility on the basis that they did not, in fact, consider the advice recipient's individual needs or intend that the recipient base investment decisions on their recommendations. Nor should they be able to continue the practice of advertising advice or counseling that is one-on-one or tailored to the investor's individual needs and then use boilerplate language to disclaim that the investment recommendations are fiduciary investment advice.
Paragraph (b)(1) describes when a communication based on its context, content, and presentation would be viewed as a “recommendation,” a fundamental element in establishing the existence of fiduciary investment advice. Paragraph (b)(2) sets forth examples of certain types of communications which are not “recommendations” under that definition. With respect to paragraph (b) in the final rule, the Department noted in the proposal that the proposed general definition of investment advice was intentionally broad to avoid weaknesses of the 1975 regulation and to reflect the broad sweep of the statutory text. But, at the same time, the Department recognized that, standing alone, it could sweep in some relationships that are not appropriately regarded as fiduciary in nature. The proposal included “carve-outs” to exclude certain specified communications and activities from the scope of the definition of investment advice. Various public comments expressed concern or confusion regarding several of the carve-outs. The commenters said certain conduct under the carve-outs did not seem to fall within the scope of the general definition such that a “carve-out” was not necessary. They also expressed concern that classifying such conduct as within a “carve-out” might carry an implication that anything that did not technically meet the conditions of the carve-out would automatically meet the definition of investment advice. The Department agrees that the “carve-out” approach, both as a structural matter and as a matter of terminology, was not the best way to address the issue of delineating the scope of fiduciary investment advice. Accordingly, the final rule in paragraphs (b) (and (c) discussed below) uses an alternative approach, more analogous to that used by FINRA in addressing a similar issue under the securities laws, that involves expanding the definition of what constitutes a “recommendation.”
In the Department's view, whether a “recommendation” has occurred is a threshold issue and the initial step in determining whether investment advice has occurred. The proposal included a definition of recommendation in paragraph (f)(1): “[A] communication that, based on its content, context, and presentation, would reasonably be viewed as a suggestion that the advice recipient engage in or refrain from taking a particular course of action.” For example, FINRA Policy Statement 01-23 sets forth guidelines to assist brokers in evaluating whether a particular communication could be viewed as a recommendation, thereby triggering application of FINRA's Rule 2111 that requires that a firm or associated person have a reasonable basis to believe that a recommended transaction or investment strategy involving a security or securities is suitable for the customer.
Some commenters argued that the definition captured too broad a range of communications, citing as an example use of the term “suggestion” in the proposed definition and argued that it could be read so broadly that nearly every casual conversation between an adviser and a client could constitute investment advice. The commenters suggested that the definition require a “clear and affirmative endorsement” of a particular course of action. Some argued that their concerns could be addressed by formally adopting and citing FINRA standards as the operative text in the rule because they consider FINRA's standards to be appropriate in the context of defining fiduciary investment advice. Further, this would create consistency for service providers who must comply with both ERISA's and FINRA's requirements. Other commenters opposed wholesale adoption of FINRA standards because the final rule then would be subject to future changes or interpretations of the FINRA guidance that might not be consistent with the purposes of the conflict of interest rule. They also argued that such an approach would introduce ambiguities into the final rule because the concepts and terminology in the FINRA guidance pertained primarily to transactions involving brokers and securities, and those concepts and terminology might not be easily applied to other types of investment advisers and other types of investment advice transactions. For example, the FINRA guidance applies to recommendations to invest in securities, but the ERISA rule would also cover recommendations regarding investment advisory services.
In the final rule, the initial threshold of whether a person is a fiduciary by virtue of providing investment advice continues to be whether that person makes a recommendation as to the various activities described in paragraphs (a)(1)(i) and (ii). Paragraph (b)(1) of the final rule continues to define “recommendation” for purposes of paragraph (a) as a communication that, based on its content, context, and presentation, would reasonably be viewed as a suggestion that the advice recipient engage in or refrain from taking a particular course of action. Thus, communications that require the adviser to comply with suitability requirements under applicable securities or insurance laws will be viewed as a recommendation. The final rule also includes additional text intended to clarify the nature of communications that would constitute recommendations. The final rule makes
With respect to the comments that emphasized the breadth of the term “suggestion,” the Department notes that the same term is used in the FINRA guidance and securities laws and related regulations to define and establish standards related to investment recommendations. Accordingly, the Department does not believe the use of that term in the rule reasonably carries the risk alleged by some commenters. Nonetheless, the final rule includes new text to emphasize that there must be an investment “recommendation” as a threshold issue and initial step in determining whether investment advice has occurred, and clarifies that a recommendation requires that there be a call to action that a reasonable person would believe was a suggestion to make or hold a particular investment or pursue a particular investment strategy.
With respect to comments that suggested adopting the FINRA standard for recommendation, in the Department's view, FINRA guidance does not specifically define the term recommendation in a way that can be directly incorporated into the final rule. The Department agrees with commenters that strictly adopting FINRA guidance would mean that the final rule could be subject to changes in FINRA interpretations announced in the future and not reviewed or separately adopted by the Department as the appropriate ERISA standard. The Department, however, as described both here and elsewhere in the preamble, has taken an approach to defining “recommendation” that is consistent with and based upon FINRA's approach.
To further clarify the meaning of recommendation, the Department has stated that the rendering of services or materials in conformance with paragraphs (b)(2)(i) through (iv) would not be treated as a recommendation for purposes of the final rule. These paragraphs describe services or materials that provide general communications and commentary on investment products such as financial newsletters, which, with certain modifications, were identified as carve-outs under paragraph (b) of the proposal, such as marketing or making available a menu of investment alternatives that a plan fiduciary could choose from, identifying investment alternatives that meet objective criteria specified by a plan fiduciary, and providing information and materials that constitute investment education or retirement education.
Before discussing the specific carve-outs themselves, many commenters suggested that the Department clarify the relationship between the fiduciary definition under paragraph (a)(1) and (2) of the proposal and the carve-outs. Some commenters suggested that conduct described in certain carve-outs would not have been fiduciary in nature to begin with under the general definition of investment advice in the proposal under paragraph (a)(1) and (2). Others suggested that the Department clarify that the carve-outs are interpretative examples and do not imply that any particular conduct is otherwise fiduciary in nature.
As the Department described in the proposal, the purpose of the carve-outs was to highlight that in many circumstances, plan fiduciaries, participants, beneficiaries, and IRA owners may receive recommendations that, notwithstanding the general definition set forth in paragraph (a) of the proposal, should not be treated as fiduciary investment advice. The Department believed that the conduct and information described in those carve-outs were beneficial for plans, plan fiduciaries, participants, beneficiaries and IRA owners and wanted to make it clear that the furnishing of the described information would not be considered investment advice. However, the Department agrees with many of the commenters that much of the conduct and information described in the proposal for certain of the carve-outs did not meet the technical definition of investment advice under paragraph (a)(1) and (2) of the proposal such that they should be excluded from that definition. Some were more in the nature of examples of education or other information which would not rise to the level of a recommendation to begin with. Thus, the final rule retains these provisions, with changes made in response to comments, but presents them as examples to clarify the definition of recommendation and does not characterize them as carve-outs.
Paragraph (b)(2)(i) and (ii) of the final rule is directed to service providers, such as recordkeepers and third-party administrators, that offer a “platform” or selection of investment alternatives to participant-directed individual account plans and plan fiduciaries of these plans who choose the specific investment alternatives that will be made available to participants for investing their individual accounts. Paragraph (b)(2)(i) makes clear that such persons would not make recommendations covered under paragraph (b)(1) simply by making available, without regard to the individualized needs of the plan or its participants and beneficiaries, a platform of investment vehicles from which plan participants or beneficiaries may direct the investment of assets held in, or contributed to, their individual accounts, as long as the plan fiduciary is independent of the person who markets or makes available the investment alternatives and the person discloses in writing to the plan fiduciary that they are not undertaking to provide impartial investment advice or to give advice in a fiduciary capacity. For purposes of this paragraph, a plan participant or beneficiary will not be considered a plan fiduciary. Paragraph (b)(2)(ii) additionally makes clear that certain common activities that platform providers may carry out to assist plan fiduciaries in selecting and monitoring the investment alternatives that they make available to plan participants are not recommendations. Under paragraph (b)(2)(ii), identifying offered investment alternatives meeting objective criteria specified by the plan fiduciary,
These two paragraphs address certain common practices that have developed with the growth of participant-directed individual account plans and recognize circumstances where the platform provider and the plan fiduciary clearly understand that the provider has financial or other relationships with the offered investment alternatives and is not purporting to provide impartial investment advice. They also accommodate the fact that platform providers often provide general financial information that falls short of constituting actual investment advice or recommendations, such as information on the historic performance of asset classes and of the investment alternatives available through the provider. The provisions also reflect the Department's agreement with commenters that a platform provider who merely identifies investment alternatives using objective third-party criteria (
As an initial matter, while the provisions in paragraphs (b)(2)(i) and (b)(2)(ii) of the final rule are intended to facilitate the effective and efficient operation of plans by plan sponsors, plan fiduciaries and plan service providers, the Department reiterates its longstanding view, recently codified in 29 CFR 2550.404a-5(f) and 2550.404c-1(d)(2)(iv) (2010), that ERISA plan fiduciaries selecting the platform or investment alternatives are always responsible for prudently selecting and monitoring providers of services to the plan or designated investment alternatives offered under the plan.
Commenters requested confirmation that these provisions cover related services that are “bundled” with investment platforms. They claimed such services are an integral part of the platform offering. Some of these commenters focused on third-party administrative services and other assistance in connection with establishing a plan and its platform, such as standardized form 401(k) plans and information on investment options. Other commenters stated that platform providers must be able to communicate and explain services such as elective managed account programs, Qualified Default Investment Alternatives (QDIAs), investment adviser/manager options for participants, and non-affiliated registered investment adviser services that will provide platform selection and monitoring services. In response, the Department believes that much of this information described by these commenters does not involve an investment recommendation within the meaning of the rule. Further, other provisions in the final rule, such as the provisions on education, and selection and monitoring assistance, more directly address the issues raised by the commenters. Accordingly, the Department did not make any change in this provision based on these comments.
Several commenters also noted that the “platform” concept was not defined in the proposal, and stated that it was unclear, for example, whether the term “platform” encompassed a variety of lifetime income investment options, including group or individual annuities, or whether some other criteria also applied to the assessment of whether a proposed investment lineup constituted a platform (
Commenters also sought clarification as to the persons who could rely on both of the carve-outs relating to platform providers. As finalized by the Department, the language of the provisions in paragraphs (b)(2)(i) and (b)(2)(ii) of the final rule does not categorize or limit the persons who are engaged in the activities or communications. The language of these provisions deals with the activities themselves rather than classifying types of service providers that may evolve with market changes.
Some commenters requested clarification of the language requiring that the platform must be “without regard to the individual needs of the plan” in paragraph (b)(3) of the proposal. Commenters believe that platform providers often beneficially offer to plan sponsors one or more sample investment platforms that are tailored to the needs of plans in different industries or market segments. They believe some level of customization or individualization (an act they referred to as “segmentation”) should be permitted as offering the full array of product alternatives to every plan could be counter-productive to helping plan sponsors, especially in the small employer segment of the market. The commenters claimed that these winnowed bundles are not individualized offerings for particular plans, but rather are targeted categories of investments for different general types of plans in different market segments.
The Department generally agrees with these commenters that the marketing and making available of platforms segmented based on objective criteria would not result in providing fiduciary advice solely by virtue of the segmentation. Thus, for example, a platform provider who offers different platforms for small, medium, and large plans would not be providing investment advice merely because of this segmentation. In the Department's view, this type of activity is more akin to product development and is within the provider's discretion as a matter of business judgment, the same as if the provider decided not to offer platforms at all. Plan fiduciaries always are free to deal with vendors who do not design and offer platforms by market segment. Of course, a provider could find itself providing investment advice depending on the particular marketing technique used to promote a segmented platform. For example, if a provider were to communicate to the plan fiduciary of a small plan that a particular platform has been designed for small plans in general, and is appropriate for this plan in particular, the communication would likely constitute advice based on the individual needs of the plan and, therefore, very likely would be considered a recommendation.
In response to the Department's request for comment on whether the platform provider provision as it appeared in the proposal should be limited to large plans, many commenters opposed such a limitation arguing that the platform provider provision was needed to preserve assistance to small plan sponsors with respect to the composition of investment platforms in 401(k) and similar individual account plans. The final rule does not limit the platform provider provision to large plans.
Several commenters also asked the Department to clarify that the platform provider carve-out is available in the 403(b) plan marketplace. Since 403(b) plans are not subject to section 4975 of the Code, this issue is relevant only for 403(b) plans that are subject to Title I of ERISA. In the Department's view, a 403(b) plan that is subject to Title I of ERISA would be an individual account plan within the meaning of ERISA section 3(34) for purposes of the final rule. Thus, the platform provider provision is available with respect to such Title I plans.
Other commenters asked that the platform provider provision be generally extended to apply to IRAs. In the IRA context, however, there typically is no separate independent fiduciary who interacts with the platform provider to protect the interests of the account owners, or who is responsible for selecting the investments included in the platform. In the Department's view, when a firm or adviser narrows the wide universe of potential investments in the marketplace to a limited lineup that it holds out for consideration by an individual IRA owner, the fiduciary status of the communication is best evaluated under the general “recommendation” test, rather than under the specific exclusion for platform providers communicating with independent plan fiduciaries. Without an independent plan fiduciary overseeing the investment lineup and signing off on any disclaimers of reliance on the advice, there is too great a danger that the exclusion would effectively shield fiduciary recommendations from treatment as such, even though the IRA owner reasonably understood the communications as constituting individualized recommendations on how to manage assets for retirement. The Department is of a similar view with respect to plan participants who have individually directed brokerage accounts. Consequently, the final rule declines to extend application of the platform provider provisions to plan participants and beneficiaries, and IRAs.
Nonetheless, the Department notes that the separate provision in the final rule regarding transactions with independent plan fiduciaries with financial expertise would be available for persons providing advice to IRAs and plans regarding investment platforms. With respect to employee benefit plans in particular, the Department notes that the 2014 ERISA Advisory Council recently conducted a study and issued a report on “outsourcing” employee benefit plan services with a particular focus on functions that historically have been handled by employers, such as “named fiduciary” responsibilities. The Council report includes the following observation:
Outsourcing of benefit plan functions, administrative, investment and otherwise, is a practice that predates ERISA. However, its prevalence and scope have grown significantly since ERISA's passage, and has accelerated over the last ten years. Certain functions by their nature must be outsourced to a third party (
The Council's report is available at
Several commenters asked the Department to clarify whether the platform provider carve-out would cover a response to a RFP if the response were to contain a sample plan investment line-up based on the existing investment alternatives under the plan, the size of the plan or sponsor, or some combination of both. According to the commenters, responding to RFPs in this manner is a common practice when the plan fiduciary does not specify any, or sufficient, objective criteria, such as fund expense ratio, size of fund, type of asset, market capitalization, or credit quality. The commenters essentially argued that the plan's current investment line-up effectively serves as a proxy for objective criteria specified by the plan fiduciary. The commenters did admit, however, that even though such RFP responses typically present the line-ups as just “samples,” the responses customarily identify specific investment alternatives by name and are quite individualized to the needs of the requesting plan. The commenters, of course, emphasized that the plan fiduciary is under no obligation to hire the platform provider or to adopt the sample line-up of investments even if hired.
In response to these comments, minor changes were made to the proposal to accommodate such RFP responses, but with some protections for plan fiduciaries to prevent abuse. It was never the intent of the Department to displace common RFP practices related to platforms. The Department recognizes that RFPs can be a valuable cost-saving mechanism for plans by fostering competition among interested plan service providers, which can redound to the benefit of plan participants and beneficiaries in the form of lower costs for comparable services. Indeed, it is for this very reason that plan fiduciaries often use RFPs as part of the process of satisfying their duty of prudence under ERISA. On the other hand, without something more to counterbalance the RFP response with a sample line-up identifying investments by name, such communication could be viewed as suggesting the appropriateness of specific investments to the plan fiduciary—which, of course, would constitute a clear call to action to the fiduciary thereby triggering fiduciary status.
As revised, the platform provider provisions now explicitly clarify that a RFP response with a sample line-up of investments is not a “recommendation” for purposes of the final rule. Such treatment, however, is conditioned on written notification to the plan fiduciary that the person issuing the RFP response is not undertaking to provide impartial investment advice or to give advice in a fiduciary capacity. Further, the RFP response containing the sample line-up must disclose whether the person identifying the investment alternatives has a financial interest in any of the alternatives, and if so the precise nature of such interest. Collectively, these disclosures will put the plan fiduciary on notice that it should not have an expectation of trust in the RFP response and that composition of the sample line-up may be influenced by financial incentives not necessary aligned with the best interests of the plan and its participants.
Commenters also requested that the platform provider carve-out be extended to allow the platform provider to furnish for the plan fiduciary's consideration the objective criteria that the plan fiduciary may wish to adopt. Commenters state that plan sponsors are often unsure of what criteria are appropriate and that a service provider's objective assistance is often critical by suggesting factors that may be considered in evaluating and selecting investments. Although the Department does not believe that general advice as to the types to qualitative and quantitative criteria that similarly situated plan fiduciaries might consider in selecting and monitoring investment alternatives will ordinarily rise to the level of a recommendation of a particular investment, the Department does not believe it can craft text for this example that adequately addresses the potential for abuse and steering that could arise, and, therefore, believes the issue of whether such communications are investment advice would best be left to an examination on a case-by-case basis under the definition of recommendation provided by paragraph (b)(1) and educational communications under paragraphs (b)(2)(iii) and (b)(2)(iv).
The proposal under paragraph (b)(6) carved out investment education from the definition of investment advice. Paragraph (b)(6) of the proposal incorporated much of the Department's earlier Interpretive Bulletin, 29 CFR 2509.96-1 (IB 96-1), issued in 1996, but with important exceptions relating to communications regarding specific investment options available under the plan or IRA. Consistent with IB 96-1, paragraph (b)(6) of the proposal made clear that furnishing or making available the specified categories of information and materials to a plan, plan fiduciary, plan participant or beneficiary, or IRA owner does not constitute the rendering of investment advice, irrespective of who provides the information (
This subject received extensive input from a range of stakeholders with varying perspectives on how to draw the line between investment advice and investment education. Many commenters representing consumers and retail investors urged the Department not to create a carve-out that would allow investment advice to be presented as non-fiduciary “education.” These commenters cautioned that the final rule should not create a carve-out that is so broad that it covers communications or behavior that may fairly be interpreted by plan participants as “advice” rather than education. They cited the current practice by investment advice providers who present their services as individually tailored or “one-on-one” advice, but then use boilerplate disclaimers to avoid fiduciary responsibility for the advice under the Department's current “five-part” test regulation as a consumer protection failure that should not be repeated. Other commenters representing a range of interests and stakeholders expressed concern that the rule, and presumably the education carve-out, would adversely affect the availability of information to plan participants and beneficiaries, and IRA owners about the general characteristics and options available under the plan or IRA and general education about investments and retirement savings strategies.
There was general consensus, however, that investment education and financial literacy tools are valuable resources for retail retirement investors, that there is a difference between educational communications and activities, and that certain communications and activities should be subject to fiduciary standards as investment advice. Commenters, however, held varying views as to how the final rule should define the line between investment education and investment advice. A substantial number of the comments expressing concern about the proposal's impact on the availability of investment education to retail retirement investors appeared to be based on a misunderstanding of the proposal. For example, some commenters expressed concern that product providers could not provide general descriptions or information about their products and services without the communication being treated as investment advice under the rule. The proposal, as noted above, adopted almost without change an Interpretive Bulletin issued by the Department in 1996. IB 96-1 had been almost uniformly supported by the financial services industry. Admittedly IB 96-1 was issued against the backdrop of the current five-part test so that some of the commenters may have been less interested in its specifics because the five-part test allowed them to avoid fiduciary status for communications that fell outside the scope of non-fiduciary “education” as described in the IB 96-1. Nonetheless, IB 96-1 received substantial support from commenters as drawing an appropriate line between investment advice and investment education. IB 96-1 and, by extension, the proposal which adopted the IB, recognized four categories of non-fiduciary education:
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Furthermore, some comments from groups representing employers that sponsor plans, expressed concern that the proposal would lead employers to stop providing education about their plans to their employees. In the Department's view, since only investment advice for a fee or compensation falls within the fiduciary definition, the fact that employers do not generally receive compensation in connection with their educational communications provides employers with a high level of confidence that their educational activities would not constitute investment advice under the rule. In that regard, the Department does not believe that incidental economic advantages that may accrue to the employer by reason of sponsorship of an employee benefit plan would constitute fees or compensation within the meaning of the rule. For example, the Department does not believe that an employer would be receiving a fee or compensation under the rule merely because the plan is structured so the employer does not pay plan expenses that are paid out of an ERISA budget account funded with revenue sharing generated by investments under the plan.
Related comments similarly expressed concern that employers may not engage service providers to provide investment education to their plan participants and beneficiaries because of concern that the vendors may be investment advice fiduciaries under the rule, and the employers would have a fiduciary obligations or co-fiduciary liability in connection with the activities of those vendors. They contended that, without a blanket carve-out for plan sponsors and service providers that operate call centers to assist participants and IRA owners, educational assistance or similar participant outreach would be dramatically reduced or eliminated because, notwithstanding appropriate training and supervision, the plan sponsors and service providers could not be certain that individual communications would not carry potential fiduciary liability if individual communications actually crossed the line to give fiduciary investment advice. They similarly recommended that a blanket carve-out was necessary to protect against investment advice claims and litigation from participants and IRA owners dissatisfied with decisions they made with the benefit of education provided by the plan sponsor or service provider.
The Department notes that plan sponsors already have fiduciary obligations in connection with the selection and monitoring of plan service providers (both fiduciary and non-fiduciary service providers), including service providers that provide educational materials and assistance to plan participants and beneficiaries. In light of the investment education provisions in the final rule, the Department does not believe the rule significantly expands the obligations or potential liabilities of plan sponsors in this regard. It also bears emphasis that the chief consequence of making covered investment recommendations, rather than merely providing non-fiduciary education is that the fiduciary must give recommendations that are prudent and in the participants' best interest. The Department does not believe it would be appropriate to create a rule that relieves service providers from fiduciary responsibility when they in fact make such recommendations and thereby provide investment advice for a fee, nor would it be appropriate to have a rule that relieved plan sponsors or service providers from having to address complaints from participants and IRA owners that they in fact provided imprudent investment advice or provided investment advice tainted by prohibited self-dealing. The Department believes that such steps would be particularly inappropriate in the case of service providers who are paid to provide participant assistance services.
The final rule is intended to reflect the Department's continued view that the statutory reference to “investment advice” is not meant to encompass general investment information and educational materials, but rather is targeted at more specific recommendations and advice on the investment of plan and IRA assets. Further, as explained above, the Department agrees with those commenters who argued that classifying this provision as a “carve-out” was a misnomer because the educational activity covered by the provision are not investment recommendations in the first place. As a result, although the substance of the proposal is largely unchanged in this final rule, the “investment education” provision in
The final rule in paragraph (b)(2)(iv) divides investment education information and materials which will not be treated as recommendations into the same four general categories as set forth in the proposal: (A) Plan information; (B) general financial, investment, and retirement information; (C) asset allocation models; and (D) interactive investment materials. The final regulation also adopts the provision from the proposal (also in IB 96-1) stating that there may be other examples of information, materials and educational services which, if furnished, would not constitute investment advice or recommendations within the meaning of the final regulation and that no inference should be drawn regarding materials or information which are not specifically included in paragraph (b)(2)(iv).
Paragraph (b)(2)(iv), like the proposal, makes clear that the distinction between non-fiduciary education and fiduciary advice applies equally to information provided to plan fiduciaries as well as information provided to plan participants and beneficiaries, and IRA owners, and that it applies equally to participant-directed plans and other plans. In addition, the provision applies without regard to whether the information is provided by a plan sponsor, fiduciary, or service provider.
The Department did not receive adverse comments on the provisions in the proposal that were intended to make it clear that investment education included the provision of information and education relating to retirement income issues that extend beyond a participant's or beneficiary's date of retirement. Some commenters explicitly encouraged education in the context of fixed and variable annuities and other lifetime income products. Accordingly, paragraph (b)(2)(iv) of the final rule, as with the proposal, includes specific language to make clear that the provision of certain general information that helps an individual assess and understand retirement income needs past retirement and associated risks (
Similarly, the Department does not believe that any change in the regulatory text or addition of a specific safe harbor is necessary to address commenters' concerns regarding distinguishing advice from education in the context of benefit distribution decisions. As to the comments that suggested the Department expressly adopt FINRA's guidance in its Notice 13-45 as the standard for non-fiduciary educational information and materials, the Department does not agree that such an express incorporation of specific FINRA guidance into the regulation is advisable. In addition to the obvious problems that can arise from a federal agency adopting guidance from a self-regulatory organization as a formal regulation with the force of law, the Department is concerned that some of that guidance under the FINRA notice encompasses communications regarding individual investment alternatives or benefit distribution options that would be fiduciary investment advice under the final rule. Moreover, to the extent the commenters found the FINRA guidance useful because it allows descriptions of the typical four options available to participants when retiring—leaving the money in his former employer's plan, if permitted; rolling over the assets to his new employer's plan if available; rolling over to an IRA; or cashing out—those options, including discussions of the advantages and disadvantages of each are already clearly permitted under the education provision. The Department also believes the final rule contains appropriate examples of activities with respect to particular products sufficient to make it clear that education can convey information about investment concepts, such as annuities and lifetime income products, and does not believe amending the regulatory text to specifically emphasize or encourage particular classes of investment or benefit products would improve the provision.
The main focus of the commenters expressing concern, many representing financial services providers, about the education provisions in the proposal was the one substantive change the proposal made to the Department's IB 96-1. Specifically, the proposal did not allow asset allocation models and interactive investment materials to identify specific investment alternatives and distribution options unless they were affirmatively inserted into the interactive materials by the plan participant, beneficiary or IRA owner. A few commenters supported this change. They argued that participants are highly vulnerable to subtle, but powerful, influences by advisers when they receive asset allocation information. They believe that ordinary participants may view these models, particularly when accompanied by references to specific investments, as investment recommendations even if the provider does not intend it as advice and even if the provider includes caveats or statements about the availability of other products. In contrast, other commenters argued—particularly with respect to ERISA-covered plans—that it is a mistake to prohibit the use of specific investment options in asset allocation models used for educational purposes. They said this information is a critical step to “connect the dots” for retirement investors in understanding how to apply educational tools to the specific options or options available in their plan or IRA. They claimed that the inability to reference specific investment options in asset allocation models and interactive materials would greatly undermine the effectiveness of these models and materials as educational tools. They said that without the ability to include specific investment products, participants could have a hard time understanding how the educational materials relate to specific investment options. Further, some commenters argued that the Department had presented no evidence that there is actual abuse under the guidance in IB 96-1 that would support a change. With the change, the commenters asserted that the Department has effectively shifted the obligation to populate asset allocation models to plan participants, who for a variety of reasons are unlikely to do so, thereby significantly undermining what has become a valuable tool for participants.
Many commenters suggested ideas for how to address this issue. Some told the Department that it should not depart from the original IB 96-1 on this point. Some commenters argued that the value that plan participants and beneficiaries, and IRA owners, get from having specific investment options identified in asset allocation models and interactive materials was so important that the Department should adopt a safe harbor specifically for communications designed to assist plan participants and beneficiaries and IRA owners with decisions regarding investment alternatives and distribution options. Others suggested that the final rule should permit the identification of designated investment alternatives (DIAs) in asset allocation models with restrictions such as fee neutrality across the presented options, allow the selection of the investment options for the model by an independent third party, or require the model to offer at least three DIAs within each asset class (which may require some plans to
Some commenters drew a distinction between ERISA-covered plans and IRAs, and agreed with the Department's concern about permitting specific product references to be treated as non-fiduciary education when associated with asset allocation guidance for IRA customers. In the ERISA plan context, a separate fiduciary is responsible for overseeing the funds on the plan lineup and for making sure that the plan's designated investment alternatives are prudent and otherwise consistent with ERISA's standards. Potential “steering” by use of an asset allocation model can be effectively constrained by an already approved menu of DIAs, but no analogous protection exists for IRA investors. An adviser's limited explanation of how specific plan-designated alternatives line up with particular asset categories, without more, is far less likely to be perceived by the investor as an investment recommendation—and far less prone to abuse—than is an IRA adviser's discussion of particular asset allocations tied to specific investment products chosen by the adviser or his firm. In the IRA context, the adviser both presents the customer with an allocation and populates the allocation with specific products that the adviser or his firm screened from the entire universe of investments. A broad safe harbor for such communications could permit advisers to steer customers by effectively making specific investment recommendations under the guise of education, with no fiduciary protection.
Some commenters proposed different solutions for the presentation of specific investments to IRA owners. These proposed solutions tried to introduce somewhat analogous protections for IRA owners as for plan participants by making the identification of specific investment alternatives contingent on investment platforms selected or approved by independent third parties. Other commenters sought to eliminate the concern about asset allocation models and interactive materials being used to steer IRA investors to particular products that generated better fees for investment providers by requiring the available investment options to be “fee neutral” or paid for on a fixed basis.
After evaluation of the comments and considerations above, the Department has made the following adjustments in the final rule. Paragraphs (b)(2)(iv)(C)(
In this connection, it is important to emphasize that a responsible plan fiduciary would also have, as part of the ERISA obligation to monitor plan service providers, an obligation to evaluate and periodically monitor the asset allocation model and interactive materials being made available to the plan participants and beneficiaries as part of any education program.
The Department does not agree that the same conclusion applies in the case of presentations of specific investments to IRA owners because of the lack of review and prudent selection of the presented options by an independent plan fiduciary, and because of the likelihood that such “guidance” or “education” amounts to specific investment recommendations in the IRA context. The Department was not able to reach the conclusion that it should create a broad safe harbor from fiduciary status for circumstances in which the IRA provider effectively narrows the entire universe of investment alternatives available to IRA owners to just a few coupled with asset allocation models or interactive materials.
When an adviser couples a suggestion of a particular asset allocation with specific investment options that the adviser has specifically selected from the entire universe of investments, he is doing more than explaining how the limited designated investment alternatives available under a plan's design fit the various categories in an asset allocation model. Instead, the adviser is pointing out particular investments for special consideration, and likely making a “recommendation” within the meaning of the rule about an investment in which he has a financial interest. In the Department's view, such recommendations should be subject to a best interest standard, not treated as falling within a potential loophole for specific investment recommendations that need not adhere to basic fiduciary norms. If the adviser were treated as a non-fiduciary, the Department could not readily import the other protective conditions applicable to such plan communications to IRA communications. For example, there would not necessarily be any other fiduciary exercising oversight over the adviser's recommendation. Additionally, the Department was unable to conclude that disclosures analogous to the disclosures regarding DIAs under 29 CFR 2550.404a-5 could be made available about the vast universe of other comparable investment alternatives available under an IRA.
Similarly, because the provision is limited to DIAs available under employee benefit plans, the use of asset allocation models and interactive materials with specific investment alternatives available through a self-directed brokerage account is not covered by the “education” provision in the final rule. Such communications lack the safeguards associated with DIAs, and pose many of the same problems and dangers as identified with respect to IRAs.
These tools and models are important in the IRA and self-directed brokerage account context, just as in the plan context more generally. An asset
Many commenters, as the Department noted above, expressed concern about the phrase “specifically directed” in the proposal under paragraph (a)(2)(ii) and asked that the Department clarify the application of the final rule to certain communications including casual conversations with clients about an investment, distribution, or rollovers; responding to participant inquiries about their investment options; ordinary sales activities; providing research reports; sample fund menus; and other similar support activities. For example, they were concerned about communications made in newsletters, media commentary, or remarks directed to no one in particular. Commenters specifically raised the issue of whether on-air personalities like Dave Ramsey, Jim Cramer, or Suze Orman would be treated as fiduciary investment advisers based on their broadcast communications. The concern is unfounded. With respect to media personalities, the rule is focused on ensuring that paid investment professionals make recommendations that are in the best interest of retirement investors, not on regulating journalism or the entertainment industry. Nonetheless, and although the Department believes that the definition of “recommendation” in the proposal sufficiently distinguished such communications from investment advice, the Department has concluded that it would be helpful if the final rule more expressly addressed these types of communications to alleviate commenters' continuing concerns. Thus, the final rule includes a new “general communications” paragraph (b)(2)(iii) as an example of communications that are not considered recommendations under the definition. This paragraph affirmatively excludes from investment advice the furnishing of general communications that a reasonable person would not view as an investment recommendation, including general circulation newsletters; television, radio, and public media talk show commentary; remarks in widely attended speeches and conferences; research reports prepared for general distribution; general marketing materials; general market data, including data on market performance, market indices, or trading volumes; price quotes; performance reports; or prospectuses.
In developing this paragraph, the Department adapted some terms from FINRA guidance addressing a similar issue under the suitability rules for brokers. See, for example, FINRA Rule 2111 (Suitability) (FAQs available at
The Department notes that the requirement that a reasonable person would not view the materials as a recommendation is a recognition that even though the list includes very common communications that we do think could fairly be interpreted to cover communications that are investment recommendations under paragraph (b)(1), the label on the document or communication is not determinative under the final rule because there may be circumstances in which a person uses a label for a communications from the list but the communication nonetheless clearly meets the requirements of a recommendation under paragraph (b)(1).
Paragraph (c) of the final rule provides that certain communications and activities shall not be deemed to be fiduciary investment advice within the meaning of section 3(21)(A)(ii) of the Act. This paragraph incorporates, with modifications, the “carve-outs” from the proposal that addressed counterparty transactions, swaps transactions, and
Paragraph (b)(1)(i) of the proposed rule provided a carve-out (referred to as the “seller's” or “counterparty” carve-out) from the general definition for incidental advice provided in connection with an arm's length sale, purchase, loan, or bilateral contract between an expert plan investor and the adviser. The exclusion also applied in connection with an offer to enter into such an arm's length transaction, and when the person providing the advice acts as a representative, such as an agent, for the plan's counterparty. In particular, paragraph (b)(1)(i) of the proposal provided a carve-out for incidental advice provided in connection with counterparty transactions with a plan fiduciary with financial expertise. As a proxy for financial expertise the rule required that the advice recipient be a fiduciary of a plan with 100 or more participants or have responsibility for managing at least $100 million in plan assets. Additional conditions applied to each of these two categories of sophisticated investors that were intended to ensure the parties understood the non-fiduciary nature of the relationship.
Some commenters on the 2015 Proposal offered threshold views on whether the Department should include a seller's carve-out as a general matter or whether, for example, an alternative approach such as requiring specific disclosures would be preferable. Others strongly supported the inclusion of a seller's carve-out, believing it to be a critical component of the proposal. As explained in the proposal, the purpose of the proposed carve-out was to avoid imposing ERISA fiduciary obligations on sales pitches that are part of arm's length transactions where neither side assumes that the counterparty to the plan is acting as an impartial or trusted adviser. The premise of the proposed carve-out was that both sides of such transactions understand that they are acting at arm's length, and neither party expects that recommendations will necessarily be based on the buyer's best interests, or that the buyer will rely on them as such.
Consumer advocates generally agreed with the Department's views expressed in the preamble that it was appropriate to limit the carve-out to large plans and sophisticated asset managers. These commenters encouraged the Department to retain a very narrow and stringent carve-out. They argued that the communications to participants and retail investors are generally presented as advice and understood to be advice. Indeed, both FINRA and state insurance law commonly require that recommendations reflect proper consideration of the investment's suitability in light of the individual investor's particular circumstances, regardless of whether the transaction could be characterized as involving a “sale.” Additionally commenters noted that participants and IRA owners cannot readily ascertain the nuanced differences among different types of financial professionals (including differences in legal standards that apply to different professionals) or easily determine whether advice is impartial or potentially conflicted, or assess the significance of the conflict. Similar points were made concerning advice in the small plan marketplace.
These commenters expressed concern, shared by the Department, that allowing investment advisers to claim non-fiduciary status as “sellers” across the entire retail market would effectively open a large loophole by allowing brokers and other advisers to use disclosures in account opening agreements, investor communications, advertisements, and marketing materials to avoid fiduciary responsibility and accountability for investment recommendations that investors rely upon to make important investment decisions. Just as financial service companies currently seek to disclaim fiduciary status under the five-part test through standardized statements disclaiming the investor's right to rely upon communications as individualized advice, an overbroad seller's exception could invite similar statements that recommendations are made purely in a sales capacity, even as oral communications and marketing materials suggest expert financial assistance upon which the investor can and should rely.
On the other hand, many commenters representing financial services providers argued for extending the “seller's” carve-out to include transactions in the market composed of smaller plans and individual participants, beneficiaries and IRA owners. These commenters contended that the lines drawn in the proposal were based on a flawed assumption that representatives of small plans and individual investors cannot understand the difference between a sales pitch and advice. They argued that failure to extend the carve-out to these markets will limit the ability of small plans and individual investors to obtain advice and to choose among a variety of services and products that are best suited to their needs. They also argued that there is no statutory basis for distinguishing the scope of fiduciary responsibility based on plan size. Some commenters suggested that the Department could extend the carve-out to individuals that meet financial or net worth thresholds or to “accredited investors,” “qualified purchasers,” or “qualified clients” under federal securities laws. Some commenters also requested that the Department expand the persons and entities that would be considered “sophisticated” fiduciaries for purposes of the carve-out, for example asking that banks, savings and loan associations, and insurance companies be explicitly covered. Others alternatively argue that the carve-out should be expanded to fiduciaries of participant-directed plans regardless of plan size, which they said is not a reliable predictor for financial sophistication, or if the plan is represented by a financial expert such as an ERISA section 3(38) investment manager or an ERISA qualified professional asset manager. Other commenters asked that the carve-out be expanded to all proprietary products on the theory that investors generally understand that a person selling proprietary products is going to be making recommendations that are biased in favor of the proprietary product. Others suggested that the Department could address its concern about retail investor confusion by requiring specified disclosures, warranties, or representations to investors or small plan fiduciaries.
Other commenters argued that communications by product manufacturers and other financial services providers directed to financial intermediaries who then directly advise plans, participants, beneficiaries or IRA owners should not be investment advice within the meaning of the rule. Some commenters referred to this as “wholesaling” activities or “daisy chain” relationships. Some assert that a wholesaler's suggestions or recommendations about funds and sample plan line-ups, even if viewed as
Some commenters sought elimination of the requirement that counterparties obtain a representation concerning the plan fiduciary's sophistication. They argued that a counterparty's reasonable belief as to such sophistication should be sufficient or that there should be a presumption of such sophistication absent clear evidence otherwise. Finally, commenters questioned the requirement that no direct fee may be paid by the plan in connection with the transaction. Some argued that the condition should be removed, while others asked for clarification of what constitutes a fee for this purpose, for example whether it includes payments through plan assets and whether “direct” fees include the receipt of asset management or incentive fees received from a fund or other investment manager.
The Department does not believe it would be consistent with the language or purposes of ERISA section 3(21) to extend this exclusion to advice given to small retail employee benefit plan investors or IRA owners. The Department explained its rationale in the preamble to the proposal. In summary, retail investors were not included in this carve-out because (1) the Department did not believe the relationships fit the arm's length characteristics that the seller's carve-out was designed to preserve; (2) the Department did not believe disclaimers of adviser status were effective in alerting retail investors to nature and consequences of the conflicting financial interests; (3) IRA owners in particular do not have the benefit of a menu selected or monitored by an independent plan fiduciary; (4) small business sponsors of small plans are more like retail investors compared to large companies that often have financial departments and staff dedicated to running the company's employee benefit plans; (5) it would be inconsistent with congressional intent under ERISA section 408(b)(14) to create such a broad carve-out, as most recently reflected in enactment of a statutory provision that placed substantial conditions on the provision of investment advice to individual participants and IRA owners; and (6) there were other more appropriate ways to ensure that such retail investors had access to investment advice, such as prohibited transaction exemptions, and investment education. In addition, and perhaps more fundamentally, the Department rejects the purported dichotomy between a mere “sales” recommendation, on the one hand, and advice, on the other in the context of the retail market for investment products. As reflected in financial service industry marketing materials, the industry's comment letters reciting the guidance they provide to investors, and the obligation to ensure that recommended products are at least suitable to the individual investor, sales and advice go hand in hand in the retail market. When plan participants, IRA owners, and small businesses talk to financial service professionals about the investments they should make, they typically pay for, and receive, advice.
The Department continues to believe for all of those reasons that it would be an error to provide a broad “seller's” exemption for investment advice in the retail market. Recommendations to retail investors and small plan providers are routinely presented as advice, consulting, or financial planning services. In fact, in the securities markets, brokers' suitability obligations generally require a significant degree of individualization. Most retail investors and many small plan sponsors are not financial experts, are unaware of the magnitude and impact of conflicts of interest, and are unable effectively to assess the quality of the advice they receive. IRA owners are especially at risk because they lack the protection of having a menu of investment options chosen by an independent plan fiduciary charged to protect their interests. Similarly, small plan sponsors are typically experts in the day-to-day business of running an operating company, not in managing financial investments for others. In this retail market, such an exclusion would run the risk of creating a loophole that would result in the rule failing to make any real improvement in consumer protections because it could be used by financial service providers to evade fiduciary responsibility for their advice through the same type of boilerplate disclaimers that some advisers use to avoid fiduciary status under the current “five-part test” regulation.
The Department also is not prepared to conclude that written disclosures, including models developed by the Department, are sufficient to address investor confusion about financial conflicts of interest. Although some commenters urged the Department to focus on the delivery of comprehensive disclosures to investors as preferable to imposing a fiduciary duty with related exemptions and offered various views on format, content, e-disclosure, cost, and related issues, the Department was not persuaded. Other commenters, however, countered with the view that disclosure is not sufficient as a substitute for the establishment of an affirmative fiduciary duty. Disclosure alone has proven ineffective to mitigate conflicts in advice. Extensive research has demonstrated that most investors have little understanding of their advisers' conflicts of interest, and little awareness of what they are paying via indirect channels for the conflicted advice. Even if they understand the scope of the advisers' conflicts, many consumers are not financial experts and therefore, cannot distinguish good advice or investments from bad. The same gap in expertise that makes investment advice necessary and important frequently also prevents investors from recognizing bad advice or understanding advisers' disclosures. As noted above in the summary “Benefit-Cost Assessment,” some research suggests that even if disclosure about conflicts could be made simple and clear, it could be ineffective—or even harmful. In addition to problems with the effectiveness of such disclosures, the possibility of inconsistent oral representations raises questions about whether any boilerplate written disclosure could ensure that the person's financial interest in the transaction is effectively communicated as being in conflict with the interests of the advice recipient.
Further, the Department is not prepared to adopt the approach suggested by some commenters that the provision be expanded to include individual retail investors through an accredited or sophisticated investor test that uses wealth as a proxy for the type of investor sophistication that was the
In developing this provision of the final rule, the Department carefully considered the comments from several financial services providers who argued that the Department's proposal violated traditional legal principles that they say recognize the right of businesses to market their products and services. These comments also argued that the proposal's protection for retail investors somehow disrespected the ability of retail investors to differentiate bad advice from good advice. The Department does not believe these comments have merit or require the adoption of a broad based “seller's” exception for the retail market. None of the commenters pointed to any provision in the federal securities laws containing a “seller's” carve-out or similar concept used to draw distinctions between advice relationships that are fiduciary from non-fiduciary under the federal securities laws. See also NAIC Model Regulation 275 on application of suitability standards to recommendations to retail investors involving annuity product transactions (available at
Moreover, the Department does not believe there is merit to the arguments that traditional legal principles support such a broad-based carve out from fiduciary status. The commenters' arguments, in the Department's view, essentially ask the Department to adopt a modified version of a “caveat emptor” or “buyer beware” principle that once prevailed under traditional contract law. That principle does not govern regulation of modern market relationships, particularly in regulated industries, and is incongruent to what, absent a regulatory exemption of the sort requested by the commenters, would be a fiduciary relationship subject to the highest legal standards of trust and loyalty. It is particularly incongruent with a statutory scheme that is designed to protect the interests of workers in tax-preferred assets that support their financial security and physical health, and that broadly prohibits conflicted transactions because of the dangers they pose, unless the Department grants an exemption based on express findings that the exemption is in the interest of participants and IRA owners and protective of their interests. Also, while some commenters supporting such a broad carve out have suggested that an enhanced disclosure regime would protect investors from conflicts of interest, as described elsewhere in this Notice in more detail, their arguments are not persuasive. A disclosure regime, standing alone, would not obviate conflicts of interest in investment advice even if it were possible to flawlessly disclose complex fee and investment structures.
Nonetheless, the Department agrees with the commenters that criticized the proposal with arguments that the criteria in the proposal were not good proxies for appropriately distinguishing non-fiduciary communications taking place in an arm's length transaction from instances where customers should reasonably be able to expect investment recommendations to be unbiased advice that is in their best interest. The Department notes that the definition of investment advice in the proposal expressly required a recommendation directly to a plan, plan fiduciary, plan participant, or IRA owner. The use of the term “plan fiduciary” in the proposal was not intended to suggest that ordinary business activities among financial institutions and licensed financial professionals should become fiduciary investment advice relationships merely because the institution or professional was acting on behalf of an ERISA plan or IRA. The “100 participant plan” threshold was borrowed from annual reporting provisions in ERISA that were designed to serve different purposes related to simplifying reporting for small plans and reducing administrative burdens on small businesses that sponsor employee benefit plans. The “$100 million in assets under management” threshold was a better proxy for the type of financial capabilities the carve-out was intended to capture, but it failed to include a range of financial services providers that fairly could be said to have the financial capabilities and understanding that was the focus of the carve-out.
Thus, after carefully evaluating the comments, the Department has concluded that the exclusion is better tailored to the Department's stated objective by requiring the communications to take place with plan or IRA fiduciaries who are independent from the person providing the advice and are either licensed and regulated providers of financial services or plan fiduciaries with responsibility for the management of $50 million in assets. This provision does not require that the $50 million be attributable to only one plan, but rather allows all the plan and non-plan assets under management to be included in determining whether the threshold is met. Such parties should have a high degree of financial sophistication and may often engage in arm's length transactions in which neither party has an expectation of reliance on the counterparty's recommendations. The final rule revises and re-labels the carve-out in a new paragraph (c)(1) that provides that a person shall not be deemed to be a fiduciary within the meaning of section 3(21)(A)(ii) of the Act solely because of the provision of any advice (including the provision of asset allocation models or other financial analysis tools) to an independent person who is a fiduciary of the plan or IRA (including a fiduciary to an investment contract, product, or entity that holds plan assets as determined pursuant to sections 3(42) and 401 of the Act and 29 CFR 2510.3-101) with respect to an arm's length sale, purchase, loan, exchange, or other transaction involving the investment of
Whether a party is “independent” for purposes of the final rule will generally involve a determination as to whether there exists a financial interest (
Additional conditions are intended to ensure that this provision in the final rule is limited to circumstances that involve true arm's length transactions between investment professionals or large asset managers who do not have a legitimate expectation that they are in a relationship of trust and loyalty where they fairly can rely on the other person for impartial advice. Specifically, the person must also fairly inform the independent plan fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and must fairly inform the independent plan fiduciary of the existence and nature of the person's financial interests in the transaction. The person must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies. The final rule expressly provides that the person may rely on written representations from the plan or independent fiduciary to satisfy this condition. The person must know or reasonably believe that the independent fiduciary is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this requirement). In the Department's view, this condition is designed to ensure that the parties, including the plan or IRA, understand the nature of their relationships. Finally, the person must not receive a fee or other compensation directly from the plan, or plan fiduciary, for the provision of investment advice (as opposed to other services) in connection with the transaction. If a plan expressly pays a fee for advice, the essence of the relationship is advisory, and subject to the provisions of ERISA and the Code. Thus, the person may not charge the plan a direct fee to act as an adviser with respect to the transaction, and then disclaim responsibility as a fiduciary adviser by asserting that he or she is merely an arm's length counterparty.
In formulating this provision in the final rule, the Department considered FINRA guidance on a similar issue under the federal securities laws. Specifically, FINRA guidance provides that the suitability rule in federal securities law applies to a broker-dealer's or registered representative's recommendation of a security or investment strategy involving a security to a “customer.” FINRA's definition of a customer in FINRA Rule 0160 excludes a “broker or dealer.” In explaining this exclusion, FINRA has noted that:
[I]n general, for purposes of the suitability rule, the term customer includes a person who is not a broker or dealer who opens a brokerage account at a broker-dealer or purchases a security for which the broker-dealer receives or will receive, directly or indirectly, compensation even though the security is held at an issuer, the issuer's affiliate or a custodial agent (
The $50 million threshold in the final rule for “other plan fiduciaries” is similarly based upon the definition of “institutional account” in FINRA rule 4512(c)(3) to which the suitability rules of FINRA rule 2111 apply and responds to the requests of commenters that the test for sophistication be based on market concepts that are well understood by brokers and advisers. Specifically, FINRA Rule 2111(b) on suitability and FINRA's “books and records” Rule 4512(c) both use a definition of “institutional account,” which means the account of a bank, savings and loan association, insurance company, registered investment company, registered investment adviser, or any other person (whether a natural person, corporation, partnership, trust or otherwise) with total assets of at least $50 million. Id. at Q&A 8.1. In regard to the “other person” category, FINRA's rule had used a standard of at least $10 million invested in securities and/or under management, but revised it to the current $50 million standard. Id. at footnote 80. In addition, the FINRA rule requires: (1) That the broker have “a reasonable basis to believe the institutional customer is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies involving a security or securities” and (2) that “the institutional customer affirmatively indicates that it is exercising independent judgment.”
The Department intends that a person seeking to avoid fiduciary status under this exception has the burden of demonstrating compliance with all applicable requirements of the limitation. Whether the burden is met in any particular case will depend on the individual facts and circumstances. For example, with regard to comments asking for clarification regarding the timing of the required disclosures, in particular whether the required representations have to be made on a transaction-by-transaction basis or could be made more generally when establishing the relationship, nothing in the final rule requires the disclosures to be on an individual transaction basis or prohibits the disclosures from being framed to cover a broader range of transactions. Whether particular disclosures satisfy the conditions in the final rule would depend on the transaction or transactions involved and the substance and timing of the disclosures that are being proffered as satisfying the condition.
Finally, although the seller's carve-out is not available under the final rule in the retail market for communications directly to retail investors, the Department notes that the final rule includes other provisions that are more appropriate ways to address some concerns raised by commenters and ensure that small plan fiduciaries, plan participants, beneficiaries, and IRA owners would be able to obtain essential information regarding important decisions they make regarding their investments without the providers of that information crossing the line into providing recommendations that would be fiduciary in nature. Under paragraph (b)(2) of the final rule, platform providers (
Further, in the absence of a recommendation, nothing in the final rule would make a person an investment advice fiduciary merely by reason of selling a security or investment property to an interested buyer. For example, if a retirement investor asked a broker to purchase a mutual fund share or other security, the broker would not become a fiduciary investment adviser merely because the broker purchased the mutual fund share for the investor or executed the securities transaction. Such “purchase and sales” transactions do not include any investment advice component. The final rule has a specific provision in paragraph (e) that expressly confirms that conclusion in connection with the execution of securities transactions by broker-dealers, certain reporting dealers, and banks.
The proposal included a “carve-out” intended to make it clear that communications and activities engaged in by counterparties to ERISA-covered employee benefit plans in swap and security-based swap transactions did not result in the counterparties becoming investment advice fiduciaries to the plan. As explained in the preamble to the 2015 Proposal, swaps and security-based swaps are a broad class of financial transactions defined and regulated under amendments to the Commodity Exchange Act and the Securities Exchange Act of 1934 by the Dodd-Frank Act. Section 4s(h) of the Commodity Exchange Act (7 U.S.C. 6s(h)) and section 15F of the Securities Exchange Act of 1934 (15 U.S.C. 78o-10(h) establish similar business conduct standards for dealers and major participants in swaps or security-based swaps. Special rules apply for swap and security-based swap transactions involving “special entities,” a term that includes employee benefit plans covered under ERISA. Under the business conduct standards in the Commodity Exchange Act as added by the Dodd-Frank Act, swap dealers or major swap participants that act as counterparties to ERISA plans, must, among other conditions, have a reasonable basis to believe that the plans have independent representatives who are fiduciaries under ERISA. 7 U.S.C. 6s(h)(5). Similar requirements apply for security-based swap transactions. 15 U.S.C 78o-10(h)(4) and (5). The CFTC has issued a final rule to implement these requirements and the SEC has issued a proposed rule that
A commenter asked that the Department confirm in the final rule that this provision includes communications and activities in swaps and security-based swaps that are not cleared by a central counterparty. In the view of the Department, there are differences in the characteristics of cleared and uncleared swaps. For example, uncleared swaps can be highly-customizable, bespoke agreements subject to extensive negotiation. In contrast, we understand that cleared swaps and cleared security-based swaps tend to offer greater standardization and increased transparency of terms and pricing. In addition, cleared swaps and cleared security-based swaps may have other beneficial characteristics that may be important to ERISA plans, such as greater liquidity and centrally managed counterparty risk. Thus, there are issues that a plan fiduciary must consider in evaluating whether to engage in a swap transaction through a cleared or uncleared channel. However, the Dodd-Frank Act provisions apply the business conduct standards similarly to cleared and uncleared swap transactions involving employee benefit plans. Accordingly, notwithstanding the difference between cleared and uncleared swap transactions, the Department does not believe the potential consequences under this final rule should be different for cleared versus uncleared swap and security-based swap transactions with respect to whether compliance with the business conduct standards could result in swap dealers, security-based swap dealers, major swap participants, and major security-based swap participants becoming investment advice fiduciaries under the final rule.
Thus, paragraph (c)(2) of the final rule is intended to confirm that persons acting as swap dealers, security-based swap dealers, major swap participants, and major security-based swap participants do not become investment advice fiduciaries as a result of communications and activities conducted during the course of swap or security-based swap transactions regulated under the Dodd-Frank Act provisions in the Commodity Exchange Act or the Securities Exchange Act of 1934 and applicable CFTC and SEC implementing rules and regulations. The provision in the final rule requires in such transactions that (1) in the case of a swap dealer or security-based swap dealer, the person must not be acting as an advisor to the plan, within the meaning of the applicable business conduct standards under the Commodity Exchange Act or the Securities Exchange Act, (2) the employee benefit plan must be represented in the transaction by an independent plan fiduciary,
Some commenters indicated that the swaps and security-based swaps provision in the proposal was too narrow because it was limited to “counterparties,” and, accordingly, did not include other parties with roles in cleared swap or cleared security-based swap transactions. The commenters said it is common for a clearing firm to provide its customers with information, such as valuations, pricing and liquidity information that is important to customers in deciding whether to execute, maintain, or liquidate swap or security-based swap positions, or the collateral supporting these positions. Clearing firms in this context means members of a derivatives clearing organization or members of a clearing agency as compared to the derivatives clearing organization or clearing agency itself. According to this commenter, if clearing firms are deterred from providing these services due to the risk of being a fiduciary under the final rule, customers may receive less information and make less-informed decisions, which decisions could also result in greater risks for the clearing firms. The commenter indicated that as a result, the clearing role, which Congress considered important, could be compromised. The Department understands that a central concern of the comments in this area focused on the possibility that providing valuation, pricing, and liquidity information would constitute fiduciary investment advice under the provision in the 2015 Proposal that included appraisals and valuations. As noted elsewhere in this Notice, that provision was not carried forward in the final rule, but was reserved for future consideration. Thus, providing such valuation, pricing, and liquidity information would not give rise to potential status as an investment advice fiduciary under the final rule. Nonetheless, the commenters asked that clearing firms be expressly included in the swap and security-based swap provision in the final rule. The final rule has been adjusted accordingly.
The Department, however, is not prepared to include a more open-ended class of “other similar service providers” in the swap and security-based swap provision in the final rule. It was not clear from the information submitted by the commenter who requested such an expansion of the provision who these service providers
This same commenter also questioned whether the provisions in the proposal were intended to change the conclusions of Advisory Opinion 2013-01A regarding the fiduciary and party in interest status of certain parties involved in the clearing process, such as clearing firms and clearinghouses. The conclusions in Advisory Opinion 2013-01A did not involve interpretations of the investment advice fiduciary provision in ERISA section 3(21)(A)(ii). Rather, they involved other elements of the fiduciary definition under section 3(21). Accordingly, the final rule does not change the conclusions expressed in the advisory opinion.
Some commenters argued that IRA owners should be able to engage in a swap and security-based swap transaction under appropriate circumstances, assuming the account owner is an “eligible contract participant.” The Department notes that IRAs and IRA owners would not appear to be “special entities” under the Dodd-Frank Act provisions and transactions with IRAs would not be subject to the business conduct standards that apply to cleared and uncleared swap and security-based swap transactions with employee benefit plans. Moreover, for the same reasons discussed elsewhere in this Notice that the Department declined to adopt a broad “seller's” exception for retail retirement investors, the Department does not believe extending the swap and security-based swap provisions to IRA investors is appropriate. Rather, as described below, the Department concluded that it was more appropriate to address this issue in the context of the “independent plan fiduciary with financial expertise” provision described elsewhere in this Notice.
Some commenters requested that the swap and security-based swap provision include transactions involving pooled investment funds, and other alternative investments, including specifically futures contracts. The Department does not believe it has an adequate basis for a wholesale expansion of the swaps and security-based swap provision to other classes of investments that are not subject to the business conduct standards in the Dodd-Frank Act regarding swaps and security-based swaps. Rather, the final rule's general provision relating to transactions with “independent plan fiduciaries with financial expertise” (paragraph (c)(1)) has been significantly adjusted and expanded from the so-called “counterparty” carve-out in the proposal. That provision in the final rule gives an alternative avenue for parties involved in futures, alternative investments, or other investment transactions to conduct the transaction in a way that would ensure they do not become investment advice fiduciaries under the final rule. With respect to pooled investment funds that hold plan assets, the same “independent plan fiduciary” provision is available for swap and security-based swap transactions involving pooled investment vehicles managed by independent fiduciaries.
Paragraph (c)(3) of the final rule provides that a person is not an investment advice fiduciary if, in his or her capacity as an employee of the plan sponsor of a plan, as an employee of an affiliate of such plan sponsor, as an employee of an employee benefit plan, as an employee of an employee organization, or as an employee of a plan fiduciary, the person provides advice to a plan fiduciary, or to an employee (other than in his or her capacity as a participant or beneficiary of a plan) or independent contractor of such plan sponsor, affiliate, or employee benefit plan, provided the person receives no fee or other compensation, direct or indirect, in connection with the advice beyond the employee's normal compensation for work performed for the employer.
This exclusion from the scope of the fiduciary investment advice definition addresses concerns raised by public comments seeking confirmation that the rule does not include as investment advice fiduciaries employees working in a company's payroll, accounting, human resources, and financial departments, who routinely develop reports and recommendations for the company and other named fiduciaries of the sponsors' plans. The exclusion was revised to make it clear that it covers employees even if they are not the persons ultimately communicating directly with the plan fiduciary (
Similarly, and as requested by commenters, the exclusion covers communications between employees, such as human resources department staff communicating information to other employees about the plan and distribution options in the plan subject to certain conditions designed to prevent the exclusion from covering employees who are in fact employed to provide investment recommendations to plan participants or otherwise becoming a possible loophole for financial services providers seeking to avoid fiduciary status under the rule. Specifically, the exclusion covers circumstances where an employee of the plan sponsor of a plan, or as an employee of an affiliate of such plan sponsor, provides advice to another employee of the plan sponsor in his or her capacity as a participant or beneficiary of the plan, provided the person's job responsibilities do not involve the provision of investment advice or investment recommendations, the person is not registered or licensed under federal or state securities or insurance laws, the advice they provide does not require the person to be registered or licensed under federal or state securities or insurance laws, and the person receives no fee or other compensation, direct or indirect, in
Paragraph (d) confirms that a person who is a fiduciary with respect to the assets of a plan or IRA by reason of rendering investment advice defined in the general provisions of the final rule shall not be deemed to be a fiduciary regarding any assets of the plan or IRA with respect to which that person does not have or exercise any discretionary authority, control, or responsibility or with respect to which the person does not render or have authority to render investment advice defined by the final rule, provided that nothing in paragraph (d) exempts such person from the provisions of section 405(a) of the Act concerning liability for violations of fiduciary responsibility by other fiduciaries or excludes such person from the definition of party in interest under section 3(14)(B) of the Act or section 4975(e)(2) of the Code. This provision is unchanged from the current 1975 regulation and the 2015 Proposal. Although this is long-held guidance, there were a number of comments on this provision. Many commenters asked whether the Department could clarify whether parties may limit the scope and timeframe for a fiduciary relationship, including when the fiduciary relationship is terminated. Many commenters asked the Department to clarify the point in time during a transaction when investment advice takes place, such that the fiduciary standard is triggered. Some commenters argued that the parties to the advice arrangement should be able to define fiduciary relationships for themselves, including whether a fiduciary role is intended. Others suggested that there should be a time period during which an investor could reasonably rely upon the advice provided. Other commenters requested clarification as to whether there is an ongoing duty to monitor the advice once it was provided. Other commenters requested clarification on the interaction of the proposal with existing DOL guidance on fiduciary responsibility such as advisory opinions on fee neutrality or the use of independently designed computer models
The final rule defines the circumstances when a person is providing fiduciary investment advice. Paragraph (d) merely confirms longstanding guidance that, except for co-fiduciary liability under section 405(a) of the Act, being an investment advice fiduciary for certain assets of a plan or IRA does not make that person a fiduciary for all of the assets of the plan or IRA. In response to comments regarding the use of an agreement to define the fiduciary relationship, the Department notes that parties cannot by contract or disclaimer alter the application of the final rule as to whether fiduciary investment advice has occurred in the first instance or will occur during the course of a relationship. In keeping with past guidance, whether someone is a fiduciary for a particular activity is a functional test based on facts and circumstances. The final rule amends the factors to be considered under a functional test for the provision of fiduciary investment advice, but it does not alter the “facts and circumstances” nature of the test.
The Department notes that some questions involving temporal issues, such as when an advice recommendation becomes stale if not immediately acted upon, are addressed in the section below discussing the definition of advice for a fee or other compensation, direct or indirect. With respect to commenters' questions about the ongoing duty to monitor advice recommendations, the Department notes that, if the recommendations relate to the advisability of acquiring or exchanging securities or other investment property in a particular transaction, the final rule does not impose on the person an automatic fiduciary obligation to continue to monitor the investment or the advice recipient's activities to ensure the recommendations remain prudent and appropriate for the plan or IRA.
As has been made clear by the Department, there are a number of ways to provide investment advice without engaging in transactions prohibited by ERISA and the Code because of the conflicts of interest they pose. For example, the adviser can structure the fee arrangement to avoid prohibited conflicts of interest as explained in advisory opinions issued by the Department or the adviser can comply with a statutory exemption such as that provided by section 408(b)(14) of the Act. There is nothing in the final rule that alters these advisory opinions. Additionally, the Department notes that many of the issues raised by commenters in this area were seeking guidance on existing advisory opinions or statutory exemptions and were not comments on the 2015 Proposal. The Department does not believe that this Notice is the appropriate vehicle to address such questions or issue new guidance on those advisory opinions or statutory exemptions. Rather, the Department directs those commenters to that the Advisory Opinion process under ERISA Procedure 76-1.
Paragraph (e) of the final rule provides that a broker or dealer
The Department has decided not to modify paragraph (e). In the proposal, the Department did not propose an exclusion for the activities requested. Further, this provision modifies all of the prongs of section 3(21)(A) of the Act, not merely section 3(21)(A)(ii) which is the subject of this final rule. Further, the Department believes that the exclusion under paragraph (c)(1) should cover, to a significant degree, the requested changes when the transactions are conducted with sophisticated fiduciaries.
Certain provisions of Title I of ERISA, 29 U.S.C. 1001-1108, such as those relating to participation, benefit accrual, and prohibited transactions, also appear in the Code. This parallel structure ensures that the relevant provisions apply to ERISA-covered employee benefit plans, whether or not they are subject to the section 4975 provisions in the Code, and to tax-qualified plans, including IRAs, regardless of whether they are subject to Title I of ERISA. With regard to prohibited transactions, the ERISA Title I provisions generally authorize recovery of losses from, and imposition of civil penalties on, the responsible plan fiduciaries, while the Code provisions impose excise taxes on persons engaging in the prohibited transactions. The definition of fiduciary is the same in section 4975(e)(3)(B) of the Code as the definition in section 3(21)(A)(ii) of ERISA, 29 U.S.C. 1002(21)(A)(ii). The Department's 1975 regulation defining fiduciary investment advice is virtually identical to the regulation that defines the term “fiduciary” under the Code. 26 CFR 54.4975-9(c) (1975).
To rationalize the administration and interpretation of the parallel provisions in ERISA and the Code, Reorganization Plan No. 4 of 1978 divided the interpretive and rulemaking authority for these provisions between the Secretaries of Labor and of the Treasury, so that, in general, the agency with responsibility for a given provision of Title I of ERISA would also have responsibility for the corresponding provision in the Code. Among the sections transferred to the Department of Labor were the prohibited transaction provisions and the definition of a fiduciary in both Title I of ERISA and in the Code. ERISA's prohibited transaction rules, 29 U.S.C. 1106-1108, apply to ERISA-covered plans, and the Code's corresponding prohibited transaction rules, 26 U.S.C. 4975(c), apply both to ERISA-covered pension plans that are tax-qualified pension plans, as well as other tax-advantaged arrangements, such as IRAs, that are not subject to the fiduciary responsibility and prohibited transaction rules in ERISA.
A provision of the final rule states that the final rule applies to the parallel provision defining investment advice fiduciary under section 4975(e)(3) of the Internal Revenue Code. Thus, notwithstanding 26 CFR 54.4975-9, the effective and applicability dates provided for in this rule apply to the definition of investment advice fiduciary under both Section 4975(e)(3) of the Code and Section 3(21) of ERISA, and the Department's changes to 29 CFR 2510.3-21 supersede 26 CFR 54.4975-9 as of the effective and applicability dates of this final rule. See below for a discussion of public comments on the scope of the Department's regulatory authority.
Paragraph (a)(1) of the proposal required that in order to be fiduciary advice, the advice must be in exchange for a fee or other compensation, whether direct or indirect. Paragraph (f)(6) of the proposal provided that fee or other compensation, direct or indirect, means any fee or compensation for the advice received by the person (or by an affiliate) from any source and any fee or compensation incident to the transaction in which the investment advice has been rendered or will be rendered. The proposal referenced the term fee or other compensation as including, for example, brokerage fees, mutual fund and insurance sales commissions.
Some commenters expressed support for the definition arguing that it captured more of the indirect payments that pervade the current investment advice marketplace. Others criticized the definition as too broad and possibly sweeping in fees with no intrinsic connection to the advice or resulting transaction. Commenters asked that the Department state that a recommendation is not fiduciary advice until a transaction is entered into and fees have been received. Commenters also asked that the Department state that the advice must be acted upon within a reasonable time frame and that such a requirement be included in the rule. Those commenters expressed concern about possible fiduciary liability in such cases if the advice recipient acts on advice only after market conditions or other relevant facts have changed. Some commenters said the phrase “incident to the transaction” was ambiguous, especially in the rollover context where they argued that more than one “transaction” occurs during the rollover process. Other commenters expressed concerns that service providers, such as call center employees who receive a salary but are not compensated by an incremental fee based on actions taken by plan participants or IRA owners, would be considered investment advice fiduciaries if their communications included “investment recommendations” as defined in the rule. Several commenters focused on certain types of fees or compensation, with some asserting that revenue sharing, asset-based fees paid by mutual funds to their investment advisers, and profits banks earn on deposit and savings accounts should be excluded from the definition. Commenters asked whether the use of “in exchange for” was intended to change the Department's prior guidance under section 3(21) of the Act, which provided that any fee or compensation “incident” to the transaction was sufficient to establish fiduciary investment advice. Other questions involved issues of timing, such as whether advice that is provided in the hopes of obtaining business but that does not result in a transaction executed by the adviser or an affiliate should give rise to fiduciary status. According to the commenters, this may occur when the advice recipient walks away without engaging in a recommended transaction, but then follows the advice on his or her own and chooses some other way to execute it.
The Department already addressed many of these issues in the preamble to
To further emphasize these points, however, the Department has revised the text of the final rule. The final rule does not use the phrase “in exchange for.” Rather, consistent with the preamble to the 2015 Proposal, the final rule provides that “fee or other compensation, direct or indirect” for purposes of this section and section 3(21)(A)(ii) of the Act, means any explicit fee or compensation for the advice received by the person (or by an affiliate) from any source, and any other fee or compensation received from any source in connection with or as a result of the recommended purchase or sale of a security or the provision of investment advice services, including, though not limited to, commissions, loads, finder's fees, revenue sharing payments, shareholder servicing fees, marketing or distribution fees, underwriting compensation, payments to brokerage firms in return for shelf space, recruitment compensation paid in connection with transfers of accounts to a registered representative's new broker-dealer firm, gifts and gratuities, and expense reimbursements. The final rule also expressly provides that a fee or compensation is paid “in connection with or as a result of” advice if the fee or compensation would not have been paid but for the recommended transaction or advisory service or if eligibility for or the amount of the fee or compensation is based in whole or in part on the transaction or service.
With respect to the timing issues presented by some commenters, in the Department's view, if a participant, beneficiary or IRA owner receives investment advice from an adviser, does not open an account with that adviser, but nevertheless acts on the advice through another channel and purchases a recommended investment that pays revenue sharing to the adviser or an affiliate, that revenue sharing would still be treated as paid to the adviser or an affiliate “in connection with” the advice for purposes of the final rule. As explained in more detail in the preamble to the Best Interest Contract Exemption, commenters expressed concern that this position could result in a prohibited transaction for which there was no relief because the adviser and financial institution would not be able to satisfy all of the conditions in the exemption. For example, they cited as an example an adviser who was affiliated with the mutual fund recommending an investment in that fund, which the investor followed by executing the transaction through a separate institution unaffiliated with the mutual fund. The Department has addressed this problem in the Best Interest Contract Exemption by providing a method of complying with the exemption in the event that the participant, beneficiary or IRA owner does not open an account with the adviser or otherwise conduct the recommended transaction through the adviser.
As discussed above, the Department received extensive comments on whether the proposal should apply to other non-ERISA plans covered by Code section 4975, such as Health Savings Accounts (HSAs), Archer Medical Savings Accounts and Coverdell Education Savings Accounts. The Department notes that these accounts are given tax preferences, as are IRAs. Further, some of the accounts, such as HSAs, may have associated investment accounts that can be used as long term savings accounts for retiree health care expenses. HSA funds may be invested in investments approved for IRAs (
The Department received comments arguing that the proposal was inconsistent with the statutory text of ERISA, that the proposal exceeded the Department's regulatory authority under
As courts have recognized, ERISA attaches fiduciary status more broadly than trust law which generally reserves fiduciary status for express trustees.
Thus, the statute broadly provides that a person is a fiduciary under ERISA if the person “renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan, or has any authority or responsibility to do so . . . .” The statute neither requires an express trust, nor limits fiduciary status to an ongoing advisory relationship. A plan may need specialized advice for a single, unusual and complex transaction, and the paid adviser may fully understand the plan's dependence on his or her professional judgment. As the preamble points out, the “regular basis” requirement would mean that the adviser is not a fiduciary with respect to his one-time advice, no matter what the parties' understanding, the significance of the advice to the retirement investor, or the language of the statutory definition, which included no “regular basis” requirement.
Nor is the Department bound by the Investment Advisers Act in defining a person's status as a fiduciary adviser under ERISA and the Code. The Investment Advisers Act specifically excludes from the definition of investment adviser “any broker or dealer whose performance of such services is solely incidental to the conduct of his business as a broker or dealer and who receives no special compensation therefore.” 15 U.S.C. 80b-2(11). Nothing in ERISA, or its legislative history, gives any indication that Congress meant to limit fiduciary investment advisers under Title I of ERISA or the Code to persons who meet the Investment Advisers Act's definition of investment adviser, and commenters have cited no such indication.
Whether a securities broker will be a fiduciary under this regulation depends on the facts and circumstances. If the broker is only executing a purchase or sale at the client's request, then, as both the current rule and the final rule make clear, the broker is not a fiduciary.
The Department also disagrees with comments that argued that the Dodd-Frank Act somehow prevents the Department from defining the term “fiduciary investment advice.” Section 913 of that Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 also authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers. 15 U.S.C. 80b-11(g)(1). Nothing in the Dodd-Frank Act indicates that Congress meant to preclude the Department's regulation of fiduciary investment advice under ERISA or its application of such a regulation to securities brokers or dealers. To the contrary, Dodd-Frank Act specifically directed the SEC to study the effectiveness of existing legal or regulatory standards of care under other federal and state authorities. Dodd-Frank Act, sec. 913(b)(1) and (c)(1). The SEC has also consistently recognized ERISA as an applicable authority in this area, noting “that advisers entering into performance fee arrangements with employee benefit plans covered by the Employee Retirement Income Security Act of 1974 (“ERISA”) are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA.” SE.C. Investment Advisers Act Release No. 1732, (July 17, 1998), 63 FR 39022, 39024 (July 21, 1998).
Other comments have stated that that the Department should publish yet another proposal before moving to publish a final rule. The Department disagrees. As noted elsewhere, the 2015 Proposal benefitted from comments received on a proposal issued in 2010. The changes in this final rule reflect the Department's careful consideration of the extensive comments received on both the 2010 Proposal and the second 2015 Proposal. Moreover, the Department believes that such changes are consistent with reasonable expectations of the affected parties and, together with the prohibited transaction exemptions being finalized with this rule, strike an appropriate balance in addressing the need to modernize the fiduciary rule with the various
To the extent compliance and interpretive issues arise after publication of the final rule, the Department fully intends to provide advisers, plan sponsors and fiduciaries, and other affected parties with extensive compliance assistance and education, including guidance specifically tailored to small businesses as required under the Small Business Regulatory Enforcement Fairness Act, Pub. Law 104-121 section 212. The Department routinely provides such assistance following its issuance of highly technical or significant guidance. For example, the Department's compliance assistance Web page, at
Some commenters argued that the Department does not have the power to regulate IRAs, and the broker-dealers who offer them. The Department disagrees. The Reorganization Plan No. 4 of 1978 specifically gives the Department the authority to define “fiduciary” under both ERISA and the Code.
Some commenters argued that because Congress has amended ERISA without changing the definition of “fiduciary,” Congress has implicitly endorsed the five-part test. The Department disagrees. ERISA is an extensive, complex statute that Congress has amended many times since its original enactment in 1974. It does not make sense to say that whenever Congress amended any part of ERISA, it was indicating its approval of all the Secretary's regulations and interpretations. On none of these occasions did Congress amend any part of the fiduciary definition in section 3(21) of ERISA.
In addition to the final rule in this Notice, the Department is also finalizing elsewhere in this edition of the
Investment advice fiduciaries to plans and plan participants must meet ERISA's standards of prudence and loyalty to their plan customers. Such fiduciaries also face excise taxes, remedies, and other sanctions for engaging in certain transactions, such as self-dealing with plan assets or receiving payments from third parties in connection with plan transactions, unless the transactions are permitted by an exemption from ERISA's and the Code's prohibited transaction rules. IRA fiduciaries do not have the same general fiduciary obligations of prudence and loyalty under the statute, but they too must adhere to the prohibited transaction rules or they must pay an excise tax. The prohibited transaction rules help ensure that investment advice provided to plan participants and IRA owners is not driven by the adviser's financial self-interest.
The new exemptions adopted today are the Best Interest Contract Exemption and the Class Exemption for Principal Transactions in Certain Assets between Investment Advice Fiduciaries and Employee Benefit Plans and IRAs (the Principal Transactions Exemption). The Best Interest Contract Exemption is specifically designed to address the conflicts of interest associated with the wide variety of payments advisers receive in connection with retail transactions involving plans and IRAs. The Principal Transactions Exemption permits investment advice fiduciaries to sell or purchase certain debt securities and other investments out of their own inventories to or from plans and IRAs. These exemptions require, among other things, that investment advice fiduciaries adhere to certain Impartial Conduct Standards, which are fundamental obligations of fair dealing and fiduciary conduct, and include obligations to act in the customer's best interest, avoid misleading statements, and receive no more than reasonable compensation.
At the same time that the Department has granted these new exemptions, it has also amended existing exemptions to ensure uniform application of the Impartial Conduct Standards.
The amendments also revoke certain existing exemptions, which provided little or no protections to IRA and non-plan participants, in favor of more uniform application of the Best Interest Contract Exemption in the market for
Several commenters asked whether a fiduciary investment adviser would need to utilize the Best Interest Contract Exemption or other prohibited transaction exemptions if the only compensation the adviser receives is a fixed percentage of the value of assets under management. Whether a particular relationship or compensation structure would result in an adviser having an interest that may affect the exercise of its best judgment as a fiduciary when providing a recommendation, in violation of the self-dealing provisions of prohibited transaction rules under section 406(b) of ERISA, depends on the surrounding facts and circumstances. The Department believes that, by itself, the ongoing receipt of compensation calculated as a fixed percentage of the value of a customer's assets under management, where such values are determined by readily available independent sources or independent valuations, typically would not raise prohibited transaction concerns for the adviser. Under these circumstances, the amount of compensation received depends solely on the value of the investments in a client account, and ordinarily the interests of the adviser in making prudent investment recommendations, which could have an effect on compensation received, are consistent with the investor's interests in growing and protecting account investments.
However, the Department notes that a recommendation to a plan participant to take a full or partial distribution from a plan to invest in recommended assets that will generate a fee for the adviser that he would not otherwise receive implicates the prohibited transaction rules, even if the fee going forward is based on a fixed percent of assets under management. In that circumstance, the adviser should use the Best Interest Contract Exemption or other applicable prohibited transaction exemption. Prohibited transaction rules would similarly be implicated by a recommendation to switch from a commission-based account to an account that charges a fixed percent of assets under management. Further, the Department notes that other remunerations (
The proposal stated that the final rule and amended and new prohibited transaction exemptions would be effective 60 days after publication in the
Commenters asked the Department to provide sufficient time for orderly and efficient adjustments to, for example, recordkeeping systems; internal compliance, monitoring, education, and training programs; affected service provider contracts; compensation arrangements; and other business practices as necessary to make the transition to the new expanded definition of investment advice fiduciary. The commenters also asked that the Department make it clear that the final rule does not apply in connection with advice provided before the effective date of the final rule. Many commenters expressed concern with the provision in the proposal that the final rule and class exemptions would be effective 60 days after their publication in the
After careful consideration of the public comments, the Department has determined that it is important for the final rule to become effective on the earliest possible date. The Congressional Review Act provides that significant final rules can be effective 60 days after
The Department has also determined that, in light of the importance of the final rule's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, that an applicability date of one year after publication of the final rule in the
This action is a significant regulatory action and was therefore submitted to the Office of Management and Budget (OMB) for review. The Department prepared an analysis of the potential costs and benefits associated with this action. This analysis is contained in the document,
The Regulatory Flexibility Act (5 U.S.C. 601
The Secretary has determined that this final rule will have a significant economic impact on a substantial number of small entities. The Secretary has separately published a Regulatory Impact Analysis (RIA) which contains the complete economic analysis for this rulemaking including the Department's FRFA for this rule and the related prohibited transaction exemptions also published this issue of the
As noted in section 6.1 of the RIA, the Department has determined that regulatory action is needed to mitigate conflicts of interest in connection with investment advice to retirement investors. The regulation is intended to improve plan and IRA investing to the benefit of retirement security. In response to the proposed rulemaking, organizations representing small businesses submitted comments expressing particular concern with three issues: The carve-out for investment education, the best interest contract exemption, and the carve-out for persons acting in the capacity of counterparties to plan fiduciaries with financial expertise. Section 2 of the RIA contains an extensive discussion of these concerns and the Department's response.
As discussed in section 6.2 of the RIA, the Small Business Administration (SBA) defines a small business in the Financial Investments and Related Activities Sector as a business with up to $38.5 million in annual receipts. In response to a comment received from the SBA's Office of Advocacy on our Initial Regulatory Flexibility Analysis, the Department contacted the SBA, and received from them a dataset containing data on the number of firms by North American Industry Classification System (NAICS) codes, including the number of firms in given revenue categories. This dataset allows the estimation of the number of firms with a given NAICS code that fall below the $38.5 million threshold and would therefore be considered small entities by the SBA. However, this dataset alone does not provide a sufficient basis for the Department to estimate the number of small entities affected by the rule. Not all firms within a given NAICS code would be affected by this rule, because being an ERISA fiduciary relies on a functional test and is not based on industry status as defined by a NAICS code. Further, not all firms within a given NAICS code work with ERISA-covered plans and IRAs.
Over 90 percent of broker-dealers, registered investment advisers, insurance companies, agents, and consultants are small businesses according to the SBA size standards (132 CFR 121.201). Applying the ratio of entities that meet the SBA size standards to the number of affected entities, based on the methodology described at greater length in the RIA, the Department estimates that the number of small entities affected by this rule is 2,414 BDs, 16,524 registered investment advisers, 395 insurers, and 3,358 other ERISA service providers.
For purposes of the RFA, the Department continues to consider an employee benefit plan with fewer than 100 participants to be a small entity. Further, while some large employers may have small plans, in general small employers maintain most small plans. The definition of small entity considered appropriate for this purpose differs, however, from a definition of small business that is based on size standards promulgated by the SBA. These small pension plans will benefit from the rule, because as a result of the rule, they will receive non-conflicted advice from their fiduciary service providers. The 2013 Form 5500 filings show nearly 595,000 ERISA covered retirement plans with less than 100 participants.
Section 6.5 of the RIA summarizes the projected reporting, recordkeeping, and other compliance costs of the rule, which are discussed in detail in section 5 of the RIA. Among other things, the Department concludes that it is likely that some small service providers may find that the increased costs associated with ERISA fiduciary status outweigh the benefits of continuing to service the ERISA plan market or the IRA market. The Department does not believe that this outcome will be widespread or that it will result in a diminution of the amount or quality of advice available to small or other retirement savers, because other firms are likely to fill the void and provide services the ERISA plan and IRA market. It is also possible that the economic impact of the rule on small entities would not be as significant as it would be for large entities, because anecdotal evidence indicates that small entities do not have as many business arrangements that give rise to conflicts of interest. Therefore, they would not be confronted with the same costs to restructure transactions that would be faced by large entities.
Section 5.3.1 of the RIA includes a discussion of the changes to the proposed rule and exemptions that are intended to reduce the costs affecting both small and large business. These include elimination of data collection and annual disclosure requirements in the Best Interest Contract Exemption, and changes to the implementation of the contract requirement in the exemption. Section 7 of the RIA discusses significant regulatory alternatives considered by the Department and the reasons why they were rejected.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Department's amendment to its 1975 rule that defines when a person who provides investment advice to an employee benefit plan or IRA becomes a fiduciary, solicited comments on the information collections included therein. The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposed regulation, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally comments were submitted which contained information relevant to the information collection costs and administrative burdens attendant to the proposal. The Department took into account such public comments in connection with making changes to the final rule, analyzing the economic impact of the proposal, and developing the revised paperwork burden analysis summarized below.
In connection with publication of the Department's amendment to its 1975 rule that defines when a person who provides investment advice to an employee benefit plan or IRA becomes a fiduciary, the Department is submitting an ICR to OMB requesting approval of a new collection of information under OMB Control Number 1210-0155. The Department will notify the public when OMB approves the ICR.
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail above, paragraph (b)(2)(i) of the final rule provides that a person is not an investment advice fiduciary by reason of certain communications with plan fiduciaries of participant-directed individual account employee benefit plans described in section 3(3) of ERISA regarding platforms of investment vehicles from which plan participants or beneficiaries may direct the investment of assets held in, or contributed to, their individual accounts. A condition of paragraph (b)(2)(i) is that the person discloses in writing to the plan fiduciary that the person is not undertaking to provide impartial investment advice or to give advice in a fiduciary capacity.
Paragraph (b)(2)(iv)(C) and (D) of the regulation make clear that furnishing and providing certain specified investment educational information and materials (including certain investment allocation models and interactive plan materials) to a plan, plan fiduciary, participant, beneficiary, or IRA owner would not constitute the rendering of investment advice within the meaning of the final rule if certain conditions are met. The investment education provision includes conditions that require asset allocation models or interactive materials to include certain explanations and that they be accompanied by a statement with certain specified information.
Paragraph (c)(1) of the final rule provides that a person shall not be deemed to be an investment advice fiduciary within the meaning of the final rule by reason of advice to certain independent fiduciaries of a plan or IRA in connection with an arm's length sale, purchase, loan, exchange, or other transaction involving the investment of securities or other property if, before entering into the transaction, the independent fiduciary represents to the person that the fiduciary is exercising independent judgment in evaluating any recommendation, and the person fairly informs the independent plan fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity and fairly informs the independent plan fiduciary of the existence and nature of the person's financial interests in the transaction.
Paragraph (c)(2) of the final rule provides that, in the case of certain swap transactions required to be cleared under provisions of the Dodd-Frank Act, certain counterparties, clearing members and clearing organizations are not deemed to be investment advice fiduciaries within the meaning of the final rule. A condition in the provision is that the plan fiduciary involved in the swap transaction, before entering into the transaction, represents that the fiduciary understands that the counterparty, clearing member or clearing organization are not undertaking to provide impartial investment advice and that the plan fiduciary is exercising independent judgment in evaluating any recommendations.
The disclosures needed to satisfy the platform provider, investment education, independent plan fiduciary, and swap transaction provisions of the final rule are information collection requests (ICRs) subject to the Paperwork Reduction Act. The Department has made the following assumptions in order to establish a reasonable estimate of the paperwork burden associated with these ICRs:
• Approximately 2,000 service providers will produce the platform provider disclosures;
• Approximately 23,500 financial institutions and service providers will add the investment education disclosure to their investment education materials;
• Approximately 36,000 independent plan fiduciaries with financial expertise would receive the independent plan fiduciary with financial expertise disclosure;
• Service providers producing the platform provider disclosure already maintain contracts with their customers as a regular and customary business practice and the materials costs arising from inserting the platform provider disclosure into the existing contracts would be negligible;
• Materials costs arising from inserting the required investment education disclosure into existing models and interactive materials would be negligible;
• In transactions with independent plan fiduciaries covered by the provision in the final rule, the independent fiduciary would receive substantially all of the disclosures electronically via means already used in their normal course of business and the costs arising from electronic distribution would be negligible;
• Persons relying on these provisions in the final rule would use existing in-house resources to prepare the disclosures; and
• The tasks associated with the ICRs would be performed by clerical personnel at an hourly rate of $55.21 and legal professionals at an hourly rate of $133.61.
In response to a recommendation made during testimony at the Department's August 2015 public hearing on the proposed rule, the Department tasked several attorneys with drafting sample legal documents in an attempt to determine the hour burden associated with complying with the ICRs. Commenters did not provide time or cost estimates needed to draft these disclosures; the legal burden estimates in this analysis, therefore, use the data generated by the Department to estimate the time required to create sample disclosures.
The Department estimates that it would require ten minutes of legal professional time to draft the disclosure needed under the platform provider provision; a statement that the person is not providing impartial investment advice or acting in a fiduciary capacity. Therefore, the platform provider disclosure would result in approximately 300 hours of legal time at an equivalent cost of approximately $45,000.
The Department estimates that it would require one hour of legal professional time to draft the disclosure needed under the investment education provision. Therefore, this disclosure would result in approximately 23,500 hours of legal time at an equivalent cost of approximately $3.1 million.
The Department estimates that it would require 25 minutes of legal professional time and 30 minutes of clerical time to produce the disclosure needed under the provision regarding transactions with independent plan fiduciaries. Therefore, the Department estimates that this disclosure would result in approximately 15,000 hours of legal time at an equivalent cost of approximately $2.0 million. It would also result in approximately 18,000 hours of clerical time at an equivalent cost of approximately $994,000. In total, the burden associated with producing the disclosure is approximately 33,000 hours at an equivalent cost of $3.0 million.
Plan fiduciaries covered by the swap transactions provision must already make the required representation to the counterparty under the Dodd-Frank Act provisions governing cleared swap transactions. This rule adds a requirement that the representation be made to the clearing member and financial institution involved in the transaction. The Department believes that the incremental burden of this additional requirement would be de minimis. Plan fiduciaries would be required to add a few words to the representations required under the Dodd-Frank Act provisions reflecting the additional recipients of the representation. Due to the sophisticated nature of the entities engaging in swap transactions, the Department believes that all of these representations are transmitted electronically; therefore, the incremental burden of transmitting this representation to two additional parties is de minimis. Further, keeping records that the representation had been received is a usual and customary business practice. Accordingly, the
In total, the hour burden for information collections in this rule is approximately 57,000 hours at an equivalent cost of $6.2 million.
Because the Department assumes that all disclosures would either be distributed electronically or incorporated into existing materials, the Department has not associated any cost burden with these ICRs.
These paperwork burden estimates are summarized as follows:
The final rule is subject to the Congressional Review Act provisions of the Small Business Regulatory Enforcement Fairness Act of 1996 (5 U.S.C. 801,
Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4) requires each Federal agency to prepare a written statement assessing the effects of any Federal mandate in a proposed or final agency rule that may result in an expenditure of $100 million or more (adjusted annually for inflation with the base year 1995) in any one year by State, local, and tribal governments, in the aggregate, or by the private sector. Such a mandate is deemed to be a “significant regulatory action.” The final rule is expected to have such an impact on the private sector, and the Department hereby provides such an assessment.
The Department is issuing the final rule under ERISA section 3(21)(A)(ii) (29 U.S.C. 1002(21)(a)(ii)).
The Department assessed the anticipated benefits and costs of the final rule pursuant to Executive Order 12866 in the Regulatory Impact Analysis for the final rule and concluded that its benefits would justify its costs. The Department's complete Regulatory Impact Analysis is available at
The final rule is not expected to have any material economic impacts on State, local or tribal governments, or on health, safety, or the natural environment. In fact, the North American Securities Administrators Association submitted a comment in support of the Department's 2015 Proposal that did not suggest a material economic impact on state securities regulators. The National Association of Insurance Commissioners also submitted a comment that recognized that oversight of the retirement plans marketplace is a shared regulatory responsibility, and indicated a shared commitment to protect, educate and empower consumers as they make important decisions to provide for their retirement security. They pointed out that it is important that the approaches regulators take within their respective regulatory frameworks are consistent and compatible as much as possible, but did not suggest the rule would require an expenditure of $100 million or more by state insurance regulators. Similarly, comments from the National Conference of Insurance Legislators and the National Association of Governors suggested further dialogue with the NAIC, insurance legislators, and other state officials to ensure the federal and state approaches to consumer protection in this area are consistent and compatible, but did not identify a monetary impact on state or local governments resulting from the rule. As noted elsewhere in this Notice, the Department's obligation and overriding objective in developing regulations implementing ERISA (and the relevant prohibited transaction provisions in the Code) is to achieve the consumer protection objectives of ERISA and the Code. The Department believes the final rule reflects that obligation and objective while also reflecting that care was taken to craft the rule so it does not require state banking, insurance, or securities regulators to take steps that would impose additional costs on them or conflict with applicable state statutory or regulatory requirements. In fact, the Department noted that ERISA section 514 expressly saves state regulation of insurance, banking, and securities from ERISA's express preemption provision and has added a new paragraph (i) to the final rule to acknowledge that the regulation is not intended to change the scope or effect of ERISA section 514, including the savings clause in ERISA section 514(b)(2)(A) for state regulation of insurance, banking, or securities. The Department also, in response to state regulator suggestions, agreed that it would be appropriate for the final rule to include an express provision acknowledging the savings clause in ERISA section 514(b)(2)(A) for state insurance, banking, or securities laws to emphasize the fact that those state regulators all have important roles in the administration and enforcement of standards for retirement plans and products within their jurisdiction.
Executive Order 13132 (August 4, 1999) outlines fundamental principles of federalism, and requires the adherence to specific criteria by Federal agencies in the process of formulating and implementing policies that have substantial direct effects on the States, the relationship between the national government and States, or on the distribution of power and responsibilities among the various levels of government. As discussed elsewhere in this Notice, the Department does not believe this final rule has federalism implications because it has no substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the
This regulation is issued pursuant to the authority in section 505 of ERISA (Pub. L. 93-406, 88 Stat. 894; 29 U.S.C. 1135) and section 102 of Reorganization Plan No. 4 of 1978, 5 U.S.C. App. 237, and under Secretary of Labor's Order No. 1-2011, 77 FR 1088 (Jan. 9, 2012).
Employee benefit plans, Employee Retirement Income Security Act, Pensions, Plan assets.
For the reasons set forth in the preamble, the Department is amending parts 2509 and 2510 of subchapters A and B of Chapter XXV of Title 29 of the Code of Federal Regulations as follows:
29 U.S.C. 1135. Secretary of Labor's Order 1-2011, 77 FR 1088 (Jan. 9, 2012). Sections 2509.75-10 and 2509.75-2 issued under 29 U.S.C. 1052, 1053, 1054. Sec. 2509.75-5 also issued under 29 U.S.C. 1002. Sec. 2509.95-1 also issued under sec. 625, Pub. L. 109-280, 120 Stat. 780.
29 U.S.C. 1002(2), 1002(21), 1002(37), 1002(38), 1002(40), 1031, and 1135; Secretary of Labor's Order 1-2011, 77 FR 1088; Secs. 2510.3-21, 2510.3-101 and 2510.3-102 also issued under Sec. 102 of Reorganization Plan No. 4 of 1978, 5 U.S.C. App. 237. Section 2510.3-38 also issued under Pub. L. 105-72, Sec. 1(b), 111 Stat. 1457 (1997).
(a)
(1) Such person provides to a plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner the following types of advice for a fee or other compensation, direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred, or distributed from the plan or IRA;
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, selection of investment account arrangements (
(2) With respect to the investment advice described in paragraph (a)(1) of this section, the recommendation is made either directly or indirectly (
(i) Represents or acknowledges that it is acting as a fiduciary within the meaning of the Act or the Code;
(ii) Renders the advice pursuant to a written or verbal agreement, arrangement, or understanding that the advice is based on the particular investment needs of the advice recipient; or
(iii) Directs the advice to a specific advice recipient or recipients regarding the advisability of a particular investment or management decision with respect to securities or other investment property of the plan or IRA.
(b)(1) For purposes of this section, “recommendation” means a communication that, based on its content, context, and presentation, would reasonably be viewed as a suggestion that the advice recipient engage in or refrain from taking a particular course of action. The determination of whether a “recommendation” has been made is an objective rather than subjective inquiry. In addition, the more individually tailored the communication is to a specific advice recipient or recipients about, for example, a security, investment property, or investment strategy, the more likely the communication will be viewed as a recommendation. Providing a selective list of securities to a particular advice recipient as appropriate for that investor would be a recommendation as to the advisability of acquiring securities even if no recommendation is made with respect to any one security. Furthermore, a series of actions, directly or indirectly (
(2) The provision of services or the furnishing or making available of information and materials in conformance with paragraphs (b)(2)(i) through (iv) of this section is not a “recommendation” for purposes of this section. Determinations as to whether any activity not described in this paragraph (b)(2) constitutes a recommendation must be made by reference to the criteria set forth in paragraph (b)(1) of this section.
(i)
(ii)
(A) Identifying investment alternatives that meet objective criteria specified by the plan fiduciary (
(B) In response to a request for information, request for proposal, or similar solicitation by or on behalf of the plan, identifying a limited or sample set of investment alternatives based on only the size of the employer or plan, the current investment alternatives designated under the plan, or both, provided that the response is in writing and discloses whether the person identifying the limited or sample set of investment alternatives has a financial interest in any of the alternatives, and if so the precise nature of such interest; or
(C) Providing objective financial data and comparisons with independent benchmarks to the plan fiduciary.
(iii)
(iv)
(A)
(B)
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(C)
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(D)
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(c) Except for persons who represent or acknowledge that they are acting as a fiduciary within the meaning of the Act or the Code, a person shall not be deemed to be a fiduciary within the meaning of section 3(21)(A)(ii) of the Act or section 4975(e)(3)(B) of the Code solely because of the activities set forth in paragraphs (c)(1), (2), and (3) of this section.
(1)
(i) The person knows or reasonably believes that the independent fiduciary of the plan or IRA is:
(A) A bank as defined in section 202 of the Investment Advisers Act of 1940 or similar institution that is regulated and supervised and subject to periodic examination by a State or Federal agency;
(B) An insurance carrier which is qualified under the laws of more than one state to perform the services of managing, acquiring or disposing of assets of a plan;
(C) An investment adviser registered under the Investment Advisers Act of 1940 or, if not registered an as investment adviser under the Investment Advisers Act by reason of paragraph (1) of section 203A of such Act, is registered as an investment adviser under the laws of the State (referred to in such paragraph (1)) in which it maintains its principal office and place of business;
(D) A broker-dealer registered under the Securities Exchange Act of 1934; or
(E) Any independent fiduciary that holds, or has under management or control, total assets of at least $50 million (the person may rely on written representations from the plan or independent fiduciary to satisfy this paragraph (c)(1)(i));
(ii) The person knows or reasonably believes that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this paragraph (c)(1)(ii));
(iii) The person fairly informs the independent fiduciary that the person is not undertaking to provide impartial
(iv) The person knows or reasonably believes that the independent fiduciary of the plan or IRA is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this paragraph (c)(1)(iv)); and
(v) The person does not receive a fee or other compensation directly from the plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner for the provision of investment advice (as opposed to other services) in connection with the transaction.
(2)
(i) The employee benefit plan is represented by a fiduciary under ERISA independent of the person;
(ii) In the case of a swap dealer or security-based swap dealer, the person is not acting as an advisor to the employee benefit plan (within the meaning of section 4s(h) of the Commodity Exchange Act or section 15F(h) of the Securities Exchange Act of 1934) in connection with the transaction;
(iii) The person does not receive a fee or other compensation directly from the plan or plan fiduciary for the provision of investment advice (as opposed to other services) in connection with the transaction; and
(iv) In advance of providing any recommendations with respect to the transaction, or series of transactions, the person obtains a written representation from the independent fiduciary that the independent fiduciary understands that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and that the independent fiduciary is exercising independent judgment in evaluating the recommendation.
(3)
(ii) In his or her capacity as an employee of the plan sponsor of a plan, or as an employee of an affiliate of such plan sponsor, the person provides advice to another employee of the plan sponsor in his or her capacity as a participant or beneficiary of the plan, provided the person's job responsibilities do not involve the provision of investment advice or investment recommendations, the person is not registered or licensed under federal or state securities or insurance law, the advice he or she provides does not require the person to be registered or licensed under federal or state securities or insurance laws, and the person receives no fee or other compensation, direct or indirect, in connection with the advice beyond the employee's normal compensation for work performed for the employer.
(d)
(1) Exempt such person from the provisions of section 405(a) of the Act concerning liability for fiduciary breaches by other fiduciaries with respect to any assets of the plan; or
(2) Exclude such person from the definition of the term “party in interest” (as set forth in section 3(14)(B) of the Act) or “disqualified person” (as set forth in section 4975(e)(2) of the Code) with respect to any assets of the employee benefit plan or IRA.
(e)
(i) Neither the fiduciary nor any affiliate of such fiduciary is such broker, dealer, or bank; and
(ii) The instructions specify:
(A) The security to be purchased or sold;
(B) A price range within which such security is to be purchased or sold, or, if such security is issued by an open-end investment company registered under the Investment Company Act of 1940 (15 U.S.C. 80a-1,
(C) A time span during which such security may be purchased or sold (not to exceed five business days); and
(D) The minimum or maximum quantity of such security which may be purchased or sold within such price range, or, in the case of a security issued by an open-end investment company registered under the Investment Company Act of 1940, the minimum or maximum quantity of such security which may be purchased or sold, or the value of such security in dollar amount which may be purchased or sold, at the price referred to in paragraph (e)(1)(ii)(B) of this section.
(2) A person who is a broker-dealer, reporting dealer, or bank which is a fiduciary with respect to a plan or IRA
(i) Exempt such broker-dealer, reporting dealer, or bank from the provisions of section 405(a) of the Act concerning liability for fiduciary breaches by other fiduciaries with respect to any assets of the plan; or
(ii) Exclude such broker-dealer, reporting dealer, or bank from the definition of the term “party in interest” (as set forth in section 3(14)(B) of the Act) or “disqualified person” (as set forth in section 4975(e)(2) of the Code) with respect to any assets of the plan or IRA.
(f)
(g)
(1) The term “affiliate” means any person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with such person; any officer, director, partner, employee, or relative (as defined in paragraph (g)(8) of this section) of such person; and any corporation or partnership of which such person is an officer, director, or partner.
(2) The term “control,” for purposes of paragraph (g)(1) of this section, means the power to exercise a controlling influence over the management or policies of a person other than an individual.
(3) The term “fee or other compensation, direct or indirect” means, for purposes of this section and section 3(21)(A)(ii) of the Act, any explicit fee or compensation for the advice received by the person (or by an affiliate) from any source, and any other fee or compensation received from any source in connection with or as a result of the purchase or sale of a security or the provision of investment advice services, including, though not limited to, commissions, loads, finder's fees, revenue sharing payments, shareholder servicing fees, marketing or distribution fees, underwriting compensation, payments to brokerage firms in return for shelf space, recruitment compensation paid in connection with transfers of accounts to a registered representative's new broker-dealer firm, gifts and gratuities, and expense reimbursements. A fee or compensation is paid “in connection with or as a result of” such transaction or service if the fee or compensation would not have been paid but for the transaction or service or if eligibility for or the amount of the fee or compensation is based in whole or in part on the transaction or service.
(4) The term “investment property” does not include health insurance policies, disability insurance policies, term life insurance policies, and other property to the extent the policies or property do not contain an investment component.
(5) The term “IRA owner” means, with respect to an IRA, either the person who is the owner of the IRA or the person for whose benefit the IRA was established.
(6)(i) The term “plan” means any employee benefit plan described in section 3(3) of the Act and any plan described in section 4975(e)(1)(A) of the Code, and
(ii) The term “IRA” means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
(7) The term “plan fiduciary” means a person described in section (3)(21)(A) of the Act and 4975(e)(3) of the Code. For purposes of this section, a participant or beneficiary of the plan or a relative of either is not a “plan fiduciary” with respect to the plan, and the IRA owner or a relative is not a “plan fiduciary” with respect to the IRA.
(8) The term “relative” means a person described in section 3(15) of the Act and section 4975(e)(6) of the Code or a brother, a sister, or a spouse of a brother or sister.
(9) The term “plan participant” or “participant” means, for a plan described in section 3(3) of the Act, a person described in section 3(7) of the Act.
(h)
(2)
(3) Until the applicability date under this paragraph (h), the prior regulation under the Act and the Code (as it appeared in the July 1, 2015 edition of 29 CFR part 2510 and the April 1, 2015 edition of 26 CFR part 54) applies.
(i)
(j)
(i) A person shall be deemed to be rendering “investment advice” to an employee benefit plan, within the meaning of section 3(21)(A)(ii) of the Act, section 4975(e)(3)(B) of the Code and this paragraph (j), only if:
(A) Such person renders advice to the plan as to the value of securities or other property, or makes recommendation as to the advisability of investing in, purchasing, or selling securities or other property; and
(B) Such person either directly or indirectly (
(
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(2)
(A) Any person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with such person;
(B) Any officer, director, partner, employee or relative (as defined in section 3(15) of the Act) of such person; and
(C) Any corporation or partnership of which such person is an officer, director or partner.
(ii) For purposes of this paragraph (j), the term “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual.
(3)
Employee Benefits Security Administration (EBSA), U.S. Department of Labor.
Adoption of Class Exemption.
This document contains an exemption from certain prohibited transactions provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code (the Code). The provisions at issue generally prohibit fiduciaries with respect to employee benefit plans and individual retirement accounts (IRAs) from engaging in self-dealing and receiving compensation from third parties in connection with transactions involving the plans and IRAs. The exemption allows entities such as registered investment advisers, broker-dealers and insurance companies, and their agents and representatives, that are ERISA or Code fiduciaries by reason of the provision of investment advice, to receive compensation that may otherwise give rise to prohibited transactions as a result of their advice to plan participants and beneficiaries, IRA owners and certain plan fiduciaries (including small plan sponsors). The exemption is subject to protective conditions to safeguard the interests of the plans, participants and beneficiaries and IRA owners. The exemption affects participants and beneficiaries of plans, IRA owners and fiduciaries with respect to such plans and IRAs.
Brian Shiker or Susan Wilker, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor, (202) 693-8824 (this is not a toll-free number).
The Department grants this exemption in connection with its publication, elsewhere in this issue of the
This Best Interest Contract Exemption is designed to promote the provision of investment advice that is in the best interest of retail investors such as plan participants and beneficiaries, IRA owners, and certain plan fiduciaries, including small plan sponsors. ERISA and the Code generally prohibit fiduciaries from receiving payments from third parties and from acting on conflicts of interest, including using their authority to affect or increase their own compensation, in connection with transactions involving a plan or IRA. Certain types of fees and compensation common in the retail market, such as brokerage or insurance commissions, 12b-1 fees and revenue sharing payments, may fall within these prohibitions when received by fiduciaries as a result of transactions involving advice to the plan, plan participants and beneficiaries, and IRA owners. To facilitate continued provision of advice to such retail investors under conditions designed to safeguard the interests of these investors, the exemption allows investment advice fiduciaries, including investment advisers registered under the Investment Advisers Act of 1940 or state law, broker-dealers, and insurance companies, and their agents and representatives, to receive these various forms of compensation that, in the absence of an exemption, would not be permitted under ERISA and the Code.
Rather than create a set of highly prescriptive transaction-specific exemptions, which has been the Department's usual approach, the exemption flexibly accommodates a wide range of compensation practices, while minimizing the harmful impact of conflicts of interest on the quality of advice. As a condition of receiving compensation that would otherwise be prohibited, individual Advisers and the Financial Institutions that employ or otherwise retain them must adhere to conditions designed to mitigate the harmful impact of conflicts of interest. By taking a standards-based approach, the exemption permits firms to continue to rely on many common compensation
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant administrative exemptions from ERISA's prohibited transaction provisions.
This Best Interest Contract Exemption is broadly available for Advisers and Financial Institutions that make investment recommendations to retail “Retirement Investors,” including plan participants and beneficiaries, IRA owners, and non-institutional (or “retail”) fiduciaries. As a condition of receiving compensation that would otherwise be prohibited under ERISA and the Code, the exemption requires Financial Institutions to acknowledge their fiduciary status and the fiduciary status of their Advisers in writing. The Financial Institution and Advisers must adhere to enforceable standards of fiduciary conduct and fair dealing with respect to their advice. In the case of IRAs and non-ERISA plans, the exemption requires that the standards be set forth in an enforceable contract with the Retirement Investor. Under the exemption's terms, Financial Institutions are not required to enter into a contract with ERISA plan investors, but they are obligated to adhere to these same standards of fiduciary conduct, which the investors can effectively enforce pursuant to ERISA sections 502(a)(2) and (3). Likewise, “Level Fee” Fiduciaries that, with their Affiliates, receive only a Level Fee in connection with advisory or investment management services, do not have to enter into a contract with Retirement Investors, but they must provide a written statement of fiduciary status, adhere to standards of fiduciary conduct, and prepare a written documentation of the reasons for the recommendation.
The exemption is designed to cover a wide variety of current compensation practices, which would otherwise be prohibited as a result of the Department's Regulation extending fiduciary status to many investment professionals who formerly were not treated as fiduciaries. Rather than flatly prohibit compensation structures that could be beneficial in the right circumstances—such as commission accounts for investors that make infrequent trades—the exemption permits individual Advisers
In order to protect the interests of the plan participants and beneficiaries, IRA owners, and plan fiduciaries, the exemption requires the Financial Institution to acknowledge fiduciary status for itself and its Advisers. The Financial Institutions and Advisers must adhere to basic standards of impartial conduct. In particular, under this standards-based approach, the Adviser and Financial Institution must give prudent advice that is in the customer's best interest, avoid misleading statements, and receive no more than reasonable compensation. Additionally, Financial Institutions generally must adopt policies and procedures reasonably designed to mitigate any harmful impact of conflicts of interest, and disclose basic information about their conflicts of interest and the cost of their advice. Level Fee Fiduciaries are subject to more streamlined conditions, including a written statement of fiduciary status, compliance with the standards of impartial conduct, and, as applicable, documentation of the specific reason or reasons for the recommendation of the Level Fee arrangement.
The exemption is calibrated to align the Adviser's interests with those of the plan or IRA customer, while leaving the Adviser and Financial Institution the flexibility and discretion necessary to determine how best to satisfy the exemption's standards in light of the unique attributes of their business.
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Order and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the OMB. Section 3(f) of Executive Order 12866, defines a “significant regulatory action” as an action that is likely to result in a rule (1) having an annual effect on the economy of $100 million or more, or adversely and materially affecting a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities (also referred to as “economically significant” regulatory actions); (2) creating serious inconsistency or otherwise interfering with an action taken or planned by another agency; (3) materially altering the budgetary impacts of entitlement grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raising novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of the Executive Order, OMB has determined that this action is “significant” within the meaning of Section 3(f)(1) of the Executive Order. Accordingly, the Department has undertaken an assessment of the costs and benefits of the proposal, and OMB has reviewed this regulatory action. The Department's complete Regulatory Impact Analysis is available at
The Department proposed this class exemption on its own motion, pursuant to ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR art 2570, subpart B (76 FR 66637 (October 27, 2011)).
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans and their participants and beneficiaries.
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service. Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violations of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, ERISA section 3(21)(A) and Code section 4975(e)(3) provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of its assets; (ii) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan or IRA, or has any authority or responsibility to do so; or, (iii) has any discretionary authority or discretionary responsibility in the administration of such plan or IRA.
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants, and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, the providers of investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c)(1975), defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of ERISA section 3(21)(A)(ii) (the “1975 regulation”).
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the 1975 regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B), (the “Regulation”) which are also published in this issue of the
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, plan participant or beneficiary, IRA or IRA owner, the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage versus advisory), or recommendations with respect to rollovers, transfers or distributions from a plan or IRA, including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also provides that as a threshold matter in order to be fiduciary advice, the communication must be a “recommendation” as defined therein. The Regulation, as a matter of clarification, provides that a variety of other communications do not constitute “recommendations,” including non-fiduciary investment education; general communications; and specified communications by platform providers. These communications which do not rise to the level of “recommendations” under the Regulation are discussed more fully in the preamble to the final Regulation.
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in ERISA section 3(3)) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Exchange Act (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
The Department anticipates that the Regulation will cover many investment professionals who did not previously consider themselves to be fiduciaries under ERISA or the Code. Under the Regulation, these entities will be subject to the prohibited transaction restrictions in ERISA and the Code that apply specifically to fiduciaries. ERISA section 406(b)(1) and Code section 4975(c)(1)(E) prohibit a fiduciary from dealing with the income or assets of a plan or IRA in his own interest or his own account. ERISA section 406(b)(2), which does not apply to IRAs, provides that a fiduciary shall not “in his individual or in any other capacity act in any transaction involving the plan on behalf of a party (or represent a party) whose interests are adverse to the interests of the plan or the interests of its participants or beneficiaries.” ERISA section 406(b)(3) and Code section 4975(c)(1)(F) prohibit a fiduciary from receiving any consideration for his own personal account from any party dealing with the plan or IRA in connection with a transaction involving assets of the plan or IRA.
Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA.
Investment professionals typically receive compensation for services to retirement investors in the retail market through a variety of arrangements, which would typically violate the prohibited transaction rules applicable to plan fiduciaries. These include commissions paid by the plan, participant or beneficiary, or IRA, or commissions, sales loads, 12b-1 fees, revenue sharing and other payments from third parties that provide investment products. A fiduciary's receipt of such payments would generally violate the prohibited transaction provisions of ERISA section 406(b) and Code section 4975(c)(1)(E) and (F) because the amount of the fiduciary's compensation is affected by the use of its authority in providing investment advice, unless such payments meet the requirements of an exemption.
As the prohibited transaction provisions demonstrate, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however, the statutes provide exemptions from their broad prohibitions on conflicts of interest. For example, ERISA section 408(b)(14) and Code section 4975(d)(17) specifically exempt transactions involving the provision of fiduciary investment advice to a participant or beneficiary of an individual account plan or IRA owner if the advice, resulting transaction, and the adviser's fees meet stringent conditions carefully designed to guard against conflicts of interest.
In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions. However, when they choose to give advice in which they have a conflict of interest, they must rely upon an exemption.
Pursuant to its exemption authority, the Department has previously granted several conditional administrative class exemptions that are available to fiduciary advisers in defined circumstances. As a general proposition, these exemptions focused on specific advice arrangements and provided relief for narrow categories of compensation. In contrast to these earlier exemptions, this new Best Interest Contract Exemption is specifically designed to address the conflicts of interest associated with the wide variety of payments Advisers receive in connection with retail transactions involving plans and IRAs. Similarly, the Department has granted a new exemption for principal transactions, Exemption for Principal Transactions in Certain Assets between Investment Advice Fiduciaries and Employee Benefit Plans and IRAs, (Principal Transactions Exemption), also published in this issue of the
At the same time that the Department has granted these new exemptions, it has also amended existing exemptions to ensure uniform application of the Impartial Conduct Standards, which are fundamental obligations of fair dealing and fiduciary conduct, and include obligations to act in the customer's best interest, avoid misleading statements, and receive no more than reasonable compensation.
The amendments also revoke certain existing exemptions, which provided little or no protections to IRA and non-ERISA plan participants, in favor of a more uniform application of the Best Interest Contract Exemption in the market for retail investments. With limited exceptions, it is the Department's intent that investment advice fiduciaries in the retail investment market rely on statutory exemptions or the Best Interest Contract Exemption to the extent that they receive conflicted forms of compensation that would otherwise be prohibited. The new and amended exemptions reflect the Department's view that Retirement Investors should be protected by a more consistent application of fundamental fiduciary standards across a wide range of investment products and advice relationships, and that retail investors, in particular, should be protected by the stringent protections set forth in the Best Interest Contract Exemption. When fiduciaries have conflicts of interest, they will uniformly be expected to adhere to fiduciary norms and to make recommendations that are in their customer's best interest.
These new and amended exemptions follow a lengthy public notice and comment process, which gave interested persons an extensive opportunity to comment on the proposed Regulation and exemption proposals. The proposals initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department then held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule.
As finalized, the Best Interest Contract Exemption retains the core protections of the proposed exemption, but with revisions designed to facilitate implementation and compliance with the exemption's terms. In broadest outline, the exemption permits Advisers and the Financial Institutions that employ or otherwise retain them to receive many common forms of compensation that ERISA and the Code would otherwise prohibit, provided that they give advice that is in their customers' Best Interest and the Financial Institution implements basic protections against the dangers posed by conflicts of interest. In particular, to rely on the exemption, Financial Institutions generally must:
• Acknowledge fiduciary status with respect to investment advice to the Retirement Investor;
• Adhere to Impartial Conduct Standards requiring them to:
○ Give advice that is in the Retirement Investor's Best Interest (
○ Charge no more than reasonable compensation; and
○ Make no misleading statements about investment transactions, compensation, and conflicts of interest;
• Implement policies and procedures reasonably and prudently designed to prevent violations of the Impartial Conduct Standards;
• Refrain from giving or using incentives for Advisers to act contrary to the customer's best interest; and
• Fairly disclose the fees, compensation, and Material Conflicts of Interest, associated with their recommendations.
Advisers relying on the exemption must adhere to the Impartial Conduct Standards when making investment recommendations.
The exemption takes a principles-based approach that permits Financial Institutions and Advisers to receive many forms of compensation that would otherwise be prohibited, including, inter alia, commissions, trailing commissions, sales loads, 12b-1 fees, and revenue-sharing payments from investment providers or other third parties to Advisers and Financial Institutions. The exemption is available for advice to retail “Retirement Investors,” including IRA owners, plan participants and beneficiaries, and “retail fiduciaries” (including such fiduciaries of small participant-directed plans). All Financial Institutions relying on the exemption must notify the Department in advance of doing so, and retain records that can be made available to the Department and Retirement Investors for evaluating compliance with the exemption.
The exemption neither bans all conflicted compensation, nor permits Financial Institutions and Advisers to act on their conflicts of interest to the detriment of the Retirement Investors they serve as fiduciaries. Instead, it holds Financial Institutions and their Advisers responsible for adhering to fundamental standards of fiduciary conduct and fair dealing, while leaving them the flexibility and discretion necessary to determine how best to satisfy these basic standards in light of the unique attributes of their particular businesses. The exemption's principles-based conditions, which are rooted in the law of trust and agency, have the breadth and flexibility necessary to apply to a large range of investment and compensation practices, while ensuring that Advisers put the interests of Retirement Investors first. When Advisers choose to give advice to retail Retirement Investors pursuant to conflicted compensation structures, they must protect their customers from the dangers posed by conflicts of interest.
In order to ensure compliance with its broad protective standards and purposes, the exemption gives special attention to the enforceability of its terms by Retirement Investors. When Financial Institutions and Advisers breach their obligations under the exemption and cause losses to Retirement Investors, it is generally critical that the investors have a remedy to redress the injury. The existence of enforceable rights and remedies gives Financial Institutions and Advisers a powerful incentive to comply with the exemption's standards, implement policies and procedures that are more than window-dressing, and carefully police conflicts of interest to ensure that the conflicts of interest do not taint the advice.
Thus, in the case of IRAs and non-ERISA plans, the exemption generally requires the Financial Institution to commit to the Impartial Conduct Standards in an enforceable contract with Retirement Investor customers. The exemption does not similarly require the Financial Institution to execute a separate contract with ERISA investors (which includes plan participants, beneficiaries, and fiduciaries), but the Financial Institution must acknowledge its fiduciary status and that of its advisers, and ERISA investors can directly enforce their rights to proper fiduciary conduct under ERISA section 502(a)(2) and (3). In addition, the exemption safeguards Retirement Investors' enforcement rights by providing that Financial Institutions and Advisers may not rely on the exemption if they include contractual provisions disclaiming liability for compensatory remedies or waiving or qualifying Retirement Investors' right to pursue a class action or other representative action in court. However, the exemption does permit Financial Institutions to include provisions waiving the right to punitive damages or rescission as contract remedies to the extent permitted by other applicable laws. In the Department's view, the availability of make-whole relief for such claims is sufficient to protect Retirement Investors and incentivize compliance with the exemption's conditions.
While the final exemption retains the proposed exemption's core protections, the Department has revised the exemption to ease implementation in response to commenters' concerns about its workability. Thus, for example, the final exemption eliminates the contract requirement altogether in the ERISA context, simplifies the mechanics of contract-formation for IRAs and plans not covered by Title I of ERISA, and provides streamlined conditions for “Level Fee Fiduciaries” that give ongoing advice on a relatively un-conflicted basis. For new customers, the final exemption provides that the required contract terms may simply be incorporated in the Financial Institution's account opening documents and similar commonly-used agreements. The exemption additionally permits reliance on a negative consent process for existing contract holders; and provides a mechanism for Financial Institutions and Advisers to rely on the exemption in the event that the Retirement Investor does not open an account with the Adviser but nevertheless acts on the advice through other channels. The Department recognizes that Retirement Investors may talk to numerous Advisers in numerous settings over the course of their relationship with a Financial Institution. Accordingly, the exemption also simplifies execution of the contract by simply requiring the Financial Institution to execute the contract, rather than each of the individual Advisers from whom the Retirement Investor receives advice. For similar reasons, the exemption does not require execution of the contract at the start of Retirement Investors' conversations with Advisers, as long as it is entered into prior to or at the same time as the recommended investment transaction.
Other changes similarly facilitate reliance on the exemption by clarifying key terms, reducing compliance burden, increasing the exemption's availability with respect to the types of advice recipients and the types of investments that may be recommended, and streamlining and simplifying disclosure requirements. For example, in response to commenter's concerns, the final exemption clarifies that, subject to its conditions, the exemption provides relief for all of the categories of fiduciary recommendations covered by the Regulation, including advice on rollovers, distributions, and services, as well as investment recommendations concerning any asset, rather than a limited list of specified assets. Similarly, the exemption is broadly available to small plan fiduciaries, regardless of the type of plan, as well as to IRA owners, plan participants, and other Retirement Investors. Additionally, in response to concerns about the application of the Best Interest standard to Financial Institutions that limit investment recommendations to Proprietary Products and/or investments that generate Third Party Payments, the exemption includes a specific test for satisfying the Best Interest standard in these circumstances. Also in response to comments, the exemption makes clear that it does not ban commissions or mandate rigid fee-leveling (
The Department also streamlined compliance for “Level Fee Fiduciaries”—fiduciaries that, together with their Affiliates, receive only a Level Fee in connection with advisory or investment management services with respect to plan or IRA assets (
As a means of facilitating use of this exemption, the Department also reduced the compliance burden by eliminating some of the proposed conditions that were not critical to its protective purposes, and by expanding the scope of its coverage (
In making these adjustments to the exemption, the Department was mindful of public comments that expressed concern about the 2015 proposal's potential negative effects on small investors' access to affordable investment advice. In particular, the Department considered comments on the costs and benefits of the proposed Regulation and exemptions. As detailed in the Regulatory Impact Analysis
Many comments anticipating sharp increases in the cost of advice neglected many of the costs currently attributable to conflicted advice including, for example, indirect fees. Many exaggerated the negative impacts (and neglected the positive impacts) of recent overseas reforms and/or the similarity of such reforms to the 2015 proposal. Many implicitly and without support assumed rigidity in existing business models, service levels, compensation structures and/or pricing levels, neglecting the demonstrated existence of low-cost solutions and potential for investor-friendly market adjustments. Many that predicted that only wealthier investors would be served appeared to neglect that once the fixed costs of serving these investors was defrayed only the relatively small marginal cost of serving smaller investors would remain for firms and investors to bear.
Many comments arguing that costlier advice will compromise savings exaggerated their case by presenting mere correlation (wealth and advisory services are found together) as evidence that advice causes large increases in saving. Some wrongly implied that earlier Department estimates of the potential for fiduciary advice to reduce retirement investment errors—when accompanied by very strong anti-conflict consumer protections—constituted an acknowledgement that conflicted advice yields large net benefits.
The negative comments that offered their own original analysis, and whose conclusions contradicted the Department's, also are generally unpersuasive on balance in the context of this present analysis. For example, these comments variously neglected important factors such as indirect fees, made comparisons without adjusting for risk, relied on data that is likely to be unrepresentative, failed to distinguish conflicted from independent advice, and/or presented as evidence median results when the problems targeted by the 2015 proposal and the proposal's expected benefits are likely to be concentrated on one side of the distribution's median.
In light of these weaknesses in the aforementioned negative comments, the Department found their arguments largely unpersuasive. Moreover, responsive changes to the 2015 proposal reflected in this final rulemaking further minimize any risk of an unintended negative impact on small investors' access to affordable advice. The Department therefore stands by its conclusions that adviser conflicts are inflicting large, avoidable losses on retirement investors, that appropriate, strong reforms are necessary, and this final rulemaking will deliver large net gains to retirement investors. The Department does not anticipate the substantial, long-term unintended consequences predicted in these negative comments.
To ease the transition for Financial Institutions and Advisers that are now more clearly recognized as fiduciaries under the Regulation, the Department has also expanded the “grandfathered” relief for compensation associated with investments made prior to the Regulation's Applicability Date. The final exemption also provides a transition period in Section IX under which prohibited transaction relief is available for Financial Institutions and Advisers during the period between the Applicability Date and January 1, 2018, subject to more limited conditions.
The comments on the Best Interest Contract Exemption, the Regulation, and related exemptions have helped the Department improve this exemption, while preserving and enhancing its protections. As described above, the Department has revised the exemption to facilitate implementation and compliance with the exemption, without diluting its core protections, which are critical to reducing the harm caused by conflicts of interest in the marketplace for advice. The tax-preferred investments covered by the exemption are critical to the financial security and physical health of investors. After consideration of the comments, the Department remains convinced of the importance of the exemption's core protections.
ERISA and the Code are rightly skeptical of the dangers posed by conflicts of interest, and generally prohibit conflicted advice. Before granting exemptive relief, the Department has a statutory obligation to ensure that the exemption is in the interests of plan and IRA investors and protective of their rights. Adherence to the fundamental fiduciary norms and basic protective conditions of this exemption helps ensure that investment recommendations are not driven by Adviser conflicts, but by the Best Interest of the Retirement Investor. Advisers can always give conflict-free advice. But if they choose to rely upon conflicted payment structures, they should be prepared to make an enforceable commitment to safeguard Retirement Investors from biased advice that is not in the investor's Best Interest. The conditions of this exemption are carefully calibrated to permit a wide variety of compensation structures, while protecting Retirement Investors' interest in receiving sound advice on vitally important investments. Based upon these protective conditions, the Department finds that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of participants and beneficiaries of plans and IRA owners.
The preamble sections that follow provide a much more detailed discussion of the exemption's terms, comments on the exemption, and the Department's responses to those comments. After a discussion of the exemption's scope and limitations, the preamble discusses the conditions of the
The exemption provides relief for the receipt of compensation by “Advisers” and “Financial Institutions,” and their “Affiliates” and “Related Entities,” as a result of their provision of investment advice within the meaning of ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B) to a “Retirement Investor.”
In response to commenters' concerns, the exemption expressly provides relief for all categories of fiduciary recommendations set forth in the Regulation. In addition to covering asset recommendations, for example, an Adviser and Financial Institution can provide investment advice regarding the rollover or distribution of assets of a plan or IRA; the hiring of a person to advise on or manage the assets; and the advisability of acquiring, holding, disposing, or exchanging certain common investments by Retirement Investors. These activities fall within the provisions of the Regulation identifying, as fiduciary conduct: (i) Recommendations as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other property is rolled over, transferred distributed from the plan or IRA, and (ii) recommendations as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, selection of investment account arrangements (
The exemption has also been revised to extend to recommendations concerning any investment product, rather than restricted to a specific list of defined “Assets,” and to cover riskless principal transactions.
The exemption does not, however, provide relief for all transactions involving advice in the retail market. In particular, the exemption excludes advice rendered in connection with principal transactions that are not riskless principal transactions, advice from fiduciaries with discretionary authority over the recommended transaction, so-called robo-advice (unless provided by Level Fee Fiduciaries in accordance with Section II(h)), and specified advice concerning in-house plans. These exclusions, set forth in Section I(c), involve special circumstances that warrant a different approach than the one set forth in this exemption, and are discussed further below.
Commenters on the scope of the exemption, as proposed, primarily focused on six categories of issues: (1) The treatment of rollovers, distributions and services; (2) the definition of Retirement Investor; (3) the limits on the Asset recommendations covered by the exemption; (4) riskless principal transactions, (5) indexed annuities and variable annuities, and (6) the types of compensation that the Adviser or Financial Institution may receive. These issues are discussed below.
As proposed, the exemption would have applied to “compensation for services provided in connection with a purchase, sale or holding of an Asset by a plan, participant or beneficiary account, or IRA.” A number of commenters requested clarification or revision of this language. These commenters questioned whether the exemption would cover recommendations regarding rollovers, distributions, or services such as managed accounts and advice programs. Although the Department had intended to cover these recommendations as part of its original proposal, commenters expressed concern that in some circumstances, the recommendations might not be considered sufficiently connected to the purchase, sale or holding of an Asset to meet the exemption's terms.
In this regard, some commenters stated that, while the proposed Regulation made clear that providing advice to take a distribution or to roll over assets from a plan or IRA, for a fee, was clearly fiduciary advice, it did not appear that relief for any resulting prohibited transactions was contemplated in the proposed exemption. More specifically, a few commenters argued that there are several steps to a rollover recommendation and that relief may be necessary at each step. For example, one commenter suggested that a rollover recommendation is best evaluated as including four separate recommendations: “(i) A recommendation to take a distribution `from' the plan; (ii) a recommendation to hire the Adviser; (iii) the recommendation to rollover to an IRA; and (iv) the recommendation regarding how to invest the assets of the IRA once rolled over.” Other commenters indicated that in their view recommendations of individuals to provide investment advisory or investment management services, also fiduciary conduct, was not clearly covered by the proposed exemption.
In response, the Department has revised the final exemption's description of covered transactions to more clearly coincide with the fiduciary conduct described in the Regulation. Although the Department also intended to cover these recommendations in its original proposal, it agrees that the exemption should more clearly state its broad applicability. The final exemption therefore broadly permits “Advisers, Financial Institutions, and their Affiliates and Related Entities to receive compensation as a result of their provision of investment advice within the meaning of ERISA section 3(21)(A)(ii) or Code Section 4975(e)(3)(B) to a Retirement Investor.”
In addition to questions about whether these types of recommendations were covered, commenters also asked how the conditions of the proposed exemption would apply to recommendations regarding rollovers, distributions and services. Commenters expressed the view that the proposed disclosure requirements were too focused on the costs associated with investments and therefore did not appear tailored to recommendations to rollover plan assets, take a distribution, or hire a provider of investment advisory or management services. Other commenters asked whether there were ongoing monitoring obligations, even when a recommendation involved only a discrete interaction between the Adviser and Retirement Investor. Many commenters indicated that due to the general burden of compliance with the exemption, Advisers and Financial Institutions might be unwilling to provide advice to Retirement Investors who were eligible to take a distribution from their employer's plan, and that left on their own, these investors might decide to take the money out of retirement savings.
In connection with these concerns, a few commenters requested separate exemptions for rollover and distribution recommendations, and services recommendations. One commenter asked the Department to create an exemption for rollovers subject only to the condition that the Adviser act in the Retirement Investor's Best Interest. Another commenter suggested an exemption based on disclosure, signed by the participant, of the options associated with a rollover. Others requested a safe harbor for rollovers based on the Financial Industry Regulatory Authority's (FINRA's) Regulatory Notice 13-45 (“Rollovers to Individual Retirement Accounts”).
Citing the critical importance of the decision to rollover plan assets or take a distribution, other commenters asserted that the protections of the exemption would be especially important in the rollover and distribution context, and could even be strengthened. Advisers and Financial Institutions frequently stand to earn compensation as a result of a rollover that they would not be able to earn if the money remains invested in an ERISA plan. In addition, rollovers from an ERISA plan to an IRA can involve the entirety of workers' savings over a lifetime of work. Because large and consequential sums are often involved, bad advice on rollovers or distributions can have catastrophic consequences with respect to such workers' financial security in retirement.
The Department has considered these comments and questions. Rather than adopt separate exemptions, as requested by some commenters, the approach taken in the final exemption is to retain the proposed exemption's core protections, while revising the exemption to reduce burden and facilitate compliance in a wide variety of contexts. Accordingly, as described in more detail below, the Department revised the disclosure and data retention requirements in this final exemption. The exemption does not require a pre-transaction disclosure that includes projections of the total costs of the investment over time, and no longer includes the proposed annual disclosure or data collection requirements. Rather than require up-front highly-customized disclosure, the exemption requires a more general statement of the Best Interest standard of care and the Advisers' and Financial Institutions' Material Conflicts of Interest, and related disclosures, with the provision of more specific, customized disclosure, only upon the Retirement Investor's request. The exemption also expressly clarifies that the parties involved in the transaction are generally free not to enter into an arrangement involving ongoing monitoring, so that a discrete rollover or distribution recommendation, or services recommendation, without further involvement by an Adviser or Financial Institution, does not necessarily create an ongoing monitoring obligation. As a result of these changes, Advisers and Financial Institutions can satisfy the disclosure conditions of the exemption with respect to transactions involving rollovers, distributions and services.
The final exemption provides streamlined conditions for “Level Fee Fiduciaries.” A Financial Institution and Adviser are Level Fee Fiduciaries if the only fee or compensation received by the Financial Institution, Adviser and any Affiliate in connection with the advisory or investment management services is a “Level Fee” that is disclosed in advance to the Retirement Investor. A Level Fee is defined in the exemption as a fee or compensation that is provided on the basis of a fixed percentage of the value of the assets or a set fee that does not vary with the particular investment recommended, rather than a commission or other transaction-based fee.
In this regard, the Department believes that, by itself, the ongoing receipt of a Level Fee such as a fixed percentage of the value of a customer's assets under management, where such values are determined by readily available independent sources or independent valuations, typically would not raise prohibited transaction concerns for the Adviser or Financial Institution. Under these circumstances, the compensation amount depends solely on the value of the investments in a client account, and ordinarily the interests of the Adviser in making prudent investment recommendations, which could have an effect on compensation received, are aligned with the Retirement Investor's interests in increasing and protecting account investments. However, there is a clear and substantial conflict of interest when an Adviser recommends that a participant roll money out of a plan into a fee-based account that will generate ongoing fees for the Adviser that he would not otherwise receive, even if the fees going-forward do not vary with the assets recommended or invested. Similarly, the prohibited transaction rules could be implicated by a recommendation to switch from a low activity commission-based account to an account that charges a fixed percentage of assets under management on an ongoing basis.
Because the prohibited transaction in these examples is relatively discrete and the provision of advice thereafter generally does not involve prohibited transactions, the final exemption includes streamlined conditions to cover the discrete advice that requires the exemption.
Section II(h) establishes the conditions of the exemption for Level Fee Fiduciaries. It requires that the Financial Institution give the Retirement Investor the written fiduciary statement described in Section II(b) and that both the Financial Institution and any Adviser comply with the Impartial Conduct Standards described in Section II(c). Additionally, when recommending a rollover from an ERISA plan to an IRA, a rollover from another IRA, or a switch from a commission-based account to a fee-based account, the Level Fee Fiduciary must document the reasons why the level fee arrangement was considered to be in the Best Interest of the Retirement Investor.
When Level Fee Fiduciaries recommend rollovers from an ERISA plan, they must document their consideration of the Retirement Investor's alternatives to a rollover, including leaving the money in his or her current employer's plan, if permitted. Specifically, the documentation must take into account the fees and expenses associated with both the plan and the IRA; whether the employer pays for some or all of the plan's administrative expenses; and the different levels of services and different investments available under each option. In this regard, Advisers and Financial Institutions should consider the Retirement Investor's individual needs and circumstances, as described in FINRA Regulatory Notice 13-45. If a Level Fee arrangement is recommended as part of a rollover from another IRA, or a switch from a commission-based account, the Level Fee Fiduciary's documentation must include the reasons that the arrangement is considered in the Retirement Investor's Best Interest, including, specifically, the services that will be provided for the fee. The exemption does not specify any particular format or method for generating or retaining the documentation, which could be paper or electronic, but rather gives the Level Fee Fiduciary flexibility to determine what works best for its business model, so long as it meets the exemption's conditions.
It is important to note that the definition of Level Fee explicitly excludes receipt by the Adviser, Financial Institution or any Affiliate of commissions or other transaction-based payments. Accordingly, if either the Financial Institution or the Adviser or their Affiliates, receive any other remunerations (
As noted above, a number of commenters requested separate exemptions for fiduciaries that would only receive level fees after being retained. Some of these commenters indicated that more streamlined conditions would promote the receipt of rollover advice by plan participants. The commenters suggested a variety of conditions, including a contract, a best interest standard, and disclosure of compensation.
The provisions for Level Fee Fiduciaries in this exemption respond to those commenters by streamlining the conditions applicable to fiduciaries that provide advice on a Level Fee basis. Thus, for example, the exemption does not require Level Fee Fiduciaries to make the warranties required of other Advisers whose Financial Institutions will continue to receive compensation that varies with their investment recommendations. Similarly, because the most common scenario in which Level Fee Fiduciaries need an exemption is when they make a recommendation to rollover assets from an ERISA plan to an IRA, the final exemption does not require Level Fee Fiduciaries to enter into a contract. Instead, such Retirement Investors would be able to rely on their statutory rights under ERISA in the event the applicable standards are not met.
The Department did not adopt other streamlined or separate exemptions as requested by other commenters. In general, these separate exemptions suggested by commenters were not premised on the receipt of truly level fees, but would have permitted some variable compensation to occur based on the Retirement Investor's investment decisions after the fiduciary was retained. The Department determined that these transactions should occur in accordance with the general conditions of this exemption which provide additional safeguards for Retirement Investors in the context of such variable payments.
This exemption is designed to promote the provision of investment advice to retail investors that is in their Best Interest and untainted by conflicts of interest. The exemption permits receipt by Advisers and Financial Institutions, and their Affiliates and Related Entities, of compensation commonly received in the retail market, such as commissions, 12b-1 fees, and revenue sharing payments, subject to conditions specifically designed to protect the interests of retail investors. For consistency with these objectives, the exemption applies to the receipt of such compensation by Advisers, Financial Institutions, and their Affiliates and Related Entities, only when advice is provided to “Retirement Investors,” defined as participants and beneficiaries of a plan subject to Title I of ERISA or described in Code section 4975(e)(1)(A); IRA owners; and “Retail Fiduciaries” of plans or IRAs to the extent they act as fiduciaries with authority to make investment decisions for the plan. Unlike the proposed exemption, Retail Fiduciaries can include the fiduciaries of both participant-directed and non-participant directed plans. The Department also confirms that Retirement Investors can include plan participants and beneficiaries who invest through a self-directed brokerage window.
The definition of Retail Fiduciary dovetails with provisions in the Regulation that permit persons to avoid fiduciary status when they provide advice to independent fiduciaries with financial expertise (described in paragraph (c)(1)(i) of the Regulation) under certain conditions.
The exemption's definition of “Retail Fiduciary” is intended to work with the definition of independent fiduciary in the Regulation, so that if a person providing advice in the retail market cannot avoid fiduciary status under the Regulation because the advice recipient fails to meet the conditions for advice to independent fiduciaries under paragraph (c)(1)(i) of the rule, the person can rely on this exemption for advice to a Retirement Investor, if the conditions are satisfied.
As initially proposed, the definition of Retirement Investor was much more limited. It included only plan sponsors (and employees, officers and directors thereof) of non-participant directed plans with fewer than 100 participants. The proposal did not extend to small participant-directed plans, although the Department specifically sought comment on whether the exemption should be expanded in that respect. The definition of “Retail Fiduciary” in the final exemption effectively eliminates this limitation by covering the fiduciaries of such plans (including plan sponsors, employees, officers, and directors), unless they are institutional fiduciaries or fiduciaries that hold, manage, or control $50 million or more in assets.
The final exemption, like the proposal, is limited to retail investors, subject to the definitional changes described above. Persons making recommendations to independent institutional fiduciaries and large money managers in arm's length transactions have a ready means to avoid fiduciary status, and correspondingly less need for the exemption. Moreover, investment advice fiduciaries with respect to large ERISA plans have long acknowledged fiduciary status and operated within the constraints of prohibited transaction rules. As a result, extending this Best Interest Contract Exemption to such fiduciaries, and facilitating their receipt of otherwise prohibited compensation, could result in the promotion, rather than reduction, of conflicted investment advice.
Comments on the definition of Retirement Investor, and the Department's responses, are discussed in the next sections of this preamble.
Commenters generally indicated that the exemption should extend to participant-directed plans. Many commenters expressed concern that excluding such plans as Retirement Investors would leave them without sufficient access to much needed investment advice, particularly on choosing the menu of investment options available to participants and beneficiaries, and might even discourage employers from adopting ERISA-covered plans. The U.S. Small Business Administration Office of Advocacy (SBA Office of Advocacy) commented that, according to the reports from small business owners, most small plans are participant-directed, and suggested that the exclusion of participant-directed plans would result in small business advisers to small plans being prevented from taking advantage of the exemption all together. Commenters noted that advisers to these plan fiduciaries could not avoid fiduciary status under the proposed Regulation's provision on counterparty transactions (the Seller's Exception), and the “carve-out” for platform providers in the Regulation did not permit individualized advice. While one commenter acknowledged that fiduciaries of participant-directed plans could receive investment advice under compensation arrangements that do not raise prohibited transactions issues, the commenter nevertheless supported extending the exemption to participant-directed plans to facilitate access to advice under a variety of compensation arrangements.
The Department also received comments on the aspect of the proposal that limited Retirement Investors to plan sponsors (and employees, officers and directors thereof) of plans. A few commenters asserted that all types of plan fiduciaries should be able to receive advice under the exemption. One commenter specifically identified “trustees, fiduciary committees and other fiduciaries.”
The Department's expanded definition of Retail Fiduciaries in the final exemption applies generally to all fiduciaries who are not institutional fiduciaries or large money managers, regardless of whether they are fiduciaries of participant-directed plans or other plans. In addition, the exemption extends coverage to advice to all plan fiduciaries, not just plan sponsors and their employees, officers and directors. As noted above, the Department intends to cover all advisers, regardless of plan-type, who cannot avail themselves of the Regulation's exception for fiduciaries with financial expertise (
However, while the Department has expanded the exemption to cover Retail Fiduciaries with respect to participant-directed plans, it believes the commenters' concerns about a significant loss of advice and services to participant-directed plans were overstated. Investment advice providers who became fiduciaries under the Regulation would have been able to provide investment advice to all plans, as long as they did so under an arrangement that does not raise prohibited transactions issues, including by offsetting Third Party Payments against level fees.
Nevertheless, the conditions of this final exemption have been carefully crafted to protect retail investors, including small, participant-directed plans. After considering the comments, the Department agrees that small plans would benefit from the protections of the exemption, and that expanding the scope of this exemption to all Retail Fiduciaries, including such fiduciaries of participant-directed plans, would better promote the provision of best interest advice to all retail Retirement Investors.
The Department also received comments regarding the proposed 100-participant threshold for plans to qualify as Retirement Investors. Some commenters requested that the Retirement Investor definition include fiduciaries of plans with more than 100 participants. These commenters saw no reason to distinguish between small and large plans, since ERISA applies equally to both. One commenter requested that the Department use an asset-based test rather than a test based on number of participants, as a method of determining which plans should be Retirement Investors under the exemption. The commenter expressed the view that plan size might not be a proxy for sophistication, as many large employers have multiple plans, some of which may have fewer than 100 participants. Other commenters asserted that it could be difficult for Advisers and Financial Institutions to keep track of the number of plan participants to determine whether a particular plan satisfied the Retirement Investor definition.
Other commenters supported the limitation to smaller plans, writing that larger plans have other means of access to high-quality advice, including the provision in the proposed Regulation for counterparties in arm's length transactions with an independent fiduciary with financial expertise, and so did not need the protections and constraints of the exemption.
One commenter suggested that the exemption be available for advice to IRAs only, because the exemption would reduce the existing protections for ERISA plans of all sizes. According to the commenter, investment advice fiduciaries to ERISA plans should rely instead on the statutory exemption in ERISA section 408(b)(14) for “eligible investment advice arrangements” as described in ERISA section 408(g). In the commenter's view, this exemption would undermine the protections of that exemption and the regulations thereunder. In the Department's judgment, however, the exemption's conditions strike an appropriate balance for small plan investors by facilitating the continued provision of advice in reliance on common fee structures, while mitigating the impact of the conflicts of interest on the quality of the advice.
The final exemption retains the limitation for advice to retail Retirement Investors. In determining whether a plan fiduciary is a Retirement Investor, however, the Department has revised the exemption to focus on characteristics of the advice recipient rather than plan size for determining whether a plan fiduciary is a Retirement Investor. As discussed above, the definition of Retail Fiduciary, therefore, generally focuses on the fiduciary's status as a financial institution or the amount of its assets under management.
This approach in effect still limits the exemption to smaller plans, as fiduciaries that hold, manage, or control $50 million or more in assets will generally be excluded as Retirement Investors. In many cases, persons making recommendations to large plans can avoid fiduciary status by availing themselves of the Rule's exception for transactions with sophisticated investor counterparties. But when they instead act as investment advice fiduciaries, the Department believes they are appropriately excluded from the scope of this exemption, which was designed for retail Retirement Investors. As discussed above, including larger plans within the definition of Retirement Investor could have the undesirable consequence of reducing protections provided under existing law to these investors, without offsetting benefits. In particular, it could have the undesirable effect of increasing the number and impact of conflicts of interest, rather than reducing or mitigating them. Accordingly the final exemption was not expanded to include larger plans as Retirement Investors.
Several commenters asked for clarification of the types of plans that could be represented by fiduciaries that are Retirement Investors. A few commenters requested that the exemption extend to Simplified Employee Pensions (SEPs) and Savings Incentive Match Plans for Employees (SIMPLEs). In the final exemption, the definition of Retail Fiduciary includes a fiduciary with respect to both ERISA plans and plans described in Code section 4975(e)(1)(A). This definition includes SEPs and SIMPLEs.
Other commenters observed that Keogh plans were excluded from the proposed definition of Retirement Investor. While these plans are not subject to Title I of ERISA, they are defined in Code section 4975(e)(1)(A) and are covered under the prohibited transaction provisions of Code section 4975. The definition of Retail Fiduciary covers a fiduciary with respect to a plan described in Code section 4975(e)(1)(A). In addition, the Department has revised the definition of Retirement Investor to include participants and beneficiaries of plans described in Code section 4975(e)(1)(A). Conflicts of interest pose similar dangers to all retail investors, and the Department, accordingly, believes that all retail investors would benefit from the protections set forth in this Best Interest Contract Exemption.
The final exemption does not limit the types of investments that can be recommended by Advisers and Financial Institutions. The exemption is significantly broader in this respect than the proposal, which would have limited the investments that could be recommended as covered “Assets.” Although the definition in the proposed exemption was quite expansive, it did not cover all “securities or other investment property” that could be the subject of an investment recommendation under the Regulation.
As proposed, the definition of Asset included the following investment products:
Bank deposits, certificates of deposit (CDs), shares or interests in registered investment companies, bank collective funds, insurance company separate accounts, exchange-traded REITs, exchange-traded funds, corporate bonds offered pursuant to a registration statement under the Securities Act of 1933, agency debt securities as defined in FINRA Rule 6710(l) or its successor, U.S. Treasury securities as defined in FINRA Rule 6710(p) or its successor, insurance and annuity contracts, guaranteed investment contracts, and equity securities within the meaning of 17 CFR 230.405 that are exchange-traded securities within the meaning of 17 CFR 242.600. Excluded from this definition is any equity security that is a security future or a put, call, straddle, or other option or privilege of buying an equity security from or selling an equity security to another without being bound to do so.
The Department viewed the limited definition of Asset in the proposal as part of the protective framework of the exemption. The intent in proposing a limited definition of Asset was to permit investment advice on of the types of investments that Retirement Investors typically rely on to build a basic diversified portfolio, under a uniform set of protective conditions, while avoiding potential issues with less common investments that may possess unusual complexity, illiquidity, risk, lack of transparency, high fees or commissions, or illusory tax “efficiencies.” In the context of some of these investments, Retirement Investors may be less able to police the conduct of their Adviser or assess whether they are getting a good or bad deal. Accordingly, the Asset limitation was intended to work with the other safeguards in the exemption to ensure investment advice is provided in Retirement Investors' Best Interest.
Commenters representing the industry strenuously objected to the limited definition of “Asset.” Commenters took the position that the limited definition would be inconsistent with the Department's historical approach of declining to create a “legal list” of investments for plan fiduciaries. Some commenters argued that Congress imposed only very narrow limits on the types of investments IRAs may make, and therefore the Department should not impose other limitations in an exemption.
Many commenters viewed the proposed limited definition of Asset as the Department substituting its judgment for that of the Adviser and stating which investments are permissible or “worthy.” Some commenters believed that the Best Interest standard alone should guide the recommendations of specific investments. Some asserted that the limitations could even undermine Advisers' obligation to act in the best interest of Retirement Investors.
In the event that the Department determined to proceed with the limited definition of Asset, commenters argued that it should be expanded to include specific additional investments. Some examples of such additional investments include: Non-traded business development companies, cleared swaps and cleared security-based swaps, commodities, direct participation programs, energy and equipment leasing programs, exchange traded options, federal agency and government sponsored enterprise guaranteed mortgage-backed securities, foreign bonds, foreign currency, foreign equities, futures (including exchange-traded futures), hedge funds, limited partnerships, market linked CDs, municipal bonds, non-traded REITs, over-the-counter equities, precious metals, private equity, real estate, stable value wrap contracts, structured notes, structured products, and non-U.S. funds that are registered or listed on an exchange in their home jurisdiction.
Some commenters also asked how the exemption would be updated to accommodate new investments over time. One commenter suggested that, as an alternative to the definition of Asset, the exemption should establish a series of principles governing the types of investments that could be recommended. The principles suggested by the commenter included transparent pricing, sufficient liquidity, lack of excessive complexity and leverage, a sufficient track record to demonstrate its utility, and not providing a redundant or illusory tax benefit inside a retirement account.
Other commenters argued for an expansion of the types of investments that could be recommended to sophisticated investors. Commenters indicated that the definition of Asset could be expanded or eliminated entirely for these Retirement Investors, on the basis that alternative investments could be appropriate for them. These commenters suggested the Department could rely on the securities laws, specifically the accredited investor rules, to make sure that investors could bear the potential losses of their investments.
However, the Department also received comments supporting the proposed definition of Asset as an appropriate safeguard of the exemption. These commenters expressed the view that the list was sufficiently broad to allow an Adviser to meet a Retirement Investor's needs, while limiting the risks of other types of investments. Retirement Investors would still have access to these excluded investments under either pooled investment vehicles such as mutual funds, or pursuant to compensation models that do not involve conflicted advice. Some commenters expressed support for exclusion of specific investment products, such as non-traded Real Estate Investment Trusts (REITs), private placements, and other complex products, indicating these investments may be associated with extremely high fees. A commenter asserted that there have been significant problems with recommendations of non-traded REITs and private placements in recent years. Another commenter urged that the exemption not provide relief for the recommendation of variable annuity contracts, although they were in the proposed definition of Asset.
Likewise, some commenters opposed any different treatment of sophisticated investors. The commenters said that net worth of an individual is not a reliable measure of financial knowledge, and the thresholds under securities law may be too low to identify those who can risk substantial portions of their retirement savings.
After careful consideration of these comments, the Department eliminated the definition of Asset in the final exemption. In this regard, the Department ultimately determined that the other safeguards adopted in the final exemption—in particular, the requirement that Advisers and Financial Institutions provide investment advice in accordance with the Impartial Conduct Standards, the requirement that Financial Institutions adopt anti-conflict policies and procedures and the requirement that Financial Institutions disclose their Material Conflicts of Interest—were sufficiently protective to allow the exemption to apply more broadly to all securities and other investment property. If adhered to, these conditions should be protective with respect to all investments. It is not the Department's intent to foreclose fiduciaries, adhering to the exemption's standards, from recommending such investments if they prudently determine that they are the right investments for the particular customer and circumstances. For these same reasons, the Department has decided not to limit the exemption to investments meeting certain principles, as suggested by a commenter.
However, the fact that the exemption was broadened does not mean the Department is no longer concerned about some of the attributes of the investments that were not initially included in the proposed definition of Asset, such as unusual complexity, illiquidity, risk, lack of transparency, high fees or commissions, or tax benefits that are generally unnecessary in these tax preferred accounts. This broadening of the exemption for products with these attributes must be accompanied by particular care and vigilance on the part of Financial Institutions responsible for overseeing Advisers' recommendations of such products. Moreover, the Department intends to pay special attention to recommendations involving such products after the Applicability Date to ensure adherence to the Impartial Conduct Standards and verify that the exemption is sufficiently protective.
The Department expects that Advisers and Financial Institutions providing
Further, when determining the extent of the monitoring to be provided, as disclosed in the contract pursuant to Section II(e) of the exemption, such Financial Institutions should carefully consider whether certain investments can be prudently recommended to the individual Retirement Investor, in the first place, without a mechanism in place for the ongoing monitoring of the investment. This is particularly a concern with respect to investments that possess unusual complexity and risk, and that are likely to require further guidance to protect the investor's interests. Without an accompanying agreement to monitor certain recommended investments, or at least a recommendation that the Retirement Investor arrange for ongoing monitoring, the Adviser may be unable to satisfy the exemption's Best Interest obligation with respect to such investments. Similarly, the added cost of monitoring such investments should be considered by the Adviser and Financial Institution in determining whether the recommended investments are in the Retirement Investors' Best Interest.
The final exemption extends to compensation received in transactions that are “riskless principal transactions.” A riskless principal transaction is defined in Section VIII(p) as “a transaction in which a Financial Institution, after having received an order from a Retirement Investor to buy or sell an investment product, purchases or sells the same investment product for the Financial Institution's own account to offset the contemporaneous transaction with the Retirement Investor.”
Apart from riskless principal transactions, Section I(c)(2) of the final exemption, which sets forth the exclusions from relief, states that the exemption does not apply to compensation that is received as a result of a principal transaction. A “principal transaction” is defined in Section VIII(k) as “a purchase or sale of an investment product if an Adviser or Financial Institution is purchasing from or selling to a Plan, participant or beneficiary account, or IRA on behalf of the Financial Institution's own account or the account of a person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with the Financial Institution.” The definition further states that a principal transaction does not include a riskless principal transaction as defined in Section VIII(p). Thus, the exemption draws a distinction between principal transactions and riskless principal transactions.
In the Department's view, principal transactions pose especially acute conflicts of interest because the investment advice fiduciary and Retirement Investor are on opposite sides of the transaction. As a result of the special risks posed by such transactions, the Department has proposed a separate exemption for investment advice fiduciaries to engage in principal transactions involving specified investments, but subject to additional protective conditions. That exemption is also adopted today, as published elsewhere in this issue of the
Commenters on the proposed Best Interest Contract Exemption and the proposed Principal Transactions Exemption asked about the treatment of riskless principal transactions. Some commenters asked the Department to expand the scope of the Best Interest Contract Exemption to include all riskless principal transactions. Commenters argued that riskless principal transactions are the functional equivalent of agency transactions. A commenter asserted that for this reason, riskless principal transactions would not involve the incentive to “dump” unwanted investments on Retirement Investors, which was one of the Department's concerns. The commenters indicated that many investment transactions occur on a “riskless principal” basis rather than a pure agency basis. One commenter stated that this is because counterparties may not want to assume settlement risk with an investor.
The commenters indicated that the proposed restriction in the Best Interest Contract Exemption applicable to all principal transactions, in conjunction with the limited scope of the Principal Transactions Exemption, as proposed, would cause valuable investments to be unavailable to plans and IRAs as a practical matter. Commenters also asked the Department to confirm that riskless principal transactions were covered within the scope of the Principal Transactions Exemption.
In response to comments, the Department has determined to provide broader relief with respect to recommended riskless principal transactions. The scope of the Best Interest Contract Exemption is expanded to extend to riskless principal transactions involving all investments. The Department accepts commenters' representations that the lack of broader relief for riskless principal transactions would result in unnecessarily limited investment choices for Retirement Investors. In addition, the Department also confirmed in the Principal Transactions Exemption that riskless principal transactions are included in the scope of that exemption as well for the specific investments covered therein.
This approach results in some overlap between coverage of riskless principal transactions in this Best Interest Contract Exemption and the Principal Transactions Exemption. With respect to a recommended purchase of an investment that occurs in a riskless principal transaction, the Principal Transactions Exemption is available for the specified investments that are covered in that exemption. The Best Interest Contract Exemption, however, provides broader relief for all recommended purchases. In addition,
This approach is intended to provide flexibility to Financial Institutions relying on the exemptions. The Department believes that some Financial Institutions have business models that involve only riskless principal transactions. These Financial Institutions may not, as a general matter, hold investments in inventory to sell in principal transactions, but they may execute certain transactions as riskless principal transactions. Financial Institutions that do not engage in principal transactions, as defined in the
On the other hand, Financial Institutions that engage in principal transactions may want to organize their practices to comply with the Principal Transactions Exemption. They may not be certain at the outset whether a particular purchase by a plan or IRA will be executed as a principal transaction or a riskless principal transaction. Those Financial Institutions can rely on the Principal Transactions Exemption for the specified assets that may be sold to plans and IRAs without concern whether the transaction is, in fact a riskless principal transaction or a principal transaction.
A discussion of comments on the treatment of specific investments as Principal Transactions is included in a later section of this preamble, explaining the definitions used in this exemption.
The Department received many comments on the proposed exemption's approach to annuity contracts. The final exemption was not revised from the proposal with respect to the coverage of insurance and annuity products, although a number of changes were made to the exemption to make it more readily usable with respect to these products, as discussed below. Advisers and Financial Institutions are permitted to receive compensation in connection with the sale of all insurance and annuity contracts under the exemption.
However, in a companion Notice published elsewhere in this issue of the
In response to the proposal, some commenters, expressing concern about the risks associated with variable annuities, commended the Department for proposing that they should be recommended under the conditions of this exemption rather than PTE 84-24. One commenter cited the provision of FINRA's Investor Alert, “Variable Annuities: Beyond the Hard Sell,” which says:
Investing in a variable annuity within a tax-deferred account, such as an individual retirement account (IRA) may not be a good idea. Since IRAs are already tax-advantaged, a variable annuity will provide no additional tax savings. It will, however, increase the expense of the IRA, while generating fees and commissions for the broker or salesperson.
Other commenters wrote that fixed annuities, particularly indexed annuities, should also be subject to the requirements of this Best Interest Contract Exemption rather than PTE 84-24. One commenter indicated that indexed and variable annuities raise similar issues with respect to conflicted compensation, and that different treatment of the two would create incentives to sell more indexed annuities subject to the less restrictive regulation.
Other commenters urged that Advisers and Financial Institutions should be able to rely on PTE 84-24 for all insurance products, rather than bifurcating relief between two exemptions. Commenters emphasized the benefit, for compliance purposes, of one exemption for all insurance products. These commenters highlighted the importance of lifetime income options, and the ways the Department, the Treasury Department and the IRS have worked to make annuities more accessible to Retirement Investors. They expressed concern that the approach to annuity contracts in the proposals could undermine those efforts.
In this regard, many commenters expressed concern that the disclosure requirements proposed in this exemption were inapplicable to insurance products and that they would not be able to satisfy the Best Interest and other Impartial Conduct Standards, or provide a sufficiently broad range of Assets to satisfy the conditions of Section IV of this exemption, as proposed. Several raised questions about how the proposed definition of “Financial Institution” would apply to insurance companies. According to these commenters, the conditions proposed for this exemption would be so difficult and costly that broker-dealers would stop selling variable annuities to certain IRA customers and retirement plans rather than comply.
Both the Securities and Exchange Commission (SEC) staff and FINRA have issued guidance on indexed annuities. In its 2010 Investor Alert, “Equity-Indexed Annuities: A Complex Choice,” FINRA explained the need for an Alert, as follows:
Sales of equity-indexed annuities (EIAs) . . . have grown considerably in recent years. Although one insurance company at one time included the word `simple' in the name of its product, EIAs are anything but easy to understand. One of the most confusing features of an EIA is the method used to calculate the gain in the index to which the annuity is linked. To make matters worse, there is not one, but several different indexing methods. Because of the variety and complexity of the methods used to credit interest, investors will find it difficult to compare one EIA to another.”
FINRA also explained that equity-indexed annuities “give you more risk (but more potential return) than a fixed annuity but less risk (and less potential return) than a variable annuity.”
Similarly, in its 2011 “Investor Bulletin: Indexed Annuities,” the SEC staff stated “You can lose money buying an indexed annuity. If you need to cancel your annuity early, you may have to pay a significant surrender charge and tax penalties. A surrender charge may result in a loss of principal, so that
Given the risks and complexities of these investments, the Department has determined that indexed annuities are appropriately subject to the same protective conditions of the Best Interest Contract Exemption that apply to variable annuities. These are complex products requiring careful consideration of their terms and risks. Assessing the prudence of a particular indexed annuity requires an understanding, inter alia, of surrender terms and charges; interest rate caps; the particular market index or indexes to which the annuity is linked; the scope of any downside risk; associated administrative and other charges; the insurer's authority to revise terms and charges over the life of the investment; the specific methodology used to compute the index-linked interest rate; and any optional benefits that may be offered, such as living benefits and death benefits. In operation, the index-linked interest rate can be affected by participation rates; spread, margin or asset fees; interest rate caps; the particular method for determining the change in the relevant index over the annuity's period (annual, high water mark, or point-to-point); and the method for calculating interest earned during the annuity's term (
In response to comments, however, the final exemption has been revised so that the conditions identified by commenters are less burdensome and more readily complied with by all Financial Institutions, including insurance companies and distributors of insurance products. In particular, the Department has revised the pre-transaction disclosure so that it does not require a projection of the total cost of the recommended investment, which commenters indicated would be difficult to provide in the insurance context. The Department also did not adopt the proposed data collection requirement, which also posed problems for insurance products, according to commenters.
Further, the Department adjusted the language of the exemption in other places and addressed interpretive issues in the preamble to address the particular questions and concerns raised by the insurance industry. For example, the Department revised the “reasonable compensation” standard throughout the exemption to address comments from the insurance industry regarding the application of the standard to insurance transactions. Additionally, guidance is provided further in this preamble regarding the treatment of insurers as Financial Institutions, within the meaning of the exemption. Finally, the Department provided specific guidance in Section IV of the exemption on satisfaction of the Best Interest standard by Proprietary Product providers.
The Department notes that many insurance industry commenters stressed a desire for one exemption covering all insurance and annuity products. The Department agrees that efficient compliance with fiduciary norms could be promoted by a common set of requirements, but concludes, for the reasons set forth above, that this exemption is best suited to address the conflicts of interest associated with variable annuities, indexed annuities, and similar investments, rather than the less stringent PTE 84-24. Accordingly, the Department has limited the availability of PTE 84-24 to “fixed rate annuity contracts,” while requiring Advisers recommending variable and indexed annuities to rely on this Best Interest Contract Exemption, which is broadly available for any kind of annuity or asset, subject to its specific conditions. In this manner, the final exemption creates a level playing field for variable annuities, indexed annuities, and mutual funds under a common set of requirements, and avoids creating a regulatory incentive to preferentially recommend indexed annuities.
The Department did, however, leave PTE 84-24 available for recommendations involving “fixed rate annuity contracts.” The Department concluded that this approach in the final exemption and final amendment to PTE 84-24 draws the correct lines, applying protective conditions to particularly complex annuities while leaving in place a somewhat more streamlined exemption that would remain applicable to the recommendation of relatively simpler annuity products, which promote lifetime income. To illustrate the features of these products, the Department prepared a chart comparing fixed rate annuities, fixed indexed annuities and variable annuities, which is included as Appendix I.
A few commenters expressed concern that the requirements of this exemption, as proposed, would interfere with state insurance regulatory programs, which would lead to litigation. Commenters asserted that the Department's proposal ignored the role of state insurance regulators in providing consumer protections. The Department does not agree with these comments. In addition to meeting with and consulting with state insurance regulators and the NAIC as part of this project, the Department has also reviewed NAIC model laws and regulations and state reactions to those models in order to ensure that the requirements of this exemption work cohesively with the requirements currently in place. For example, in 2010 the NAIC adopted the Suitability in Annuity Transactions Model Regulation to establish suitability standards in annuity transactions. According to the NAIC, this regulation was adopted specifically to establish a framework under which insurance companies, not just the agent or broker, are “responsible for ensuring that the annuity transactions are suitable.”
Further addressing the scope of the exemption, a number of commenters requested clear confirmation of the types of payments the exemption would permit. As the commenters requested, the Department confirms that this exemption provides relief for commissions paid directly by the plan or IRA, as well as commissions, trailing commissions, sales loads, 12b-1 fees, revenue sharing payments, and other payments by investment product manufacturers or other third parties to Advisers and Financial Institutions. The exemption also covers other compensation received by the Adviser, Financial Institution or their Affiliates and Related Entities as a result of an investment by a plan, participant or beneficiary account, or IRA, such as investment management fees and administrative services fees from an investment vehicle in which the plan, participant or beneficiary account, or IRA invests, and account type fees earned as a result of the Adviser's or Financial Institution's recommendations.
A few comments suggested that the Department should grant a more limited exemption with respect to certain fees, including 12b-1 fees and account maintenance fees. One commenter asserted that account maintenance fees tend to exceed reasonable compensation and should be further constrained by a condition requiring the terms of the transaction to be arm's length. The Department has not adopted this requirement, but rather has sought to draft conditions, including the reasonable compensation conditions, which should be broadly protective, without regard to the particular type of payment or business model.
The exemption also provides relief for referral fees received by banks and bank employees, pursuant to “Bank Networking Arrangements.” A Bank Networking Arrangement is defined in Section VIII(c) of the exemption as an arrangement for the referral of retail non-deposit investment products that satisfies applicable federal banking, securities and insurance regulations, under which bank employees refer bank customers to an unaffiliated investment adviser registered under the Investment Advisers Act of 1940 or under the laws of the state in which the adviser maintains its principal office and place of business, insurance company qualified to do business under the laws of a state, or broker or dealer registered under the Exchange Act, as amended. The exemption provides relief for the receipt of compensation by an Adviser who is a bank employee, and a Financial Institution that is a bank or similar financial institution supervised by the United States or state, or a savings association (as defined in section 3(b)(1) of the Federal Deposit Insurance Act (12 U.S.C. 1813(b)(1)) (a bank), pursuant to a Bank Networking Arrangement in connection with their provision of investment advice to a Retirement Investor, provided the investment advice adheres to the Impartial Conduct Standards set forth in Section II(c).
The exemption's provisions regarding such payments were developed in response to a comment from the American Bankers Association (ABA) regarding such arrangements. The ABA stated that bank employees are permitted to receive a fee for referring bank customers to the bank's brokerage unit or unaffiliated third party under the Gramm-Leach-Bliley Act (GLBA), and indicated that such referrals could result in prohibited transactions if the employees are deemed fiduciaries. The ABA requested that the Department clarify in the final Regulation that referrals permitted under applicable federal banking and securities regulations do not result in fiduciary status in order to avoid potential prohibited transaction liability for an activity that is expressly permitted under federal banking laws.
The Department has considered the ABA's comment and has reviewed related banking, insurance and securities regulations regarding bank referral of retail nondeposit investment products.
Because of the limitations on the activities of bank employees in making referrals, the Department believes in most cases such referrals will not constitute fiduciary investment advice because they will not constitute a “recommendation” within the meaning of the Regulation or because they will not involve a covered recommendation to hire a non-affiliated third party. However, to the extent banks do not choose to structure their operations to avoid providing fiduciary investment advice, the Department concurs with commenters that relief for bank referral compensation is appropriate as long as the arrangement satisfies applicable banking, securities and insurance regulations and the advice is provided in accordance with the Impartial Conduct Standards. In general, the Department is of the view that the existing regulatory structure governing referrals of retail nondeposit investment products provides significant protections to Retirement Investors.
However, should banks choose to provide investment advice within the meaning of the Regulation, the exemption requires that the advice satisfy the core fiduciary standards required under this exemption for conflicted investment advice—they must give prudent advice that is in the customer's best interest, avoid misleading statements, and receive no more than reasonable compensation.
Section I, discussed above, establishes the scope of relief provided by this Best Interest Contract Exemption. Sections II-V of the exemption set forth the conditions applicable to the exemption described in Section I. All applicable conditions must be satisfied in order to avoid application of the specified prohibited transaction provisions of ERISA and the Code. The Department finds that, subject to these conditions, the exemption is administratively feasible, in the interests of plans and of their participants and beneficiaries, and IRA owners and protective of the rights of the participants and beneficiaries of such plans and IRA owners. Under ERISA section 408(a), and Code section 4975(c)(2), the Secretary may not grant an exemption without making such findings. The conditions of the exemption, comments on those conditions, and the Department's responses, are described below.
Section II of the exemption sets forth the requirements that establish the Retirement Investor's enforceable right to adherence to the Impartial Conduct Standards and related conditions. For advice to certain Retirement Investors—specifically, advice regarding investments in IRAs, and plans that are not covered by Title I of ERISA (“non-ERISA plans”), such as Keogh plans—Section II(a) requires the Financial Institution and Retirement Investor to enter into a written contract that includes the provisions described in Section II(b)-(d) of the exemption and that also does not include any of the ineligible provisions described in Section II(f) of the exemption. Financial Institutions additionally must provide the disclosures set forth in Section II(e). As discussed further below, pursuant to Section II(g) of the exemption, advice to Retirement Investors regarding ERISA plans does not have to be subject to a written contract, but Advisers and Financial Institutions must comply with the substantive standards established in Section II(b)-(e) to avoid liability for a non-exempt prohibited transaction. Likewise, in Section II(h), Level Fee Fiduciaries do not have to provide a contract but must provide the written fiduciary acknowledgment, satisfy the Impartial Conducts and document the specific reasons for a recommendation of the level fee arrangement.
The contract with Retirement Investors regarding IRAs and non-ERISA plans must include the Financial Institution's acknowledgment of its fiduciary status and that of its Advisers, as required by Section II(b); the Financial Institution's agreement that it and its Advisers will adhere to the Impartial Conduct Standards, including a Best Interest standard, as required by Section II(c); the Financial Institution's warranty that it has adopted and will comply with anti-conflict policies and procedures reasonably and prudently designed to ensure that Advisers adhere to the Impartial Conduct standards, as required by Section II(d); and the Financial Institution's disclosure of information about its services and applicable fees and compensation, as required by Section II(e). Section II(f) generally provides that the exemption is unavailable if the contract includes exculpatory provisions or provisions waiving the rights and remedies of the plan, IRA or Retirement Investor, including their right to participate in a class action in court. The contract may, however, provide for binding arbitration of individual claims, and may waive contractual rights to punitive damages or rescission.
Of course, Advisers and Financial Institutions are not required to enter into the contract contemplated by this exemption in order to provide investment advice to these Retirement Investors. Advisers and Financial Institutions may always provide advice and receive compensation without the contract requirement if they work with IRAs and non-ERISA plans under circumstances that do not give rise to a prohibited transaction. The contract is required so that Advisers and Financial Institutions can receive the types of compensation as a result of their advice, such as commissions, that are otherwise prohibited by ERISA and the Code due to the significant conflicts of interest they create. To appropriately offset these conflicts, the Department has determined that the enforceable right to adherence to the Impartial Conduct Standards is a critical safeguard with respect to investments in IRAs and non-ERISA plans.
The contract between the IRA or non-ERISA plan, and the Financial Institution, forms the basis of the IRA's or non-ERISA plan's enforcement rights. The Department intends that all the contractual obligations imposed on the
In the Department's view, these contractual rights serve a critical function for IRA owners and participants and beneficiaries of non-ERISA plans. Unlike participants and beneficiaries in plans covered by Title I of ERISA, IRA owners and participants and beneficiaries in non-ERISA plans do not have an independent statutory right to bring suit against fiduciaries for violation of the prohibited transaction rules. Nor can the Secretary of Labor bring suit to enforce the prohibited transactions rules on their behalf.
Under Section II(g), however, the written contract requirement does not apply to advice to Retirement Investors regarding investments in plans that are covered by Title I of ERISA (“ERISA plans”) in light of the existing statutory framework which provides a pre-existing enforcement mechanism for these investors and the Department. Instead, Advisers and Financial Institutions must simply satisfy the provisions in Section II(b)-(e) as conditions of the exemption when transacting with such Retirement Investors. Under the terms of the exemption, the Financial Institution must provide an acknowledgment of its and its Advisers fiduciary status, although it does not have to be part of a contract, as required by Section II(b); the Financial Institution and its Advisers must comply with the Impartial Conduct Standards, as required by Section II(c); the Financial Institutions must establish and comply with anti-conflict policies and procedures, as required by Section II(d); and they must provide the disclosures required by Section II(e).
If these conditions are not satisfied with respect to an ERISA plan in a transaction in which an Adviser or Financial Institution received prohibited compensation, the Adviser and Financial Institution would be unable to rely on the exemption for relief from ERISA's prohibited transactions restrictions. An Adviser's failure to comply with the exemption would result in a non-exempt prohibited transaction under ERISA section 406 and would likely constitute a fiduciary breach under ERISA section 404. As a result, a plan, plan participant or beneficiary would be able to sue under ERISA section 502(a)(2) or (3) to recover any loss in value to the plan (including the loss in value to an individual account), or to obtain disgorgement of any wrongful profits or unjust enrichment. In addition, the Secretary of Labor can enforce ERISA's prohibited transaction and fiduciary duty provisions with respect to these ERISA plans, and an excise tax under the Code, as described above, applies.
In this regard, under Section II(g)(5) of the exemption, the Financial Institution and Adviser may not rely on the exemption if, in any contract, instrument, or communication they purport to disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by ERISA section 410, waive or qualify the right of the Retirement Investor to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or require arbitration or mediation of individual claims in locations that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption. The exemption's enforceability, and the potential for liability, are critical to ensuring adherence to the exemption's stringent standards and protections, notwithstanding the competing pull of the conflicts of interest associated with the covered compensation structures.
The Department expects claims of Retirement Investors regarding investments in ERISA plans to be brought under ERISA's enforcement provisions, discussed above. In general, Section 410 of ERISA invalidates instruments purporting to relieve a fiduciary from responsibility or liability for any responsibility, obligation, or duty under ERISA. Accordingly, provisions purporting to waive fiduciary obligations under ERISA serve only to mislead Retirement Investors about the scope of their rights. Additionally, the legislative intent of ERISA was, in part, to provide for “ready access to federal courts.” Accordingly, any recommended transaction covered by a contract or other instrument that waives or qualifies the right of the Retirement Investor to bring or participate in a class action or other representative action in court will not be eligible for relief under this exemption.
A number of comments were received on the contract requirement as it was proposed. The comments, and the Department's responses, are discussed below.
A number of commenters took the position that the consumer protections afforded by the contract requirement are an essential feature of the exemption, particularly in the IRA market. Commenters indicated that enforceability is critical in the IRA market because of IRA owners' lack of a statutory right to enforce prohibited transactions provisions. Commenters said that, in order to achieve the goal of providing meaningful new protections to Retirement Investors, the exemption must provide a mechanism by which Advisers and Financial Institutions can be held legally accountable for the retirement recommendations they make. More than one commenter specifically stated that due to the broad relief provided in the exemption, the contract requirement is necessary for the Department to make the required findings under ERISA section 408(a) and Code section 4975(c)(2) that the exemption is in the interests of and protective of Retirement Investors.
Many other commenters, however, raised significant objections to the contract requirement. Commenters pointed to certain conditions of the exemption that they found ambiguous or subjective and indicated that these conditions could form the basis of class action lawsuits by disappointed investors. Some commenters said the contract requirement and associated litigation exposure would cause investment advice providers to stop serving Retirement Investors or provide only fee-based accounts that do not vary on the basis of the advice provided, resulting in the loss of services to Retirement Investors with smaller account balances. These commenters stated that investment advice fiduciaries
In the final exemption, the Department retained the contract requirement with respect to IRAs and non-ERISA plans. The contractual commitment provides an administrable means of ensuring fiduciary conduct, eliminating ambiguity about the fiduciary nature of the relationship, and enforcing the exemption's conditions, thereby assuring compliance. The existence of enforceable rights and remedies gives Financial Institutions and Advisers a powerful incentive to comply with the exemption's standards, implement effective anti-conflict policies and procedures, and carefully police conflicts of interest. The enforceable contract gives clarity to the fiduciary nature of the undertaking, and ensures that Advisers and Financial Institutions do not subordinate the interests of the Retirement Investor to their own competing financial interests. The contract effectively aligns the interests of Retirement Investor, Advisers, and the Financial Institution, and gives the Retirement Investor the means to redress injury when violations occur.
Without a contract, the possible imposition of an excise tax provides an additional, but inadequate, incentive to ensure compliance with the exemption's standards-based approach. This is particularly true because imposition of the excise tax critically depends on fiduciaries' self-reporting of violations, rather than independent investigations and litigation by the IRS. In contrast, contract enforcement does not rely on conflicted fiduciaries' assessment of their own adherence to fiduciary norms or require the creation and expansion of a government enforcement apparatus. The contract provides an administrable way of ensuring adherence to fiduciary standards, broadly applicable to an enormous range of investments and advice relationships.
The enforceability of the exemption's provisions enables the Department to grant exemptive relief based upon broad protective standards, applicable to a wide range of investments and compensation structures, rather than rely exclusively upon highly prescriptive conditions applicable only to tightly-specified investments and compensation structures. In the context of this exemption, the risk of litigation and enforcement serves many of the same functions that it has for hundreds of years under the law of trust and agency. It gives fiduciaries a powerful incentive to adhere to broad, flexible, and protective standards applicable to an enormous range of transactions by imposing liability and providing a remedy when fiduciaries fail to comply with those standards.
In addition, a number of features of this final exemption, discussed more fully below, should temper concerns about the risk of excessive litigation. In particular, the exemption permits Advisers and Financial Institutions to require mandatory arbitration of individual claims, so that claims that do not involve systemic abuse or entire classes of participants can be resolved outside of court. Similarly, the exemption permits waivers of the right to obtain punitive damages or rescission based on violation of the contract. In the Department's view, make-whole compensatory relief is sufficient to incentivize compliance and redress injury caused by fiduciary misconduct.
The Department has also clarified a number of the exemption's conditions and simplified the disclosure and compliance obligations to facilitate adherence to the exemption's terms. The core principles of the exemption are well-established under trust law, ERISA and the Code, and have a long history of interpretations in court. Moreover, the Impartial Conduct standards are measured based on the circumstances existing at the time of the recommendation, not based on the ultimate performance of the investment with the benefit of hindsight. It is well settled as a legal matter that fiduciary advisers are not guarantors of the success of investments under ERISA or the Code, and this exemption does nothing to change that fact. Finally, the Department added several provisions enabling Advisers and Financial Institutions to correct good faith errors in disclosure, without facing loss of the exemption. These factors should ease commenters' concerns about loss of services to Retirement Investors with smaller account balances.
One commenter asked the Department to address the interaction of the contract cause of action and state securities laws. In this connection, the Department confirms that it is not its intent to preempt or supersede state securities law and enforcement, and that state securities laws remain subject to the ERISA section 514(b)(2)(A) savings clause.
Under Section II(g) of the exemption, there is no contract requirement for transactions involving ERISA plans, but Financial Institutions and their Advisers must satisfy the conditions of Section II(b)-(e), including the conditions requiring written fiduciary acknowledgment, adherence to Impartial Conduct Standards, anti-conflict policies and procedures, and disclosures. Likewise, in Section II(h), Level Fee Fiduciaries do not have to enter into a contract but must provide the written fiduciary acknowledgment, adhere to the Impartial Conduct Standards and document the specific reason or reasons for a recommendation to enter into the level fee arrangement.
The Department eliminated the proposed contract requirement with respect to ERISA plans in this final exemption in response to public comment on this issue. A number of commenters indicated that the contract requirement was unnecessary for ERISA plans due to the statutory framework that already provides enforcement rights to such plans, their participants and beneficiaries, and the Secretary of Labor. Some commenters additionally questioned the extent to which the contract provided additional rights or remedies, and whether state-law contract claims would be pre-empted under ERISA's pre-emption provisions.
In the Department's view, the requirement that a Financial Institution provide written acknowledgement of fiduciary status for itself and its Advisers provides protections in the ERISA plan context that are comparable to the contract requirement for IRAs and non-ERISA plans. As a result of the written acknowledgment of fiduciary status, the fiduciary nature of the relationship will be clear to the parties both at the time of the investment transaction, and in the event of subsequent disputes over the conduct of the Advisers or Financial Institutions. There will be far less cause for the parties to litigate disputes over fiduciary status, as opposed to the substance of the fiduciaries' recommendations and conduct.
Section II(a) specifies the mechanics of entering into the contract and provides that the contract must be enforceable against the Financial Institution. In addition, the section provides that the contract may be a master contract covering multiple recommendations, and that it may cover advice rendered prior to execution of the contract as long as the contract is entered into prior to or at the same time as the execution of the recommended transaction.
Section II(a)(1) further describes the methods for obtaining customer assent to the contract. For “new contracts,” the Retirement Investor's assent must be demonstrated through a written or electronic signature. The exemption provides flexibility by permitting the contract terms to be set forth in a standalone document or in an investment advisory agreement, investment program agreement, account opening agreement, insurance or annuity contract or application, or similar document, or amendment thereto.
For Retirement Investors with “existing contracts,” the exemption permits assent to be evidenced either by affirmative consent, as described above, or by a negative consent procedure. Under the negative consent procedure, the Financial Institution delivers a proposed contract amendment along with the disclosure required in Section II(e) to the Retirement Investor prior to January 1, 2018, and if the Retirement Investor does not terminate the amended contract within 30 days, the amended contract is effective. If the Retirement Investor does terminate the contract within that 30-day period, this exemption will provide relief for 14 days after the date on which the termination is received by the Financial Institution. In that event, the Retirement Investor's account generally should be able to fall within the provisions of Section VII for pre-existing transactions. An existing contract is defined in the exemption as “an investment advisory agreement, investment program agreement, account opening agreement, insurance contract, annuity contract, or similar agreement or contract that was executed before the Applicability Date and remains in effect.” If the Financial Institution elects to use the negative consent procedure, it may deliver the proposed amendment by mail or electronically, but it may not impose any new contractual obligations, restrictions, or liabilities on the Retirement Investor by negative consent.
The final exemption additionally provides a method of complying with the exemption in the event that the Retirement Investor does not open an account with the Adviser but nevertheless acts on the advice through other channels. In some circumstances, Retirement Investors could receive fee-generating advice, fail to open an account with the particular Adviser or Financial Institution, and nevertheless follow the advice in a way that generates additional compensation for the Financial Institution or an Affiliate or Related Entity. Commenters expressed concern that this could result in a prohibited transaction for which there was no relief because the Financial Institution would have been unable to execute the required contract with the Retirement Investor. Generally, commenters raised the issue in the context of mutual funds. For example, an Adviser affiliated with the mutual fund could recommend investment in that fund, which the Retirement Investor followed by executing the transaction through a separate institution unaffiliated with the mutual fund.
To address this concern, Section II(a)(1)(iii) provides conditions under which the exemption will continue to be available notwithstanding the Financial Institution's failure to affirmatively enter into a contract with a Retirement Investor who does not have an existing contract. These conditions are designed to ensure that the Financial Institution does not use Section II(a)(1)(iii) to evade the contract requirement. First, the individual Adviser making the recommendation may not receive compensation, directly or indirectly, as a result of the recommendation or the Retirement Investor's investment transaction. This means that the individual Adviser may not receive transaction-specific compensation, such as a commission or 12b-1 fee, that is tied to the particular Retirement Investor's investment. Second, the Financial Institution's policies and procedures must prohibit the Financial Institution and its Affiliates and Related Entities from providing compensation to the Adviser, in this circumstance, in lieu of compensation that is reasonably attributable to the Retirement Investor's investment transaction, including, but not limited to bonuses or prizes or other incentives, and the Financial Institution has to reasonably monitor such policies and procedures. Thus, the Financial Institution may not compensate Advisers, directly or indirectly, for providing advice as part of a scheme to avoid the contract requirement with respect to Retirement Investors. Third, the Adviser and Financial Institution must comply with the Impartial Conduct Standards set forth in Section II(c), the policies and procedures requirements of Section II(d) (except for the requirement of a warranty with respect to those policies procedures), the web disclosure requirements of Section III(b) and, as applicable, the conditions of Section IV(b)(3)-(6) (Conditions for Advisers and Financial Institution that restrict recommendations, in whole or part, to Proprietary Products or to investments that generate Third Party Payments) with respect to the recommendation. Finally, the Financial Institution's failure to enter into the contract must not be part of an effort, attempt, agreement, arrangement or understanding designed by the Adviser or the Financial Institution to avoid compliance with the exemption or enforcement of its conditions, including the contractual conditions set forth in subsections (i) and (ii). This provision of the exemption is intended for the narrow circumstances in which an Adviser and Financial Institution provide advice that comports with the conditions of the exemption but, due to circumstances generally outside of their control, the Financial Institution did not have the opportunity to enter into a contract with the Retirement Investor.
Finally, Section II(a)(2) of the exemption requires the Financial Institution to provide an electronic copy of the Retirement Investor's contract on its Web site that is accessible by the Retirement Investor. The condition ensures that the Retirement Investor has ready access to the terms of the contract, and reinforces the exemption's goals of clearly establishing the fiduciary status of the Adviser and Financial Institution and ensuring their adherence to the exemption's conditions.
Comments on specific contract operational issues are discussed below.
As proposed, Section II(a) required that, “[p]rior to recommending that the plan, participant or beneficiary account, or IRA purchase, sell or hold the Asset, the Adviser and Financial Institution enter into a written contract with the Retirement Investor that incorporates the terms required by Section II(b)-(e).” A large number of commenters responded to various aspects of this proposed requirement.
Many commenters objected to the timing of the contract requirement. They said that requiring execution of a contract “prior to” any recommendations would be contrary to existing industry practices. The commenters indicated that preliminary discussions may evolve into recommendations before a Retirement Investor has decided to work with a particular Adviser and Financial Institution. Requiring a contract upfront could chill such preliminary discussions, unduly complicate the relationship between the Adviser and the Retirement Investor, and interfere with an investor's ability to shop around. Many commenters suggested that it would be better to time the requirement so that the contract would
In the Department's view, the precise timing of the contract is not critical to the exemption, provided that the parties enter into a contract covering the advice (subject to the narrow exception above). The Department did not intend to chill developing advice relationships or limit investors' ability to shop around. Therefore, the Department adjusted the exemption on this point by deleting the proposed requirement that the contract be entered into prior to the advice recommendation. Instead, the exemption generally provides that the advice must be subject to an enforceable written contract entered into prior to or at the same time as the execution of the recommended transaction. However, in order for the exemption to be available to recommendations made prior to the contract's formation, the contract's terms must cover the prior recommendations.
A few commenters suggested that the Department require the contract to be a separate document, not combined with any other document. However, other commenters requested that the Department allow Financial Institutions to incorporate the contract terms into other account documents. While the Department believes the contract is critical to IRA and non-ERISA plan investors, the Department recognizes the need for flexibility in its implementation. Therefore, the exemption contemplates that the contract may be incorporated into other documents to the extent desired by the Financial Institution. Additionally, as requested by commenters, the Department confirms that the contract requirement may be satisfied through a master contract covering multiple recommendations and does not require execution prior to each additional recommendation.
A number of commenters also questioned the necessity of the proposed requirement that Advisers be parties to the contract. These commenters indicated that the proposed requirement posed significant logistical challenges. For example, commenters stated that Advisers often work in teams and it would be difficult to obtain signatures from all such Advisers. Similarly, if call center representatives made recommendations, it could be hard to cover them under a contract. Over the course of a Retirement Investor's relationship with a Financial Institution, he or she could receive advice from a number of persons concerning a wide variety of transactions. Requiring that each such person execute a contract could prove difficult and unwieldy.
Based upon these objections, the Department has deleted the requirement that individual Advisers be parties to the contract. The Financial Institution must be a party to the contract and assume responsibility for advice provided by any of its Advisers. Such Advisers include call center representatives who provide investment advice within the meaning of the Regulation.
Several commenters asked about the circumstance in which two entities could satisfy the definition of Financial Institution with respect to the same Adviser and same transaction. This largely came up in the context of an insurance product that is offered by an insurance company but sold by a representative of a broker-dealer. Commenters asked whether multiple Financial Institutions would be required to be parties to the contract.
In response, the Department notes that there must always be a Financial Institution, as defined in the exemption, that is a party to the contract. That Financial Institution must take responsibility for satisfying the exemption's conditions, including the obligation to have policies and procedures reasonably and prudently designed to ensure that individual Advisers adhere to the Impartial Conduct Standards, and the obligation to insulate the Adviser from incentives to violate the Best Interest Standard.
Some commenters suggested that the Department provide additional flexibility and allow the individual Adviser to be obligated under the contract instead of the Financial Institution. The Department has not adopted that suggestion. To ensure operation of the exemption as intended, the Financial Institution should be a party to the contract. The supervisory responsibility and liability of the Financial Institution is important to the exemption's protections. In particular, the exemption contemplates that the Financial Institution will adopt and monitor stringent anti-conflict policies and procedures; avoid financial incentives that undermine Advisers' compliance with the Impartial Conduct standards; and take appropriate measures to ensure that it and its representatives adhere to the exemption's conditions. The contract provides both a mechanism for imposing these obligations on the Financial Institution and creates a powerful incentive for the Financial Institution to take the obligations seriously in the management and supervision of investment recommendations.
Section II(a) of the exemption provides that the contract must be enforceable against the Financial Institution. As long as that is the case, the Financial Institution is not required to sign the contract. Section II(a) of the exemption further describes the methods through which customer assent may be achieved, and reflects commenters' requests for greater specificity on this point.
With respect to new contracts, a few commenters asked the Department to confirm that electronic execution by the Retirement Investor is sufficient. Another commenter asked about telephone assent. In the final exemption, the Department specifically permits electronic execution as a form of customer assent. The Department has not permitted telephone assent, however, because of the potential issues of proof regarding the existence and terms of a contract executed in that manner. It is the Department's goal that Retirement Investors obtain clear evidence of the contract terms and their applicability to the Retirement Investor's own account or contract. The exemption will best serve its purpose if the contractual commitments are clear to all the parties, and if ancillary disputes about the fiduciary nature of the advice relationship are avoided. For this same reason, the exemption requires that a copy of the applicable contract be maintained on a Web site accessible to the investor.
Commenters also asked for the ability to use a negative consent procedure with respect to existing customers to avoid the expense and difficulty associated with obtaining a large number of client signatures. The Department adjusted the exemption on
Treating the Retirement Investor's silence as consent after 30 days provides the Retirement Investor a reasonable opportunity to review the new terms and to reject them. The Financial Institution may not use the negative consent procedure, however, to impose new obligations, restrictions or liabilities on the Retirement Investor in connection with the Best Interest Contract. Any attempt by the Financial Institution to impose additional obligations, restrictions, or liabilities on the Retirement Investor must receive affirmative consent from the Retirement Investor, and cannot violate Section II(f).
A number of commenters also asked that the exemption authorize Financial Institutions to satisfy the contract requirement for all Retirement Investors—including new customers after the Applicability Date—through unilateral contracts or implied or negative consent. Some commenters suggested that the Department should not require a contract at all, but only a “customer bill of rights” or similar disclosure, without any additional signature requirement. Some commenters suggested that the requirement of obtaining signatures could delay execution of time sensitive investment strategies.
Although the final exemption accommodates a wide variety of concerns regarding contract operational issues, the Department did not adopt the alternative approaches suggested by some commenters, such as merely requiring delivery of a customer bill of rights, broader reliance on a unilateral contract approach, or increased reliance on negative consent. The Department intends that Retirement Investors that are new customers of the Financial Institution should enter into an enforceable contract under Section II(a)(1)(i). Consistent with the Department's goal that Retirement Investors obtain clear evidence of the contract terms and their applicability to the Retirement Investor's own account or contract, the exemption limits the negative consent option to existing customers as a form of transitional relief, so that Financial Institutions can avoid the burdens associated with obtaining signatures from a large number of already-existing customers.
Apart from this transitional relief, the Department does not believe it is appropriate to dispense with the clarity, enforceability and legal protections associated with an affirmative contract. Contracts are commonplace in a wide range of commercial transactions occurring in person, on the web, and elsewhere. The Department has facilitated the process by providing that Financial Institutions can incorporate the contract terms into commonplace account opening or similar documents that they already use; by permitting electronic signatures; and by revising the timing rules, so that the contract's execution can follow the provision of advice, as long as it precedes or occurs at the same time as the execution of the recommended transaction.
Section II(b) of the exemption requires the Financial Institution to affirmatively state in writing that it and its Adviser(s) act as fiduciaries under ERISA or the Code, or both, with respect to the investment advice subject to the contract or, in the case of an ERISA plan, with respect to any investment advice regarding the plan or beneficiary or participant account.
With respect to IRAs and non-ERISA plans, if this acknowledgment of fiduciary status does not appear in a contract with a Retirement Investor, the exemption is not satisfied with respect to transactions involving that Retirement Investor. With respect to ERISA plans, this acknowledgment must be provided to the Retirement Investor prior to or at the same time as the execution of the recommended transaction, but not as part of a contract. This fiduciary acknowledgment is critical to ensuring clarity and certainty with respect to the fiduciary status of both the Adviser and Financial Institution under ERISA and the Code with respect to that advice.
The fiduciary acknowledgment provision received significant support from some commenters. Commenters described it as a necessary protection and noted that it would clarify the obligations of the Adviser. One commenter said that facilitating proof of fiduciary status should enhance investors' ability to obtain a remedy for Adviser misconduct in arbitration by eliminating ancillary litigation over fiduciary status. Rather than litigate over fiduciary status, the fiduciary acknowledgment would help ensure that such proceedings focused on the Advisers' compliance with fundamental fiduciary norms.
Some commenters opposed the fiduciary acknowledgment requirement in the proposal, as applicable to Financial Institution, on the basis that it could force Financial Institutions to take on fiduciary responsibilities, even if they would not otherwise be functional fiduciaries under ERISA or the Code. The commenters pointed out that, under the proposed Regulation, the acknowledgment of fiduciary status would have been a factor in imposing fiduciary status on a party. Therefore, Financial Institutions could become fiduciaries by virtue of the fiduciary acknowledgment. To address these concerns, a few commenters suggested language under which a Financial Institution would only be considered a fiduciary to the extent that it is “an affiliate of the Adviser within the meaning of 29 CFR 2510.3-21(f)(7) that, with the Adviser, functions as a fiduciary.”
The Department has not adjusted the exemption as these commenters requested. The exemption requires as a condition of relief that a sponsoring Financial Institution accept fiduciary responsibility for the recommendations of its Adviser(s). The Financial Institution's role in supervising individual Advisers and overseeing their adherence to the Impartial Conduct Standards is a key safeguard of the exemption. The exemption's success critically depends on the Financial Institution's careful implementation of anti-conflict policies and procedures, avoidance of Adviser incentives to violate the Impartial Conduct Standards, and broad oversight of Advisers. Accordingly, Financial Institutions that wish to receive compensation streams that would otherwise be prohibited under ERISA and the Code must agree to take on these responsibilities as a condition of relief under the exemption. To the extent Financial Institutions do not wish to take on this role with its associated responsibilities and liabilities, they may structure their operations to avoid prohibited transactions and the resultant need of the exemption.
A commenter requested clarification of the circumstances in which a credit union shares employees with a broker-dealer. The commenter requested confirmation that the credit union would not have to comply with the exemption merely because it shared employees. Consistent with the approach set forth above, the
Other commenters expressed the view that the fiduciary acknowledgement would potentially require broker-dealers to satisfy the requirements of the Investment Advisers Act of 1940. As described by commenters, the Act does not require broker-dealers to register as investment advisers if they provide advice that is solely incidental to their brokerage services. Commenters expressed concern that acknowledging fiduciary status and providing advice in satisfaction of the Impartial Conduct Standards could call into question whether the advice provided was solely incidental.
The Department does not, however, require the Adviser or Financial Institution to acknowledge fiduciary status under the securities laws, but rather under ERISA or the Code or both. Neither does the Department require Advisers to agree to provide advice on an ongoing, rather than transactional, basis. An Adviser's status as an ERISA fiduciary is not dispositive of its obligations under the securities laws, and compliance with the exemption does not trigger an automatic loss of the broker-dealer exception under the separate requirements of those laws. A broker-dealer who provides investment advice under the Regulation is an ERISA fiduciary; acknowledgment of ERISA fiduciary status would not, by itself, cause the Adviser to lose the broker-dealer exception. Under the Regulation and this exemption, the primary import of fiduciary status is that the broker has to act in the customer's best interest when making recommendations; receive no more than reasonable compensation; and refrain from making misleading statements. Certainly, nothing in the securities laws precludes brokers from adhering to these basic standards, or forbids them from working for firms that implement appropriate policies and procedures to ensure that these standards are met.
The Department changed the fiduciary acknowledgment provision in response to several comments requesting revisions to clarify the required extent of the fiduciary acknowledgment. Accordingly, the Department has clarified that the acknowledgment can be limited to investment recommendations subject to the contract or, in the case of an ERISA plan, any investment recommendations regarding the plan or beneficiary or participant account. As discussed in more detail below, the exemption (including the required fiduciary acknowledgment) does not in and of itself, impose an ongoing duty to monitor on the Adviser or Financial Institution. However, there may be some investments which cannot be prudently recommended to the individual Retirement Investor, in the first place, without a mechanism in place for the ongoing monitoring of the investment.
Section II(c) of the exemption requires that the Adviser and Financial Institution comply with fundamental Impartial Conduct Standards. Generally stated, the Impartial Conduct Standards require that Advisers and Financial Institutions provide investment advice in the Retirement Investor's Best Interest, not recommend transactions that they anticipate will result in more than reasonable compensation, and not make misleading statements to the Retirement Investor about recommended transactions. As defined in the exemption, a Financial Institution and Adviser act in the Best Interest of a Retirement Investor when they provide investment advice “that reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party.”
The Impartial Conduct Standards represent fundamental obligations of fair dealing and fiduciary conduct. The concepts of prudence, undivided loyalty and reasonable compensation are all deeply rooted in ERISA and the common law of agency and trusts.
Under ERISA section 408(a) and Code section 4975(c)(2), the Department cannot grant an exemption unless it first finds that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of participants and beneficiaries of plans and IRA owners. An exemption permitting transactions that violate the Impartial Conduct Standards would fail these standards.
The Impartial Conduct Standards are conditions of the exemption for the provision of advice with respect to all Retirement Investors. For advice to Retirement Investors on investments in IRAs and non-ERISA plans, the Impartial Conduct Standards must also
Comments on each of the Impartial Conduct Standards are discussed below. Additionally, in response to commenters' assertion that the exemption is not administratively feasible due to uncertainty regarding some terms and requests for additional clarity, the Department has clarified some key terms in the text and provides additional interpretative guidance in the preamble discussion that follows. Finally, the Department discusses comments on whether the Impartial Conduct Standards should serve as both exemption conditions for all Retirement Investors as well as contractual representations with respect to IRAs and non-ERISA plans.
Under Section II(c)(1), the Financial Institution must state that it and its Advisers will comply with a Best Interest standard when providing investment advice to the Retirement Investor, and, in fact, adhere to the standard. Advice in the Retirement Investor's Best Interest means advice that, at the time of the recommendation reflects:
The Best Interest standard set forth in the final exemption is based on longstanding concepts derived from ERISA and the law of trusts. It is meant to express the concept, set forth in ERISA section 404, that a fiduciary is required to act “solely in the interest of the participants . . . with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent man acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims.” Similarly, both ERISA section 404(a)(1)(A) and the trust-law duty of loyalty require fiduciaries to put the interests of trust beneficiaries first, without regard to the fiduciaries' own self-interest. Under this standard, for example, an Adviser, in choosing between two investments, could not select an investment because it is better for the Adviser's or Financial Institution's bottom line, even though it is a worse choice for the Retirement Investor.
A wide range of commenters indicated support for a broad “best interest” standard. Some comments indicated that the best interest standard is consistent with the way advisers provide investment advice to clients today. However, a number of these commenters expressed misgivings as to the definition used in the proposed exemption, in particular, the “without regard to” formulation. The commenters indicated uncertainty as to the meaning of the phrase, including: Whether it permitted the Adviser and Financial Institution to be paid and whether it permitted investment advice on Proprietary Products.
Other commenters asked the Department to use a different definition of Best Interest, or simply use the exact language from ERISA's section 404 duty of loyalty. Others suggested definitional approaches that would require that the Adviser and Financial Institution “not subordinate” their customers' interests to their own interests, or that the Adviser and Financial Institution “put their customers' interests ahead of their own interests,” or similar constructs.
FINRA suggested that the federal securities laws should form the foundation of the Best Interest standard. Specifically, FINRA urged that the Best Interest definition in the exemption incorporate the “suitability” standard applicable to investment advisers and broker dealers under federal securities laws. According to FINRA, this would facilitate customer enforcement of the Best Interest standard by providing adjudicators with a well-established basis on which to find a violation.
Other commenters found the Best Interest Standard to be an appropriate statement of the obligations of a fiduciary investment advice provider and believed it would provide concrete protections against conflicted recommendations. These commenters asked the Department to maintain the Best Interest definition as proposed. One commenter wrote that the term “best interest” is commonly used in connection with a fiduciary's duty of loyalty and cautioned the Department against creating an exemption that failed to include the duty of loyalty. Others urged the Department to avoid definitional changes that would reduce current protections to Retirement Investors. Some commenters also noted that the “without regard to” language is consistent with the recommended standard in the SEC staff Dodd-Frank Study, and suggested that it had the added benefit of potentially harmonizing with a future securities law standard for broker-dealers.
The final exemption retains the Best Interest definition as proposed, with minor adjustments. The first prong of the standard was revised to more closely track the statutory language of ERISA section 404(a), and, is consistent with the Department's intent to hold investment advice fiduciaries to a prudent investment professional standard. Accordingly, the definition of Best Interest now requires advice that “reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person
The Department has not specifically incorporated the suitability obligation as an element of the Best Interest standard, as suggested by FINRA but many aspects of suitability are also elements of the Best Interest standard. An investment recommendation that is not suitable under the securities laws would not meet the Best Interest standard.
The Department recognizes that FINRA issued guidance on rule 2111 in which it explains that “in interpreting the suitability rule, numerous cases explicitly state that a broker's recommendations must be consistent with his customers' best interests,” and provided examples of conduct that would be prohibited under this standard, including conduct that this exemption would not allow.
Moreover, suitability under SEC practice differs somewhat from the FINRA approach. According to the SEC staff Dodd-Frank Study, the SEC requirements are based on the anti-fraud provisions of the Securities Act Section 17(a), the Exchange Act Section 10(b) and Rule 10b-5 thereunder.
The Best Interest standard, as set forth in the exemption, is intended to effectively incorporate the objective standards of care and undivided loyalty that have been applied under ERISA for more than forty years. Under these objective standards, the Adviser must adhere to a professional standard of care in making investment recommendations that are in the Retirement Investor's Best Interest. The Adviser may not base his or her recommendations on the Adviser's own financial interest in the transaction. Nor may the Adviser recommend the investment, unless it meets the objective prudent person standard of care. Additionally, the duties of loyalty and prudence embodied in ERISA are objective obligations that do not require proof of fraud or misrepresentation, and full disclosure is not a defense to making an imprudent recommendation or favoring one's own interests at the Retirement Investor's expense.
A few commenters also questioned the requirement in the Best Interest standard that recommendations be made without regard to the interests of the Adviser, Financial Institution, Affiliates, Related Entities, or “
Other commenters asked for confirmation that the Best Interest standard is applied based on the facts and circumstances as they existed at the time of the recommendation, and not based on hindsight. Consistent with the well-established legal principles that exist under ERISA today, the Department confirms that the Best Interest standard is not a hindsight standard, but rather is based on the facts as they existed at the time of the recommendation. Thus, the courts have evaluated the prudence of a fiduciary's actions under ERISA by focusing on the process the fiduciary used to reach its determination or recommendation—whether the fiduciary, “at the time they engaged in the challenged transactions, employed the proper procedures to investigate the merits of the investment and to structure the investment.”
This is not to suggest that the ERISA section 404 prudence standard, or Best Interest standard, are solely procedural standards. Thus, the prudence standard, as incorporated in the Best Interest standard, is an objective standard of care that requires investment advice fiduciaries to investigate and evaluate
The Department additionally confirms its intent that the phrase “without regard to” be given the same meaning as the language in ERISA section 404 that requires a fiduciary to act “solely in the interest of” participants and beneficiaries, as such standard has been interpreted by the Department and the courts. Therefore, the standard would not, as some commenters suggested, foreclose the Adviser and Financial Institution from being paid. In response to concerns about the satisfaction of the standard in the context of Proprietary Product recommendations or investment menus limited to Proprietary Products and/or investments that generate Third Party Payments, the Department has revised Section IV of the exemption to provide additional clarity and specific guidance on this issue.
Section IV specifically provides that Financial Institutions and Advisers that restrict their recommendations, in whole or in part, to Proprietary Products or to investments that generate Third Party Payments may rely on the exemption provided that the recommendation is prudent, the fees reasonable, the conflicts disclosed (so that the customer can fairly be said to have knowingly assented to the compensation arrangement), and the conflicts are managed through stringent policies and procedures that keep the Adviser's focus on the customer's Best Interest, rather than any competing financial interest of the Adviser or others.
In response to commenter concerns, the Department also confirms that the Best Interest standard does not impose an unattainable obligation on Advisers and Financial Institutions to somehow identify the single “best” investment for the Retirement Investor out of all the investments in the national or international marketplace, assuming such advice were even possible. Instead, as discussed above, the best interest standard set out in the exemption, incorporates two fundamental and well-established fiduciary obligations: The duties of prudence and loyalty. Thus, the advice fiduciary's obligation under the Best Interest standard is to give advice that adheres to professional standards of prudence, and to put the Retirement Investor's financial interests in the driver's seat, rather than the competing interests of the Adviser or other parties.
Finally, in response to questions regarding the extent to which the Best Interest standard or other provisions of the exemption impose an ongoing monitoring obligation on Advisers or Financial Institutions, the Department has added specific language in Section II(e) regarding monitoring. The text does not impose a monitoring requirement, but instead requires clarity. As suggested by FINRA, Section II(e) requires Advisers and Financial Institutions to disclose whether or not they will monitor the Retirement Investor's investments and alert the Retirement Investor to any recommended changes to those investments and, if so, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted. This is consistent with the Department's interpretation of an investment advice fiduciary's monitoring responsibility as articulated in the preamble to the Regulation.
The terms of the contract or disclosure along with other representations, agreements, or understandings between the Adviser, Financial Institution and Retirement Investor, will govern whether the nature of the relationship between the parties is ongoing or not. The preamble to the proposed exemption stated that adherence to a Best Interest standard did not mandate an ongoing or long-term relationship, but instead left that the determination of whether to enter into such a relationship to the parties.
The Impartial Conduct Standards also include the reasonable compensation standard, set forth in Section II(c)(2). Under this standard, the Financial Institution and its Advisers must not recommend a transaction that will cause the Financial Institution, Adviser, or their Affiliates or Related Entities, to receive, directly or indirectly, compensation for their services that is in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
The obligation to pay no more than reasonable compensation to service providers is long recognized under ERISA and the Code. ERISA section 408(b)(2) and Code section 4975(d)(2) require that services arrangements involving plans and IRAs result in no more than reasonable compensation to the service provider. Accordingly, Advisers and Financial Institutions—as service providers—have long been subject to this requirement, regardless of their fiduciary status. At bottom, the standard simply requires that compensation not be excessive, as measured by the market value of the particular services, rights, and benefits the Adviser and Financial Institution are delivering to the Retirement Investor. Given the conflicts of interest associated with the commissions and other payments covered by the exemption, and the potential for self-dealing, it is particularly important that Advisers and Financial Institutions adhere to these statutory standards, which are rooted in common law principles.
Several commenters supported this standard. The requirement that compensation be limited to what is reasonable is an important protection of the exemption and a well-established standard, they said. One commenter made the point that the reasonable compensation standard is particularly important in this exemption because it provides relief for Third Party Payments which may not be transparent to Retirement Investors. The commenter asserted that under current market
A number of other commenters requested greater specificity as to the meaning of the reasonable compensation standard. As proposed, the standard stated:
When providing investment advice to the Retirement Investor regarding the Asset, the Adviser and Financial Institution will not recommend an Asset if the total amount of compensation anticipated to be received by the Adviser, Financial Institution, Affiliates and Related Entities in connection with the purchase, sale or holding of the Asset by the Plan, participant or beneficiary account, or IRA, will exceed reasonable compensation in relation to the total services they provide to the Retirement Investor.
Some commenters stated that the proposed reasonable compensation standard was too vague. Because the language of the proposal did not reference ERISA section 408(b)(2) and Code section 4975(d)(2), commenters asked whether the standard differed from those statutory provisions. In particular, some commenters questioned the meaning of the proposed language “in relation to the total services they provide to the Retirement Investor.” The commenters indicated that the proposal did not adequately explain this formulation of the reasonable compensation standard.
There was concern that the standard could be applied retroactively rather than based on the parties' reasonable beliefs as to the reasonableness of the compensation at the time of the recommendation. Commenters also indicated uncertainty as to how to comply with the condition and asked whether it would be necessary to survey the market to determine market rates. Some commenters requested that the Department include the words “and customary” in the reasonable compensation definition, to specifically permit existing compensation arrangements. One commenter raised the concern that the reasonable compensation determination raised antitrust concerns because it would require investment advice fiduciaries to agree upon a market rate and result in anti-competitive behavior.
Commenters also asked the Department to provide examples of scenarios that met the reasonable compensation standard and safe harbors and others requested examples of scenarios that would fail to meet these standards. FINRA and other commenters suggested that the Department incorporate existing FINRA rules 2121 and 2122, and NASD rule 2830 regarding the reasonableness of compensation for broker-dealers.
Commenters also asked how the standard would be satisfied for Proprietary Products, particularly insurance and annuity contracts. In such a case, commenters indicated, the Retirement Investor is not only paying for a service, but also for insurance guarantees; a standard that appeared to focus solely on services appeared inapposite. Commenters asked about the treatment of the insurance company's spread, which was described, in the case of a fixed annuity, or the fixed component of a variable annuity, as the difference between the fixed return credited to the contract holder and the insurer's general account investment experience. One commenter indicated that the calculation should not include affiliates' or related entities' compensation as this would appear to put them at a comparative disadvantage.
Finally, a few commenters took the position that the reasonable compensation determination should not be a requirement of the exemption (or the contract). In their view, a plan fiduciary that is not the Adviser or Financial Institution should decide the reasonableness of the compensation. Another commenter suggested that if an independent plan fiduciary sets the menu this should be sufficient to comply with the reasonable compensation standard.
In response to comments on this requirement, the Department has retained the reasonable compensation standard as a condition of the exemption, and requires Financial Institutions to include the standard in their contracts with IRA and non-ERISA plan Retirement Investors. As noted above, the “reasonable compensation” obligation is a feature of ERISA and the Code under current law that has long applied to financial services providers, whether fiduciaries or not. The standard is also applicable to fiduciaries under the common law of agency and trusts. It is particularly important that Advisers and Financial Institutions adhere to these standards when engaging in the transactions covered under this exemption, so as to avoid exposing Retirement Investors to harms associated with conflicts of interest.
Although some commenters suggested that the reasonable compensation determination be made by another plan fiduciary, the contractual commitment (like the statutory obligation) obligates investment advice fiduciaries to avoid overcharging their Retirement Investor customers, despite the conflicts of interest associated with their compensation. Fiduciaries and other services providers may not charge more than reasonable compensation regardless of whether another fiduciary has signed off on the compensation. Nothing in the exemption, however, precludes Financial Institutions or others from seeking impartial review of their fee structures to safeguard against abuse, and they may well want to include such reviews in their policies and procedures.
Further, the Department disagrees that the requirement is inconsistent with antitrust laws. Nothing in the exemption contemplates or requires that Advisers or Financial Institutions agree upon a price with their competitors. The focus of the reasonable compensation condition is on preventing overcharges to Retirement Investors, not promoting anti-competitive practices. Indeed, if Advisers and Financial Institutions consulted with competitors to set prices, the agreed-upon prices could well violate the condition.
In response to comments, however, the operative text of the final exemption was clarified to adopt the well-established reasonable compensation standard, as set out in ERISA section 408(b)(2) and Code section 4975(d)(2), and the regulations thereunder. The reasonableness of the fees depends on the particular facts and circumstances at the time of the recommendation. Several factors inform whether compensation is reasonable including,
In response to concerns about application of the standard to investment products that bundle together services and investment
A commenter urged the Department to provide that compensation received by an Affiliate or Related Entity would not have to be considered in applying the reasonable compensation standard. According to the commenter, including such compensation in the assessment of reasonable compensation would place Proprietary Products at a disadvantage. The Department disagrees with the proposition that a Proprietary Product would be disadvantaged merely because more of the compensation goes to affiliated parties than in the case of competing products, which allocate more of the compensation to non-affiliated parties. The availability of this Best Interest Contract Exemption, however, does not turn on how compensation is allocated between affiliates and non-affiliates. Certainly, the Department would not expect that a Proprietary Product would be at a disadvantage in the marketplace because it carefully ensures that the associated compensation is reasonable. As part of this exemption, the Department has provided specific provisions describing how Proprietary Products can meet the Best Interest standard. Assuming the Best Interest standard is satisfied and the compensation is reasonable, the exemption should not impede the recommendation of proprietary products. Accordingly, the Department disagrees with the commenter. The Department declines suggestions to provide specific examples of “reasonable” amounts or specific safe harbors. Ultimately, the “reasonable compensation” standard is a market based standard. As noted above, the standard incorporates the familiar ERISA section 408(b)(2) and Code section 4975(d)(2) standards. The Department is unwilling to condone all “customary” compensation arrangements and declines to adopt a standard that turns on whether the agreement is “customary.” For example, it may in some instances be “customary” to charge customers fees that are not transparent or that bear little relationship to the value of the services actually rendered, but that does not make the charges reasonable. Finally, the Department notes that all recommendations are subject to the overarching Best Interest standard, which incorporates the fundamental fiduciary obligations of prudence and loyalty. An imprudent recommendation for an investor to overpay for an investment transaction would violate that standard, regardless of whether the overpayment was attributable to compensation for services, a charge for benefits or guarantees, or something else.
The final Impartial Conduct Standard, set forth in Section II(c)(3), requires that statements by the Financial Institution and its Advisers to the Retirement Investor about the recommended transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's investment decisions, may not be materially misleading at the time they are made. In response to commenters, the Department adjusted the text to clarify that the standard is measured at the time of the representations,
The Department did not accept certain other comments, however. One commenter requested that the Department add a qualifier providing that the standard is violated only if the statement was “reasonably relied” on by the Retirement Investor. The Department rejected the comment. The Department's aim is to ensure that Financial Institutions and Advisers uniformly adhere to the Impartial Conduct Standards, including the obligation to avoid materially misleading statements, when they give advice. Whether a Retirement Investor relied on a particular statement may be relevant to the question of damages in subsequent arbitration or court proceedings, but it is not and should not be relevant to the question of whether the advice fiduciary violated the exemption's standards in the first place. Moreover, inclusion of a “reasonable reliance” standard runs the risk of inviting boilerplate disclaimers of reliance in contracts and disclosure documents precisely so the Adviser can assert that any reliance is unreasonable.
One commenter asked the Department to require only that the Adviser “reasonably believe” the statements are not misleading. The Department is concerned that this standard too could undermine the protections of this condition, by requiring Retirement Investors or the Department to prove the Adviser's actual belief rather than focusing on whether the statement is objectively misleading. However, to address commenters' concerns about the risks of engaging in a prohibited transaction, as noted above, the Department has clarified that the standard is measured at the time of the representations and has added a materiality standard.
The Department believes that Retirement Investors are best served by statements and representations that are free from material misstatements. Financial Institutions and Advisers best avoid liability—and best promote the interests of Retirement Investors—by ensuring that accurate communications are a consistent standard in all their interactions with their customers.
A commenter suggested that the Department adopt FINRA's “Frequently Asked Questions regarding Rule 2210” in this connection.
Some commenters asserted that some of the exemption's terms were too vague and would result in the exemption failing to meet the “administratively feasible” requirement under ERISA section 408(a) and Code section 4975(c)(2). The Department disagrees with these commenters' suggestion that ERISA section 408(a) and Code section 4975(c)(2) fail to be satisfied by this exemption's principles-based approach, or that the exemption's standards are unduly vague. It is worth repeating that the Impartial Conduct Standards are built on concepts that are longstanding and familiar in ERISA and the common law of trusts and agency. Far from requiring adherence to novel standards with no antecedents, the exemption primarily requires adherence to basic, well-established obligations of fair dealing and fiduciary conduct. Moreover, as discussed above, the exemption's reliance on these familiar fiduciary standards is precisely what enables the Department to apply the exemption to the wide variety of investment and compensation practices that characterize the market for retail retirement advice, rather than to a far narrower category of transactions subject to much more detailed and highly-proscriptive conditions.
This section is designed to provide specific interpretations and responses to a number of specific issues raised in connection with a number of the Impartial Conduct Standards. In response to commenters, the Department specifically notes that the Impartial Conduct Standards (either as proposed or finalized) are not properly interpreted to foreclose the recommendation of Proprietary Products. The Department has revised Section IV of the exemption, in particular, as discussed below, to specifically address the application of the Best Interest Standard in the context of Proprietary Products and products that generate Third Party Payments. As Section IV makes clear, the exemption is fully available to such recommendations, provided that the Financial Institutions and Advisers adhere to appropriate standards and implement specified safeguards.
The Impartial Conduct Standards also are not properly interpreted to foreclose the receipt of commissions or other transaction-based payments. To the contrary, a significant purpose of granting this exemption is to continue to permit such payments, as long as Financial Institutions and Advisers are willing to adhere to Best Interest standards. The discussion of the policies and procedures in Section II(d) provides guidance on satisfying the exemption while preserving differential payments structures. In particular, the Department confirms that the receipt of a commission on an annuity product does not result in a per se violation of any of the Impartial Conduct Standards, or warranties or other conditions of the exemption, even though such a commission may be greater than the commission on a mutual fund purchase of the same amount as long as the commission meets the requirement of “reasonable compensation” and other applicable conditions.
One commenter asked that the Department make an explicit statement that “offering products on which there are varying opinions within the industry (
Finally, the Department notes that the exemption, and in particular the requirement to adhere to a Best Interest Standard, does not mandate an ongoing or long-term advisory relationship, but rather leaves the duration of the relationship to the parties. The terms of the contract (if applicable), along with other representations, agreements, or understandings between the Adviser, Financial Institution and Retirement Investor, will govern whether the relationship between the parties is ongoing or not. Additionally, compliance with the exemption's conditions is necessary only with respect to transactions that otherwise would constitute prohibited transactions under ERISA and the Code. The exemption does not purport to impose conditions on the management of investments held outside of plans or IRAs covered by ERISA and defined in the Code. Accordingly, the conditions in the exemption are mandatory only with respect to investments held by ERISA plans, IRAs and non-ERISA plans.
Commenters expressed a variety of views on whether violations of the Impartial Conduct Standards with respect to advice to Retirement Investors regarding IRAs and non-ERISA plans should result in loss of the exemption, violation of the contract, or both.
Other commenters advocated for the opposite result, asserting that the Impartial Conduct Standards should be required for contractual promises only, and not treated as exemption conditions. These commenters asserted that the Impartial Conduct Standards are too vague and would result in uncertainty as to whether an excise tax under the Code, which is self-assessed, is owed. There were also suggestions to limit the contractual representation to the Best Interest standard alone. One commenter asserted that the reasonable compensation requirement and the obligation not to make misleading statements fall within a Best Interest standard, and do not need to be stated separately. There were also suggestions that the Impartial Conduct Standards not apply to ERISA plans because fiduciaries to these plans already are required to adhere to similar statutory fiduciary obligations. In these commenters' view, requiring these standards in an exemption is redundant and inappropriately increases the consequences of any fiduciary breach by imposing an excise tax.
In response to comments, the Department has revised the language of the Impartial Conduct Standards and provided interpretive guidance to
As previously discussed, the Impartial Conduct Standards are not unduly vague or unknown, but rather track longstanding concepts in law and equity. In response to interpretive questions posed in the comments, the Department has provided a series of requested interpretations in the preceding preamble section. Also, the Department has simplified execution of the contract, streamlined disclosure, and made certain language changes, such as the revisions discussed above to the reasonable compensation standard, to address legitimate concerns.
Similarly, the Department has not accepted the comment that the Impartial Conduct Standards should apply only to IRAs and non-ERISA plans. One of the Department's goals is to ensure equal footing for all Retirement Investors. The SEC staff Dodd-Frank Study found that investors were frequently confused by the differing standards of care applicable to broker-dealers and registered investment advisers. The Department hopes to minimize such confusion in the market for retirement advice by holding Advisers and Financial Institutions to similar standards, regardless of whether they are giving the advice to an ERISA plan, IRA, or a non-ERISA plan.
Moreover, inclusion of the standards in the exemption's conditions adds an important additional safeguard for ERISA and IRA investors alike because the party engaging in a prohibited transaction has the burden of showing compliance with an applicable exemption, when violations are alleged.
Moreover, as noted repeatedly, the language for the Impartial Conduct Standards borrows heavily from ERISA and the law of trusts, providing sufficient clarity to alleviate the commenters' concerns. Ensuring that fiduciary investment advisers adhere to the Impartial Conduct Standards and that all Retirement Investors have an effective legal mechanism to enforce the standards are central goals of this regulatory project.
Under Section II(d) of the exemption, the Financial Institution is required to adopt and comply with certain anti-conflict policies and procedures and to insulate Advisers from incentives to violate the Best Interest standard. In order for relief to be available under the exemption, a Financial Institution that meets the definition set forth in the exemption must provide oversight of Advisers' recommendations, as described in this section.
The Financial Institution must prepare a written document describing the Financial Institution's policies and procedures and make copies of the document readily available to Retirement Investors, free of charge, upon request as well as on the Financial Institution's Web site.
The policies and procedures obligations have several important components. First, the Financial Institution must adopt and comply with written policies and procedures reasonably and prudently designed to ensure that its Advisers adhere to the Impartial Conduct Standards set forth in Section II(c). Second, the Financial Institution in formulating its policies and procedures, must specifically identify and document its Material Conflicts of Interest; adopt measures reasonably and prudently designed to prevent Material Conflicts of Interest from causing violations of the Impartial Conduct Standards set forth in Section II(c); and designate a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards. For purposes of the exemption, a Material Conflict of Interest exists when an Adviser or Financial Institution has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.
Finally, the Financial Institution's policies and procedures must require that neither the Financial Institution nor (to the best of its knowledge) its Affiliates or Related Entities use or rely on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor.
In this respect, however, the exemption makes clear that that requirement does not prevent the Financial Institution or its Affiliates, or Related Entities from providing Advisers with differential compensation (whether in type or amount, and including, but not limited to, commissions) based on investment
The anti-conflict policies and procedures will safeguard the interests of Retirement Investors by causing Financial Institutions to consider the conflicts of interest affecting the provision of advice to Retirement Investors and to take action to mitigate the impact of such conflicts. In particular, under the final exemption, Financial Institutions must not use compensation and other employment incentives to the extent they are intended to or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Financial Institutions must also establish a supervisory structure reasonably and prudently designed to ensure the Advisers will adhere to the Impartial Conduct Standards. This includes consideration of the incentives of branch managers and supervisors and their potential effect on Advisers' recommendations. Mitigating conflicts of interest by requiring greater alignment of the interests of the Adviser and Financial Institution, and the Retirement Investor, is necessary for the Department to make the findings under ERISA section 408(a) and Code section 4975(c)(2) that the exemption is in the interests of, and protective of, Retirement Investors. This warranty gives the Financial Institution a powerful incentive to ensure advice is provided in accordance with fiduciary norms, rather than risk litigation, including class litigation and liability.
Like the proposal, the final exemption does not specify the precise content of the anti-conflict policies and procedures, but rather sets out the overarching standards for assessing their adequacy. This flexibility is intended to allow Financial Institutions to develop policies and procedures that are effective for their particular business models, while prudently ensuring compliance with their and their Advisers' fiduciary obligations and the Impartial Conduct Standards. The policies and procedures requirement, if taken seriously, can also reduce Financial Institutions' litigation risk by minimizing incentives for Advisers to provide advice that is not in Retirement Investors' Best Interest.
As adopted in the final exemption, the policies and procedures requirement is a condition of the exemption for all Retirement Investors—in ERISA plans, IRAs and non-ERISA plans. Failure to comply could result in liability under ERISA for engaging in a prohibited transaction and the imposition of an excise tax under the Code, payable to the Treasury. Additionally, with respect to Retirement Investors in IRAs and non-ERISA plans, the requirement takes the form of a contractual warranty. The Financial Institution must warrant that it has adopted and will comply with the anti-conflict policies and procedures (including the obligation to avoid misaligned incentives). Failure to comply with the warranty could result in contractual liability.
Comments on the proposed policies and procedures requirement are discussed below.
Under the policies and procedures requirement, described in greater detail above, Financial Institutions must adopt and comply with anti-conflict policies and procedures. In addition, neither the Financial Institution nor (to the best of its knowledge) its Affiliates or Related Entities may use or rely on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor.
Some commenters were extremely supportive of the policies and procedures requirement as proposed. They expressed the view that the policies and procedures requirement, and in particular the restrictions on compensation and other employment incentives, was one of the most critical investor protections in the proposal because it would cause Financial Institutions to make specific and necessary changes to their compensation arrangements that would result in significant protections to Retirement Investors.
Some commenters believed the Department did not go far enough. These commenters indicated that flat compensation arrangements should be required, or at least that the rules applicable to differential compensation arrangements should be more specific and stringent. A few commenters also indicated that, in addition to focusing on the Adviser, the Financial Institution's policies and procedures need to consider the impact of compensation practices on branch managers. A commenter indicated that branch managers have responsibilities under FINRA's supervisory rules to ensure suitability and possibly approve individual transactions. The commenter asserted that branch managers financially benefit from Advisers' recommendations and have a variety of methods of influencing Adviser behavior.
Many others objected to the policies and procedures warranty, and requested that it be eliminated in the final exemption. Some commenters believed that compliance would require drastic changes to current compensation arrangements or could possibly result in the complete prohibition of commissions and other transaction-based compensation. Other commenters suggested that the requirement should be eliminated as it would be unnecessary in light of the exemption's Best Interest standard, and because it would unnecessarily increase litigation risk to Financial Institutions. Alternatively, there were requests to clarify specific provisions and provide safe harbors in the policies and procedures requirement.
In the final exemption, the Department has retained the general approach of the proposal. The Department concurs with commenters who view the policies and procedures requirement as an important safeguard for Retirement Investors, and as a necessary condition for the Department to make the findings under ERISA section 408(a) and Code section 4975(c)(2) that the exemption is in the interests of, and protective of, Retirement Investors. This provision will require Financial Institutions to take concrete and specific steps to ensure that its individual Advisers adhere to the Impartial Conduct Standards, and in particular, forego compensation practices and employment incentives (quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives) that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Strong policies and procedures reduce the temptation (conscious or unconscious) to violate the Best Interest standard in the first place by ensuring that the Advisers' incentives are appropriately aligned with the interests of the customers they serve, and by ensuring appropriate monitoring and supervision of individual Advisers' conduct. While the Department views
The Department has not made the requirements more stringent, as suggested by some commenters, so as to require completely level compensation. Different payments for different classes of investments may be appropriate based on differences in the time and expertise necessary to recommend them. Similarly, transaction-based compensation can be more cost effective for some investors who do not trade frequently. The exemption was designed to preserve commissions and other transaction-based compensation structures, thereby allowing Retirement Investors to choose the payment structure that works best for them.
In response to commenters who expressed the view that the exemption did not provide a clear path for the payment of differential compensation, the Department has elaborated below on its example of policies and procedures and compensation practices that could satisfy the requirement. In addition, the examples address branch manager incentives.
The Department also adopted the suggestion of one commenter that the exemption require the Financial Institution to designate a specific person to address Material Conflicts of Interest and monitor Advisers' adherence to the Impartial Conduct Standards.
There were also questions and comments on the specific language of the proposed policies and procedures requirement. As proposed, the components of the policies and procedures requirement read as follows:
• The Financial Institution has adopted written policies and procedures reasonably designed to mitigate the impact of Material Conflicts of Interest and ensure that its individual Advisers adhere to the Impartial Conduct Standards set forth in Section II(c);
• In formulating its policies and procedures, the Financial Institution has specifically identified Material Conflicts of Interest and adopted measures to prevent the Material Conflicts of Interest from causing violations of the Impartial Conduct Standards set forth in Section II(c); and
• Neither the Financial Institution nor (to the best of its knowledge) any Affiliate or Related Entity uses quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives to the extent they would tend to encourage individual Advisers to make recommendations that are not in the Best Interest of the Retirement Investor.
A few commenters asked the Department to explain the difference between the first and second prongs of the policies and procedures requirement, as proposed. In response, the first prong of the requirement was intended to establish a general standard, while the second (and third) prongs provided specific rules regarding the policies and procedures requirement. This approach was also adopted in the final exemption. In addition, the language of Section II(d)(3) specifically provides that the third prong of the requirement, requiring Financial Institutions to insulate Advisers from incentives to violate the Best Interest standard, is part of the policies and procedures requirement.
There were also comments on (i) the definition and use of the term “Material Conflicts of Interest;” (ii) the language requiring the policies and procedures to be “reasonably designed” to mitigate the impact of such conflicts of interest, and (iii) the meaning of incentives that “tend to encourage” individual Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. In addition, comments from the insurance industry requested guidance on certain industry practices regarding employee benefits for statutory employees. These comments are discussed below.
A number of commenters focused on the definition of Material Conflict of Interest used in the proposal. Under the definition as proposed, a Material Conflict of Interest exists when an Adviser or Financial Institution “has a financial interest that could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.” Some commenters took the position that the proposal did not adequately explain the term “material” or incorporate a “materiality” standard into the definition. A commenter wrote that the proposed definition was so broad that it would be difficult for Financial Institutions to comply with the various aspects of the exemption related to Material Conflicts of Interest, such as provisions requiring disclosures of Material Conflicts of Interest.
Another commenter indicated that the Department should not use the term “material” in defining conflicts of interest. The commenter believed that it could result in a standard that was too subjective from the perspective of the Adviser and Financial Institution, and could undermine the protectiveness of the exemption.
After consideration of the comments, the Department adjusted the definition of Material Conflict of Interest. In the final exemption, a Material Conflict of Interest exists when an Adviser or Financial Institution has a “financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.” This language responds to concerns about the breadth and potential subjectivity of the standard. The Department did not, as some commenters suggested, include the word “material” in the definition of Material Conflict of Interest, to avoid the potential circularity of that approach.
One commenter asked that the Department more broadly use the modifier “reasonably designed” in describing the standard the policies and procedures must meet so as to avoid a construction that required standards that ensured perfect compliance, a potentially unattainable standard. The Department has accepted the comment and adjusted the language in Sections II(d)(1) and (2) to generally use the phrase “reasonably and prudently designed.” Other commenters asked for guidance on the proposed phrasing “reasonably designed to mitigate” the impact of Material Conflicts of Interest.
A number of commenters asked for clarification or revision of the proposed exemption's prohibition of incentives that “tend to encourage” violation of the Best Interest standard, generally to require a tight link between the incentives and the Advisers' recommendations. Commenters argued that the “tend to encourage” language established a standard that could be impossible to meet in the context of differential compensation. Accordingly, they requested that the Department use language such as “intended to encourage,” “does encourage” “causes,” or similar formulations.
In response to these commenters the Department has adjusted the condition's language as follows:
The Financial Institution's policies and procedures require that neither the Financial Institution nor (to the best of its knowledge) any Affiliate or Related Entity use or rely on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are
This language more accurately captures the Department's intent, which was to require that procedures reasonably address Advisers' incentives, not guarantee perfection. The Department disagrees, however, with the suggestion that Financial Institutions should be permitted to tolerate or create incentives that would “reasonably be expected to cause such violations” unless the Retirement Investor can actually prove the Financial Institution's intent to cause violations of the standard or the Adviser's improper motivation in making the recommendation. The aim of the policies and procedures requirement is to require the Financial Institution to take prophylactic measures to ensure that Retirement Advisers adhere to the Impartial Conduct Standards, a goal completely at odds with the creation of incentives to violate the Best Interest Standard. In exchange for its continuing receipt of compensation that would otherwise be prohibited by ERISA and the Code, the Financial Institution's responsibility under the exemption is to protect Retirement Investors from conflicts of interest, not to promote or continue to offer incentives to violate the Best Interest standard. Moreover, absent extensive discovery or the ability to prove the motivations of individual Advisers, Retirement Investors would generally be in a poor position to prove such ill intent.
Similar adjustments were made to the language of the proposal that provided that the policies and procedures requirement does not:
[P]revent the Financial Institution or its Affiliates and Related Entities from providing Advisers with differential compensation based on investments by Plans, participant or beneficiary accounts, or IRAs,
Accordingly, in this final exemption, the language now provides that the policies and procedures requirement does not:
[P]revent the Financial Institution or its Affiliates or Related Entities from providing Advisers with differential compensation
This language is designed to make clear that differential compensation is permitted but only if the Financial Institution's policies and procedures, as a whole are reasonably designed to avoid a misalignment of interests between Advisers and Retirement Investors. As discussed in greater detail below, the Financial Institution's payment of differential compensation should be based only on neutral factors.
A number of commenters from the insurance industry asked for clarification or revision of the policies and procedures provision as applicable to statutory employees of insurance companies. Insurance companies explained that they often rely on the statutory employee rules of the Internal Revenue Code, specifically Code section 3121 and the regulations thereunder. Under these rules, an independent contractor is treated as a full-time employee if that individual “is devoted to the solicitation of life insurance or annuity contracts, or both, primarily for one life insurance company.”
These commenters requested clarification that the provision of employee benefits based on status as a statutory employee under the Internal Revenue Code (which, as explained, may involve evaluation of the amount of Proprietary Products sold) would not violate the exemption, and in particular, the policies and procedures requirement. The Department did not intend the exemption to effectively prohibit the receipt of these benefits. Accordingly, the Department confirms that the receipt by an Adviser who is an insurance agent of reasonable and customary deferred compensation or subsidized health or pension benefit arrangements such as typically provided to an “employee” as defined in Code section 3121(d)(3) does not, in and of itself, violate the policies and procedures requirement or the Impartial Conduct Standards. However, consistent with the standard, such Financial Institutions must ensure that their policies and procedures and incentive practices, when viewed as a whole, are reasonably and prudently designed to avoid a misalignment of the interests of Advisers with the interests of the Retirement Investors they serve as fiduciaries. In the Department's view, the satisfaction of the requirement involves an evaluation of the relevant facts and circumstances.
Under the exemption, a Financial Institution must have policies and procedures in place that are reasonably and prudently designed to ensure compliance with the Impartial Conduct Standards, and the Financial Institution is prohibited from relying on incentive structures that are intended or would
Despite the Department's intent to permit a variety of commission and compensation structures many commenters questioned how a compensation structure that permitted differential compensation could be in compliance with the exemption's standards as proposed. For example, insurance industry commenters questioned whether Advisers could continue to receive different (typically higher) commissions for annuity contracts than for comparable mutual funds, which do not have an insurance component. The exemption was not intended to bar commissions or all forms of differential compensation. Accordingly, the Department has specifically revised the exemption's text to make clear that differential compensation is permissible, and has changed the prohibition on incentive structures that would “tend to encourage” violations of the Best Interest Standard to a prohibition on incentive structures “intended” or “reasonably expected” to cause such violations.
Thus, the final exemption specifically states that differential compensation is permissible, subject to policies and procedures “reasonably and prudently designed to prevent Material Conflicts of Interest from causing violations of the Impartial Conduct Standards,” and subject to the requirement that the differentials are not “intended” and would not “reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Compensation structures should be prudently designed to avoid a misalignment if the interests of Advisers and the Retirement Investors they serve, but may nevertheless provide for differential compensation. The exemption's goal is not to wring out every potential conflict, no matter how slight, but rather to ensure that Financial Institutions and Advisers put Retirement Investors' interests first, take care to minimize incentives to act contrary to investors' interests, and carefully police those conflicts that remain. Within this best interest framework, the exemption is designed to preserve commissions and other transaction-based compensation structures, thereby allowing Retirement Investors to choose the payment structure that works best for them.
The Department intends that Financial Institutions will identify Material Conflicts of Interest applicable to its and its Advisers' provision of investment advice and reasonably and prudently design policies and procedures to prevent those particular conflicts from causing violations of the Impartial Conduct Standards. The extent and contours of the policies and procedures will depend on the type of and pervasiveness of the conflicts in the Financial Institution's business. If, for example, the chief conflict of interest is a discrete conflict associated with advice on the rollover or distribution of plan assets, the Financial Institution's policies and procedures should focus on that conflict. In that context, the Financial Institution would exercise special care to ensure that the Adviser gives sufficient weight to consideration and documentation of any factors supporting leaving the investments in the plan, and not just any benefits of taking the distribution, which would generate fees for the Financial Institution and Adviser. On the other hand, a Financial Institution that compensates Advisers through a wide variety of commissions and other transaction-based payments and incentives would need to exercise great care in designing and policing the differential compensation structure. For example, the Financial Institution should give special attention to ensuring that supervisory mechanisms and procedures protect investors from recommendations to make excessive trades, or to buy investment products, annuities, or riders that are not in the customer's best interest or that tie up too much of the customer's wealth in illiquid or risky investments. In general, Financial Institutions should carefully focus on the particular aspects of their business model that potentially create misaligned incentives.
Accordingly, a Financial Institution could retain a structure in which Advisers receive differential compensation for different categories of investments, but are subject to policies and procedures that safeguard against the conflicts caused by the differential categories. For example, in many circumstances, it may require more time to explain the features of a complex annuity product than a relatively simpler mutual fund investment. Based on such neutral considerations, the Financial Institution's policies and procedures could permit the payment of greater commissions in connection with annuity sales, subject to appropriate controls and oversights as described below, including that the neutral factors be neutral in operation as well as selection. Differential compensation between categories of investments could be permissible as long as the compensation structure and lines between categories were drawn based on neutral factors that were not tied to the Financial Institution's own conflicts of interest, such as the time or complexity of the advisory work, rather than on promoting sales of the most lucrative products. In such cases, the policies and procedures would focus with particular care on adopting supervisory and monitoring mechanisms to police adviser's recommendations as they relate to investment products in differential categories, but the exemption would not prohibit the differentials. The Department also expects that Advisers and Financial Institutions providing advice will exercise special care when assets are hard to value, illiquid, complex, or particularly risky. Financial Institutions responsible for overseeing recommendations of these investments must give special attention to the policies and procedures surrounding such investments and their oversight of Advisers' recommendations.
As noted above, Financial Institutions also must pay attention to the incentives of branch managers and supervisors, and how the incentives potentially impact Adviser recommendations. Certainly, Financial Institutions must not provide incentives to branch managers or other supervisors that are intended to, or would reasonably be expected to cause such entities, in turn, to incentivize Advisers to make recommendations that do not meet the Best Interest standard. Financial
The examples set forth below are intended to illustrate some possible approaches that Financial Institutions could take to managing Adviser incentives. They are not intended to provide detailed descriptions of all the attributes of strong and effective policies and procedures, but rather to describe broad approaches to mitigating conflicts of interest. The examples are not intended to be an exhaustive list of permissible approaches or mutually exclusive, and range from examples that focus on eliminating or nearly eliminating compensation differentials to examples that permit, but police, the differentials. Moreover, these examples and the policies and procedures are not intended as mere “check the box” exercises, but rather must involve the adoption and monitoring of meaningful policies and procedures reasonably and prudently designed to ensure Advisers' adherence to the Impartial Conduct Standards. While the examples are intended to provide guidance regarding the design of policies and procedures, whether a specific set of policies and procedures is sufficient will depend on the specific facts and circumstances.
The preamble to the proposed exemption also included a series of examples. A number of commenters requested additional specificity, more examples and safe harbors with respect to the policies and procedures requirement. A few commenters made specific suggestions for safe harbors or additional examples. For example, one commenter suggested that compliance with policies and procedures requirements under existing securities laws should suffice. Another suggested a series of components of a safe harbor approach, based on controls and parameters to limit conflicts of interest (including a potential cap on fees for different product types) and other supervisory oversight. Another offered an example under which the Financial Institution would permit Advisers to receive either a commission that generally did not exceed the average commission for similar products, or asset-based compensation, but not both, with respect to any investment product, with additional limitations and requirements. Another offered an example focused on compliance with the terms of the exemption, but did not offer any specific provisions addressing compensation and other employment incentives.
The Department considered all the requests for additional examples and safe harbors. The Department views commenters' suggestions as outlining useful components of a Financial Institution's policies and procedures. However, the Department views the limitations on compensation and other employments incentives as a critical aspect of a Financial Institution's policies and procedures, and the examples offered by commenters generally did not demonstrate, in and of themselves, sufficient mitigation of Adviser-level conflicts of interest. Therefore, the Department did not adopt them as additional examples or safe harbors.
To the extent Financial Institutions decide they need additional guidance as to the adequacy of their policies and procedures as they move forward with implementation of the exemption's requirements, the Department is available to provide guidance on particular approaches. Each of the examples below assumes that the Financial Institution otherwise complies with all of the exemption's requirements; ensures that any compensation paid to the Firm and the Adviser (whether directly by the investor or indirectly by third parties) is reasonable in relation to the services delivered to the investor; and that it carefully supervises and oversees its Advisers' compliance with the Impartial Conduct Standards, disclosure obligations, and other requirements of the exemption.
Independently certified computer models. The Adviser interacts directly with the Retirement Investor, but makes investment recommendations in accordance with an unbiased computer model created by an independent third party. Under this example, the Adviser could receive any form or amount of compensation so long as the advice is rendered in strict accordance with the model.
Asset-based compensation. The Financial Institution accepts differential compensation but pays the Adviser a percentage, which does not vary based on the types of investments, of the dollar amount of assets invested by the plans, participant and beneficiary accounts, and IRAs with the Adviser. The Adviser earns the same percentage on the same payment schedule, regardless of how the Retirement Investor's assets are allocated between different investments (
Fee offset. The Financial Institution establishes a fee schedule for its services and the services of its Advisers. The fees are competitive and reasonable in relation to the services provided to the Retirement Investor and are not themselves intended to nor would they reasonably be expected to cause Advisers to violate the Impartial Conduct Standards. The Financial Institution accepts transaction-based payments directly from the plan, participant or beneficiary account, or IRA, and/or from third party investment providers. To the extent the payments from third party investment providers exceed the established fee, the additional amounts are rebated to the plan, participant or beneficiary account, or IRA. To the extent Third Party Payments do not satisfy the established fee, the plan, participant or beneficiary account, or IRA is charged directly for the remaining amount due.
Commissions and stringent supervisory structure.
• Establishment of a comprehensive system to monitor and supervise Adviser recommendations, evaluate the quality of the advice individual customers receive, properly train Advisers, and correct any identified problems. Particular attention is given to recommendations associated with higher compensation and recommendations at key liquidity events of an investor (
• Systems to evaluate whether Advisers recommend imprudent reliance on investment products sold by or through the Financial Institution. If the conditions of section IV(b)(3) of the exemption apply (relating to Proprietary Products and Third Party Payments), systems to assess the validity of any assumptions underlying the required written determination and mechanisms to ensure that Advisers provide advice consistent with the analysis, with particular attention to any assumptions or conclusions about how much money a prudent investor would invest in particular classes of products or products with certain features.
• The use of metrics for behavior (
• Penalizing Advisers and supervisors (including the branch manager) by reducing compensation based on the receipt of customer complaints or indications that conflicts are not being carefully managed, and/or using clawback provisions to revoke some or all of deferred compensation based on the failure to properly manage conflicts of interest.
• Appointment of a committee to assess the risks and conflicts associated with new investment products, determine the prudence of the products for retirement investors, and assess the adequacy of the Financial Institution's procedures to police any associated conflicts of interest.
• Ensuring that no Adviser nor any supervisor (including the branch manager) participates in any revenue sharing from a “preferred provider,” earns more for the sale of a product issued by a “preferred provider,” or earns more for the sale of a Proprietary Product over other comparable products, and ensuring that the Adviser discloses to customers the payments that the Financial Institution and its Affiliates have received from a preferred provider or for a Proprietary Product.
• The Financial Institution periodically reviews, and revises as necessary, the policies and procedures to ensure that they are appropriately safeguarding proper fiduciary conduct, and that the factors used to justify any compensation differentials (
Rewards for Best Interest Advice. The Financial Institution's policies and procedures establish a compensation structure that is reasonably designed to reward Advisers for giving advice that adheres to the Impartial Conduct Standards. For example, this might include compensation that is primarily asset-based, as discussed in Example 2, with the addition of bonuses and other incentives paid to promote advice that is in the Best Interest of the Retirement Investor. While the compensation would be variable, it would align with the customer's best interest.
As indicated above, these examples are meant to be illustrative, not exhaustive, and many other compensation and employment arrangements may satisfy the contractual warranties. The exemption imposes a broad standard for the warranty and policies and procedures requirement, not an inflexible and highly-prescriptive set of rules. The Financial Institution retains the latitude necessary to design its compensation and employment arrangements, provided that those arrangements promote, rather than undermine, the Best Interest and other Impartial Conduct Standards. Whether a Financial Institution adopts one of the specific approaches taken in the examples above or a different approach, the Department expects that it will engage in a prudent process to establish and oversee policies and procedures that will effectively mitigate conflicts of interest and ensure adherence to the Impartial Conduct Standards. It is important that the Financial Institution carefully monitor whether the policies and procedures are, in fact, working to prevent the provision of biased advice. The Financial Institution must correct isolated or systemic violations of the Impartial Conduct Standards and reasonably revise policies and procedures when failures are identified.
A number of commenters addressed Example 4 in the preamble to the proposed exemption, which, like Example 4 above, illustrated a compensation structure for differential payments, such as commissions. In the proposal the example suggested a model permitting payment of differential compensation based on neutral factors, such as “a reasonable assessment of the time and expertise necessary to provide prudent advice on the product or other reasonable and objective neutral factors.”
Some commenters expressed significant support for this approach and urged the Department to clearly limit the receipt of differential compensation in the final exemption to differential compensation based only on neutral factors. A commenter stated that a limitation to differential compensation based on neutral factors would be a significant improvement over the status quo. Other commenters indicated the
Some industry commenters took issue with the neutral factors example. FINRA and other commenters asserted that while the exemption applied to differential compensation such as trailing commissions, 12b-1 fees and revenue sharing, it would not be easy for Financial Institutions to demonstrate that such payments are based on neutral factors. Commenters expressed the view that the example appeared to establish a subjective standard that could expose them to class action litigation, and there were requests for more certainty or a safe harbor regarding the compliance with the exemption for differential compensation. One commenter stated that prices are established by third party product manufacturers and the neutral factors analysis would require a complete overhaul of existing practices. The commenter indicated there might be antitrust concerns with such an approach. FINRA further suggested that the proposal permit Financial Institutions to choose between adopting stringent policies and procedures that address the conflicts of interest arising from differential compensation, or pay only neutral compensation to Advisers.
The Department has considered these competing comments and determined for purposes of this preamble to limit the example regarding differential compensation to one based on neutral factors. The Department agrees with the commenters that suggested that differential compensation based on non-neutral factors is likely to encourage advice that is not in Retirement Investors' Best Interest. While the policies and procedures requirement is intended to give necessary flexibility to Financial Institutions, the Department emphasizes that the policies must be reasonably and prudently designed to ensure that Advisers adhere to the Impartial Conduct Standards, and the compensation structures must be prudently designed to avoid an inappropriate misalignment of the Advisers' interests with the interests of the Retirement Investors they serve a fiduciaries. Thus, for example, it would be impermissible for a Financial Institution to use or permit ratcheted compensation thresholds that enable an Adviser to disproportionately increase the amount of his or her compensation based on a specific recommendation to an individual investor. Similarly, the Financial Institution and related parties could not use or permit the use of bonuses, prizes, travel, entertainment, cash or noncash compensation that a reasonable person would expect to cause the preferential recommendation of a specific investment product or feature, without regard to the best interest of the Retirement Investor (
While differential payments are permitted, the differentials must reflect neutral factors, not the higher compensation the Financial Institution stands to gain by recommending one investment rather than another. Therefore, while pure mathematical precision is not necessary to justify differential payments, it would not be permissible to draw categories based on the differential compensation the Financial Institution receives from different mutual fund complexes, or differences in the amounts paid to the firm for different annuities or riders. Financial Institutions should be prepared to justify the reasons for differential payments to Advisers, to demonstrate that they are not based on what is more lucrative to the Financial Institution. In addition, the neutral factors must be neutral in application as well as in selection. Differentials based on neutral factors that operate in practice to encourage Advisers to violate the Impartial Conduct Standards are not permissible.
In addition to basing differential compensation on neutral factors, it is important for Financial Institutions that pay differential compensation to employ supervisory oversight structures. This is particularly necessary to ensure that Advisers are making recommendations between different categories based on the customer's financial interest, and not on the differential compensation the Adviser stands to make. But more fundamentally, Financial Institutions will not be able to ensure that their Advisers are providing advice in accordance with the Impartial Conduct Standards without appropriate supervision. Accordingly, the final exemption does not adopt FINRA's suggestion that the proposal permit Financial Institutions to choose between adopting stringent policies and procedures that address the conflicts of interest arising from differential compensation, or pay only neutral compensation to Advisers. Both are required.
In the proposal, both the Adviser and Financial Institution had to give a warranty to the Retirement Investor about the adoption and implementation of anti-conflict policies and procedures. A few commenters indicated that the Adviser should not be required to give the warranty, and questioned whether the Adviser would always be in a position to speak to the Financial Institution's incentive and compensation arrangements. The Department agrees that the Financial Institution has the primary responsibility for design and implementation of the policies and procedures requirement and, accordingly, has limited the warranty requirement to the Financial Institution.
Some commenters believed that even if the Department included a policies and procedure requirement in the exemption, it should not require a warranty on implementation and compliance with the requirement. According to some of these commenters the warranty was unnecessary in light of the Best Interest standard, and would unduly contribute to litigation risk. A few commenters also suggested that a Financial Institution's failure to comply with the contractual warranty could give rise to a cause of action to Retirement Investors who had suffered no injuries from failure to implement or comply with appropriate policies and procedures. A few other commenters expressed concern that the provision of a “warranty” could result in tort liability, rather than just contractual liability.
Other commenters argued that the Department should require Financial Institutions not only to make an enforceable warranty as a condition of
As noted above, the final exemption adopts the required policies and procedures as a condition of the exemption. The policies and procedures requirement is a critical part of the exemption's protections. The risk of liability associated with a non-exempt prohibited transaction gives Financial Institutions a strong incentive to design protective policies and procedures in a way that is consistent with the purposes and requirements of this exemption.
In addition, the final exemption requires the Financial Institution to make a warranty regarding the policies and procedures in contracts with Retirement Investors regarding IRAs and other non-ERISA plans. The warranty, and potential liability associated with that warranty, gives Financial Institutions both the obligation and the incentive to tamp down harmful conflicts of interest and protect Retirement Investors from misaligned incentives that encourage Advisers to violate the Best Interest standard and other fiduciary obligations and ensures that there is a means to redress the failure to do so. While the warranty exposes Financial Institutions and Advisers to litigation risk, these risks are circumscribed by the availability of binding arbitration for individual claims and the legal restrictions that courts generally use to police class actions.
The Department does not share a commenter's view that it would be too difficult for Retirement Investors to prove that the policies and procedures were not “reasonably designed” to achieve the required purpose. The final exemption requires the Financial Institution to disclose Material Conflicts of Interest to Retirement Investors and to describe its policies and procedures for safeguarding against those conflicts of interest. These disclosures should assist Retirement Investors in assessing the care with which Financial Institutions have designed their procedures, even if they are insufficient to fully convey how vigorously the Financial Institution implements the protections. In some cases, a systemic violation, or the possibility of such a violation, may be apparent on the face of the policies. In other cases, normal discovery in litigation may provide the information necessary. Certainly, if a Financial Institution were to provide significant prizes or bonuses for Advisers to push investments that were not in the Best Interest of Retirement Investors, Retirement Investors would often be in a position to pursue the claim. Most important, however, the enforceable obligation to maintain and comply with the policies and procedures as set forth herein, and to make relevant disclosures of the policies and procedures and of Material Conflicts of Interest, should create a powerful incentive for Financial Institutions to carefully police conflicts of interest, reducing the need for litigation in the first place.
In response to commenters that expressed concern about the specific use of the term “warranty,” the Department intends the term to have its standard meaning as a “promise that something in furtherance of the contract is guaranteed by one of the contracting parties.”
Additionally, although the policies and procedure requirement applies equally to ERISA plans, the final exemption does not require Financial Institutions to make a warranty with respect to ERISA plans, just as it does not require the execution of a contract with respect to ERISA plans. For these plans, a separate warranty is unnecessary because Title I of ERISA already provides an enforcement mechanism for failure to comply with the policies and procedures requirement. Under ERISA sections 502(a), plan participants, fiduciaries, and the Secretary of Labor have ready means to enforce any failure to meet the conditions of the exemption, including a failure to comply with the policies and procedure requirement. A Financial Institution's failure to comply with the exemption's policies and procedure requirements would result in a non-exempt prohibited transaction under ERISA section 406 and would likely constitute a fiduciary breach under ERISA section 404. As a result, a plan participant or beneficiary, plan fiduciary, and the Secretary would be able to sue under ERISA section 502(a) to recover any loss in value to the plan (including the loss in value to an individual account), or to obtain disgorgement of any wrongful profits or unjust enrichment. Accordingly, the warranty is unnecessary in the context of ERISA plans.
The proposed exemption also contained a requirement for the Adviser and Financial Institution to warrant that they and their Affiliates would comply with all applicable federal and state laws regarding the rendering of the investment advice, the purchase, sale or holding of the Asset and the payment of compensation related to the purchase, sale and holding. While the Department did receive some support for this condition in comments, several commenters opposed this warranty proposal as being overly broad, and urged that it be deleted. These commenters argued that the warranty could create contract claims based on a wide variety of state and federal laws, without regard to the limitations imposed on individual actions under those laws. In addition, commenters suggested that many of the violations associated with these laws could be quite minor or unrelated to the Department's concerns about conflicts of interest. In response to these concerns, the Department has eliminated this warranty from the final exemption.
Under Section II(f) of the final exemption, relief is not available if a Financial Institution's contract with Retirement Investors regarding investments in IRAs and non-ERISA plans contains the following:
(1) Exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms;
(2) Except as provided in paragraph (f)(4), a provision under which the Plan, IRA or Retirement Investor waives or qualifies its right to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or in an individual or class claim agrees to an amount representing liquidated damages for breach of the contract; provided that, the parties may knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law; or
(3) Agreements to arbitrate or mediate individual claims in venues that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption.
Section II(f)(4), provides that, in the event the provision on pre-dispute
The purpose of Section II(f) is to ensure that Retirement Investors receive the full benefit of the exemption's protections by preventing them from being contracted away. If an Adviser makes a recommendation, for a fee or other compensation, within the meaning of the Regulation, he or she may not disclaim the duties or liabilities that flow from the recommendation. For similar reasons, the exemption is not available if the contract includes provisions that purport to waive a Retirement Investor's right to bring or participate in class actions. However, contract provisions in which Retirement Investors agree to arbitrate any individual disputes are allowed to the extent permitted by applicable state law. Moreover, Section II(f) does not prevent Retirement Investors from voluntarily agreeing to arbitrate class or representative claims after the dispute has arisen.
The Department's approach in this respect is consistent with FINRA's rules permitting mandatory pre-dispute arbitration for individual claims, but not for class action claims.
A number of commenters addressed the proposed approach to arbitration and the other ineligible provisions in Section II(f). A discussion of the comments and the Department's responses follow.
The Department included Section II(f)(1) in the final exemption without changes from the proposal. Commenters did, however, raise a few questions on the provision. In particular, commenters asked whether the contract could disclaim liability for acts or omissions of third parties, and whether there could be venue selection clauses. In addition, commenters asked whether the contract could require exhaustion of arbitration or mediation before filing in court.
Section II(f)(1) does not prevent a Financial Institution's contract with IRA and non-ERISA plan investors from disclaiming liability for acts or omissions of third parties to the extent permissible under applicable law. In addition, for individual claims, reasonable arbitration and mediation requirements are not prohibited. In response to questions about venue selection, the final exemption includes a new Section II(f)(3), which provides that investors may not be required to arbitrate or mediate their individual claims in unreasonable or distant venues that are distant or that otherwise unreasonably limit their ability to assert the claims safeguarded by this exemption.
The Department has not revised Section II(f) to address every provision that may or may not be included in the contract. While some commenters submitted specific requests regarding specific contract language, and others suggested the Department provide model contracts for Financial Institutions to use, the Department has declined to make these changes in the exemption. The Department notes that Section II(f)(1) prohibits all exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms, and Section II(g)(5) prohibits Financial Institutions and Advisers from purporting to disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by Section 410 of ERISA. Therefore, in response to comments regarding choice of law provisions, modifying ERISA's statute of limitations, and imposing obligations on the Retirement Investor, the Financial Institutions must determine whether their specific provisions are exculpatory and would disclaim or limit their liability under ERISA, or that of their Advisers. If so, they are not permitted. The Department will provide additional guidance in response to questions and enforcement proceedings.
Section II(f)(2) of the final exemption adopts the approach, as proposed, that individual claims may be the subject of contractual pre-dispute binding arbitration. Class or other representative claims, however, must be allowed to proceed in court. The final exemption also provides that contract provisions may not limit recoveries to an amount representing liquidated damages for breach of the contract. However, the final exemption expressly permits Retirement Investors to knowingly waive their rights to obtain punitive damages or rescission of recommended transactions to the extent such waivers are permitted under applicable law.
Commenters on the proposed exemption were divided on the approach taken in the proposal, as discussed below. Some commenters objected to limiting Retirement Investors' right to sue in court on individual claims and specifically focused on FINRA's arbitration procedures. These commenters described FINRA's arbitration as an unequal playing field, with insufficient protections for individual investors. They asserted that arbitrators are not required to follow federal or state laws, and so would not be required to enforce the terms of the contract. In addition, commenters complained that the decision of an arbitrator generally is not subject to appeal and cannot be overturned by any court. According to these commenters, even when the arbitrators find in favor of the consumer, the consumers often receive significantly smaller recoveries than they deserve. Moreover, some asserted that binding pre-dispute arbitration may be contrary to the legislative intent of ERISA, which provides for “ready access to federal courts.”
Some commenters opposed to arbitration indicated that preserving the right to bring or participate in class actions in court would not give Retirement Investors sufficient access to courts. According to these commenters, allowing Financial Institutions to require resolution of individual claims by arbitration would impose additional and unnecessary hurdles on investors seeking to enforce the Best Interest standard. One commenter warned that the Regulation would make it more difficult for Retirement Investors to pursue class actions because the
Other commenters just as forcefully supported pre-dispute binding arbitration agreements. Some asserted that arbitration is generally quicker and less costly than judicial proceedings. They argued that FINRA has well-developed protections in place to protect the interests of aggrieved investors. One commenter pointed out that FINRA requires that the arbitration provisions of a contract be highlighted and disclosed to the customer, and that customers be allowed to choose an “all-public” panel of arbitrators.
A number of commenters argued that arbitration should be available for
After consideration of the comments on this subject, the Department has decided to adopt the general approach taken in the proposal. Accordingly, contracts with Retirement Investors may require pre-dispute binding arbitration of individual disputes with the Adviser or Financial Institution. The contract, however, must preserve the Retirement Investor's right to bring or participate in a class action or other representative action in court in such a dispute in order for the exemption to apply.
The Department recognizes that for many claims, arbitration can be more cost-effective than litigation in court. Moreover, the exemption's requirement that Financial Institutions acknowledge their own and their Advisers' fiduciary status should eliminate an issue that frequently arises in disputes over investment advice. In addition, permitting individual matters to be resolved through arbitration tempers the litigation risk and expense for Financial Institutions, without sacrificing Retirement Investors' ability to secure judicial relief for systemic violations that affect numerous investors through class actions.
On the other hand, the option to pursue class actions in court is an important enforcement mechanism for Retirement Investors. Class actions address systemic violations affecting many different investors. Often the monetary effect on a particular investor is too small to justify pursuit of an individual claim, even in arbitration. Exposure to class claims creates a powerful incentive for Financial Institutions to carefully supervise individual Advisers, and ensure adherence to the Impartial Conduct Standards. This incentive is enhanced by the transparent and public nature of class proceedings and judicial opinions, as opposed to arbitration decisions, which are less visible and pose less reputational risk to firms or Advisers found to have violated their obligations.
The ability to bar investors from bringing or participating in such claims would undermine important investor rights and incentives for Advisers to act in accordance with the Best Interest standard. As one commenter asserted, courts impose significant hurdles for bringing class actions, but where investors can surmount these hurdles, class actions are particularly well suited for addressing systemic breaches. Although by definition communications to a specific investor generally must have a degree of specificity in order to constitute fiduciary advice, a class of investors should be able to satisfy the requirements of commonality, typicality and numerosity where there is a systemic or wide-spread problem, such as the adoption or implementation of non-compliant policies and procedures applicable to numerous Retirement Investors, the systematic use of prohibited or misaligned financial incentives, or other violations affecting numerous Retirement Investors in a similar way. Moreover, the judicial system ensures that disputes involving numerous retirement investors and systemic issues will be resolved through a well-established framework characterized by impartiality, transparency, and adherence to precedent. The results and reasoning of court decisions serve as a guide for the consistent application of that law in future cases involving other Retirement Investors and Financial Institutions.
This is consistent with the approach long adopted by FINRA and its predecessor self-regulatory organizations. FINRA Arbitration rule 12204 specifically bars class actions from FINRA's arbitration process and requires that pre-dispute arbitration agreements between brokers and customers contain a notice that class action matters may not be arbitrated. In addition, it provides that a broker may not enforce any arbitration agreement against a member of certified or putative class action, until the certification is denied, the class action is decertified, the class member is excluded from, or elects not participate in, the class. This rule was adopted by the National Association of Securities Dealers and approved by the SEC in 1992.
[T]he NASD believes, and the Commission agrees, that the judicial system has already developed the procedures to manage class action claims. Entertaining such claims through arbitration at the NASD would be difficult, duplicative and wasteful. . . . The Commission agrees with the NASD's position that, in all cases, class actions are better handled by the courts and that investors should have access to the courts to resolve class actions efficiently.
One commenter suggested that if the Department preserved the ability of a Financial Institution to require arbitration of claims, it should consider requiring a series of additional safeguards for arbitration proceedings permitted under the exemption. The commenter suggested that the conditions could state that (i) the arbitrator must be qualified and independent; (ii) the arbitration must be held in the location of the person challenging the action; (iii) the cost of the arbitration must be borne by the Financial Institution; (iv) the Financial Institution's attorneys' fees may not be shifted to the Retirement Investor, even if the challenge is unsuccessful; (v) statutory remedies may not be limited or altered by the contract; (vi) access to adequate discovery must be permitted; (vii) there must be a written record and a written decision; (viii) confidentiality
The Department declines to mandate additional procedural safeguards for arbitration beyond those already mandated by other applicable federal and state law, or self-regulatory organizations. In the Department's view, the FINRA arbitration rules, in particular, provide significant safeguards for fair dispute resolution, notwithstanding the concerns raised by some commenters. FINRA's Code of Arbitration Procedures for Customer Disputes applies when required by written agreement between the FINRA member and the customer, or if the customer requests arbitration. The rules cover any dispute between the member and the customer that arises from the member's business activities, except for disputes involving insurance business activities of a member that is an insurance company.
One commenter focused on dispute resolution processes engaged in by entities licensed as fraternal benefit societies under the laws of a State and exempt from federal income taxation under code section 501(c)(8). The commenter requested that these entities be carved out from the prohibitions of Section II(f) if they provided laws or rules for grievance or complaint procedures for members. The Department has declined to provide special provisions for specific parties based on mission or tax exempt status. Nothing in the legal structure relating to such organizations uniformly requires that their dispute-resolution processes adhere to stringent protective standards. Nevertheless, the Department notes that as long as Section II(f) and Section II(g)(5) are satisfied, the exemption would not be violated by a Financial Institution's adoption of additional protections for customers beyond the requirements of applicable regulators, such as payment of administrative costs of mediation and/or arbitration, as is the practice of some fraternal benefit societies.
Some commenters asserted that the Department does not have the authority to include the exemption's provisions on class action waivers under the Federal Arbitration Act (FAA), which they said protects enforceable arbitration agreements and expresses a federal policy in favor of arbitration over litigation. Without clear statutory authority to restrict arbitration, these commenters said, the Department cannot include the provisions on class action waivers.
These comments misconstrue the effect of the FAA on the Department's authority to grant exemptions from prohibited transactions. The FAA protects the validity and enforceability of arbitration agreements. Section 2 of the FAA states: “[a] written provision in any . . . contract . . . to settle by arbitration a controversy thereafter arising out of such contract . . . shall be valid, irrevocable, and enforceable, save upon such grounds as exist at law or in equity for the revocation of any contract.”
Section II(f)(2) of the exemption is fully consistent with the FAA. The exemption does not purport to render an arbitration provision in a contract between a Financial Institution and a Retirement Investor invalid, revocable, or unenforceable. Nor, contrary to the concerns of one commenter, does Section II(f)(2) prohibit such waivers. Both Institutions and Advisers remain free to invoke and enforce arbitration provisions, including provisions that waive or qualify the right to bring a class action or any representative action in court. Instead, such a contract simply does not meet the conditions for relief from the prohibited transaction provisions of ERISA and the Code. As a result, the Financial Institution and Adviser would remain fully obligated under both ERISA and the Code to refrain from engaging in prohibited transactions. In short, Section II(f)(2) does not affect the validity, revocability, or enforceability of a class-action waiver in favor of individual arbitration. This regulatory scheme is thus a far cry from the State judicially created rules that the Supreme Court has held preempted by the FAA,
The Department has broad discretion to craft exemptions subject to its overarching obligation to ensure that the exemptions are administratively feasible, in the interests of plan participants, beneficiaries, and IRA owners, and protective of their rights. In this instance, the Department has concluded that the enforcement rights and protections associated with class action litigation are important to safeguarding the Impartial Conduct Standards and other anti-conflict provisions of the exemption. If a Financial Institution enters into a contract requiring binding arbitration of class claims, the Department would not purport to invalidate the provision, but rather would insist that the Financial Institution fully comply with statutory provisions prohibiting conflicted fiduciary transactions in its dealings with its Retirement Investment customers. The FAA is not to the contrary. It neither limits the Department's express grant of discretionary authority over exemptions, nor entitles parties that enter into arbitration agreements to a pass from the prohibited transaction rules.
While the Department is confident that its approach in the exemption does not violate the FAA, it has carefully considered the position taken by several commenters that the Department exceeded its authority in including provisions in the exemption on waivers of class and representative claims, and the possibility that a court might rule that the condition regarding arbitration of class claims in Section II(f)(2) of the exemption is invalid based on the FAA. Accordingly, in an abundance of caution, the Department has specifically provided that Section II(f)(2) can be severable if a court finds it invalid based on the FAA. Specifically, Section II(f)(4) provides that:
In the event that the provision on pre-dispute arbitration agreements for class or representative claims in paragraph (f)(2) of this Section is ruled invalid by a court of
The Department is required to find that the provisions of an exemption are administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of participants and beneficiaries and IRA owners. The Department finds that the exemption with Section II(f)(2) satisfies these requirements. The Department believes, consistent with the position of the SEC and FINRA, that the courts are generally better equipped to handle class claims than arbitration procedures and that the prohibition on contractual provisions mandating arbitration of such claims helps the Department makes the requisite statutory findings for granting an exemption.
Nevertheless, the Department has determined that, based on all the exemption's other conditions, it can still make the necessary findings to grant the exemption even without the condition prohibiting pre-dispute agreements to arbitrate class claims. In particular, if a court were to invalidate the condition, the Department would still find that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries, and protective of the rights of the participants and beneficiaries. It would be less protective, but still sufficient to grant the exemption.
The Department's adoption of the specific severability provision in Section II(f)(4) of the exemption should not be viewed as evidence of the Department's intent that no other conditions of this or the other exemptions granted today are severable if a court were to invalidate them. Instead, the Department intends that invalidated provisions of the rule and exemptions may be severed when the remainder of the rule and exemptions can function sensibly without them.
Some commenters asked whether the proposal's prohibition of exculpatory clauses would affect the parties' ability to limit remedies under the contract, particularly regarding liquidated damages, punitive damages, consequential damages and rescission. In response, the Department has added text to Section II(f)(2) in the final exemption clarifying that the parties, in an individual or class claim, may not agree to an amount representing liquidated damages for breach of the contract. However, the exemption, as finalized, expressly permits the parties to knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law.
In the Department's view, it is sufficient to the exemptions' protective purposes to permit recovery of actual losses. The availability of such a remedy should ensure that plaintiffs can be made whole for any losses caused by misconduct, and provide an important deterrent for future misconduct. Accordingly, the exemption does not permit the contract to include liquidated damages provisions, which could limit Retirement Investors' ability to obtain make-whole relief.
On the other hand, the exemption permits waiver of punitive damages to the extent permissible under governing law. Similarly, rescission can result in a remedy that's disproportionate to the injury. In cases where an advice fiduciary breached its obligations, but there was no injury to the participant, a rescission remedy can effectively make the fiduciary liable for losses caused by market changes, rather than its misconduct. These new provisions in section II(f)(2) only apply to waiver of the contract claims; they do not qualify or limit statutory enforcement rights under ERISA. Those statutory remedies generally provide for make-whole relief and to rescission in appropriate cases, but they do not provide for punitive damages.
The exemption requires disclosure of Material Conflicts of Interest and basic information relating to those conflicts and the advisory relationship in Sections II and III. The exemption requires contract disclosures (Section II(e)), pre-transaction (or point of sale) disclosures (Section III(a)), and web-based disclosures (Section III(b)). One of the chief aims of the disclosures is to ensure that the Retirement Investor is fairly informed of the Adviser's and Financial Institution's conflicts of interest. The final exemption adopts a tiered approach, generally providing for automatic disclosure of basic information on conflicts of interest and the advisory relationship, but requiring more detailed disclosure, free of charge, upon request. As discussed below, the final exemption requires disclosure of the information Retirement Investors need to assess conflicts of interest and compensation structures, while reducing compliance burden.
Section II(e) obligates the Financial Institution to make specified disclosures to Retirement Investors. For advice to Retirement Investors regarding investments in IRAs and non-ERISA plans, the disclosures must be provided prior to or at the same time as the execution of the recommended transaction, either as part of the contract or in a separate written disclosure provided to the Retirement Investor with the contract. For advice to Retirement Investors regarding investments in ERISA plans, the disclosures must be provided prior to or at the same time as the execution of the recommended transaction. The disclosures require the provision of more general information upfront to the Retirement Investor accompanied by notice that more specific information is available free of charge, upon request. If the Retirement Investor makes a request for more specific information prior to the transaction, the information must be provided prior to the transaction. For requests made after the transaction, the information must be provided within 30 business days. Although the contract disclosure is a one-time disclosure, the Financial Institution must also post model disclosures on its Web site, and on a quarterly basis review and update the model disclosures as necessary for accuracy.
The pre-transaction disclosure in Section III(a) supplements the contract disclosure, and must be provided to all Retirement Investors (whether regarding an ERISA plan, non-ERISA plan or IRA) prior to or at the same time as the execution of a recommended transaction. The pre-transaction disclosure repeats certain information in the contract disclosure to ensure that the Retirement Investor has received the information sufficiently close to the time of the transaction, when the information is most relevant. Such disclosure is particularly important when the advisory relationship extends over time. To minimize burden, however, the Financial Institution does not need to repeat the pre-transaction disclosure more frequently than annually after the initial contract disclosure, or other transaction disclosures, with respect to additional recommendations regarding the same investment product.
The web-based disclosure in Section III(b) is intended to provide information about the Financial Institutions' arrangements with product
The Department significantly revised the disclosures from the proposed exemption. Commenters responded to the Department's disclosure proposals and specific requests for comment with feedback on the cost, feasibility and utility of the proposed disclosures. The Department carefully considered the comments in order to formulate an approach in the final exemption that responded to commenters' legitimate concerns, while ensuring fair disclosure of important information to Retirement Investors.
In broad outline, the final exemption takes a “two-tier” approach, as suggested by some commenters,
The specific content requirements of the disclosure provisions, comments received on the proposals and the Department's responses are discussed below.
Under Section II(e) of the exemption, the Financial Institution must clearly and prominently, in a single written disclosure:
(1) State the Best Interest standard of care owed by the Adviser and Financial Institution to the Retirement Investor; inform the Retirement Investor of the services provided by the Financial Institution and the Adviser; and describe how the Retirement Investor will pay for services, directly or through Third Party Payments. If, for example, the Retirement Investor will pay through commissions or other forms of transaction-based payments, the contract or writing must clearly disclose that fact;
(2) Describe Material Conflicts of Interest; disclose any fees or charges the Financial Institution, its Affiliates, or the Adviser imposes upon the Retirement Investor or the Retirement Investor's account; and state the types of compensation that the Financial Institution, its Affiliates, and the Adviser expect to receive from third parties in connection with investments recommended to Retirement Investors;
(3) Inform the Retirement Investor that the Investor has the right to obtain copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as specific disclosure of costs, fees, and compensation, including Third Party Payments regarding recommended transactions, as set forth in Section III(a) of the exemption, described in dollar amounts, percentages, formulas or other means reasonably designed to present materially accurate disclosure of their scope, magnitude, and nature in sufficient detail to permit the Retirement Investor to make an informed judgment about the costs of the transaction and about the significance and severity of the Material Conflicts of Interest, and describe how the Retirement Investor can get the information, free of charge; provided that if the Retirement Investor's request is made prior to the transaction, the information must be provided prior to the transaction, and if the request is made after the transaction, the information must be provided within 30 business days after the request;
(4) Include a link to the Financial Institution's Web site as required by Section III(b), and inform the Retirement Investor that: (i) The model contract disclosures updated as necessary on a quarterly basis for accuracy are maintained on the Web site, and (ii) the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) are available free of charge on the Web site;
(5) Disclose to the Retirement Investor whether the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to any recommended transaction; and to the extent the Financial Institution or Adviser limits investment recommendations, in whole or part, to Proprietary Products or investments that generate Third Party Payments, notify the Retirement Investor of the limitations placed on the universe of investments that the Adviser may offer for purchase, sale, exchange, or holding by the Retirement Investor. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis.
(6) Provide contact information (telephone and email) for a representative of the Financial Institution that the Retirement Investor can use to contact the Financial Institution with any concerns about the advice or service they have received; and, if applicable, a statement explaining that the Retirement Investor can research the Financial Institution and its Advisers using FINRA's BrokerCheck database or the Investment Adviser Registration Depository (IARD), or other database maintained by a governmental agency or instrumentality, or self-regulatory organization; and
(7) Describe whether or not the Adviser and Financial Institution will monitor the Retirement Investor's investments and alert the Retirement Investor to any recommended change to those investments and, if so, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted.
By “clearly and prominently in a single written disclosure,” the Department means that the Financial Institution may provide a document prepared for this purpose containing only the required information, or include the information in a specific section of the contract in which the disclosure information is provided, rather than requiring the Retirement Investor to locate the relevant information in several places throughout a larger disclosure or series of disclosures.
Section II(e)(8) provides a mechanism for correcting disclosure errors, without losing the exemption. It provides that the Financial Institution will not fail to satisfy Section II(e), or violate a contractual provision based thereon, solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, provided the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. Section II(e)(8) further provides that to the extent compliance with the contract disclosure requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information
The proposal contained three elements of the contractual disclosure set forth in Section II(e). The Financial Institution would have been required to: Identify and disclose any Material Conflicts of Interest; inform the Retirement Investor of his or her right to obtain complete information about all the fees currently associated with Assets in which he or she is invested; and disclose to the Retirement Investor whether the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to the purchase, sale or holding of any Asset, and of the address of the required Web site that discloses the Financial Institutions' and Advisers' compensation arrangements.
Several commenters supported the proposed disclosures. Commenters recognized that well-designed disclosure can serve multiple purposes, including facilitating informed investment decisions. However, even if investors do not carefully review the disclosures they receive, commenters perceived a benefit to investors from the greater transparency of public disclosure. For example, firms may change practices that run contrary to Retirement Investors' interests rather than disclose them publicly. The Department received a few questions and requests for clarification of these proposed disclosure requirements. One commenter requested that the Department clarify that, for purposes of the disclosure provisions, “direct” and “indirect” compensation had the same meanings as they did in ERISA section 408(b)(2). Several other commenters suggested that the Department rely to a greater extent on existing conflicts disclosure requirements applicable to investment advisers registered under the Investment Advisers Act of 1940. Additionally, there were questions as to how the information in the contractual disclosure should be updated.
As noted above, the Department modeled the final exemption's disclosure provisions, in part, on comments suggesting adoption of a “two-tier” approach, under which an investor would receive a “first tier” disclosure at the time of account opening, with a “second tier” of more in-depth information available on the Financial Institution's Web site and in other formats upon request. The Department adopted a number of these commenters' suggestions as part of the contractual disclosure set forth in Section II(e), viewing the contractual disclosure as similar to the first tier approach suggested by the commenters.
Specifically, the Department adopted commenters' suggestions that the disclosures: State the standard of care owed to the Retirement Investor; inform the Retirement Investor of the services to be provided; and inform the Retirement Investor of how he or she will pay for services. A commenter also suggested that the disclosure include any significant limitations on services provided by the Financial Institution, such as the sale of only propriety products. The suggestion was adopted in Section II(e)(5).
A commenter further suggested that the disclosure provide information on a representative of the Financial Institution that the Retirement Investor can contact with complaints, and a statement explaining that the Retirement Investor can research the Financial Institution and its Advisers using FINRA's BrokerCheck database or the Investment Adviser Registration Depository (IARD). The Department incorporated this suggestion in Section II(e)(6). Further, the commenter's suggestion that Retirement Investors should be informed of their ability to obtain additional more detailed information, free of charge, was adopted in Section II(e)(3).
FINRA's suggestion that the parties agree on the extent of monitoring of the Retirement Investor's investments was adopted, in Section II(e)(7). In making this determination, Financial Institutions should carefully consider whether certain investments can be prudently recommended to the individual Retirement Investor, in the first place, without a mechanism in place for the ongoing monitoring of the investment. Finally, a number of commenters requested relief for good faith inadvertent failures to comply with the exemption. A specific provision applicable to the Section II(e) disclosures is included in Section II(e)(8).
In response to a commenter's question regarding the meaning of direct versus indirect expenses, the Department has generally revised the exemption to refer to “Third Party Payments,” rather than indirect expenses. The phrase “Third Party Payments” is a defined term in the exemption.
The Department has also addressed how the contractual disclosure must be updated. Under the exemption, the contract provides one-time disclosure, but the information must be maintained on the Web site and updated quarterly as necessary for accuracy. Additionally, the transaction disclosure required under Section III(a) must be accurate at the time it is provided, which will serve to provide the Retirement Investor with the most current information prior to or at the same time as the execution of a recommended transaction, essentially updating the contractual disclosure.
Section III(a) of the exemption requires that, prior to or at the same time as the execution of a recommended investment transaction, the Financial Institution must provide the Retirement Investor a disclosure that clearly and prominently, in a single written document:
(1) States the Best Interest standard of care owed by the Adviser and Financial Institution to the Retirement Investor; and describes any Material Conflicts of Interest;
(2) Informs the Retirement Investor that the Retirement Investor has the right to obtain copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as specific disclosure of costs, fees and other compensation including Third Party Payments regarding recommended transactions. The costs, fees, and other compensation may be described in dollar amounts, percentages, formulas, or other means reasonably designed to present materially accurate disclosure of their scope, magnitude, and nature in sufficient detail to permit the Retirement Investor to make an informed judgment about the costs of the transaction and about the significance and severity of the Material Conflicts of Interest. The information required under this section must be provided to the Retirement Investor prior to the transaction, if requested prior to the transaction, and if the request occurs after the transaction, the information must be provided within 30 business days after the request; and
(3) Includes a link to the Financial Institution's Web site as required by Section III(b), and informs the Retirement Investor that: (i) Model contract disclosures updated as necessary on a quarterly basis are maintained on the Web site, and (ii) the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) are available free of charge on the Web site.
This disclosure is required only at the time an investment is made, and does not have to be repeated if there is a recommendation to hold or sell the
To reduce compliance burden, Section III(a)(4) provides that these disclosures do not have to be repeated for subsequent recommendations by the Adviser and Financial Institution of the same investment product within one year after the provision of the contract disclosure required by Section II(e) or a prior disclosure required by Section III(a), unless there are material changes in the subject of the disclosure. Additionally, in the final exemption, the Department makes clear that the Financial Institution is responsible for the required disclosures. This is consistent with a commenter that indicated that it is not industry practice for individual Advisers to prepare disclosures.
The Department revised the transaction disclosure in the final exemption based on input from commenters. In the proposed exemption, the transaction disclosure in Section III(a) would have required the provision to the Retirement Investor of a chart setting forth the “total cost” of the recommended investment for 1-, 5- and 10-year periods, expressed as a dollar amount, assuming an investment of the dollar amount recommended by the Adviser and reasonable assumptions about investment performance. In addition, an annual disclosure proposed under Section III(b) would have required an annual disclosure of investments purchased during the year, the total dollar amount of all fees and expenses paid by the investor and the total dollar amount of all compensation received by the Adviser and Financial Institution, directly or indirectly, from any party as a result of the investments. The disclosure was to be provided within 45 days of the end of the applicable year.
A few commenters indicated their support for a point of sale disclosure to Retirement Investors, which the commenters said is not currently required in many cases. Some commenters highlighted the importance of alerting Retirement Investors to the costs of an investment over time, which was the intent of the proposed transaction disclosure. Other commenters described the benefit of the annual disclosure as a means of showing actual costs paid, rather than the projections provided in the proposed transaction disclosure. Nonetheless, many supporters of the disclosures took the position that the disclosure requirements would be secondary in importance to the Impartial Conduct Standards and policies and procedures requirement set forth in Section II.
A number of other commenters raised significant objections to the disclosures proposed in Section III(a) and (b). These commenters generally indicated the disclosures would be costly to implement and Financial Institutions would need an extensive transition period in order to comply. In this vein, several commenters stated that Financial Institutions do not currently assemble or maintain all of the required information and that current systems could not deliver the disclosures. Commenters expressed concerns that the logistics of providing the disclosures were unduly burdensome. These logistics included the application of the disclosure provisions to all investment products, including annuities and insurance products, the specific formatting and wording of the disclosure, the acceptable means of providing the disclosure (whether verbal or electronic communications would be permitted), and the allocation of responsibilities between the Financial Institution and Adviser. One commenter stated that the burden was so great that only very large Financial Institutions would be able to continue to provide investment advice to Retirement Investors.
Some commenters questioned the substance of the proposed disclosure requirements. According to some commenters, it would be difficult to provide specific dollar amounts of indirect compensation received on an account or transaction level. Comments from the insurance industry stated that the transactional disclosures were a poor fit for insurance transactions, in particular. Commenters also specifically objected to the obligation to project investment performance for purposes of calculating costs over 1-, 5-, and 10-year holding periods. Commenters, including FINRA, stated that requirement would conflict with FINRA Rule 2210, which generally prohibits broker-dealers from including projections of performance in communications with the public. A few comments suggested that the Department could instead proceed with the proposed point of sale disclosure using hypothetical amounts that would comply with the FINRA rule.
A number of commenters urged the Department to rely on existing disclosure requirements, including required disclosures under ERISA sections 404 and 408(b)(2), state insurance law, the SEC's Form ADV for registered investment advisers, or product-specific information such as a prospectus or summary prospectus. Several commenters observed that the Department recently implemented a series of disclosure requirements under ERISA sections 404 and 408(b)(2), and relying on these disclosures would avoid additional investment in costly technology and procedures.
Other commenters suggested specific alternative disclosures that are not currently required by law. For example, a commenter suggested a so-called “20/20 disclosure,” showing the effect of fees on a $20,000 initial investment over a 20-year period. The commenter further suggested an “annual retirement receipt,” that indicates the percentage and dollar amount of fees by fund in addition to compensation received.
Other commenters took the position that the disclosures would not be helpful to Retirement Investors or would contribute to information overload. In this connection, one commenter noted the Department's own skepticism in its Regulatory Impact Analysis of the effectiveness of disclosure. According to one commenter, regarding the annual disclosure, customers' accounts typically include a mix of investments and reflect a range of transactions, only some of which are the result of a recommendation, and it may not be possible to distinguish the two. Therefore, the annual statement would reflect all transactions in the account, and would not provide meaningful information about compensation or Material Conflicts of Interest with respect to investment advice.
Several commenters raised questions about the timing of the disclosures. Some commenters argued that transaction disclosure should be provided sufficiently in advance of the transaction (or before entering into the relationship at all) so that the Retirement Investor has the time needed to review the materials provided. Other commenters expressed concern that the proposal would have required the disclosure to be provided too early; as a result, the transaction disclosure requirements could the delay the investment or cause the Retirement Investor to miss the opportunity entirely. Some commenters warned that the specific prices required to be disclosed may not be knowable at the time of the required disclosure. Regarding the annual disclosure, commenters were also concerned that 45 days following the end of the applicable year was not enough time to collect a detailed accounting of the dollars attributable to each asset and prepare the disclosure.
In response to commenters, the Department has significantly revised the disclosure requirements to reduce the burden, focus on pre-transaction disclosure of the most salient information about the contractual relationship and conflicts of interest, and facilitate more detailed disclosure, upon request, to Retirement Investors specifically interested in more detail. The contract and transaction disclosures provide basic information that is critical to the Retirement Investor's understanding of the nature of the relationship and the scope of the conflicts of interest. Without these disclosures, it cannot be fairly said that the Investor has entered into the investment or the advisory relationship with eyes open.
It is true that the final exemption does not chiefly rely on disclosure as a means of protection, but rather on the imposition of fiduciary standards of conduct, anti-conflict policies and procedures, and the prohibition of misaligned incentive structures. Nevertheless, disclosure can serve a salutary purpose in the right circumstances and is critical to obtaining the Retirement Investor's knowing assent to the conflicted advisory relationship. In addition, the public web disclosure is intended as much for intermediaries, consumer watchdogs, and other third parties who can use it to force competitive forces to work on conflicted structures. Similarly, the Department has calibrated the contract and transaction disclosures to focus on the most important information about conflicts of interest and the contractual relationship in a way that is neither too technical nor overwhelming. Thus, more detailed information is available upon request for consumers who are interested in digging deeper and who are presumably better able to use the information.
In this regard, the Department has limited the individual disclosures under Section III to a transaction-based disclosure, focusing on the Financial Institution's Material Conflicts of Interest with respect to the recommended transaction, and the availability upon request, free of charge, of more specific information about the costs, fees and other compensation associated with the investment. The Department has intentionally provided flexibility on the timing of disclosure, as long as it is provided prior to or at the same time as the execution of the recommended investment. Similarly, while the Department proposed a specific model form for the transaction disclosure, in this final exemption it has determined to provide flexibility on the format. In response to concerns about burden, cost, and utility, discussed above, the Department did not adopt the annual disclosure requirement in the final exemption.
The Department did not attempt to revise the transaction disclosure to use hypotheticals, permitted under FINRA rule 2210, because such disclosure would not achieve the desired goal of informing Retirement Investors in a specific way of the costs of the investment over time. The Department also declined to merely duplicate existing disclosure requirements under ERISA sections 404 and 408(b)(2), but rather to focus on the specific disclosures related to the anti-conflict goals of this project. The Department also did not adopt the other specific disclosure suggestions by commenters, as it was persuaded that the two-tier approach most efficiently achieved the Department's objectives. As noted above, the disclosure requirements in the final exemption minimize the burden on both the Financial Institution and the Retirement Investor, without reducing the protections of the disclosure. Additionally, in response to commenters, the Department has included a good faith compliance provision applicable to the Section III disclosures. Section III(c) provides that the Financial Institution will not fail to satisfy the transaction disclosure requirement if, acting in good faith and with reasonable diligence, it makes an error or omission in disclosing the required information, provided the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. This approach enables and incentivizes the Financial Institution to correct good faith errors without losing the benefit of the exemption.
Section III(c) further provides that, to the extent compliance with the Section III disclosures requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
Some commenters also responded to the suggestion in the proposal that the transaction disclosure could be replaced with a “cigarette warning”-style disclosure, such as the following:
Investors are urged to check loads, management fees, revenue-sharing, commissions, and other charges before investing in any financial product. These fees may significantly reduce the amount you are able to invest over time and may also determine your adviser's take-home pay. If these fees are not reported in marketing materials or made apparent by your investment adviser, do not forget to ask about them.
Several commenters wrote that this, perhaps in combination with an existing disclosure, would be preferable to the specific proposed requirements. Other commenters opposed the proposal. Some were concerned that such a general disclosure would not provide Retirement Investors with the information they needed to understand their investments. The Department is similarly skeptical about the utility of such a general warning, and believes that the goals of the warning are better served by the contract and transaction disclosures contained in the final exemption. Accordingly, the Department declines to mandate the additional disclosure.
Under Section III(b) of the exemption, the Financial Institution is required to maintain a Web site, freely accessible to the public and updated no less than quarterly, which contains:
(i) A discussion of the Financial Institution's business model and the Material Conflicts of Interest associated with that business model;
(ii) A schedule of typical account or contract fees and service charges;
(iii) A model contract or other model notice of the contractual terms (if applicable) and required disclosures described in Section II(b)-(e), which are reviewed for accuracy no less frequently than quarterly and updated within 30 days if necessary;
(iv) A written description of the Financial Institution's policies and procedures that accurately describes or summarizes key components of the policies and procedures relating to conflict-mitigation and incentive practices in a manner that permits Retirement Investors to make an informed judgment about the stringency of the Financial Institution's protections against conflicts of interest;
(v) To the extent applicable, a list of all product manufacturers and other parties with whom the Financial Institution maintains arrangements that provide Third Party Payments to either the Adviser or the Financial Institution with respect to specific investment products or classes of investments recommended to Retirement Investors; a description of the arrangements, including a statement on whether and how these arrangements impact Adviser compensation, and a statement on any benefits the Financial Institution provides to the product manufacturers or other parties in exchange for the Third Party Payments; and
(vi) Disclosure of the Financial Institution's compensation and incentive arrangements with Advisers including, if applicable, any incentives (including both cash and non-cash compensation or awards) to Advisers for recommending particular product manufacturers, investments or categories of investments to Retirement Investors, or for Advisers to move to the Financial Institution from another firm or to stay at the Financial Institution, and a full and fair description of any payout or compensation grids, but not including information that is specific to any individual Adviser's compensation or compensation arrangement.
Section III(b)(1)(vii) clarifies that the Web site may describe the above arrangements with product manufacturers, Advisers, and others by reference to dollar amounts, percentages, formulas, or other means reasonably calculated to present a materially accurate description of the arrangements. Similarly, the Web site may group disclosures based on reasonably defined categories of investment products or classes, product manufacturers, Advisers, and arrangements, and it may disclose reasonable ranges of values, rather than specific values, as appropriate. By permitting Financial Institutions to present information in reasonably-defined categories and in reasonable ranges of values, the Department does not intend to permit disclosures that are so broad as to obscure significant conflicts of interest. A broad category covering all mutual funds, or insurance products, for example, would not be sufficiently detailed unless the Financial Institution maintained the same compensation arrangement with all such mutual funds or insurance products. Likewise, disclosing a very broad range of compensation structures applicable to all the Financial Institution's Advisers would not be sufficient if in fact there are material differences among adviser compensation. However constructed, the Web site must fairly disclose the scope, magnitude, and nature of the compensation arrangements and Material Conflicts of Interest in sufficient detail to permit visitors to the Web site to make an informed judgment about the significance of the compensation practices and Material Conflicts of Interest with respect to transactions recommended by the Financial Institution and its Advisers. Section III(b)(1)(vi) clarifies that the disclosure also must include incentives the Financial Institution offers to Advisers to move to or stay the firm. These disclosures need not contain amounts paid to specific individuals, but instead should be a reasonable description of the incentives paid and factors considered by the Financial Institution. This change is intended to clarify and narrow the requirement in the proposal that the Web site include “indirect material compensation payable to the Adviser.”
Additionally, Section III(b)(2) makes clear that, to the extent the information required by this section is provided in other disclosures which are made public, including those required by the SEC and/or the Department such as a Form ADV, Part II, the Financial Institution may satisfy Section III(b) by posting such disclosures to its Web site with an explanation that the information can be found in the disclosures and a link to precisely where it can be found. Further, Section III(b)(3) provides that the Financial Institution is not required to disclose information on the web if such disclosure is otherwise prohibited by law. Section III(b)(4) requires that, in addition to providing the written descriptions of the Financial Institution's policies and procedures on its Web site, as required by under Section III(b)(1)(iv), Financial Institutions must provide their complete policies and procedures, adopted pursuant to Section II(d), to the Department upon request. Finally, Section III(b)(5) requires that, in the event that a Financial Institution determines to group disclosures as described above, it must retain the data and documentation supporting the group disclosure during the time that it is applicable to the disclosure on the Web site, and 6 years after that, and make the data and documentation available to the Department within 90 days of the Department's request.
Finally, Section III(c) contains a good faith exception in the event of an error or omission in disclosing the required information, or if the Web site is temporarily inaccessible. The Financial Institution will not fail to satisfy the exemption provided it discloses the correct information as soon as practicable, but, in the case of an error or omission on the web, not later than 7 days after the date on which it discovers or reasonably should have discovered the error or omission, and in the case of an error or omission with respect to the transaction disclosure, not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. The periods differ because of the likelihood that errors or omissions on the Web site will have a greater impact than an error in an individual disclosure, due to the wider audience. Moreover, the Web site should be able to be updated more quickly than an individual disclosure; the 30-day period for correction of transaction disclosures builds in time to provide the corrected disclosure to the Retirement Investor through a variety of means, including mailing.
In addition, to the extent compliance with the disclosure requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, the exemption provides that they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6))
The good faith provisions apply to the requirement that the Financial Institution retain the data and documentation supporting the disclosure during the time that it is applicable to the disclosure on the Web site and provide it to the Department upon request. In addition, if such records are lost or destroyed due to circumstances beyond the control of the Financial Institution, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and no party, other than the Financial Institution responsible for complying with subsection (b)(1)(vii) will be subject to the civil penalty that may be assessed under ERISA section 502(i) or the taxes imposed by Code section 4975(a) and (b), if applicable, if the records are not maintained or provided to the Department within the required timeframes.
In the proposed exemption, the Web site disclosure focused on the direct and indirect material compensation payable to the Adviser, Financial Institution and any Affiliate for services provided in connection with recommended investments available for purchase, holding or sale within the last 365 days, as well as the source of the compensation, and how the compensation varied within and among Assets. The proposal indicated that the compensation disclosure could be expressed as a monetary amount, formula or percentage of the assets involved in the purchase, sale or holding. Under the proposal, the Financial Institution's Web site was required to provide access to the information in a machine readable format.
The Department's intent in proposing the web disclosure was to provide broad transparency about the pricing and compensation structures adopted by Financial Institutions and Advisers. The Department contemplated that the data could be used by financial information companies to analyze and provide information comparing the practices of different Advisers and Financial Institutions. This information would allow Retirement Investors to evaluate and compare the practices of particular Advisers and Financial Institutions. A few commenters expressed support for the proposed web disclosure as an effort to increase transparency and use market forces to positively affect industry practices.
A number of other commenters viewed the proposed web disclosure as too costly, burdensome, and unlikely to be used by individual Retirement Investors, or expressed confidentiality and privacy concerns. In particular, commenters opposed disclosure of Adviser-level compensation. A few commenters misinterpreted the proposal to require disclosure of the precise total compensation amounts earned by each individual Adviser, and strongly opposed such disclosure. Other commenters took the position that the requirements of the proposed web disclosure would violate other legal or regulatory requirements applicable to advertising and antitrust law.
Other commenters expressed concerns about the logistics of the Web site. For example, they argued that the requirement that the Financial Institution describe compensation received in connection with each asset available for purchase, holding or sale within the past 365 days could require constant updating. Some commenters also raised questions about the meaning of the requirement that the data on the site be “machine readable,” although others expressed support for the requirement, which could have made the information more easily accessible to the public.
In the final exemption, the web disclosure requirement has been reworked as a more principles-based approach to avoid commenters' concerns. The Department accepted the suggestion of a commenter that the web disclosure should contain: A schedule of typical account or contract fees and service charges, and a list of product manufacturers with whom the Financial Institution maintains arrangements that provide payments to the Adviser and Financial Institution, including whether the arrangements impact Adviser compensation. Another commenter suggested that the Department require disclosure of the Financial Institution's business model and the Material Conflicts of Interest associated with the model. The commenter further suggested the Department should require disclosure of the Financial Institution's compensation practices with respect to Advisers, including payout grids and non-cash compensation and rewards. The Department has adopted these suggestions as well. However, with respect to the level of detail required, the Department has qualified the requirements of Section III(b) by giving the Financial Institution considerable flexibility on how best to present the information subject to the following principle: The Web site must “fairly disclose the scope, magnitude, and nature of the compensation arrangements and Material Conflicts of Interest in sufficient detail to permit visitors to the Web site to make an informed judgment about the significance of the compensation practices and Material Conflicts of Interest with respect to transactions recommended by the Financial Institution and its Advisers.”
The approach in the final exemption addresses many of the commenters' concerns about the burdens of the proposed web disclosure. To that end, the Department made the changes described above and also eliminated the proposed requirement that the information on the web be made available in machine readable format. However, the Department did not accept comments that suggested only general information be required on the web, or that no information on Adviser compensation arrangements should be provided. Certainly, the Financial Institution need not itemize or otherwise disclose the specific compensation it pays to an individual Adviser on its public Web site. However, the information on the Financial Institution's arrangements, including its compensation arrangements with Advisers, should be provided with enough specificity to inform users of the significance of these arrangements with respect to the transactions recommended by the Financial Institution and its Advisers. Consistent with the Department's initial goals, the web disclosure in the final exemption will create a mechanism for Retirement Investors and financial information companies to evaluate and compare compensation practices and Material Conflicts of Interests among different Financial Institutions and Advisers.
The final disclosure requirement responds to other comments as well. Permitting Financial Institutions to rely on other public disclosures, as set forth in Section III(b)(2), responds to several requests that the Department incorporate existing disclosures to ease the burden on the Financial Institutions. These commenters argued that the information required to be disclosed as part of the exemption may already be part of other existing disclosures, such as those provided pursuant to ERISA sections 404(a)(5) and 408(b)(2) and the SEC's required mutual fund summary prospectuses and Form ADV. The Department has accepted these comments insofar as the information required disclosed pursuant to other requirements also satisfies the conditions of the exemption, and so long as the Financial Institution provides an explanation that the information can be found in the
Other commenters were concerned that these Web sites would be considered advertising, and therefore become subject to additional requirements under other federal and state laws, or that disclosure of certain arrangements would violate antitrust laws. Section III(b)(3) of the exemption provides that the Financial Institution is not required to disclose information on the web if such disclosure is otherwise prohibited by law. However, this provision does not excuse a Financial Institution from seeking approval from a regulator under established procedures for such approval, such as for review of advertising material, if such procedures exist.
Commenters also raised antitrust concerns, specifically with regard to the information that the proposed exemptions required Financial Institutions to post on their Web site. The Department believes that the Web site disclosure requirements of the final exemption avoids these concerns by providing Financial Institutions considerable flexibility as to how the information is published on the Web site as long as the Financial Institutions compensation arrangements are described in sufficient detail to allow visitors to the Web site to make an informed judgment about the significance of compensation practice and Material Conflicts of Interest. Additionally, this exemption permits the Financial Institution to group disclosures based on reasonable-defined categories and to disclose reasonable range of values rather than specific numbers. The purpose of the information on the Web site is to allow investors to make informed decisions about their advisers, not to promote anticompetitive arrangements. Moreover, the exemption makes clear that Financial Institutions are not required to disclose information if such disclosure is otherwise prohibited by law.
A commenter also asked for clarification on the requirement that the Web site be “freely accessible to the public,” and whether a Web site that requires a visitor to create a user name and password to gain access would comply. The Department clarifies that such requirements are permissible assuming that they impose no additional constraints or conditions on free public access to the Web site, so that the site can serve its purpose of providing transparency in the marketplace, promoting competition, and facilitating the work of financial information companies to review and analyze such information. Another commenter cautioned that many small financial advisers do not maintain a Web site and this disclosure requirement would impose a significant burden on them. In the Department's view, however, the modest cost of maintaining a Web site is more than offset by the need to ensure that the information is freely and easily accessible to the general public, so that the disclosure can serve its competitive and protective purposes. Accordingly, the Department has decided to retain the requirement to provide disclosures through a Web site.
Finally, the correction procedure in Section III(c) addresses the risk to the Financial Institution, raised by commenters, that minor mistakes in the published disclosures could cause large numbers of transactions to become non-exempt prohibited transactions subject to excise tax and rescission.
Section IV of the exemption applies to Financial Institutions that restrict their Advisers' investment recommendations, in whole or in part, to investments that are Proprietary Products or that generate Third Party Payments. Section IV is intended to clarify that such Financial Institutions and Advisers may rely on the exemption. This responds to a number of comments asking the Department to provide certainty as to the treatment of Proprietary Products and limited menus.
Specifically, Section IV(a) of the final exemption provides that a Financial Institution that at the time of the transaction restricts its Advisers' investment recommendations, in whole or in part, to Proprietary Products or to investments that generate Third Party Payments, may rely on the exemption provided all of the applicable conditions are satisfied. Proprietary Products are defined in the exemption as products that are managed, issued or sponsored by the Financial Institution or any of its Affiliates. Third Party Payments are defined to include sales charges that are not paid directly by the plan, participant or beneficiary account, or IRA; gross dealer concessions; revenue sharing payments; 12b-1 fees; distribution, solicitation or referral fees; volume-based fees; fees for seminars and educational programs; and any other compensation, consideration or financial benefit provided to the Financial Institution or an Affiliate or Related Entity by a third party as a result of a transaction involving a plan, participant or beneficiary account, or IRA.
Section IV(b) describes how a Financial Institution that limits its Advisers' investment recommendations, in whole or part, based on whether the investments are Proprietary Products or generate Third Party Payments, and an Adviser making recommendations subject to such limitations, will be deemed to satisfy the Best Interest standard. Some, but not all, of the conditions are already applicable to Financial Institutions and Advisers under other provisions of the exemption. Nevertheless, the text sets out each condition in detail rather than by reference so that the section provides a clear statement in one place of the components of the Best Interest standard for such Financial Institutions and Advisers.
Section IV does contain additional conditions for such Financial Institutions, however. In particular, as described in greater detail below, under Section IV(b)(3), Financial Institutions must document the limitations they place on their Advisers' investment recommendations, the Material Conflicts of Interest associated with proprietary or third party arrangements, and the services that will be provided both to Retirement Investors as well as third parties in exchange for payments. Such Financial Institutions must then reasonably conclude that the limitations will not cause the Financial Institution or its Advisers to receive compensation in excess of reasonable compensation, and, after consideration of their policies and procedures, reasonably determine that the limitations and associated conflicts of interest will not cause the Financial Institution or its Advisers to recommend imprudent investments. Financial Institutions must document the bases for their conclusions in these respects and retain the documentation pursuant to the recordkeeping requirements in Section V of the exemption, for examination upon request by the Department and other parties set forth in that section.
The condition in Section IV(b)(3) reflects the Departments' deep and continuing concern regarding the Financial Institutions' own conflicts of interest in limiting products available for investment recommendations. The purpose of Section IV(b)(3) is to require Financial Institutions to carefully consider their business models and form a reasonable conclusion about the impact of conflicts of interest associated with these particular limitations on Advisers' advice. The exemption will be available only if the Financial Institution reasonably concludes that these limitations, in conjunction with the anti-conflict policies and
Specifically, under Section IV(b) such Financial Institutions and Advisers shall be deemed to satisfy the Best Interest standard of Section VIII(d) if:
(1) Prior to or at the same time as the execution of a transaction based on the advice, the Retirement Investor is clearly and prominently informed in writing that the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to the purchase, sale, exchange, or holding of recommended investments; and the Retirement Investor is informed in writing of the limitations placed on the universe of investments that the Adviser may recommend to the Retirement Investor. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis;
(2) Prior to or at the same time as the execution of a recommended transaction, the Retirement Investor is fully and fairly informed in writing of any Material Conflicts of Interest that the Financial Institution or Adviser have with respect to the recommended transaction, and the Adviser and Financial Institution comply with the disclosure requirements set forth in Section III (providing for web and transaction-based disclosure of costs, fees, compensation, and Material Conflicts of Interest);
(3) The Financial Institution documents in writing its limitations on the universe of recommended investments; documents in writing the Material Conflicts of Interest associated with any contract, agreement, or arrangement providing for its receipt of Third Party Payments or associated with the sale or promotion of Proprietary Products; documents any services it will provide to Retirement Investors in exchange for the Third Party Payments, as well as any services or consideration it will furnish to any other party, including the payor, in exchange for Third Party Payments; reasonably concludes that the limitations on the universe of recommended investments and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to receive compensation in excess of reasonable compensation for Retirement Investors as set forth in Section II(c)(2); reasonably determines, after consideration of the policies and procedures established pursuant to Section II(d), that these limitations and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to recommend imprudent investments; and documents the bases for its conclusions;
(4) The Financial Institution adopts, monitors, implements, and adheres to policies and procedures and incentive practices that meet the terms of Section II(d)(1) and (2); and, in accordance with Section II(d)(3), neither the Financial Institution nor (to the best of its knowledge) any Affiliate or Related Entity uses or relies upon quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause the Adviser to make imprudent investment recommendations, to subordinate the interests of the Retirement Investor to the Adviser's own interests, or to make recommendations based on the Adviser's considerations of factors or interests other than the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor;
(5) At the time of the recommendation, the amount of compensation and other consideration reasonably anticipated to be paid, directly or indirectly, to the Adviser, Financial Institution, or their Affiliates or Related Entities for their services in connection with the recommended transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and
(6) The Adviser's recommendation with respect to the transaction reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor; and the Adviser's recommendation is not based on the financial or other interests of the Adviser or on the Adviser's consideration of any factors or interests other than the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor.
The purpose of Section IV, as proposed, was to establish conditions that help ensure that the particular conflicts of interest associated with proprietary business models or the receipt of Third Party Payments did not undermine Advisers' ability to provide advice in Retirement Investors' Best Interest.
Some commenters on Section IV of the proposed exemption focused in large part on the structure of the section. In the proposal, Section IV(a) provided a general requirement that the Financial Institution offer a “range of Assets that is broad enough to enable the Adviser to make recommendations with respect to all of the asset classes reasonably necessary to serve the Best Interests of the Retirement Investor in light of its investment objectives, risk tolerance, and specific financial circumstances.” Section IV(b) then provided specific conditions for Financial Institutions that could not satisfy Section IV(a).
Commenters expressed uncertainty as to the meaning of proposed Section IV(a). They requested clarity on the terms “asset classes” and “range of Assets.” Some pointed out that all Financial Institutions limit their products in some ways, and so it may be that no Financial Institution would be able to satisfy Section IV(a). A few commenters described this requirement as a penalty for certain investment specialists who offer only a limited set of investments. Particular concerns were raised by insurance companies, many of which sell Proprietary Products.
Several commenters were concerned that Section IV would prohibit advice relating to Proprietary Products. Some commenters requested that Section IV be replaced with a disclosure requirement, so that any Financial Institution which disclosed its Proprietary Products could provide advice relating to those products without satisfying the other conditions of the exemption. Some commenters raised specific concerns about insurance products and fraternal organizations, and whether they would be able to continue to sell their Proprietary Products.
In response to all of these comments, the Department has revised Section IV(a) to clarify that Financial Institutions may limit the products their Advisers offer to Proprietary Products and those that generate Third Party Payments. The Department has revised Section IV(b) to clarify
In response to a commenter that indicated that the proprietary status of products can change over time, the Department notes that the conditions of Section IV must be satisfied at the time of the transaction with the Retirement
The sections below discuss the conditions of Section IV and the comments that the Department received on the proposal, including (a) the general conditions, (b) the written findings, (c) the reasonable compensation condition, and (d) the notification condition.
Section IV responds to concerns expressed by Financial Institutions that limit Advisers' recommendations to Proprietary Products or to products that generate Third Party Payments, as to whether they could ever be said to act “without regard to” their own interests, as required by the general definition of “Best Interest.” This section makes clear that such Financial Institutions can satisfy the standard, provided that the recommendation is prudent, the fees reasonable, the conflicts disclosed (so that the customer can fairly be said to have knowingly assented to them) and the conflicts managed through stringent policies and procedures that keep the Adviser's focus on the customer's Best Interest.
Commenters on this issue expressed significant concern about their ability to recommend Proprietary Products under the exemption. They asked for assurance that the “without regard to” language would not effectively prohibit advice regarding Proprietary Products because of an implication that the Financial Institution could not have any interest in the transaction. As a result, the commenters feared that the exemption effectively foreclosed proprietary investment providers from receiving compensation under the exemption.
As noted above, Section IV has been crafted to provide a specific definition of Best Interest applicable to Financial Institutions and Advisers that recommend investments from a restricted menu that includes Proprietary Products or investments that generate Third Party Payments, while protecting Retirement Investors from the harmful impact of conflicts of interest. A number of the conditions of this specific definition are already required elsewhere in the exemption, and should not impose any special or additional burden beyond what is required of all Advisers and Financial Institutions subject to the exemption. Thus, Section IV(b)(1) requires that, prior to or at the same time as the execution of a recommended transaction, the Financial Institution provide notice to the Retirement Investor that it offers Proprietary Products or receives Third Party Payments, and inform the Retirement Investor of the limitations placed on the universe of investments available for Advisers to recommend, in accordance with the required contractual disclosure in Section II(e)(5). The notice to the Retirement Investor regarding Proprietary Products must inform the Retirement Investor that a Proprietary Product is a product managed, issued or sponsored by the Financial Institution and that the Adviser or Financial Institution may have a greater conflict of interest when recommending Proprietary Products due to the benefit to the Financial Institution.
Section IV(b)(2) requires that, prior to or at the same time as the execution of the recommended transaction, the Retirement Investor be informed of Material Conflicts of Interest with respect to the recommended transaction, in accordance with the requirements of Section III. Section IV(b)(4) generally requires that the Financial Institution adopt, implements and adhere to policies and procedures that meet the terms of Section II(d). When Advisers make recommendations from a restricted menu, the Financial Institution may not incentivize Advisers to preferentially recommend those products on the menu that are most lucrative to the Financial Institution.
Section IV(b)(6) places a requirement on the Adviser to recommend investments that are prudent. In addition, when making recommendations from the universe of investments offered by the Financial Institution, the Adviser's recommendations may not be based on the financial or other interests of the Adviser or on the Adviser's consideration of any factors or interests other than the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor. This is an articulation of the Adviser's Best Interest obligation in the context of Proprietary Products or investments that generate Third Party Payments.
In addition to the sections described above, Section IV(b)(3) retains a requirement of a written finding regarding the effect of these arrangements on advice to Retirement Investors. Some commenters on the proposal objected to a similar provision in proposed Section IV(b)(1) that a Financial Institution which offered a limited range of investment options make a specific written finding that the limitations it has placed would not prevent the Adviser from providing advice that is the Best Interest of the Retirement Investor or otherwise adhering to the Impartial Conduct Standards. A few commenters questioned whether the written finding, as proposed, had to be made with respect to each Retirement Investor individually. A number of commenters more generally objected to the requirement as overly burdensome and of questionable protective value to Retirement Investors.
After consideration of the comments, the Department has restated the condition in Section IV(b)(3) and included specific documentation requirements. The written documentation required in this condition is not individualized and does not have to be provided to Retirement Investors, addressing commenters' concerns that the written finding might have to be made on an individual Retirement Investor basis. But the Department remains convinced of the importance of ensuring that the Financial Institution safeguard against conflicts in the manner proposed. While other provisions of the definition and the exemption create strong limitations on conflicted conduct by individual Advisers, this condition focuses specifically on firm-level conflicts, and for that reason is important to protecting Retirement Investors from harm. As revised, the exemption now imposes the following condition:
(3) The Financial Institution documents in writing its limitations on the universe of recommended investments; documents in writing the Material Conflicts of Interest associated with any contract, agreement, or arrangement providing for its receipt of Third Party Payments or associated with the sale or promotion of Proprietary Products; documents any services it will provide to Retirement Investors in exchange for Third Party Payments, as well as any services or consideration it will furnish to any other party, including the payor, in exchange for Third Party Payments; reasonably concludes that the limitations on the universe of recommended investments and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to receive compensation in excess of reasonable compensation for Retirement Investors as set forth in Section II(c)(2); reasonably determines, after consideration of the policies and procedures established pursuant to Section II(d), that these limitations and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to recommend imprudent investments; and documents the bases for its conclusions;
The purpose of this requirement is to ensure that the Financial Institution reasonably safeguards Retirement Investors from dangerous conflicts of
These requirements of Section IV(b)(3), together with the disclosure and other requirements of Section IV(b) and the rest of the exemption, were carefully crafted to protect the interests of Retirement Investors. The Department has made the requirements more specific in response to comments, but it declines requests to provide greater exemptive relief to Financial Institutions that make conflicted recommendations of Proprietary Products or investments that generate Third Party Payments. In such cases, it is particularly important that conflicts of interest be carefully addressed at the level of the Financial Institution, not just at the level of the Adviser. Section IV(b)(3) adds clarity and substance to the Financial Institutions' important obligations to their Retirement Investor customers.
Section IV(b)(5) retains a reasonable compensation requirement for Financial Institutions that fall within the parameters of Section IV. The proposal had departed, in some respects, from the formulation of the reasonable compensation standard under ERISA section 408(b)(2) and in Section II(c)(2) of the exemption. In particular, rather than looking at the reasonableness of the aggregate compensation for all of the services to the Retirement Investor, the test required that each instance of compensation be reasonable in relation to the fair market value of the specific service that generated the compensation. The Department's intent in this regard was to ensure that any additional payments, such as Third Party Payments, received in connection with advice, where advice is limited to certain products, were tied to specific services of equivalent value.
Some commenters questioned the need for a special reasonable compensation standard in this context. In particular, they complained that it would be difficult to comply with the test, or to match up particular payments with particular investors. A commenter explained that some investors may pay slightly more due to the funds they select while others may pay slightly less even though the services are basically the same. In addition, higher net-worth clients with larger account balances subsidize those with more modest lower account balances, according to the commenter. Another commenter described the requirement as a departure from prior Department guidance, which focused on the reasonableness of compensation in the aggregate, and did not require that each stream of compensation be determined to be reasonable in relation to the specific services provided.
After considering the comments, the Department has decided to use the same reasonable compensation standard throughout the exemption as set forth in Section II(c)(2), rather than a special standard for Financial Institutions making recommendations from a limited menu. Accordingly, Section IV(b)(5) now states the following condition:
At the time of the recommendation, the amount of compensation and other consideration reasonably anticipated to be paid, directly or indirectly, to the Adviser, Financial Institution, or their Affiliates or Related Entities for their services in connection with the recommended transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2);
This condition, used throughout the exemption, applies the familiar reasonable compensation standard applicable to service providers (fiduciary or non-fiduciary) under ERISA and the Code. Although the standard is a fair market standard, there is no requirement to allocate specific compensation to specific services.
The Department stresses the importance of Financial Institutions' obligations in this regard, particularly when limiting their recommendations to Proprietary Products or products that generate Third Party Payments. In such cases, the Financial Institution's conflicts of interest are acute, and the additional compensation generated by their recommendations often are not transparent to the Retirement Investor. Accordingly, Financial Institutions should give special care to meeting their obligations under Section IV(b)(3) to reasonably conclude that the limitations and conflicts of interest associated with Proprietary Products and Third Party Payments will not cause the Financial Institution or its Advisers to receive compensation in excess of reasonable compensation, and to document the bases for their findings.
Section IV(b)(4) of the proposal contained a provision requiring the Adviser to notify the Retirement Investor if the Adviser does not recommend a sufficiently broad range of Assets to meet the Retirement Investor's needs. Some commenters requested that the Department clarify the purpose of the notice, in part to confirm that it is not punitive. Others asked about the specifics of the wording of the notice and whether it could be phrased to emphasize what is offered instead of what is not. A commenter also suggested it was unnecessary in light of some of the initial disclosures regarding the limitations placed on recommendations.
As explained above, Section IV was re-worked in the final exemption to clarify that Financial Institutions and Advisers may limit the products they offer to Proprietary Products and those that generate Third Party Payments and to specify
Section V of the exemption establishes record retention and disclosure conditions that a Financial Institution must satisfy for the
Before receiving compensation in reliance on the exemption, the Financial Institution must notify the Employee Benefits Security Administration (EBSA) of the Department of Labor of its intention to rely on the exemption. The notice will remain in effect until revoked in writing by the Financial Institution. The notice need not identify any plan or IRA.
The Department received several requests to delete the EBSA notice requirement. One commenter complained this would be a “foot fault” for Financial Institutions trying to comply, placing a burden on the Financial Institutions without adding significant protections for the Retirement Investors. According to the comment, the EBSA notice would not be useful for Retirement Investors or the Department because almost all Financial Institutions would make the one-time filing. The commenter also raised questions about the logistics of the notice; whether each separate legal entity would be required to file the notice and if Financial Institutions would be required to amend their notices when restructuring operations.
The Department has retained the notice requirement in the final exemption. The EBSA notice, while imposing a minimal obligation on the Financial Institution, serves a valuable function by enabling the Department to determine which and which type of Financial Institutions intend to rely on the exemption, and by facilitating the Department's audit and compliance assistance programs. These efforts promote compliance with the exemption's terms and redound to the benefit of Retirement Investors. The Department has kept the notice requirement simple to avoid placing an undue burden on Financial Institutions, but it confirms that each Financial Institution relying on the exemption must file the notice, and, if operations are restructured and a new legal entity becomes the Financial Institution, the new entity must file prior to reliance on the exemption.
The Department has clarified the manner of service in response to comments. The notice must be provided by email to the Department of Labor, Employee Benefits Security Administration, Office of Exemption Determinations at
The same commenter also suggested that the notices be provided to the Employee Benefits Security Administration, Office of Enforcement, to allow the Department's investigators to target those Financial Institutions for compliance evaluations. The Department has rejected this comment, however, because the notice serves broader purposes than just enforcement, and the information will be readily available to EBSA's Office of Enforcement regardless of the initial recipient of the information within EBSA.
Other commenters suggested the Department share the information more broadly. One commenter requested that the Department create a mechanism to share the notices with other regulators, including the states, the SEC and FINRA to promote investor protection. Another suggested a publicly accessible registry where filings could be electronically verified and viewed. In addition to providing increased transparency, this would also provide a way for Financial Institutions to confirm that their notification has been received. The Department has declined to accept these comments. This is a notice provision only and the Department does not intend to require any approval or finding by the Department that the Financial Institution is eligible for the exemption. As in the proposal, once a Financial Institution has sent the notice, it can immediately begin to rely on the exemption, provided the conditions are satisfied. However, the Department notes that Financial Institutions should retain documentation of having provided the notification in accordance with Section V(b) discussed below.
One commenter requested a change in the timing of the notification, so that it would be required at the time an investment advice program is implemented, rather than before implementation. The Department has not made this change in the text, but notes that the notification need not be provided significantly in advance of any recommendations and that it is effective upon sending. Therefore, a Financial Institution could send the Department its notice immediately prior to receiving compensation in reliance on the Best Interest Contract Exemption and this condition would be satisfied.
Section V(b) of the proposal would have required the Financial Institution to collect and maintain data relating to inflows, outflows, holdings, and returns for retirement investments for six years from the date of the applicable transactions and to provide that data to the Department upon request within six months. The Department reserved the right to publicly disclose the information provided on an aggregated basis, although it made clear it would not disclose any individually identifiable financial information regarding Retirement Investor accounts.
The Department eliminated the data request in its entirety in response to comments. While the Department received some comments supporting the requirement, a large number of commenters requested elimination of the requirement. Commenters expressed concerned about the burden and costs of maintaining the necessary materials and responding to the Department within the timeframe. They also raised concerns about coordinating with other regulatory requirements, as well as privacy and security, including trade secrets, especially in light of the provision that would potentially have allowed the Department to make portfolio returns and other information public. One commenter asserted that the provision may violate federal banking law. Still other commenters raised questions regarding the purpose and necessity of the requirement, and the consequences of failure to comply.
While the proposed data collection requirement was not adopted as part of the final exemption, the separate proposed general recordkeeping requirement was adopted, with some modifications, as Section V(b) and (c). The requirement to maintain the records necessary to determine compliance with the exemption both encourages thoughtful compliance and provides an important means for the Department and Retirement Investors to assess whether Financial Institutions and their Advisers are, in fact, complying with the exemption's conditions and fiduciary standards. Although the requirement does not lend itself to the same sorts of statistical and quantitative analyses that would have been promoted by the data collection requirement, it too assists the Department and Retirement Investors in evaluating compliance with the exemption, but at substantially less cost.
Under Section V(b) and (c) of the exemption, the Financial Institution
Some commenters objected that these proposed recordkeeping requirements were too burdensome, and expressed concern about required disclosure of trade secrets. One commenter indicated that the exemption should not allow parties such as plan fiduciaries, participants, beneficiaries and IRA owners, to obtain information about a transaction involving another plan or IRA. Another raised concerns that the Department's right to review a bank's records could conflict with federal banking laws that prohibit agencies other than the Office of the Comptroller of the Currency (OCC) from exercising “visitorial” powers over national banks and federal savings associations. The commenter asserted that such visitorial powers, governed by 12 U.S.C. 484, include the power of a regulator to inspect, examine, supervise, and regulate the affairs of an entity.
After consideration of the comments, the Department has modified the recordkeeping provision in the following ways. The Department has clarified which parties may view the records that are maintained by the Financial Institution. Plan fiduciaries, participants, beneficiaries, contributing employers, employee organizations with members covered by the plan, and IRA owners are not authorized to examine records regarding a recommended transaction involving another Retirement Investor. Financial Institutions are not required to disclose privileged trade secrets or privileged commercial or financial information to any of the parties other than the Department, as was also true of the proposal. Financial Institutions are also not required to disclose records if such disclosure would be precluded by 12 U.S.C. 484. As revised, the exemption requires the records be “reasonably” available, rather than “unconditionally” available.
The recordkeeping provision in the exemption is necessary to demonstrate compliance with the terms of the exemption and therefore should represent prudent business practices in any event. The Department notes that similar language is used in many other exemptions and has been the Department's standard recordkeeping requirement for exemptions for some time.
Although Section I(b) broadly permits the receipt of compensation resulting from investment advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B) to a Retirement Investor, the exemption is subject to some specific exclusions, as discussed below.
Section I(c)(1) provides that the exemption does not apply to the receipt of compensation from a transaction involving an ERISA plan if the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the plan. Industry commenters requested elimination of this exclusion. In particular, they said that Financial Institutions in the business of providing investment advice should not be compelled to hire a competitor to provide services to the Financial Institution's own plan. They warned that the exclusion could effectively prevent these Financial Institutions from providing any investment advice to their employees. Some commenters additionally stated that for compliance reasons, employees of a Financial Institution are often required to maintain their financial assets with that firm. As a result, they argued employees of Financial Institutions could be denied access to investment advice on their retirement savings.
In general, the Department has not scaled back the exclusion. The Department continues to be concerned that the danger of abuse is compounded when the advice recipient receives recommendations from the employer, upon whom he or she depends for a job, to make investments in which the employer has a financial interest. To protect employees from abuse, employers generally should not be in a position to use their employees' retirement benefits as potential revenue or profit sources, without stringent safeguards. See,
In accordance with this condition, the exemption is not available for compensation received in a rollover from such a plan to an IRA, where the compensation is derived from transactions involving the plan, not the IRA. Additionally, the exclusion in Section I(c) does not apply in the case of an IRA or other similar plan that is not covered by Title I of ERISA. The decision to open an IRA account or obtain IRA services from the employer is much more likely to be entirely voluntary on the employees' part than would be true of their interactions with the retirement plan sponsored and designed by their employer for its employee benefit program. Accordingly, an Adviser or Financial Institution may provide advice to the beneficial owner of an IRA who is employed by the Adviser, its Financial Institution or an Affiliate, and receive prohibited compensation as a result, provided the IRA is not covered by Title I of ERISA, and the conditions of this exemption are satisfied.
Section I(c)(1) further provides that the exemption is unavailable if the Adviser or Financial Institution is a named fiduciary or plan administrator, as defined in ERISA section 3(16)(A)) with respect to an ERISA plan, or an affiliate thereof, that was selected to provide advice to the plan by a fiduciary who is not independent of them. This provision is intended to disallow the selection of Advisers and Financial Institutions by named fiduciaries or plan administrators that have a significant financial stake in the selection and was adopted in the final exemption unchanged from the proposal.
Section I(c)(2) excludes compensation earned in “principal transactions” from the scope of the exemption. In a “principal transaction,” the Financial Institution engages in a purchase or sale transaction with a Retirement Investor for the Financial Institution's own account (or for the account of a person directly or indirectly, through one or more intermediaries, controlling,
In the proposal for this Best Interest Contract Exemption, the Department stated that principal transactions would be excluded from the relief provided, but did not define the term “principal transaction.” The Department received several requests for clarification of the term, particularly with respect to recommendations of proprietary insurance products. After considering the comments, the Department defined “principal transaction” to clarify that purchases and sales of insurance and annuity contracts will not be treated as principal transactions.
Other commenters asked about the treatment of unit investment trusts (UITs). UITs are generally traded on a principal basis, according to commenters, but are sold in ways that are similar to mutual funds sales. Commenters noted that in the proposal, the Department specifically indicated that mutual fund transactions were not treated as excluded principal transactions because they are traded on a riskless principal basis. Commenters asked for confirmation that UITs would receive the same treatment. The Department concurs that to the extent UITs are sold in riskless principal transactions, they can be recommended under this exemption. They are also included within the types of investments that can be recommended under the Principal Transactions Exemption.
Section I(c)(3) generally provides that the exemption does not cover compensation that is received as a result of investment advice generated solely by an interactive Web site in which computer software-based models or applications provide investment advice to Retirement Investors based on personal information the investor supplies through the Web site without any personal interaction or advice from an individual Adviser. Such computer derived advice is often referred to as “robo-advice.” A statutory prohibited transaction exemption at ERISA section 408(b)(14) covers computer-generated investment advice and is available for robo-advice involving prohibited transactions if its conditions are satisfied.
The exclusion does not apply, however, to robo-advice providers that are Level Fee Fiduciaries. Such providers may rely on the exemption with respect to investment advice to engage the robo-advice provider for advisory or investment management services with respect to the Plan or IRA assets, provided they comply with the conditions applicable to Level Fee Fiduciaries.
The Department received several requests to include robo-advice in this exemption or provide a separate streamlined exemption for robo-advice. Commenters argued that all advice should be treated the same, regardless of whether it is provided through a computer or through a human Adviser. Some commenters thought that by excluding robo-advice from the exemption, the Department was limiting options for Retirement Investors. In addition, some commenters stated that robo-advice can be difficult to define, and many Financial Institutions and Advisers may use hybrid programs that rely on both computer software-based models and personal advice. One commenter was concerned that excluding robo-advice from the exemption could leave Retirement Investors who rely on robo-advice without any legal remedy, and may force more Retirement Investors to rely on an untested alternative.
The Department is of the view that the marketplace for robo-advice is still evolving in ways that both appear to avoid conflicts of interest that would violate the prohibited transaction rules and minimize cost. Therefore, the Department included robo-advice in the exemption only if the advice is provided by a Level Fee Fiduciary to enter into the arrangement for robo-advice, including by means of a rollover from an ERISA plan to an IRA, and if the conditions applicable to Level Fee Fiduciaries are satisfied. Accordingly, the fiduciary and its Affiliates must receive only a Level Fee, as defined in the exemption. In addition, the Department notes that hybrid programs in which the Adviser relies upon or works in tandem with such interactive materials are not excluded under the language of Section I(c)(3), regardless if they utilize a level fee arrangement. However, the Department determined against providing relief for robo-advice providers acting purely through the web to receive non-level compensation after being retained by the Retirement Investor. Including such relief in this exemption could adversely affect the incentives currently shaping the market for robo-advice.
The Department further notes that to the extent robo-advice is not covered under exemption, it does not mean that Retirement Investors have no protections with respect to their interactions with such advice providers; to the contrary, it means that the robo-advice providers that are fiduciaries under the Regulation must provide advice under circumstances that do not constitute a prohibited transaction, or rely on another exemption, including ERISA section 408(g).
Finally, Section I(c)(4) provides that the exemption is not available if the Adviser has or exercises any discretionary authority or discretionary control with respect to the recommended transaction. This has been revised from the proposal in response to comments. Under the proposal, relief would not have been available if an Adviser exercised discretionary authority or control respecting management of the plan or IRA assets involved in the transaction, exercised any authority or control respecting management or disposition of the assets, or had any discretionary authority or responsibility in the administration of the Plan or IRA. Commenters expressed concern that the exclusion was too broad. For example, some commenters asserted that it could be read to exclude an Adviser who had no discretionary or authority with respect to the assets at the time of the transaction, but subsequently acquired such control (
Commenters additionally requested that the exemption apply to discretionary asset management, as well as advice, so that Financial Institutions offering both discretionary and non-discretionary services could comply with the same set of rules. The commenters stated that, as part of this regulatory package, there were proposed amendments that would change some prohibited transaction class exemptions previously relied on by discretionary managers.
The Department has considered these comments but has determined not to broaden the exemption to include relief for fiduciaries with investment discretion over the recommended transactions. These fiduciaries are currently subject to a robust regulatory regime, developed over decades, which specifically addresses the issues raised
Commenters requested that the exemption continue to apply in the event of a Financial Institution's or Adviser's good faith failure to comply with one or more of the conditions. In the commenters' views, the exemption was sufficiently complex and the implementation timeline sufficiently short to justify such a provision. For example, FINRA suggested that the Department include a provision for continued application of the exemption despite a failure to comply with “any term, condition or requirement of this exemption . . . if the failure to comply was insignificant and a good faith and reasonable attempt was made to comply with all applicable terms, conditions and requirements.” Several commenters specifically supported FINRA's suggestion.
There were other specific suggestions regarding good faith compliance. For example, one commenter suggested that there be a provision to bar litigation concerning “de minimis” claims, including accounts of $5,000 or less, if the Adviser and Financial Institution acted in good faith. Another suggested the Department adopt a “Compliance Program Safe Harbor,” which would provide a safe harbor from litigation if the Financial Institution adopted and implemented a compliance program. The suggested compliance program included, among other features, diligence, training, oversight, annual certification of the compliance program by the Chief Compliance Officer of the Financial Institution or a Related Entity, and an annual audit (by internal or external auditors) of the operation of the compliance program. Other commenters were less specific. One suggested a “principles-based approach” to the penalties and corrections to match the principles-based approach to the conditions. Several other commenters pointed to other good faith compliance provisions in the Department's regulations under ERISA sections 404 and 408(b)(2).
The Department has reviewed the exemption's requirements with these comments in mind and has included a good faith correction mechanism for the disclosure requirements in Section II(e) and Section III. These provisions take a similar approach to the provisions in the Department's regulations under ERISA sections 404 and 408(b)(2). In addition, as discussed above, the Department has eliminated a condition requiring compliance with other federal and state laws, which many commenters had argued could expose them to loss of the exemption based on small or technical violations. The Department has also facilitated compliance by streamlining the contracting process (and eliminating the contract requirement for ERISA plans), reducing the disclosure burden, expanding the scope of the grandfather provision, and extending the time for compliance with many of the exemption's conditions. These and other changes should reduce the need for a self-correction process for excusing violations.
The Department declines to permanently adopt a broader unilateral good faith provision for Financial Institutions and their Advisers because it could undermine fiduciaries' long-run incentive to comply with the fundamental standards imposed by the exemption. The exemption's primary purpose is to combat harmful conflict of interest. If the exemption is too forgiving of abusive conduct, however, it runs the risk of permitting those same conflicts of interest to play a role in the design of policies and procedures, the use and oversight of adviser-incentives, the supervision of Adviser conduct, and the substance of investment recommendations. At the very least, it could encourage Financial Institutions and Advisers to resolve doubts on such questions in favor of their own financial interests rather than the interests of the Retirement Investor. Given the dangers posed by conflicts, the Department has deliberately structured this exemption to provide a strong counter-incentive to such conduct.
Additionally, many of the exemption's standards, such as the Best Interest standard and the reasonable compensation standard, already have a built-in reasonableness or prudence standard governing compliance. It would be inappropriate, in the Department's view, to create a self-correction mechanism for conduct that was imprudent or unreasonable. For example, the Best Interest standard requires that the Adviser and Financial Institution providing the advice act with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party. Similarly, the policies and procedures requirement under Section II(d) turns to a significant degree on adherence to standards of prudence and reasonableness. Thus, under Section II(d)(1), the Financial Institution is required to adopt and comply with written policies and procedures
The considerations above apply to large and small investor accounts alike. The Department does not intend for Financial Institutions be less sensitive or careful about adherence to fiduciary norms with respect to small investors, and declines the suggestion that it adopt a special provision to bar litigation for “de minimis” claims. Additionally, the provision allowing mandatory arbitration of individual claims is also responsive to the practicalities of resolving disputes over small claims. The Department also stresses that violations of the exemption's conditions with respect to a particular Retirement Investor or transaction, eliminates the availability of the exemption for that investor or transaction. Such violations do not render the exemption unavailable with respect to other Retirement Investors or other transactions.
The Department received a number of comments questioning the Department's jurisdiction and legal authority to proceed with the proposal. A number of commenters focused on the Department's authority to impose
Some commenters asserted that by requiring a contract for all Retirement Investors, and thereby facilitating contract claims by such parties, the proposal would expand upon the remedies established by Congress under ERISA and the Code. Commenters stated that ERISA preempts state law actions, including breach-of-contract actions. With respect to IRAs and non-ERISA plans, commenters stated that Congress provided that the enforcement of the prohibited transaction rules should be carried out by the Internal Revenue Service, not private plaintiffs. These commenters argued that the Department's proposal would impermissibly create a private right of action in violation of Congressional intent.
Commenters' arguments regarding the Impartial Conduct Standards were based generally on the fact that the standards, as noted above, are consistent with longstanding principles of prudence and loyalty set forth in ERISA section 404, but which have no counterpart in the Code. Commenters took the position that because Congress did not choose to impose the standards of prudence and loyalty on fiduciaries with respect to IRAs and non-ERISA plans, the Department exceeded its authority in proposing similar standards as a condition of relief in a prohibited transaction exemption.
With respect to ERISA plans, commenters stated that Congress' separation of the duties of prudence and loyalty (in ERISA section 404) from the prohibited transaction provisions (in ERISA section 406), showed an intent that the two should remain separate. Commenters additionally questioned why the conduct standards were necessary for ERISA plans, when such plans already have an enforceable right to fiduciary conduct that is both prudent and loyal. Commenters asserted that imposing the Impartial Conduct Standards as conditions of the exemption improperly created strict liability for prudence violations.
Some commenters additionally took the position that Congress, in the Dodd-Frank Act, gave the SEC the authority to establish standards for broker-dealers and investment advisers and therefore, the Department did not have the authority to act in that area.
The Department disagrees that the exemption exceeds its authority. The Department has clear authority under ERISA section 408(a) and the Reorganization Plan
In addition, this exemption does not create a cause of action for plan fiduciaries, participants or IRA owners to directly enforce the prohibited transaction provisions of ERISA and the Code in a federal or state-law contract action. Instead, with respect to ERISA plans and participants and beneficiaries, the exemption facilitates the existing statutory enforcement framework by requiring Financial Institutions to acknowledge in writing their fiduciary status and the fiduciary status of their Advisers. With respect to IRAs and non-ERISA plans, the exemption requires Advisers and Financial Institutions to make certain enforceable commitments to the advice recipient. Violation of the commitments can result in contractual liability to the Adviser and Financial Institution separate and apart from the legal consequences of a non-exempt prohibited transaction (
There is nothing new about a prohibited transaction exemption requiring certain written documentation between the parties. The Department's widely-used exemption for Qualified Professional Asset Managers (QPAM), requires that an entity acting as a QPAM acknowledge in a written management agreement that it is a fiduciary with respect to each plan that has retained it.
Likewise, the Impartial Conduct Standards represent, in the Department's view, baseline standards of fundamental fair dealing that must be present when fiduciaries make conflicted investment recommendations to Retirement Investors. After careful consideration, the Department determined that broad relief should be provided to investment advice fiduciaries receiving conflicted compensation only if such fiduciaries provided advice in accordance with the Impartial Conduct Standards—
The Department similarly disagrees that Congress' directive to the SEC in the Dodd-Frank Act limits its authority to establish appropriate and protective conditions in the context of a prohibited transaction exemption. Section 913 of that Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers.
Additionally, the Department notes that nothing in ERISA or the Code requires any Adviser or Financial Institution to use this exemption. Exemptions, including this class exemption, simply provide a means to engage in a transaction otherwise prohibited by the statutes. The conditions to an exemption are not equivalent to a regulatory mandate that conflicts with or changes the statutory remedial scheme. If Advisers or Financial Institutions do not want to be subject to contract claims, they can (1) change their compensation structure and avoid committing a prohibited transaction, (2) use the statutory exemptions in ERISA section 408(b)(14) and section 408(g), or Code section 4975(d)(17) and (f)(8), or (3) apply to the Department for individual exemptions tailored to their particular situations.
A number of commenters suggested complete alternatives to the approach taken in the proposed exemption. As an initial matter, some suggestions were aimed at streamlining and simplifying the exemption to reduce compliance burdens. The Department reviewed the exemption with these comments in mind and has made changes to reduce complexity and compliance burden without sacrificing significant protections. For example, the Department eliminated the proposed contract requirement for advice to Retirement Investors regarding investments in ERISA plans, adopted a less burdensome approach to disclosure, and eliminated the proposed annual disclosure and the proposed data collection requirement.
For all the reasons set forth in the preceding sections, however, the Department remains convinced of the critical importance of the core requirements of the exemption, including an up-front commitment to act as a fiduciary; enforceable adherence to the Impartial Conduct Standards; the adoption of policies and procedures to reasonably assure compliance with the Impartial Conduct Standards; a prohibition on incentives to violate the Best Interest Standard; and fair disclosure of fees, conflicts of interest, and Material Conflicts of Interest. The Impartial Conduct Standards simply require adherence to basic fiduciary norms and standards of fair dealing—rendering prudent and loyal advice that is in the best interest of the customer, receiving no more than reasonable compensation, and refraining from making misleading statements. These fundamental standards enable the Department to grant an exemption that flexibly covers a broad range of compensation structures and business models, while safeguarding the interest of Retirement Investors against dangerous conflicts of interest. The conditions were critical to the Secretary of Labor's ability to make the required findings under ERISA section 408(a) and Code section 4975(c)(2) that the exemption is in the interests of plans, their participants and beneficiaries, and IRAs, that the exemption is protective of their interests, and that the exemption is administratively feasible.
Some commenters suggested alternative approaches that included a standard characterized as a “best interest” standard of conduct, combined with certain of the other safeguards that the Department had proposed, including reasonable compensation, disclosures, or anti-conflict policies and procedures. As a general matter, however, none of the suggested alternative approaches incorporated all the components of the proposal that the Department viewed as essential to making the required findings for granting an exemption, or provided alternatives that included conditions that would appropriately safeguard the interests of Retirement Investors in light of the exemption's broad relief from the conflicts of interest and self-dealing prohibitions under ERISA and the Code.
In some instances, commenters indicated that a different best interest standard would be appropriate but failed to provide an alternative to the Department's definition. Others suggested a definition of “best interest” that did not include a duty of loyalty constraining Advisers from making recommendations based on their own financial interests. Some of these definitions focused exclusively on the fiduciary obligation of prudence, while excluding the equally fundamental fiduciary duty of loyalty. A number of commenters expressed particular concern about the application of the Department's Best Interest requirement that the recommendation be made “without regard to the financial or other interests of the Adviser, Financial Institution” or other parties. Some of these commenters suggested that the Department use different formulations that were similar to the Department's, but might be construed to less stringently forbid the consideration of the financial interests of persons other than the Retirement Investor. For example, commenters suggested a standard providing that the Adviser and Financial Institution “not subordinate” their customers' interests to their own interests, or that the Adviser and Financial Institution put their customers' interests ahead of their own interests, or similar constructs.
In response to commenter concerns, the Department created a specific “Best Interest” test for Advisers and Financial Institutions that make recommendations from a restricted range of investments, including Proprietary Products or investments that generate Third Party Payments. In that circumstance, the test ensures that the Retirement Investor receives full and fair disclosure of the
In addition, in many of the alternatives suggested by commenters, the Best Interest standard appeared to lack a clear means of enforcement. A number of commenters suggested they could abide by a Best Interest standard but at the same time objected to the enforcement mechanisms that the Department proposed, particularly in the IRA market. As discussed above, the Department does not believe that the exemption can serve its participant protective purposes, or that Financial Institutions and their Advisers will be properly incentivized to comply with its terms, if Retirement Investors do not have an enforceable entitlement to compliance.
Other alternative approaches stressed disclosure as a means of protecting Retirement Investors. Some commenters indicated that additional disclosures, alone, would address many of the Department's concerns. Full and fair disclosure of material conflicts and informed consent are, in the Department's view, important elements of exemptive relief but are not sufficient on their own to form the basis of an exemption that is this broad and flexible.
Disclosure alone has proven ineffective to mitigate conflicts in advice. Extensive research has demonstrated that most investors have little understanding of their advisers' conflicts of interest, and little awareness of what they are paying via indirect channels for the conflicted advice. Even if they understand the scope of the advisers' conflicts, many consumers are not financial experts and therefore, cannot distinguish good advice or investments from bad. The same gap in expertise that makes investment advice necessary and important frequently also prevents investors from recognizing bad advice or understanding advisers' disclosures. Indeed, some research suggests that even if disclosure about conflicts could be made simple and clear, it could be ineffective—or even harmful.
Many commenters suggested that a uniform standard applicable to all retail accounts would be preferable to the Department's proposal, and that the Department should work with other regulators, such as the SEC and FINRA, to fashion such an approach. Others suggested that the Department should wait and defer to the SEC's determination of an appropriate standard for broker-dealers under the Dodd-Frank Act. Still others suggested that the Department should provide exemptions based on fiduciary status under securities laws, or based on compliance with other applicable laws or regulations. FINRA indicated that the proposal should be based on existing principles in federal securities laws and FINRA rules but acknowledged that additional rulemaking would be required.
The Department disagrees with the commenters, and believes it is important to move forward with this proposal to remedy the ongoing injury to Retirement Investors as a result of conflicted advice arrangements. ERISA and the Code create special protections applicable to investors in tax qualified plans. The fiduciary duties established under ERISA and the Code are different from those applicable under securities laws, and would continue to differ even if both regimes were interpreted to attach fiduciary status to exactly the same parties and activities. Reflecting the special importance of plan and IRA investments to retirement and health security, this statutory regime flatly prohibits fiduciaries from engaging in transactions involving self-dealing and conflicts of interest unless an exemption applies. Under ERISA and the Code, the Department of Labor has the authority to craft exemptions from these stringent statutory prohibitions, and the Department is specifically charged with ensuring that any exemptions it grants are in the interests of Retirement Investors and protective of these interests. Moreover, the fiduciary provisions of ERISA and the Code broadly protect all investments by Retirement Investors, not just those regulated by the SEC. As a consequence, the Department uniquely has the ability to assure that these fiduciary rules work in harmony for all Retirement Investors, regardless of whether they are investing in securities, insurance products that are not securities, or others type of investment.
The Department has taken very seriously its obligation to harmonize its regulation with other applicable laws, including the securities laws. In pursuing its consultations with other regulators, the Department aimed to coordinate and minimize conflicting or duplicative provisions between ERISA, the Code and federal securities laws. The Department has coordinated—and will continue to coordinate—its efforts with other federal agencies to ensure that the various legal regimes are harmonized to the fullest extent possible. The resulting exemption provides Advisers and Financial Institutions with a choice to provide advice that does not involve prohibited conflicted transactions or comply with this exemption or another exemption, which now all require advice to be provided in accordance with basic fiduciary norms. Likewise, the exemption preserves Retirement Investors' ability to choose the method of payment that works best for them. Far from confusing investors, the standards set forth in the exemption ensure that Retirement Investors can uniformly expect to receive advice that is in their best interest with respect to their retirement investments. Moreover, the best interest standard reflects what many investors have believed they were entitled to all along, even though it was not legally required.
In this regard, waiting for the SEC to act, as some commenters suggested, would delay the implementation of these important, updated safeguards to plan and IRA investors investing in a wide variety of products, and impose substantial costs on them as current harms from conflicted advice would continue.
A few commenters opposed the grant of any exemption at all. One commenter suggested that the exemption sunset after 5 years, to permit a transition to investment advice that does not raise prohibited transaction issues at all. The Department did not accept these comments. The Department shares these commenters' concerns about conflicted advice, but nevertheless believes that simply banning all commissions, transaction-based payments, and other forms of conflicted payments could have serious adverse unintended consequences. These forms of compensation are commonplace in today's marketplace for retirement
Finally, the Department acknowledges requests for special, streamlined exemptions for certain circumstances or certain products. For example, some commenters requested special treatment for certain parties based on mission or tax-exempt status; certain products such as target date funds, employer securities, or products that qualify as default investment alternatives under 29 CFR 2550.404c-5; and circumstances in which investment advice to Retirement Investors is “ancillary” to advice on non-investment insurance products. The Department has fashioned this exemption to apply broadly to advice arrangements in the retail market by taking a standards-based approach, rather than by focusing on particular highly-specific investments, advisory arrangements, or business models subject to highly-proscriptive conditions. Additionally, as described in detail in preceding sections, the Department has carefully considered comments on how to make the exemption more workable and less burdensome. The Department's goal was to create an exemption that could broadly apply to a wide universe of investments and practices, rather than to write special rules for particular subcategories or special circumstances, such as those requested by these commenters in this class exemption. The fiduciary norms, standards, and conditions set forth in the exemption serve an important protective purpose, which should benefit investors across the board including the arrangements identified by the commenters. If, however, the commenters still believe additional relief is necessary for special categories of investments or practices, the Department invites the commenters to apply for an individual or additional class exemption.
In the proposal, the Department indicated that it was considering a separate streamlined exemption that would allow compensation to be received in connection with recommendations of certain high-quality low-fee investments. The Department sought comments on how to operationalize such an exemption, which might minimize the compliance burdens for Advisers offering high-quality low-fee investment products with minimal potential for Material Conflicts of Interest. Products that met the conditions of the streamlined exemption could be recommended to plans, participants and beneficiaries, and IRA owners, and the Adviser could receive variable and third-party compensation as a result of those recommendations, without satisfying some or all of the conditions of this exemption. The streamlined exemption could reward and encourage best practices with respect to optimizing the quality, amount, and combined, all-in cost of recommended financial products, financial advice, and other related services. In particular, a streamlined exemption could be useful in enhancing access to quality, affordable financial products and advice by savers with smaller account balances. Additionally, because it would be premised on a fee comparison, it would apply only to investments with relatively simple and transparent fee structures.
In the proposal, the Department noted that it had been unable to operationalize such an exemption in a way that would achieve the Department's Retirement Investor-protective objectives and therefore did not propose text for such an exemption. Instead, the Department sought public input to assist in the consideration of the merits and possible design of such an exemption. The Department asked a number of specific questions, including which products should be included, how the fee calculations should be established, performed, communicated and updated, what, if any additional conditions should apply, and how a streamlined exemption would affect the marketplace for investment products.
The vast majority of commenters were opposed to creating a streamlined exemption for low-fee products. Commenters expressed the view that the approach over-emphasized the importance of fees, despite prior Department guidance noting that fees were not the sole factor for investors to consider. Commenters also raised many of the same operational concerns the Department had raised in the preamble, such as identifying the appropriate fee cut off, as well as the potential for undermining suitability and fiduciary obligations under securities laws, with a sole focus on products with low fees.
The Department did receive a few comments in support of a low-fee streamlined exemption. These commenters generally recommended that the exemption be limited to certain investments, most commonly mutual funds, and perhaps just those with fees in the bottom five or ten percent. One commenter requested a carve-out from the Regulation's definition of “fiduciary,” or a streamlined exemption, for retirement investments in high-quality, low-cost financial institutions savings products, like CDs, when a direct fee is not charged and a commission is not earned by the bank employee. Other commenters were willing to consider a low fee streamlined exemption, but argued that more information was necessary and any such exemption would need to be proposed separately.
The commenters' concerns as described above echoed the Department's concerns regarding the low-fee streamlined exemption. Despite some limited support, the Department has determined not to proceed with a low fee streamlined exemption. The Department did not receive enough information in the comments to address the significant conceptual and operational concerns associated with the approach. For example, after consideration of the comments, the Department was unable to conclude that the streamlined exemption would result in meaningful cost savings. Most Financial Institutions and Advisers would likely only be able to rely on such a streamlined exemption in part. They would still need to comply with this exemption for many of the investments recommended outside of the streamlined exemption. Many of the costs associated with this exemption are upfront costs (
Section VI provides an exemption, which is supplemental to Section I, for certain prohibited transactions commonly associated with investment advice. Section I permits Advisers and Financial Institutions to receive compensation that would otherwise be prohibited by the self-dealing and conflicts of interest provisions of ERISA section 406(a)(1)(D) and 406(b), and Code section 4975(c)(1)(D)-(F). However, Section I does not extend to any other prohibited transaction sections of ERISA and the Code. ERISA section 406(a) and Code section 4975(c)(1)(A)-(D) contain additional prohibitions on certain specific transactions between plans and IRAs and “parties in interest” and “disqualified persons,” including service providers. These additional prohibited transactions include: (i) The purchase or sale of an asset between a plan/IRA and a party in interest/disqualified person, and (ii) the transfer of plan/IRA assets to a party in interest/disqualified person. These prohibited transactions are subject to excise tax and personal liability for the fiduciary.
A number of transactions that may occur as a result of an Adviser's or Financial Institution's advice involve a prohibited transaction under ERISA section 406(a)(1)(A) and Code section 4975(c)(1)(A). The entity that causes a plan or IRA to enter into the transaction would not be the Adviser or Financial Institution, but would instead be a plan fiduciary or IRA owner acting on the Adviser's or Financial Institution's advice. Because the party requiring relief for this prohibited transaction is separate from the Adviser and Financial Institution, the Department is granting this exemption subject to discrete conditions. As a result, the Adviser's or Financial Institution's failure to comply with any of the conditions of Section I would not result in the authorizing plan fiduciary or IRA owner having engaged in a non-exempt prohibited transaction.
In this regard, a plan's or IRA's purchase of an insurance or annuity product would be a prohibited transaction if the insurance company is a service provider to the plan or IRA, or is otherwise a party in interest or disqualified person. A plan's or IRA's purchase of a security from a Financial Institution in a Riskless Principal Transaction would involve a prohibited transaction if the Financial Institution also provides advice to the plan or IRA. A plan's or IRA's purchase of a proprietary investment product from a Financial Institution also may involve this type of prohibited transaction. These prohibited transactions are not included in the exemption provided under Section I, which contains conditions that an Adviser and Financial Institution must follow. However, in the Department's view, these circumstances are common enough in connection with recommendations by Advisers and Financial Institutions to warrant a supplemental exemption for these types of transactions in conjunction with the relief provided in Section I. This Section VI establishes the conditions applicable to the entity that causes the plan or IRA to enter into the transaction.
Therefore, relief is provided in Section VI for the purchase of an investment product by a plan, or a participant or beneficiary account, or IRA, from a Financial Institution that is a party in interest or disqualified person. Relief is provided solely from the prohibitions of ERISA section 406(a)(1)(A) and (D), and the sanctions imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(A) and (D).
This relief is particularly necessary as part of this exemption because of the amendment to and partial revocation of an existing exemption, PTE 84-24, elsewhere in this issue of the
The conditions for the exemptions in this Section VI are that the transaction must be effected by the Financial Institution in its ordinary course of its business; the transaction may not result in compensation, direct or indirect, to the Financial Institution and its Affiliates that exceeds reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and the terms of the transaction are at least as favorable to the Plan, participant or beneficiary account, or IRA as the terms generally available in an arm's length transaction with an unrelated party.
The scope of the exemption in Section VI is broader than the proposal. The proposed exemption was limited to transactions involving insurance or annuity contracts. However, in connection with certain other changes made in the final exemption, the Department determined that broader relief in this area is necessary. In particular, the expansion beyond insurance or annuity contracts was necessary to provide relief for transactions involving investments not within the original definition of “Asset” that may be Proprietary Products purchased and sold with a Financial Institution, and to include investments purchased or sold in Riskless Principal Transactions with Financial Institutions. Of course, the exemption remains available for insurance and annuity products as well.
One commenter requested broader supplemental relief for extensions of credit for bank deposits, certificates of deposit and debt instruments that may be recommended pursuant to Section I. The final exemption does not include such relief. The Department believes that the requested relief is generally available in existing statutory exemptions. For example, relief for extensions of credit in connection with bank deposits and CDs is available under ERISA section 408(b)(4) and Code section 4975(d)(4). Relief for extensions of credit in connection with a plan's or IRA's purchase of a debt security is available in ERISA section 408(b)(17) and Code section 4975(d)(20), provided that extension of credit is not from a fiduciary with respect to the plan or IRA. This would cover the circumstance in which a plan or IRA purchases a debt security, through the Financial Institution, if the issuer of the debt security is a party in interest or disqualified person with respect to the plan or IRA, but not a fiduciary. If relief is sought for the circumstance in which the issuer of the debt security is a fiduciary with respect to the plan or IRA, the Department believes that such transactions should be considered on an individual basis and invites Financial Institutions that wish to recommend their own debt securities to apply for an individual exemption.
The Department made certain changes to the conditions proposed for this exemption, in response to comments. As proposed, the exemption in Section VI was limited to transactions for cash. A few commenters ask that the Department reconsider, and permit in-kind purchases, on the basis that these purchases can result in advantageous pricing to the investor. Other commenters expressed concern that the proposed restriction to cash transactions would exclude a purchase via rollover. The Department concurs with these
In addition, the Department eliminated the approach in the proposed exemption that would have limited relief to small plans (in addition to IRAs, plan participants and beneficiaries). As explained above, under the companion amendment to and partial revocation of PTE 84-24, that exemption no longer provides relief from ERISA section 406(a)(1)(A) and Code section 4975(c)(1)(A) for transactions involving variable annuity contracts and indexed annuity contracts and similar contracts. In light of this restriction of PTE 84-24, there was a broader need for relief from ERISA section 406(a)(1)(A) and Code section 4975(c)(1)(A) for transactions involving plans of all sizes. The final exemption in Section VI provides such relief.
A few commenters requested that Section VI be expanded to provide a broad exemption similar to Section I, that would be specifically tailored to insurance and annuity purchases but would provide relief for Advisers and Financial Institutions from the self-dealing and conflict of interests restrictions in ERISA section 406(b) and Code section 4975(c)(1)(E) and (F). The Department has declined to accept this suggestion, opting instead to make changes regarding insurance products to the various provisions of Section I. The Department is concerned about creating a special less-protective set of conditions available just for insurers with respect to transactions prohibited by ERISA section 406(b) and Code section 4975(c)(1)(E) and (F). Such an approach could encourage Advisers and Financial Institutions, for example, to potentially recommend variable or indexed annuities based on their preference for a less protective regulatory regime rather than on the basis of the Retirement Investor's Best Interest. However, in response to commenters, the Department has revised the reasonable compensation standard in accordance with Section II(c)(2) to avoid unnecessary complexity.
Section VII provides a supplemental exemption for pre-existing transactions. The exemption permits continued receipt of compensation based on investment transactions that occurred prior to the Applicability Date as well as receipt of compensation for recommendations to continue to adhere to a systematic purchase program established before the Applicability Date. The exemption also explicitly covers compensation received as a result of a recommendation to hold an investment that was entered into prior to the Applicability Date. In this regard, some Advisers and Financial Institutions did not consider themselves fiduciaries before the Applicability Date. Other Advisers and Financial Institutions entered into transactions involving plans, participant or beneficiary accounts, or IRAs before the Applicability Date, in accordance with the terms of a prohibited transaction exemption that has since been amended. The exemption provides relief from the restrictions of ERISA section 406(a)(1)(A), (D) and 406(b) and the sanctions imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(A), (D), (E) and (F).
This exemption is conditioned on the following:
(1) The compensation is received pursuant to an agreement, arrangement or understanding that was entered into prior to the Applicability Date and that has not expired or come up for renewal post-Applicability Date;
(2) The purchase, exchange, holding or sale of the securities or other investment property was not otherwise a non-exempt prohibited transaction pursuant to ERISA section 406 and Code section 4975 on the date it occurred;
(3) The compensation is not received in connection with the plan's, participant or beneficiary account's or IRA's investment of additional amounts in the previously acquired investment vehicle; except that for avoidance of doubt, the exemption does apply to a recommendation to exchange investments within a mutual fund family or variable annuity contract pursuant to an exchange privilege or rebalancing program that was established before the Applicability Date, provided that the recommendation does not result in the Adviser and Financial Institution, or their Affiliates or Related Entities receiving more compensation (either as a fixed dollar amount or a percentage of assets) than they were entitled to receive prior to the Applicability Date;
(4) The amount of the compensation paid, directly or indirectly, to the Adviser, Financial Institution, or their Affiliates or Related Entities in connection with the transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and
(5) Any investment recommendations made after the Applicability Date by the Financial Institution or Adviser with respect to the securities or other investment property reflect the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, and are made without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party.
The Department's intent in proposing the exemption for pre-existing investments was to provide certainty that Advisers and Financial Institutions could continue to receive revenue streams based on transactions that occurred prior to the Applicability Date. Under the proposal, the relief for pre-existing transactions was limited, so that any additional advice would have had to occur under the conditions of Section I of the exemption. The Department also proposed that the pre-existing transaction relief should be limited only to limited categories of Assets as defined in the proposed exemption.
Commenters identified the need for broader grandfathering relief in these respects. They stated that limiting the relief to investments within the proposed definition of “Asset” and disallowing additional advice would cut off the ability of plans, participants and beneficiaries, and IRAs to receive advice on a broader range of investments that may already be held in their accounts. They reasoned that in many cases, an investor that has already purchased an investment may already be entitled to continued advice or services based on existing compensation arrangements.
Commenters also indicated that the proposal's approach of restricting any additional advice for investments that were not on the list of Assets could, in some circumstances, create an especially difficult situation for Financial Institutions and Advisers regulated by FINRA. According to commenters, FINRA has been clear that ongoing advice may be a requirement of suitability. Thus, commenters asserted, Financial Institutions and Advisers could be faced with the decision to risk either a prohibited transaction or a suitability violation. Similarly, commenters expressed concern that Financial Institutions would require all Retirement Investors to invest through fee-based accounts—raising concerns about “reverse churning”—if no differential payments with respect to existing investments could be received after the Applicability Date.
The Department concurs with commenters that it is appropriate to provide broader grandfathering relief as a means of affording the industry time to transition to the new regulatory structure, and to minimize disruption of existing arrangements. Consistent with
The exemption does provide, however, that the compensation received must satisfy the reasonable compensations standard, and additional advice must reflect the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, and must be made without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party.
The exemption is limited to compensation received as a result of investment advice on securities or other property purchased prior to the Applicability Date and as a result of investment advice to continue to adhere to a systematic purchase program established before the Applicability Date. Section VII(b)(3) provides that the compensation covered under the exemption may not be in connection with the Retirement Investor's investment of additional assets in the previously acquired investment vehicle. This is intended to preclude, for example, advice on additional contributions to a variable annuity product purchased prior to the Applicability Date, or recommending additional investments in a particular mutual fund or asset pool. Although commenters requested broader relief in this area, the Department has declined to permit advice on additional contributions to existing investments without compliance with the protective conditions applicable to Section I. The primary purpose of the exemption for pre-existing investments is to preserve compensation for services already rendered and to permit orderly transition from past arrangements, not to exempt future advice and investments from the important protections of the Regulation and this Best Interest Contract Exemption. Permitting Advisers to recommend additional investments in an existing investment vehicle, without the safeguards provided by the fiduciary norms and other conditions of the exemption, would permit conflicts to flourish unchecked.
Section VII(b)(3) makes clear that the exemption extends to exchanges of investments within a mutual fund family or variable annuity pursuant to exchange privileges or rebalancing programs established prior the Applicability Date.
Several commenters requested even broader relief, asking that the Department grandfather all existing Retirement Investors or Retirement Investor accounts or all IRAs. Some argued that it would not be fair for Retirement Investors who entered into agreements with their Financial Institutions and Advisers that were compliant at the time to have the terms of those agreements change over the course of the investment. The Department declines to provide broader relief. When Advisers make recommendations to make new investments after the Applicability Date, Retirement Investors should be able to expect that the recommendations will adhere to the basic fiduciary standards and conditions set out in this exemption. The Retirement Investor who had a pre-existing relationship is no less in need of protection from conflicts of interest—and no less deserving of adherence to a best interest standard—than the investor who has no such pre-existing relationship. The failure to implement safeguards against conflicts of interest would result in the continued injury of these Retirement Investors, as they invested still more money based on recommendations subject to dangerous conflicts of interest.
A few commenters requested clarification of the circumstances under which the relief in Section VII would be necessary. The fact that the Department proposed an exemption for compensation received in connection with pre-existing investments caused concern among some commenters that the Regulation might apply retroactively to circumstances that occurred prior to the Applicability Date. Therefore, the commenters sought confirmation that compliance with the exemption would not be necessary unless fiduciary investment advice is provided after the Applicability Date with respect to the pre-existing investments.
In response, the Department confirms that the Regulation does not apply retroactively to circumstances that occurred before the Applicability Date. The exemption is only necessary for non-exempt prohibited transactions occurring after the Applicability Date. By providing an exemption for compensation received for investments made prior to the Applicability Date, the Department is not suggesting otherwise; the exemption merely provides transitional relief to avoid uncertainty relating to compensation received after the Applicability Date.
Section VIII of the exemption provides definitions of the terms used in the exemption. The Department received comments on certain definitions and has addressed them as described below. Additional comments on definitions, such as “Retirement Investor,” “Best Interest,” and “Material Conflict of Interest,” are discussed above in their respective sections.
Section VIII(a) defines the term “Adviser” as an individual who:
(1) is a fiduciary of the Plan or IRA solely by reason of the provision of investment advice described in ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B), or both, and the applicable regulations, with respect to the assets of the Plan or IRA involved in the recommended transaction;
(2) is an employee, independent contractor, agent, or registered representative of a Financial Institution; and
(3) satisfies the federal and state regulatory and licensing requirements of insurance, banking, and securities laws with respect to the covered transaction, as applicable.
The Department received some comments on this definition, but has maintained the definition unchanged from the proposal. One commenter asked the Department to treat branch managers in the same manner as Advisers. The Department has declined to expand the definition of Adviser to cover branch managers, but notes that, as discussed above in Section II, the incentives of branch managers should generally be considered as part of the Financial Institution's policies and procedures. Another commenter expressed concern that, because of the requirement to satisfy applicable federal and state laws, call center employees might be required to register with the SEC as “advisers” under the Investment Advisers Act of 1940. The Department notes that the requirement in Section VIII(a)(3) is limited to
Section VIII(b) defines “Affiliate” of an Adviser or Financial Institution as:
(1) any person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution. For this purpose, “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual;
(2) any officer, director, partner, employee, or relative (as defined in ERISA section 3(15)), of the Adviser or Financial Institution; and
(3) any corporation or partnership of which the Adviser or Financial Institution is an officer, director, or partner.
The Department received a comment requesting that this definition adopt a securities law definition. The commenter expressed the view that use of a separate definition would make compliance more difficult for broker-dealers. The Department did not accept this comment. Instead, the Department made minor adjustments so that the definition is identical to the affiliate definition incorporated in prior exemptions under ERISA and the Code, that are applicable to broker dealers,
Section VIII(e) defines “Financial Institution” as the entity that employs the Adviser or otherwise retains such individual as an independent contractor, agent or registered representative, and that is one of the following:
(1) registered as an investment adviser under the Investment Advisers Act of 1940 or under the laws of the state in which the adviser maintains its principal office and place of business;
(2) a bank or similar financial institution supervised by the United States or state, or a savings association (as defined in section 3(b)(1) of the Federal Deposit Insurance Act);
(3) an insurance company qualified to do business under the laws of a state, provided that such insurance company: (i) Has obtained a Certificate of Authority from the insurance commissioner of its domiciliary state which has neither been revoked nor suspended, (ii) has undergone and shall continue to undergo an examination by an Independent certified public accountant for its last completed taxable year or has undergone a financial examination (within the meaning of the law of its domiciliary state) by the state's insurance commissioner within the preceding 5 years, and (iii) is domiciled in a state whose law requires that actuarial review of reserves be conducted annually by an Independent firm of actuaries and reported to the appropriate regulatory authority; or (4) a broker or dealer registered under the Securities Exchange Act of 1934.
The Department received several comments on this definition and has made certain modifications. One commenter said that the proposed definition did not reflect the variety of channels in which financial products and services are marketed. The commenter, and a few other commenters, recommended that the Department delete the requirement in the proposed Section VIII(e)(2) that required that advice from banks and similar institutions be provided through a trust department. The Department has accepted this change in the final exemption.
The Department also received several questions about the applicability of the exemption when more than one “Financial Institution” is involved in the sale of a financial product. This may occur, for example, if there is a product manufacturer that is an insurance company, and a broker-dealer or registered investment adviser recommending the product to clients. Commenters asked for assurances that the product manufacturer in that example would not have to satisfy the conditions of the exemption applicable to Financial Institutions. As explained earlier, under the exemption,
In a related example, commenters asked about marketing or distribution affiliates and intermediaries that would not meet the definition of Financial Institution, as proposed. One commenter specifically requested that the definition of Financial Institution be revised to include all entities within an insurance group that arrange for the marketing of financial products. The commenter stated that an insurance company, with its representatives and agents, may market the products of a second financial institution and the contractual arrangements that allow for this marketing frequently are with an entity that is affiliated with the insurance company, but which does not itself meet the proposed definition of a “Financial Institution.”
The Department declines to expand the categories of Financial Institutions to such intermediaries, but rather limits the definition of Financial Institution to the regulated entities included in the proposed definition which are subject to well-established regulatory conditions and oversight. However, the Department has made provision to add entities to the definition of Financial Institution through the grant of an individual exemption. Accordingly, the definition of Financial Institution includes “[a]n entity that is described in the definition of Financial Institution in an individual exemption granted by the Department under section 408(a) of ERISA and section 4975(c) of the Code, after the date of this exemption, that provides relief for the receipt of compensation in connection with investment advice provided by an investment advice fiduciary, under the same conditions as this class exemption.” If parties wish to expand the definition of Financial Institution to include marketing intermediaries or other entities, they can submit an application to the Department for an individual exemption, with information regarding their role in the distribution of financial products, the regulatory oversight of such entities, and their ability to effectively supervise individual Advisers' compliance with the terms of this exemption. If a marketing intermediary or other entity which does not meet the definition of Financial Institution, wishes to obtain the relief provided in this class exemption, the Department will consider such a request in an application for an individual exemption.
Section VIII(f) defines “Independent” as a person that:
(1) Is not the Adviser, the Financial Institution or any Affiliate relying on the exemption;
(2) Does not have a relationship to or an interest in the Adviser, the Financial Institution or Affiliate that might affect the exercise of the person's best judgment in connection with transactions described in this exemption; and
(3) Does not receive or is not projected to receive within the current federal income tax year, compensation or other consideration for his or her own account from the Adviser, Financial Institution or Affiliate in excess of 2% of the person's annual revenues based upon its prior income tax year.
The term Independent is used in Section I(c)(1)(ii), which precludes Financial Institutions and Advisers from relying on the exemption if they are the named fiduciary or plan administrator, as defined in ERISA section 3(16)(A), with respect to an ERISA-covered plan, unless such Financial Institutions or Advisers are selected to provide advice to the plan by a plan fiduciary that is Independent of the Financial Institutions or Advisers. The term Independent is also used in the definitions section, in describing the types of entities that may be Financial Institutions. Insurance companies that are Financial Institutions must have been examined by Independent certified public accountants and be domiciled in a state whose law requires that actuarial review of reserves be conducted annually by an Independent firm of actuaries.
In the proposed exemption, the definition of Independent provided that the person (
In response, the Department revised the definition of Independent so that it provides that the person's compensation in the current tax year from the Financial Institution may not be in excess of 2% of the person's annual revenues based on the prior year. This approach is consistent with the Department's general approach to fiduciary independence. For example, the Department's prohibited transaction exemption procedures regulation provide a presumption of independence for appraisers and fiduciaries if the revenue they receive from a party is not more than 2% of their total annual revenue.
Section VIII(g) defines “Individual Retirement Account” or “IRA” as any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code. This definition is unchanged from the proposal.
The Department received comments on both the application of the proposed Regulation and the exemption proposals to other non-ERISA plans covered by Code section 4975, such as Health Savings Accounts (HSAs), Archer Medical Savings Accounts and Coverdell Education Savings Accounts. The Department notes that these accounts are given tax preferences as are IRAs. Further, some of the accounts, such as HSAs, can be used as long term savings accounts for retiree health care expenses. These types of accounts also are expressly defined by Code section 4975(e)(1) as plans that are subject to the Code's prohibited transaction rules. Thus, although they generally may hold fewer assets and may exist for shorter durations than IRAs, there is no statutory reason to treat them differently than other conflicted transactions and no basis for suspecting that the conflicts are any less influential with respect to advice on these arrangements. Accordingly, the Department does not agree with the commenters that the owners of these accounts are entitled to less protection than IRA investors. The Regulation continues to include advisers to these “plans,” and this exemption provides relief to them in the same manner it does for individual retirement accounts described in section 408(a) of the Code.
Section VIII(l) defines “Proprietary Product” as a product that is managed, issued or sponsored by the Financial Institution or any of its Affiliates. This is revised from the proposal, which defined a Proprietary Product as one that is “managed” by the Financial Institution or an Affiliate. One commenter specifically addressed the proposed definition, and recommended that the definition use the terms “issued” or “sponsored” instead of managed, in order to better match how the industry determines whether a product is proprietary. It is the Department's understanding that a variety of terms can be used to describe a proprietary relationship, particularly depending on the nature of the investment product. Therefore, in the final exemption, the Department has retained the word “managed,” but has also added the words “issued” and “sponsored” as suggested by the commenter.
Section VIII(m) defines “Related Entity” as any entity other than an Affiliate in which the Adviser or Financial Institution has an interest which may affect the exercise of its best judgment as a fiduciary. This definition is unchanged from the proposal.
The Department received one comment requesting that this be made more specific with respect to the types of relationships the Department envisions. In response the Department explains that the intent behind the Related Entity concept is to provide relief for fiduciary investment advisers that is co-extensive with the scope of the prohibited transactions provisions under ERISA and the Code. As stated in the Department's regulation under ERISA section 408(b)(2):
The prohibitions [of Section 406(b)] are imposed upon fiduciaries to deter them from exercising the authority, control, or responsibility which makes such persons fiduciaries when they have interests which may conflict with the interests of the plans for which they act. In such cases, the fiduciaries have interests in the transactions which may affect the exercise of their best judgment as fiduciaries. Thus, a fiduciary may not use the authority, control, or responsibility which makes such a person a fiduciary to cause a plan to pay an additional fee to such fiduciary (
The Regulation will become effective June 7, 2016 and this Best Interest Contract Exemption is issued on that same date. The Regulation is effective at the earliest possible date under the Congressional Review Act. For the exemption, the issuance date serves as the date on which the exemption is intended to take effect for purposes of the Congressional Review Act. This date was selected to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the final rule are now officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the rule and exemption are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, an Applicability Date of April 10, 2017, is appropriate for plans and their affected service providers to adjust to the basic change from non-fiduciary to fiduciary status. This exemption has the same Applicability Date; parties may rely on it as of the Applicability Date.
Section IX provides a transition period under which relief from the prohibited transaction provisions of ERISA and the Code is available for Financial Institutions and Advisers during the period between the Applicability Date and January 1, 2018 (the “Transition Period”). For the Transition Period, full relief under the exemption will be available for Financial Institutions and Advisers subject to more limited conditions than the full set of conditions described above. This period is intended to give Financial Institutions and Advisers time to prepare for compliance with the conditions of Section II-V set forth above, while safeguarding the interests of Retirement Investors. The Transition Period conditions set forth in Section IX are subject to the same exclusions in Section I(c), for advice rendered in connection with Principal Transactions, advice from fiduciaries with discretionary authority over the customer's investments, robo-advice, and specified advice concerning in-house plans.
The transitional conditions of Section IX require the Financial Institution and its Advisers to comply with the Impartial Conduct Standards when making recommendations to Retirement Investors. The Impartial Conduct Standards required in Section IX are the same as required in Section II(c) but are repeated for ease of use.
During the Transition Period, the Financial Institution must additionally provide a written notice to the Retirement Investor prior to or at the same time as the execution of the recommended transaction, which may cover multiple transactions or all transactions taking place within the Transition Period, acknowledging its and its Adviser(s) fiduciary status under ERISA or the Code or both with respect to the recommended transaction. The Financial Institution also must state in writing that it and its Advisers will comply with the Impartial Conduct Standards and disclose its Material Conflicts of Interest.
Further, the Financial Institution's notice must disclose whether it recommends Proprietary Products or investments that generate Third Party Payments; and, to the extent the Financial Institution or Adviser limits investment recommendations, in whole or part, to Proprietary Products or investments that generate Third Party Payments, the Financial Institution must notify the Retirement Investor of the limitations placed on the universe of investment recommendations. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis. The disclosure may be provided in person, electronically or by mail. It does not have to be repeated for any subsequent recommendations during the Transition Period.
Similar to the disclosure provisions of Section II(e) and III, the transition exemption in Section IX provides for exemptive relief to continue despite errors and omissions with respect to the disclosures, if the Financial Institution acts in good faith and with reasonable diligence.
In addition, the Financial Institution must designate a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards.
Finally, the Financial Institution must comply with the recordkeeping provision of Section V(b) and (c) of the exemption regarding the transactions entered into during the Transition Period.
After the Transition Period, however, the limited conditions provided in Section IX for the exemption will no longer be available. After that date, Financial Institutions and Advisers must satisfy all of the applicable conditions described in Sections II-V for the relief in Section I(b) to be available for any prohibited transactions occurring after that date. This includes the requirement to enter into a contract with a Retirement Investor, where required. Financial Institutions relying on the negative consent procedure set forth in Section II(a)(1)(ii) must provide the contractual provisions to Retirement Investors with existing contracts prior to January 1, 2018, and allow those Retirement Investors 30 days to terminate the contract. If the Retirement Investor does terminate the contract within that 30-day period, this exemption will provide relief for 14 days after the date on which the termination is received by the Financial Institution. In that event, the Retirement Investor's account generally should be able to fall within the provisions of Section VII for pre-existing transactions. The provisions in Sections VI and VII of this Best Interest Contract Exemption, providing exemptions for certain purchase and sale transactions, including insurance and annuity contracts, and pre-existing transactions, respectively, are also available on the Applicability Date. The transition relief does not extend to the transactions described in Section VI which provides an exemption for purchase and sales of investments including insurance and annuity contracts, and Section VII, which provides an additional exemption for pre-existing transactions. Compliance with these exemptions does not require an extended transition period because they have relatively few conditions, which are largely based on meeting well-known standards such as reasonable compensation, arm's length terms, and prudence.
The proposed Best Interest Contract Exemption, with the proposed Regulation and other exemption
The transition provisions in Section IX of the final exemption respond to commenters' concerns about ongoing economic harm to Retirement Investors during the period in which Financial Institutions develop systems to comply with the exemption. The provisions require prompt implementation of certain core protections of the exemption in the form of the acknowledgment of fiduciary status, compliance with the Impartial Conduct Standards, and certain important disclosures, to safeguard Retirement Investors' interests. The provisions recognize, however, that the Financial Institutions will need time to develop policies and procedures and supervisory structures that fully comport with the requirements of the final exemption. Accordingly, during the Transition Period, Financial Institutions are not required to execute the contract or give Retirement Investors warranties or disclosures on their anti-conflict policies and procedures. While the Department expects that Advisers and Financial Institutions will, in fact, adopt prudent supervisory mechanisms to prevent violations of the Impartial Conduct Standards (and potential liability for such violations), the exemption will not require the Financial Institutions to make specific representations on the nature or quality of the policies and procedures during this Transition Period. The Department will be available to respond to Financial Institutions' request for guidance during this period, as they develop the systems necessary to comply with the exemption's conditions.
The transition provisions also accommodate Financial Institutions' need for time to prepare for full compliance with the exemption, and therefore full compliance with all the final exemption's applicable conditions is delayed until January 1, 2018. The Department selected that period, rather than two to three years, as requested by some commenters, in light of the adjustments in the final exemption that significantly eased compliance burdens. Although the Department believes that the conditions of the exemption set forth in Section II-V are required to support the Department's findings required under ERISA section 408(a), and Code section 4975(c)(2) over the long term, the Department recognizes that Financial Institutions may need time to achieve full compliance with these conditions. The Department therefore finds that the provisions set forth in Section IX satisfy the criteria of ERISA section 408(a) and Code section 4975(c)(2) for the Transition Period because they provide the significant protections to Retirement Investors while providing Financial Institutions with time necessary to achieve full compliance. A similar transition period is provided for the companion Principal Transactions Exemption due to the corresponding provisions in that exemption that may require time for Financial Institutions to begin compliance.
The Department considered but declined delaying the application of the rule defining fiduciary investment advice until such time as Financial Institutions could make the changes to their practices and compensation structures necessary to comply with Sections II through V of this exemption. The Department believed that delaying the application of the new fiduciary rule would inordinately delay the basic protections of loyalty and prudence that the rule provides. Moreover, a long period of delay could incentivize Financial Institutions to increase efforts to provide conflicted advice to Retirement Investors before it becomes subject to the new rule. The Department understands that many of the concerns regarding the applicability date of the rule are related to the prohibited transaction provisions of ERISA and the Code rather than the basic fiduciary standards. This transition period exemption addresses these concerns by giving Financial Institutions and Advisers necessary time to fully comply with Sections II-V of the exemption.
The Department also considered the views of commenters that requested re-proposal of the regulation and exemptions, or issuing the rule and exemptions as interim final rules with requests for additional comment. After reviewing all the comments on the 2015 proposal, which was itself a re-proposal, the Department has concluded that it is in a position to publish a final rule and exemptions. It has carefully considered and responded to the significant issues raised in the comments in drafting the final rule and exemptions. Moreover, the Department has concluded that the difference between the final documents and the proposals are also responsive to the commenters' concerns and could be reasonably foreseen by affected parties.
The amendments to and partial revocations of existing exemptions finalized elsewhere in this issue of the
This exemption does not provide relief from a transaction prohibited by ERISA section 406(a)(1)(C), or from the taxes imposed by Code section 4975(a) and (b) by reason of Code section 4975(c)(1)(C), regarding the furnishing of goods, services or facilities between a plan and a party in interest. The provision of investment advice to a plan under a contract with a plan fiduciary is a service to the plan and compliance with this exemption will not relieve an Adviser or Financial Institution of the need to comply with ERISA section 408(b)(2), Code section 4975(d)(2), and applicable regulations thereunder.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Department solicited comments on the information collections included in the proposed Best Interest Contract Exemption. 80 FR 21960, 21980-83 (Apr. 20, 2015). The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposal, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally many comments were submitted, described elsewhere in the preamble to the accompanying final rule, which contained information relevant to the costs and administrative burdens attendant to the proposals. The Department took into account such public comments in connection with making changes to the prohibited transaction exemption, analyzing the economic impact of the proposals, and developing the revised paperwork burden analysis summarized below.
In connection with publication of this final prohibited transaction exemption, the Department is submitting an ICR to OMB requesting approval of a new collection of information under OMB Control Number 1210-0156. The Department will notify the public when OMB approves the ICR.
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail below, the final class exemption will require Financial Institutions to enter into a contractual arrangement with Retirement Investors regarding investments in IRAs and plans not subject to Title I of ERISA (non-ERISA plans), adopt written policies and procedures and make disclosures to Retirement Investors (including with respect to ERISA plans), the Department, and on a publicly accessible Web site, in order to receive relief from ERISA's and the Code's prohibited transaction rules for the receipt of compensation as a result of a Financial Institution's and its Adviser's advice (
The Department has made the following assumptions in order to establish a reasonable estimate of the paperwork burden associated with these ICRs:
• 51.8 percent of disclosures to ERISA plans and plan participants
• Financial Institutions will use existing in-house resources to distribute required disclosures and to create documentations for transactions recommended by Level Fee Fiduciaries.
• Tasks associated with the ICRs performed by in-house personnel will be performed by clerical personnel at an hourly wage rate of $55.21 and financial advisers at an hourly wage rate of $198.58.
• Financial Institutions will hire outside service providers to assist with nearly all other compliance costs;
• Outsourced legal assistance will be billed at an hourly rate of $335.00.
• Approximately 7,000 broker-dealers, RIAs that are ineligible to be Level Fee Fiduciaries, and insurance companies will use this exemption. Additionally, approximately 13,000 Level Fee Fiduciary RIAs will use of this exemption under level fee conditions.
The Department believes that nearly all Financial Institutions that are not Level Fee Fiduciaries will contract with outside service providers to implement the various compliance requirements of this exemption. As described in the regulatory impact analysis, per-firm costs for BDs were calculated by allocating the total cost reductions in the medium assumptions scenario across the firm size categories, and then subtracting the cost reductions from the per-firm average costs derived from the Oxford Economics study. The methodology for calculating the per-firm costs for RIAs and Insurance Companies is described in detail in the regulatory impact analysis. The Department is attributing 50 percent of the compliance costs for BDs and RIAs to this exemption and 50 percent of the compliance costs for BDs and RIAs to the Class Exemption for Principal Transactions in Certain Assets between Investment Advice Fiduciaries and Employee Benefit Plans and IRAs (Principal Transactions Exemption) published elsewhere in today's
In order to receive compensation covered under this exemption (other than under level fee conditions, which is discussed separately below), Section II requires Financial Institutions to acknowledge, in writing, their fiduciary status and adopt written policies and procedures designed to ensure compliance with the Impartial Conduct Standards. Financial Institutions and Advisers must make certain disclosures to Retirement Investors. Financial Institutions must generally enter into a written contract with Retirement Investors with respect to investments in IRAs and non-ERISA plans with certain required provisions, including affirmative agreement to adhere to the Impartial Conduct Standards.
Sections III and V require Financial Institutions and Advisers to make certain disclosures. These disclosures include: (1) A pre-transaction disclosure, stating the best interest standard of care, describing any Material Conflicts of Interest with respect to the transaction, disclosing the recommendation of proprietary products and products that generate third party payments (where applicable), and informing the Retirement Investor of disclosures available on the Financial Institution's Web site and informing the Retirement Investor that the investor may receive specific disclosure of the costs, fees, and other compensation associated with the transaction; (2) a disclosure, on request, describing in detail the costs, fees, and other compensation associated with the transaction; (3) a web-based disclosure; and (4) a one-time disclosure to the Department.
Under Section IV, Financial Institutions that limit recommendations in whole or in part to Proprietary Products or investments that generate Third Party Payments will have to prepare a written documentation regarding these limitations.
Section IX requires Financial Institutions to make a transition disclosure, acknowledging their fiduciary status and that of their Advisers with respect to the advice, stating the Best Interest standard of care, and describing the Financial Institution's Material Conflicts of Interest and any limitations on product offerings, prior to or at the same time as the execution of any transactions during the transition period from the Applicability Date to January 1, 2018. The transition disclosure can cover multiple transactions, or all transactions occurring in the transition period.
Financial Institutions will also be required to maintain records necessary to prove that the conditions of the exemption have been met.
The Department is able to disaggregate an estimate of many of the legal costs from the costs above; however, it is unable to disaggregate any of the other costs. The Department received a comment on the proposed PTE stating that the estimates for legal professional time to draft disclosures were not supported by any empirical evidence. The Department also received multiple comments on the proposed PTE stating that its estimate of 60 hours of legal professional time during the first year a financial institution used the exemption and then no legal professional time in subsequent years was too low.
In response to a recommendation made during the Department's August 2015, public hearing on the proposed
Considered in conjunction with the estimates provided in the proposal, the Department estimates that outsourced legal assistance to draft standard contracts, contract disclosures, pre-transaction disclosures, the one-time disclosure to the Department, and the transition disclosures will cost an average of $3,857 per firm for a total of $25.0 million during the first year. In subsequent years, it will cost an average of $3,076 per firm for a total of $19.9 million annually to update the contracts, contract disclosures, and pre-transaction disclosures.
The legal costs of these disclosures were disaggregated from the total compliance costs because these disclosures are expected to be relatively uniform. Although the tested disclosures generally took less time than many of the commenters said they would, the Department acknowledges that the disclosures that were not tested are those that are expected to be the most time consuming. Importantly, as explained in greater detail in section 5.3 of the regulatory impact analysis, the Department is primarily relying on cost data provided by the Securities Industry and Financial Markets Association (SIFMA) and the Financial Services Institute (FSI) to calculate the total cost of the legal disclosures, rather than its own internal drafting of disclosures. Accordingly, in the event that any of the Department's estimates understate the time necessary to create and update the disclosures, it does not impact the total burden estimates. The total burden estimates were derived from SIFMA and FSI's all-inclusive costs. Therefore, in the event that legal costs are understated, other cost estimates in this analysis would be overstated in an equal manner.
In addition to legal costs for creating the contracts and disclosures, the start-up cost estimates include the costs of implementing and updating the IT infrastructure, creating the web disclosures, gathering and maintaining the records necessary to produce the various disclosures and to prove that the conditions of the exemption have been met, developing policies and procedures, documenting any limitations regarding proprietary products or investments that generate third party payments, addressing material conflicts of interest, monitoring Advisers' adherence to the Impartial Conduct Standards, and any other steps necessary to ensure compliance with the conditions of the exemption not described elsewhere. In addition to legal costs for updating the contracts and disclosures, the ongoing cost estimates include the costs of updating the IT infrastructure, updating the web disclosures, reviewing processes for gathering and maintaining the records necessary to produce the various disclosures and to prove that the conditions of the exemption have been met, reviewing the policies and procedures, producing the detailed transaction disclosures on request, documenting any limitations regarding proprietary products or investments that generate third party payments, monitoring investments as agreed upon with the Retirement Investor, addressing material conflicts of interest, monitoring Advisers' adherence to the Impartial Conduct Standards, and any other steps necessary to ensure compliance with the conditions of the exemption not described elsewhere. These costs total $2.4 billion during the first year and $520.4 million in subsequent years. These costs do not include the costs of distributing disclosures and contracts or the costs of operating under level fee conditions, all of which are discussed below.
The Department estimates that 1.1 million Retirement Investors with respect to ERISA plans and 29.9 million Retirement Investors with respect to IRAs and non-ERISA plans will receive a three-page transition disclosure during the first year. Additionally, 1.1 million Retirement Investors with respect to ERISA plans will receive a fifteen-page contract disclosure, and 29.9 million Retirement Investors with respect to IRAs and non-ERISA plans will receive a fifteen-page contract during the first year. In subsequent years, 320,000 million Retirement Investors with respect to ERISA plans will receive a fifteen-page contract disclosure and 6.0 million Retirement Investors with respect to IRAs and non-ERISA plans will receive a fifteen-page contract. To the extent that Financial Institutions use both the Best Interest Contract Exemption and the Principal Transactions Exemption, these estimates may represent overestimates because significant overlap exists between the requirements of the transition disclosure and the contract for both exemptions. If Financial Institutions choose to use both exemptions with the same clients, they will probably combine the documents.
The transition disclosure will be distributed electronically to 51.8 percent of ERISA plan investors and 44.1 percent of IRAs and non-ERISA plan investors during the first year. Paper disclosures will be mailed to the remaining 48.2 percent of ERISA plan investors and 55.9 percent of IRAs and non-ERISA plan investors. The contract disclosure will be distributed electronically to 51.8 percent of ERISA plan investors during the first year or during any subsequent year in which the plan begins a new advisory relationship. Paper contract disclosures will be mailed to the remaining 48.2 percent of ERISA plan investors. The contract will be distributed electronically to 44.1 percent of IRAs and non-ERISA plan investors during the first year or during any subsequent year in which the investor enters into a new advisory relationship. Paper contracts will be mailed to the remaining 55.9 percent of IRAs and non-ERISA plan investors. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $32.5 million during the first year and $4.3 million during subsequent years. Paper distribution will also require two minutes of clerical time to print and mail the disclosure or contract,
The Department assumes that ERISA plans that do not allow participants to direct investments will engage in two transactions per month that require pre-transaction disclosures. The Department assumes that ERISA plan participants and IRA holders will engage in two transactions per year that require pre-transaction disclosures. Therefore, the Department estimates that plans and IRAs will receive 62.9 million three page pre-transaction disclosures during the second year and all subsequent years. The pre-transaction disclosures will be distributed electronically for 51.8 percent of the ERISA plan investors and 44.1 percent of the IRA holders and non-ERISA plan participants. The remaining 34.9 million disclosures will be mailed. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $22.4 million. Paper distribution will also require two minutes of clerical time to print and mail the statement, resulting in 1.2 million hours at an equivalent cost of $64.3 million annually.
The Department estimates that Financial Institutions will receive ten requests per year for more detailed information on the fees, costs, and compensation associated with the transaction during the second year and all subsequent years. The detailed disclosures will be distributed electronically for 51.8 percent of the ERISA plan investors and 44.1 percent of the IRA holders and non-ERISA plan participants. The Department believes that requests for additional information will be proportionally likely with each Retirement Investor type. Therefore, approximately 36,000 detailed disclosures will be distributed on paper. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $27,000. Paper distribution will also require two minutes of clerical time to print and mail the statement, resulting in 1,000 hours at an equivalent cost of $66,000 annually.
Finally, the Department estimates that all of the 7,000 Financial Institutions that are not Level Fee Fiduciaries will submit the required one-page disclosure to the Department electronically at de minimis cost during the first year.
The Department estimates that 13,000 Level Fee Fiduciaries will make recommendations to 3.0 million Retirement Investors with respect to ERISA plans, IRAs, and non-ERISA plans annually under level fee conditions.
Based on consultation with its legal staff, the Department estimates that the standard fiduciary acknowledgements required by Level Fee Fiduciaries will take 1 hour and 25 minutes to draft.
The fiduciary acknowledgements will be distributed electronically for 51.8 percent of ERISA plan investors and 44.1 percent of the IRA holders and non-ERISA plan investors. The remaining 1.6 million acknowledgements will be mailed. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $888,000. Paper distribution will also require two minutes of clerical time to print and mail the acknowledgement, resulting in 55,000 hours at an equivalent cost of $3.0 million annually.
The Department estimates that it will take financial advisers thirty minutes to record the documentation for each recommendation. This results in 1.5 million hours annually at an equivalent cost of $296.9 million.
Overall, the Department estimates that in order to meet the conditions of this class exemption, Financial Institutions and Advisers will distribute approximately 74.6 million disclosures and contracts during the first year and 73.3 million disclosures and contracts during subsequent years. Distributing these disclosures and contracts, and maintaining records that the conditions of the exemption have been fulfilled will result in a total of 2.5 million hours of burden during the first year and 2.5 million hours of burden in subsequent years. The equivalent cost of this burden is $201.5 million during the first year and $201.2 million in subsequent years. This exemption will result in an outsourced labor, materials, and postage cost burden of $1.6 billion during the first year and $380.7 million during subsequent years.
These paperwork burden estimates are summarized as follows:
This exemption, which is issued pursuant to section 408(a) of ERISA and section 4975(c)(2) of the IRC, is part of a broader rulemaking that includes other exemptions and a final regulation published in today's
The Secretary has determined that this rulemaking, including this exemption, will have a significant economic impact on a substantial number of small entities. The Secretary has separately published a Regulatory Impact Analysis (RIA) which contains the complete economic analysis for this rulemaking including the Department's FRFA for the rule and the related prohibited transaction exemptions. This section of this preamble sets forth a
As noted in section 6.1 of the RIA, the Department has determined that regulatory action is needed to mitigate conflicts of interest in connection with investment advice to retirement investors. The regulation is intended to improve plan and IRA investing to the benefit of retirement security. In response to the proposed rulemaking, organizations representing small businesses submitted comments expressing particular concern with three issues: The carve-out for investment education, the best interest contract exemption, and the carve-out for persons acting in the capacity of counterparties to plan fiduciaries with financial expertise. Section 2 of the RIA contains an extensive discussion of these concerns and the Department's response.
As discussed in section 6.2 of the RIA, the Small Business Administration (SBA) defines a small business in the Financial Investments and Related Activities Sector as a business with up to $38.5 million in annual receipts. In response to a comment received from the SBA's Office of Advocacy on our Initial Regulatory Flexibility Analysis, the Department contacted the SBA, and received from them a dataset containing data on the number of firms by NAICS codes, including the number of firms in given revenue categories. This dataset would allow the estimation of the number of firms with a given NAICS code that fall below the $38.5 million threshold and therefore be considered small entities by the SBA. However, this dataset alone does not provide a sufficient basis for the Department to estimate the number of small entities affected by the rule. Not all firms within a given NAICS code would be affected by this rule, because being an ERISA fiduciary relies on a functional test and is not based on industry status as defined by a NAICS code. Further, not all firms within a given NAICS code work with ERISA-covered plans and IRAs.
Over 90 percent of broker-dealers, registered investment advisers, insurance companies, agents, and consultants are small businesses according to the SBA size standards (13 CFR 121.201). Applying the ratio of entities that meet the SBA size standards to the number of affected entities, based on the methodology described at greater length in the RIA, the Department estimates that the number of small entities affected by this rule is 2,438 BDs, 16,521 RIAs, 496 Insurers, and 3,358 other ERISA service providers.
For purposes of the RFA, the Department continues to consider an employee benefit plan with fewer than 100 participants to be a small entity. Further, while some large employers may have small plans, in general small employers maintain most small plans. The definition of small entity considered appropriate for this purpose differs, however, from a definition of small business that is based on size standards promulgated by the SBA. These small pension plans will benefit from the rule, because as a result of the rule, they will receive non-conflicted advice from their fiduciary service providers. The 2013 Form 5500 filings show nearly 595,000 ERISA covered retirement plans with less than 100 participants.
Section 6.5 of the RIA summarizes the projected reporting, recordkeeping, and other compliance costs of the rule and exemptions, which are discussed in detail in section 5 of the RIA. Among other things, the Department concludes that it is likely that some small service providers may find that the increased costs associated with ERISA fiduciary status outweigh the benefits of continuing to service the ERISA plan market or the IRA market. The Department does not believe that this outcome will be widespread or that it will result in a diminution of the amount or quality of advice available to small or other retirement savers, because some firms will fill the void and provide services to the ERISA plan and IRA market. It is also possible that the economic impact of the rule and exemptions on small entities would not be as significant as it would be for large entities, because anecdotal evidence indicates that small entities do not have as many business arrangements that give rise to conflicts of interest. Therefore, they would not be confronted with the same costs to restructure transactions that would be faced by large entities.
Section 5.3.1 of the RIA includes a discussion of the changes to the proposed rule and exemptions that are intended to reduce the costs affecting both small and large business. These include elimination of data collection and annual disclosure requirements in the Best Interest Contract Exemption, and changes to the implementation of the contract requirement in the exemption. Section 7 of the RIA discusses significant regulatory alternatives considered by the Department and the reasons why they were rejected.
This exemption, along with related exemptions and a final rule published elsewhere in this issue of the
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under section 408(a) of ERISA and section 4975(c)(2) of the Code does not relieve a fiduciary, or other party in interest or disqualified person with respect to a plan, from certain other provisions of ERISA and the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of section 404 of ERISA which require, among other things, that a fiduciary act prudently and discharge his or her duties respecting the plan solely in the interests of the participants and beneficiaries of the plan. Additionally, the fact that a transaction is the subject of an exemption does not affect the requirement of section 401(a) of the Code that the plan must operate for the exclusive benefit of the employees of the employer maintaining the plan and their beneficiaries;
(2) The Department finds that the exemption is administratively feasible, in the interests of the plan and of its participants and beneficiaries, and protective of the rights of participants and beneficiaries of the plan;
(3) The exemption is applicable to a particular transaction only if the transaction satisfies the conditions specified in the exemption; and
(4) The exemption is supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
(a) In general. ERISA and the Internal Revenue Code prohibit fiduciary advisers to employee benefit plans
(b) Covered transactions. This exemption permits Advisers, Financial Institutions, and their Affiliates and Related Entities, to receive compensation as a result of their provision of investment advice within the meaning of ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B) to a Retirement Investor.
As defined in Section VIII(o) of the exemption, a Retirement Investor is: (1) A participant or beneficiary of a Plan with authority to direct the investment of assets in his or her Plan account or to take a distribution; (2) the beneficial owner of an IRA acting on behalf of the IRA; or (3) a Retail Fiduciary with respect to a Plan or IRA.
As detailed below, Financial Institutions and Advisers seeking to rely on the exemption must adhere to Impartial Conduct Standards in rendering advice regarding retirement investments. In addition, Financial Institutions must adopt policies and procedures designed to ensure that their individual Advisers adhere to the Impartial Conduct Standards; disclose important information relating to fees, compensation, and Material Conflicts of Interest; and retain records demonstrating compliance with the exemption. Level Fee Fiduciaries that will receive only a Level Fee in connection with advisory or investment management services must comply with more streamlined conditions designed to target the conflicts of interest associated with such services. The exemption provides relief from the restrictions of ERISA section 406(a)(1)(D) and 406(b) and the sanctions imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(D), (E) and (F). The Adviser and Financial Institution must comply with the applicable conditions of Sections II-V to rely on this exemption. This document also contains separate exemptions in Section VI (Exemption for Purchases and Sales, including Insurance and Annuity Contracts) and Section VII (Exemption for Pre-Existing Transactions).
(c) Exclusions. This exemption does not apply if:
(1) The Plan is covered by Title I of ERISA, and (i) the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the Plan, or (ii) the Adviser or Financial Institution is a named fiduciary or plan administrator (as defined in ERISA section 3(16)(A)) with respect to the Plan, or an affiliate thereof, that was selected to provide advice to the Plan by a fiduciary who is not Independent;
(2) The compensation is received as a result of a Principal Transaction;
(3) The compensation is received as a result of investment advice to a Retirement Investor generated solely by an interactive Web site in which computer software-based models or applications provide investment advice based on personal information each investor supplies through the Web site without any personal interaction or advice from an individual Adviser (
(4) The Adviser has or exercises any discretionary authority or discretionary control with respect to the recommended transaction.
The conditions set forth in this section include certain Impartial Conduct Standards, such as a Best Interest Standard, that Advisers and Financial Institutions must satisfy to rely on the exemption. In addition, Section II(d) and (e) requires Financial Institutions to adopt anti-conflict policies and procedures that are reasonably designed to ensure that Advisers adhere to the Impartial Conduct Standards, and requires disclosure of important information about the Financial Institutions' services, applicable fees and compensation. With respect to IRAs and other Plans not covered by Title I of ERISA, the Financial Institutions must agree that they and their Advisers will adhere to the exemption's standards in a written contract that is enforceable by the Retirement Investors. To minimize compliance burdens, the exemption provides that the contract terms may be incorporated into account opening documents and similar commonly-used agreements with new customers, permits reliance on a negative consent process with respect to existing contract holders, and provides a method of meeting the exemption requirement in the event that the Retirement Investor does not open an account with the Adviser but nevertheless acts on the advice through other channels. Advisers and Financial Institutions need not execute the contract before they make a recommendation to the Retirement Investor. However, the contract must cover any advice given prior to the contract date in order for the exemption to apply to such advice. There is no contract requirement for recommendations to Retirement Investors about investments in Plans covered by Title I of ERISA, but the Impartial Conduct Standards and other requirements of Section II(b)-(e), including a written acknowledgment of fiduciary status, must be satisfied in order for relief to be available under the exemption, as set forth in Section II(g). Section II(h) provides conditions for recommendations by Level Fee Fiduciaries, which, with their Affiliates, will receive only a Level Fee in connection with advisory or investment management services with respect to the Plan or IRA assets. Section II(i) provides conditions for referral fees received by banks and bank employees pursuant to Bank Networking Arrangements. Section II imposes the following conditions on Financial Institutions and Advisers:
(a) Contracts with Respect to Investments in IRAs and Other Plans Not Covered by Title I of ERISA. If the investment advice concerns an IRA or a Plan that is not covered by Title I of ERISA, the advice is subject to an enforceable written contract on the part of the Financial Institution, which may be a master contract covering multiple recommendations, that is entered into in accordance with this Section II(a) and incorporates the terms set forth in Section II(b)-(d). The Financial Institution additionally must provide the disclosures required by Section II(e). The contract must cover advice rendered prior to the execution of the contract in order for the exemption to apply to such advice and related compensation.
(1)
(ii) Amendment of Existing Contracts by Negative Consent. As an alternative to executing a contract in the manner set forth in the preceding paragraph, the Financial Institution may amend Existing Contracts to include the terms required in Section II(b)-(d) by delivering the proposed amendment and the disclosure required by Section II(e) to the Retirement Investor prior to January 1, 2018, and considering the failure to terminate the amended contract within 30 days as assent. An Existing Contract is an investment advisory agreement, investment program agreement, account opening agreement, insurance contract, annuity contract, or similar agreement or contract that was executed before January 1, 2018, and remains in effect. If the Financial Institution elects to use the negative consent procedure, it may deliver the proposed amendment by mail or electronically, but it may not impose any new contractual obligations, restrictions, or liabilities on the Retirement Investor by negative consent.
(iii) Failure to enter into contract. Notwithstanding a Financial Institution's failure to enter into a contract as required by subsection (i) above with a Retirement Investor who does not have an Existing Contract, this exemption will apply to the receipt of compensation by the Financial Institution, or any Adviser, Affiliate or Related Entity thereof, as a result of the Adviser's or Financial Institution's investment advice to such Retirement Investor regarding an IRA or non-ERISA Plan, provided:
(A) The Adviser making the recommendation does not receive compensation, directly or indirectly, that is reasonably attributable to the Retirement Investor's purchase, holding, exchange or sale of the investment;
(B) The Financial Institution's policies and procedures prohibit the Financial Institution and its Affiliates and Related Entities from providing compensation to their Advisers in lieu of compensation described in subsection (iii)(A), including, but not limited to bonuses or prizes or other incentives, and the Financial Institution reasonably monitors such policies and procedures;
(C) The Adviser and Financial Institution comply with the Impartial Conduct Standards set forth in Section II(c), the policies and procedures requirements of Section II(d) (except for the requirement of a warranty with respect to those policies and procedures), the web disclosure requirements of Section III(b) and, as applicable, the conditions of Sections IV(b)(3)-(6) (Conditions for Advisers and Financial Institution that restrict recommendations, in whole or part, to Proprietary Products or to investments that generate Third Party Payments) with respect to the recommendation; and
(D) The Financial Institution's failure to enter into the contract is not part of an effort, attempt, agreement, arrangement or understanding by the Adviser or the Financial Institution designed to avoid compliance with the exemption or enforcement of its conditions, including the contractual conditions set forth in subsections (i) and (ii).
(2)
(b)
(c)
(1) When providing investment advice to the Retirement Investor, the Financial Institution and the Adviser(s) provide investment advice that is, at the time of the recommendation, in the Best Interest of the Retirement Investor. As further defined in Section VIII(d), such advice reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party;
(2) The recommended transaction will not cause the Financial Institution, Adviser or their Affiliates or Related Entities to receive, directly or indirectly, compensation for their services that is in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(3) Statements by the Financial Institution and its Advisers to the Retirement Investor about the recommended transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's investment decisions, will not be materially misleading at the time they are made.
(d)
(1) The Financial Institution has adopted and will comply with written policies and procedures reasonably and prudently designed to ensure that its Advisers adhere to the Impartial Conduct Standards set forth in Section II(c);
(2) In formulating its policies and procedures, the Financial Institution has specifically identified and documented its Material Conflicts of Interest; adopted measures reasonably and prudently designed to prevent Material Conflicts of Interest from causing violations of the Impartial Conduct Standards set forth in Section II(c); and designated a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring their Advisers' adherence to the Impartial Conduct Standards.
(3) The Financial Institution's policies and procedures require that neither the Financial Institution nor (to the best of its knowledge) any Affiliate or Related Entity use or rely upon quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Notwithstanding the foregoing, this Section II(d)(3) does not prevent the Financial Institution, its Affiliates or Related Entities from providing Advisers with differential compensation (whether in type or amount, and including, but not limited to, commissions) based on investment decisions by Plans, participant or beneficiary accounts, or IRAs, to the extent that the Financial Institution's policies and procedures and incentive practices, when viewed as a whole, are reasonably and prudently designed to avoid a misalignment of the interests of Advisers with the interests of the Retirement Investors they serve as fiduciaries (such compensation practices can include differential compensation based on neutral factors tied to the differences in the services delivered to the Retirement Investor
(e)
(1) States the Best Interest standard of care owed by the Adviser and Financial Institution to the Retirement Investor; informs the Retirement Investor of the services provided by the Financial Institution and the Adviser; and describes how the Retirement Investor will pay for services, directly or through Third Party Payments. If, for example, the Retirement Investor will pay through commissions or other forms of transaction-based payments, the contract or writing must clearly disclose that fact;
(2) Describes Material Conflicts of Interest; discloses any fees or charges the Financial Institution, its Affiliates, or the Adviser imposes upon the Retirement Investor or the Retirement Investor's account; and states the types of compensation that the Financial Institution, its Affiliates, and the Adviser expect to receive from third parties in connection with investments recommended to Retirement Investors;
(3) Informs the Retirement Investor that the Investor has the right to obtain copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as the specific disclosure of costs, fees, and compensation, including Third Party Payments, regarding recommended transactions, as set forth in Section III(a), below, described in dollar amounts, percentages, formulas, or other means reasonably designed to present materially accurate disclosure of their scope, magnitude, and nature in sufficient detail to permit the Retirement Investor to make an informed judgment about the costs of the transaction and about the significance and severity of the Material Conflicts of Interest, and describes how the Retirement Investor can get the information, free of charge; provided that if the Retirement Investor's request is made prior to the transaction, the information must be provided prior to the transaction, and if the request is made after the transaction, the information must be provided within 30 business days after the request;
(4) Includes a link to the Financial Institution's Web site as required by Section III(b), and informs the Retirement Investor that: (i) Model contract disclosures updated as necessary on a quarterly basis are maintained on the Web site, and (ii) the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) are available free of charge on the Web site;
(5) Discloses to the Retirement Investor whether the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to any recommended investments; and to the extent the Financial Institution or Adviser limits investment recommendations, in whole or part, to Proprietary Products or investments that generate Third Party Payments, notifies the Retirement Investor of the limitations placed on the universe of investments that the Adviser may offer for purchase, sale, exchange, or holding by the Retirement Investor. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis;
(6) Provides contact information (telephone and email) for a representative of the Financial Institution that the Retirement Investor can use to contact the Financial Institution with any concerns about the advice or service they have received; and, if applicable, a statement explaining that the Retirement Investor can research the Financial Institution and its Advisers using FINRA's BrokerCheck database or the Investment Adviser Registration Depository (IARD), or other database maintained by a governmental agency or instrumentality, or self-regulatory organization; and
(7) Describes whether or not the Adviser and Financial Institution will monitor the Retirement Investor's investments and alert the Retirement Investor to any recommended change to those investments, and, if so monitoring, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted.
(8) The Financial Institution will not fail to satisfy this Section II(e), or violate a contractual provision based thereon, solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, provided the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. To the extent compliance with this Section II(e) requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(f)
(1) Exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms;
(2) Except as provided in paragraph (f)(4) of this Section, a provision under which the Plan, IRA or Retirement Investor waives or qualifies its right to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or in an individual or class claim agrees to an amount representing liquidated damages for breach of the contract; provided that, the parties may knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law; or
(3) Agreements to arbitrate or mediate individual claims in venues that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption.
(4) In the event that the provision on pre-dispute arbitration agreements for class or representative claims in paragraph (f)(2) of this Section is ruled invalid by a court of competent jurisdiction, this provision shall not be
(g)
(1) Prior to or at the same time as the execution of the recommended transaction, the Financial Institution provides the Retirement Investor with a written statement of the Financial Institution's and its Advisers' fiduciary status, in accordance with Section II(b).
(2) The Financial Institution and the Adviser comply with the Impartial Conduct Standards of Section II(c).
(3) The Financial Institution adopts policies and procedures incorporating the requirements and prohibitions set forth in Section II(d)(1)-(3), and the Financial Institution and Adviser comply with those requirements and prohibitions.
(4) The Financial Institution provides the disclosures required by Section II(e).
(5) The Financial Institution and Adviser do not in any contract, instrument, or communication: purport to disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by ERISA section 410; purport to waive or qualify the right of the Retirement Investor to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or require arbitration or mediation of individual claims in locations that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption.
(h)
(1) Prior to or at the same time as the execution of the recommended transaction, the Financial Institution provides the Retirement Investor with a written statement of the Financial Institution's and its Advisers' fiduciary status, in accordance with Section II(b).
(2) The Financial Institution and Adviser comply with the Impartial Conduct Standards of Section II(c).
(3)(i) In the case of a recommendation to roll over from an ERISA Plan to an IRA, the Financial Institution documents the specific reason or reasons why the recommendation was considered to be in the Best Interest of the Retirement Investor. This documentation must include consideration of the Retirement Investor's alternatives to a rollover, including leaving the money in his or her current employer's Plan, if permitted, and must take into account the fees and expenses associated with both the Plan and the IRA; whether the employer pays for some or all of the plan's administrative expenses; and the different levels of services and investments available under each option; and (ii) in the case of a recommendation to rollover from another IRA or to switch from a commission-based account to a level fee arrangement, the Level Fee Fiduciary documents the reasons that the arrangement is considered to be in the Best Interest of the Retirement Investor, including, specifically, the services that will be provided for the fee.
(i)
The Financial Institution must satisfy the following conditions with respect to an investment recommendation, to be covered by this exemption:
(a)
(1) States the Best Interest standard of care owed by the Adviser and Financial Institution to the Retirement Investor; and describes any Material Conflicts of Interest;
(2) Informs the Retirement Investor that the Retirement Investor has the right to obtain copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as specific disclosure of costs, fees and other compensation including Third Party Payments regarding recommended transactions. The costs, fees, and other compensation may be described in dollar amounts, percentages, formulas, or other means reasonably designed to present materially accurate disclosure of their scope, magnitude, and nature in sufficient detail to permit the Retirement Investor to make an informed judgment about the costs of the transaction and about the significance and severity of the Material Conflicts of Interest. The information required under this Section must be provided to the Retirement Investor prior to the transaction, if requested prior to the transaction, and, if the request is made after the transaction, the information must be provided within 30 business days after the request; and
(3) Includes a link to the Financial Institution's Web site as required by Section III(b) and informs the Retirement Investor that: (i) Model contract disclosures or other model notices, updated as necessary on a quarterly basis, are maintained on the Web site, and (ii) the Financial Institution's written description of its policies and procedures as required under Section III(b)(1)(iv) are available free of charge on the Web site.
(4) These disclosures do not have to be repeated for subsequent recommendations by the Adviser and Financial Institution of the same investment product within one year of the provision of the contract disclosure in Section II(e) or a previous disclosure pursuant to this Section III(a), unless there are material changes in the subject of the disclosure.
(b)
(1) The Financial Institution maintains a Web site, freely accessible to the public and updated no less than quarterly, which contains:
(i) A discussion of the Financial Institution's business model and the Material Conflicts of Interest associated with that business model;
(ii) A schedule of typical account or contract fees and service charges;
(iii) A model contract or other model notice of the contractual terms (if applicable) and required disclosures described in Section II(b)-(e), which are reviewed for accuracy no less frequently than quarterly and updated within 30 days if necessary;
(iv) A written description of the Financial Institution's policies and procedures that accurately describes or summarizes key components of the policies and procedures relating to conflict-mitigation and incentive practices in a manner that permits Retirement Investors to make an informed judgment about the stringency of the Financial Institution's protections against conflicts of interest;
(v) To the extent applicable, a list of all product manufacturers and other parties with whom the Financial Institution maintains arrangements that provide Third Party Payments to either the Adviser or the Financial Institution with respect to specific investment products or classes of investments recommended to Retirement Investors; a description of the arrangements, including a statement on whether and how these arrangements impact Adviser compensation, and a statement on any benefits the Financial Institution provides to the product manufacturers or other parties in exchange for the Third Party Payments;
(vi) Disclosure of the Financial Institution's compensation and incentive arrangements with Advisers including, if applicable, any incentives (including both cash and non-cash compensation or awards) to Advisers for recommending particular product manufacturers, investments or categories of investments to Retirement Investors, or for Advisers to move to the Financial Institution from another firm or to stay at the Financial Institution, and a full and fair description of any payout or compensation grids, but not including information that is specific to any individual Adviser's compensation or compensation arrangement.
(vii) The Web site may describe the above arrangements with product manufacturers, Advisers, and others by reference to dollar amounts, percentages, formulas, or other means reasonably calculated to present a materially accurate description of the arrangements. Similarly, the Web site may group disclosures based on reasonably-defined categories of investment products or classes, product manufacturers, Advisers, and arrangements, and it may disclose reasonable ranges of values, rather than specific values, as appropriate. But, however constructed, the Web site must fairly disclose the scope, magnitude, and nature of the compensation arrangements and Material Conflicts of Interest in sufficient detail to permit visitors to the Web site to make an informed judgment about the significance of the compensation practices and Material Conflicts of Interest with respect to transactions recommended by the Financial Institution and its Advisers.
(2) To the extent the information required by this Section is provided in other disclosures which are made public, including those required by the SEC and/or the Department such as a Form ADV, Part II, the Financial Institution may satisfy this Section III(b) by posting such disclosures to its Web site with an explanation that the information can be found in the disclosures and a link to where it can be found.
(3) The Financial Institution is not required to disclose information pursuant to this Section III(b) if such disclosure is otherwise prohibited by law.
(4) In addition to providing the written description of the Financial Institution's policies and procedures on its Web site, as required under Section III(b)(1)(iv), Financial Institutions must provide their complete policies and procedures adopted pursuant to Section II(d) to the Department upon request.
(5) In the event that a Financial Institution determines to group disclosures as described in subsection (1)(vii), it must retain the data and documentation supporting the group disclosure during the time that it is applicable to the disclosure on the Web site, and for six years after that, and make the data and documentation available to the Department within 90 days of the Department's request.
(c)(1) The Financial Institution will not fail to satisfy the conditions in this Section III solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, or if the Web site is temporarily inaccessible, provided that, (i) in the case of an error or omission on the Web site, the Financial Institution discloses the correct information as soon as practicable, but not later than seven (7) days after the date on which it discovers or reasonably should have discovered the error or omission, and (ii) in the case of an error or omission with respect to the transaction disclosure, the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission.
(2) To the extent compliance with the Section III disclosures requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (i) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (ii) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(3) The good faith provisions of this Section apply to the requirement that the Financial Institution retain the data and documentation supporting the group disclosure during the time that it is applicable to the disclosure on the Web site and provide it to the Department upon request, as set forth in subsection (b)(1)(vii) and (b)(5) above. In addition, if such records are lost or destroyed, due to circumstances beyond the control of the Financial Institution, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and no party, other than the Financial Institution responsible for complying with subsection (b)(1)(vii) and (b)(5) will be subject to the civil penalty that may be assessed under ERISA section 502(i) or the taxes imposed by Code section 4975(a) and (b), if applicable, if the records are not maintained or provided to the Department within the required timeframes.
(a)
(b)
(1) Prior to or at the same time as the execution of the recommended transaction, the Retirement Investor is clearly and prominently informed in writing that the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to the purchase, sale, exchange, or holding of recommended investments; and the Retirement Investor is informed in writing of the limitations placed on the universe of investments that the Adviser may recommend to the Retirement Investor. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis;
(2) Prior to or at the same time as the execution of the recommended transaction, the Retirement Investor is fully and fairly informed in writing of any Material Conflicts of Interest that the Financial Institution or Adviser have with respect to the recommended transaction, and the Adviser and Financial Institution comply with the disclosure requirements set forth in Section III above (providing for web and transaction-based disclosure of costs, fees, compensation, and Material Conflicts of Interest);
(3) The Financial Institution documents in writing its limitations on the universe of recommended investments; documents in writing the Material Conflicts of Interest associated with any contract, agreement, or arrangement providing for its receipt of Third Party Payments or associated with the sale or promotion of Proprietary Products; documents in writing any services it will provide to Retirement Investors in exchange for Third Party Payments, as well as any services or consideration it will furnish to any other party, including the payor, in exchange for the Third Party Payments; reasonably concludes that the limitations on the universe of recommended investments and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to receive compensation in excess of reasonable compensation for Retirement Investors as set forth in Section II(c)(2); reasonably determines, after consideration of the policies and procedures established pursuant to Section II(d), that these limitations and Material Conflicts of Interest will not cause the Financial Institution or its Advisers to recommend imprudent investments; and documents in writing the bases for its conclusions;
(4) The Financial Institution adopts, monitors, implements, and adheres to policies and procedures and incentive practices that meet the terms of Section II(d)(1) and (2); and, in accordance with Section II(d)(3), neither the Financial Institution nor (to the best of its knowledge) any Affiliate or Related Entity uses or relies upon quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause the Adviser to make imprudent investment recommendations, to subordinate the interests of the Retirement Investor to the Adviser's own interests, or to make recommendations based on the Adviser's considerations of factors or interests other than the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor;
(5) At the time of the recommendation, the amount of compensation and other consideration reasonably anticipated to be paid, directly or indirectly, to the Adviser, Financial Institution, or their Affiliates or Related Entities for their services in connection with the recommended transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and
(6) The Adviser's recommendation reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor; and the Adviser's recommendation is not based on the financial or other interests of the Adviser or on the Adviser's consideration of any factors or interests other than the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor.
This Section establishes record retention and disclosure conditions that a Financial Institution must satisfy for the exemption to be available for compensation received in connection with recommended transactions.
(a)
(b)
(1) If such records are lost or destroyed, due to circumstances beyond the control of the Financial Institution, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and
(2) No party, other than the Financial Institution responsible for complying with this paragraph (c), will be subject to the civil penalty that may be assessed under ERISA section 502(i) or the taxes imposed by Code section 4975(a) and (b), if applicable, if the records are not maintained or are not available for examination as required by paragraph (c), below.
(c)(1) Except as provided in paragraph (c)(2) of this Section or precluded by 12 U.S.C. 484, and notwithstanding any provisions of ERISA section 504(a)(2) and (b), the records referred to in paragraph (b) of this Section are reasonably available at their customary location for examination during normal business hours by:
(i) Any authorized employee or representative of the Department or the Internal Revenue Service;
(ii) Any fiduciary of a Plan that engaged in an investment transaction pursuant to this exemption, or any authorized employee or representative of such fiduciary;
(iii) Any contributing employer and any employee organization whose members are covered by a Plan described in paragraph (c)(1)(ii), or any authorized employee or representative of these entities; or
(iv) Any participant or beneficiary of a Plan described in paragraph (c)(1)(ii), IRA owner, or the authorized representative of such participant, beneficiary or owner; and
(2) None of the persons described in paragraph (c)(1)(ii)-(iv) of this Section are authorized to examine records regarding a recommended transaction involving another Retirement Investor, privileged trade secrets or privileged
(3) Should the Financial Institution refuse to disclose information on the basis that the information is exempt from disclosure, the Financial Institution must, by the close of the thirtieth (30th) day following the request, provide a written notice advising the requestor of the reasons for the refusal and that the Department may request such information.
(4) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
(a)
(b)
(c) The following conditions are applicable to this exemption:
(1) The transaction is effected by the Financial Institution in the ordinary course of its business;
(2) The compensation, direct or indirect, for any services rendered by the Financial Institution and its Affiliates and Related Entities is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and
(3) The terms of the transaction are at least as favorable to the Plan, participant or beneficiary account, or IRA as the terms generally available in an arm's length transaction with an unrelated party.
(d)
(1) The Plan is covered by Title I of ERISA and (i) the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the Plan, or (ii) the Adviser and Financial Institution is a named fiduciary or plan administrator (as defined in ERISA section 3(16)(A)) with respect to the Plan, or an affiliate thereof, that was selected to provide advice to the plan by a fiduciary who is not Independent.
(2) The compensation is received as a result of a Principal Transaction;
(3) The compensation is received as a result of investment advice to a Retirement Investor generated solely by an interactive Web site in which computer software-based models or applications provide investment advice based on personal information each investor supplies through the Web site without any personal interaction or advice from an individual Adviser (
(4) The Adviser has or exercises any discretionary authority or discretionary control with respect to the recommended transaction.
(a)
(b)
(1) The compensation is received pursuant to an agreement, arrangement or understanding that was entered into prior to the Applicability Date and that has not expired or come up for renewal post-Applicability Date;
(2) The purchase, exchange, holding or sale of the securities or other investment property was not otherwise a non-exempt prohibited transaction pursuant to ERISA section 406 and Code section 4975 on the date it occurred;
(3) The compensation is not received in connection with the Plan's, participant or beneficiary account's or IRA's investment of additional amounts in the previously acquired investment vehicle; except that for avoidance of doubt, the exemption does apply to a recommendation to exchange investments within a mutual fund family or variable annuity contract) pursuant to an exchange privilege or rebalancing program that was established before the Applicability Date, provided that the recommendation does not result in the Adviser and Financial Institution, or their Affiliates or Related Entities, receiving more compensation (either as a fixed dollar amount or a percentage of assets) than they were entitled to receive prior to the Applicability Date;
(4) The amount of the compensation paid, directly or indirectly, to the Adviser, Financial Institution, or their Affiliates or Related Entities in connection with the transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2); and
(5) Any investment recommendations made after the Applicability Date by the Financial Institution or Adviser with respect to the securities or other investment property reflect the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, and are made without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party.
For purposes of these exemptions:
(a) “Adviser” means an individual who:
(1) Is a fiduciary of the Plan or IRA solely by reason of the provision of investment advice described in ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B), or both, and the applicable regulations, with respect to the assets of the Plan or IRA involved in the recommended transaction;
(2) Is an employee, independent contractor, agent, or registered representative of a Financial Institution; and
(3) Satisfies the federal and state regulatory and licensing requirements of insurance, banking, and securities laws with respect to the covered transaction, as applicable.
(b) “Affiliate” of an Adviser or Financial Institution means—
(1) Any person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution. For this purpose, “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual;
(2) Any officer, director, partner, employee, or relative (as defined in ERISA section 3(15)), of the Adviser or Financial Institution; and
(3) Any corporation or partnership of which the Adviser or Financial Institution is an officer, director, or partner.
(c) A “Bank Networking Arrangement” is an arrangement for the referral of retail non-deposit investment products that satisfies applicable federal banking, securities and insurance regulations, under which employees of a bank refer bank customers to an unaffiliated investment adviser registered under the Investment Advisers Act of 1940 or under the laws of the state in which the adviser maintains its principal office and place of business, insurance company qualified to do business under the laws of a state, or broker or dealer registered under the Securities Exchange Act of 1934, as amended. For purposes of this definition, a “bank” is a bank or similar financial institution supervised by the United States or a state, or a savings association (as defined in section 3(b)(1) of the Federal Deposit Insurance Act (12 U.S.C. 1813(b)(1)),
(d) Investment advice is in the “Best Interest” of the Retirement Investor when the Adviser and Financial Institution providing the advice act with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party. Financial Institutions that limit investment recommendations, in whole or part, based on whether the investments are Proprietary Products or generate Third Party Payments, and Advisers making recommendations subject to such limitations are deemed to satisfy the Best Interest standard when they comply with the conditions of Section IV(b).
(e) “Financial Institution” means an entity that employs the Adviser or otherwise retains such individual as an independent contractor, agent or registered representative and that is:
(1) Registered as an investment adviser under the Investment Advisers Act of 1940 (15 U.S.C. 80b-1
(2) A bank or similar financial institution supervised by the United States or a state, or a savings association (as defined in section 3(b)(1) of the Federal Deposit Insurance Act (12 U.S.C. 1813(b)(1));
(3) An insurance company qualified to do business under the laws of a state, provided that such insurance company:
(i) Has obtained a Certificate of Authority from the insurance commissioner of its domiciliary state which has neither been revoked nor suspended,
(ii) Has undergone and shall continue to undergo an examination by an Independent certified public accountant for its last completed taxable year or has undergone a financial examination (within the meaning of the law of its domiciliary state) by the state's insurance commissioner within the preceding 5 years, and
(iii) Is domiciled in a state whose law requires that actuarial review of reserves be conducted annually by an Independent firm of actuaries and reported to the appropriate regulatory authority;
(4) A broker or dealer registered under the Securities Exchange Act of 1934 (15 U.S.C. 78a
(5) An entity that is described in the definition of Financial Institution in an individual exemption granted by the Department under ERISA section 408(a) and Code section 4975(c), after the date of this exemption, that provides relief for the receipt of compensation in connection with investment advice provided by an investment advice fiduciary, under the same conditions as this class exemption.
(f) “Independent” means a person that:
(1) Is not the Adviser, the Financial Institution or any Affiliate relying on the exemption;
(2) Does not have a relationship to or an interest in the Adviser, the Financial Institution or Affiliate that might affect the exercise of the person's best judgment in connection with transactions described in this exemption; and
(3) Does not receive or is not projected to receive within the current federal income tax year, compensation or other consideration for his or her own account from the Adviser, Financial Institution or Affiliate in excess of 2% of the person's annual revenues based upon its prior income tax year.
(g) “Individual Retirement Account” or “IRA” means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
(h) A Financial Institution and Adviser are “Level Fee Fiduciaries” if the only fee received by the Financial Institution, the Adviser and any
(i) A “Material Conflict of Interest” exists when an Adviser or Financial Institution has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.
(j) “Plan” means any employee benefit plan described in section 3(3) of the Act and any plan described in section 4975(e)(1)(A) of the Code.
(k) A “Principal Transaction” means a purchase or sale of an investment product if an Adviser or Financial Institution is purchasing from or selling to a Plan, participant or beneficiary account, or IRA on behalf of the Financial Institution's own account or the account of a person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with the Financial Institution. For purposes of this definition, a Principal Transaction does not include the sale of an insurance or annuity contract, a mutual fund transaction, or a Riskless Principal Transaction as defined in Section VIII(p) below.
(l) “Proprietary Product” means a product that is managed, issued or sponsored by the Financial Institution or any of its Affiliates.
(m) “Related Entity” means any entity other than an Affiliate in which the Adviser or Financial Institution has an interest which may affect the exercise of its best judgment as a fiduciary.
(n) A “Retail Fiduciary” means a fiduciary of a Plan or IRA that is not described in section (c)(1)(i) of the Regulation (29 CFR 2510.3-21(c)(1)(i)).
(o) “Retirement Investor” means—
(1) A participant or beneficiary of a Plan subject to Title I of ERISA or described in section 4975(e)(1)(A) of the Code, with authority to direct the investment of assets in his or her Plan account or to take a distribution,
(2) The beneficial owner of an IRA acting on behalf of the IRA, or
(3) A Retail Fiduciary with respect to a Plan subject to Title I of ERISA or described in section 4975(e)(1)(A) of the Code or IRA.
(p) A “Riskless Principal Transaction” is a transaction in which a Financial Institution, after having received an order from a Retirement Investor to buy or sell an investment product, purchases or sells the same investment product for the Financial Institution's own account to offset the contemporaneous transaction with the Retirement Investor.
(q) “Third-Party Payments” include sales charges when not paid directly by the Plan, participant or beneficiary account, or IRA; gross dealer concessions; revenue sharing payments; 12b-1 fees; distribution, solicitation or referral fees; volume-based fees; fees for seminars and educational programs; and any other compensation, consideration or financial benefit provided to the Financial Institution or an Affiliate or Related Entity by a third party as a result of a transaction involving a Plan, participant or beneficiary account, or IRA.
(a)
(b)
(c)
(1) The Plan is covered by Title I of ERISA, and (i) the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the Plan, or (ii) the Adviser or Financial Institution is a named fiduciary or plan administrator (as defined in ERISA section 3(16)(A)) with respect to the Plan, or an Affiliate thereof, that was selected to provide advice to the Plan by a fiduciary who is not Independent;
(2) The compensation is received as a result of a Principal Transaction;
(3) The compensation is received as a result of investment advice to a Retirement Investor generated solely by an interactive Web site in which computer software-based models or applications provide investment advice based on personal information each investor supplies through the Web site without any personal interaction or advice from an individual Adviser (
(4) The Adviser has or exercises any discretionary authority or discretionary control with respect to the recommended transaction.
(d)
(1) The Financial Institution and Adviser adhere to the following standards:
(i) When providing investment advice to the Retirement Investor, the Financial Institution and the Adviser(s) provide investment advice that is, at the time of the recommendation, in the Best Interest of the Retirement Investor. As further defined in Section VIII(d), such advice reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party;
(ii) The recommended transaction does not cause the Financial Institution, Adviser or their Affiliates or Related Entities to receive, directly or indirectly, compensation for their services that is in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(iii) Statements by the Financial Institution and its Advisers to the Retirement Investor about the recommended transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's investment decisions, are not materially misleading at the time they are made.
(2)
(i) Affirmatively states that the Financial Institution and the Adviser(s) act as fiduciaries under ERISA or the Code, or both, with respect to the recommendation;
(ii) Sets forth the standards in paragraph (d)(1) of this Section and affirmatively states that it and the Adviser(s) adhered to such standards in recommending the transaction;
(iii) Describes the Financial Institution's Material Conflicts of Interest; and
(iv) Discloses to the Retirement Investor whether the Financial Institution offers Proprietary Products or receives Third Party Payments with respect to any investment recommendations; and to the extent the Financial Institution or Adviser limits investment recommendations, in whole or part, to Proprietary Products or investments that generate Third Party Payments, notifies the Retirement Investor of the limitations placed on the universe of investment recommendations. The notice is insufficient if it merely states that the Financial Institution or Adviser “may” limit investment recommendations based on whether the investments are Proprietary Products or generate Third Party Payments, without specific disclosure of the extent to which recommendations are, in fact, limited on that basis.
(v) The disclosure may be provided in person, electronically or by mail. It does not have to be repeated for any subsequent recommendations during the Transition Period.
(vi) The Financial Institution will not fail to satisfy this Section IX(d)(2) solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, provided the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. To the extent compliance with this Section IX(d)(2) requires Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know, or unless they should have known, that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(3) The Financial Institution designates a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards; and
(4) The Financial Institution complies with the recordkeeping requirements of Section V(b) and (c).
Employee Benefits Security Administration (EBSA), U.S. Department of Labor.
Adoption of Class Exemption.
This document contains an exemption from certain prohibited transactions provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code (the Code). The provisions at issue generally prohibit fiduciaries with respect to employee benefit plans and individual retirement accounts (IRAs) from purchasing and selling investments when the fiduciaries are acting on behalf of their own accounts (principal transactions). The exemption permits principal transactions and riskless principal transactions in certain investments between a plan, plan participant or beneficiary account, or an IRA, and a fiduciary that provides investment advice to the plan or IRA, under conditions to safeguard the interests of these investors. The exemption affects participants and beneficiaries of plans, IRA owners, and fiduciaries with respect to such plans and IRAs.
Brian Shiker, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor (202) 693-8824 (not a toll-free number).
The Department grants this exemption in connection with its publication today, elsewhere in this issue of the
This exemption allows investment advice fiduciaries to engage in purchases and sales of certain investments out of their inventory (
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant administrative exemptions from ERISA's prohibited transaction provisions.
The exemption allows an individual investment advice fiduciary (an Adviser)
The exemption is calibrated to align the Adviser's interests with those of the plan or IRA customer, while leaving the Adviser and the Financial Institution the flexibility and discretion necessary to determine how best to satisfy the exemption's standards in light of the unique attributes of their business. Financial Institutions relying on the exemption must obtain the Retirement Investor's consent to participate in principal transactions and riskless principal transactions, and the Financial Institutions are subject to recordkeeping requirements.
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Order and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal agencies to develop a plan under which the agencies will periodically review their existing significant regulations to make the agencies' regulatory programs more effective or less burdensome in achieving their regulatory objectives.
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the OMB. Section 3(f) of Executive Order 12866, defines a “significant regulatory action” as an action that is likely to result in a rule (1) having an annual effect on the economy of $100 million or more, or adversely and materially affecting a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities (also referred to as “economically significant” regulatory actions); (2) creating serious inconsistency or otherwise interfering with an action taken or planned by another agency; (3) materially altering the budgetary impacts of entitlement grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raising novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of the Executive Order, OMB has determined that this action is “significant” within the meaning of Section 3(f)(1) of the Executive Order. Accordingly, the Department has undertaken an assessment of the costs and benefits of the proposal, and OMB has reviewed this regulatory action. The Department's complete Regulatory Impact Analysis is available at
The Department proposed this class exemption on its own motion, pursuant to ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637 (October 27, 2011)).
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of stringent fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans and their participants and beneficiaries.
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service. Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violations of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, ERISA section 3(21)(A) and Code section 4975(e)(3) provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, the providers of investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c)(1975) defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of section 3(21)(A)(ii) of ERISA (the 1975 regulation).
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At the same time, the variety and complexity of financial products have increased, widening the information gap between advisers and their clients. Plan fiduciaries, plan participants and IRA investors must often rely on experts for advice, but are unable to assess the quality of the expert's advice or effectively guard against the adviser's conflicts of interest. This challenge is especially true of retail investors, who typically do not have financial expertise and can ill-afford lower returns to their retirement savings caused by conflicts. The IRA accounts of these investors often account for all or the lion's share of their assets, and can represent all of savings earned for a lifetime of work. Losses and reduced returns can be devastating to the investors who depend upon such savings for support in their old age. As baby boomers retire, they are increasingly moving money from ERISA-covered plans, where their employer has both the incentive and the fiduciary duty to facilitate sound investment choices, to IRAs where both good and bad investment choices are myriad and advice that is conflicted is commonplace. These rollovers are expected to approach $2.4 trillion cumulatively from 2016 through 2020.
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the 1975 regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B) (the Regulation), which are also published in this issue of the
The Regulation describes the types of advice that constitute “investment advice” with respect to plan or IRA assets for purposes of the definition of a fiduciary at ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B). The Regulation covers ERISA-covered plans, IRAs, and other plans not covered by Title I, such as Keogh plans, and health savings accounts described in Code section 223(d).
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, plan participant or beneficiary, IRA or IRA owner, the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage versus advisory), or recommendations with respect to rollovers, transfers or distributions from a plan or IRA, including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also provides that as a threshold matter in order to be fiduciary advice, the communication must be a “recommendation” as defined therein. The Regulation, as a matter of clarification, provides that a variety of other communications do not constitute “recommendations,” including non-fiduciary investment education; general communications; and specified communications by platform providers. These communications which do not rise to the level of “recommendations” under the Regulation are discussed more fully in the preamble to the final Regulation.
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person making the recommendation must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); (2) the person must fairly inform the independent fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and must fairly inform the independent fiduciary of the existence and nature of the person's financial interests in the transaction; (3) the person must know or reasonably believe that the independent fiduciary of the plan or IRA is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); and (4) the person cannot receive a fee or other compensation directly from the plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner for the provision of investment advice (as opposed to other services) in connection with the transaction.
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in ERISA section 3(3)) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Exchange Act (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
The Department anticipates that the Regulation will cover many investment professionals who did not previously consider themselves to be fiduciaries under ERISA or the Code. Under the Regulation, these entities will be subject to the prohibited transaction restrictions in ERISA and the Code that apply specifically to fiduciaries. ERISA section 406(b)(1) and Code section 4975(c)(1)(E) prohibit a fiduciary from dealing with the income or assets of a plan or IRA in his own interest or his own account. ERISA section 406(b)(2), which does not apply to IRAs, provides that a fiduciary shall not “in his individual or in any other capacity act in any transaction involving the plan on behalf of a party (or represent a party) whose interests are adverse to the interests of the plan or the interests of its participants or beneficiaries.” ERISA section 406(b)(3) and Code section 4975(c)(1)(F) prohibit a fiduciary from receiving any consideration for his own personal account from any party dealing with the plan or IRA in connection with a transaction involving assets of the plan or IRA.
Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA.
The purchase or sale of an investment in a principal transaction or riskless principal transaction between a plan or IRA and a fiduciary, resulting from the fiduciary's provision of investment advice, implicates the prohibited
Certain principal transactions and riskless principal transactions between a plan or IRA and an investment advice fiduciary may not need exemptive relief because they are blind transactions executed on an exchange. The ERISA Conference Report states that a transaction will, generally, not be a prohibited transaction if the transaction is an ordinary “blind” purchase or sale of securities through an exchange where neither the buyer nor the seller (nor the agent of either) knows the identity of the other party involved.
As the prohibited transaction provisions demonstrate, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however, the statutes provide exemptions from their broad prohibitions on conflicts of interest. In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions. However, when they choose to give advice in which they have a conflict of interest, they must rely upon an exemption.
ERISA section 408(b)(14) provides a statutory exemption for transactions entered into in connection with the provision of fiduciary investment advice to a participant or beneficiary of an individual account plan or an IRA owner. The exemption provides relief for, among other things, the acquisition, holding, or sale of a security or other property as an investment under the plan pursuant to the investment advice. As set forth in ERISA section 408(g), the exemption is available if the advice is provided under an “eligible investment advice arrangement” which either (1) “provides that any fees (including any commission or other compensation) received by the fiduciary adviser for investment advice or with respect to the sale, holding or acquisition of any security or other property for purposes of investment of plan assets do not vary depending on the basis of any investment option selected” or (2) “uses a computer model under an investment advice program meeting the requirements of [ERISA section 408(g)(3)].” The ERISA section 408(g) exemptions include special conditions calibrated to insulate the fiduciary adviser from conflicts of interest. Code section 4975(d)(17) provides the same relief from the taxes imposed by Code section 4975(a) and (b).
ERISA section 408(b)(16) provides relief for transactions involving the purchase or sale of securities between a plan and a party in interest, including an investment advice fiduciary, if the transactions are executed through an electronic communication network, alternative trading system, or similar execution system or trading venue. Among other conditions, subparagraph (B) of the statutory exemption requires that either: (i) “the transaction is effected pursuant to rules designed to match purchases and sales at the best price available through the execution system in accordance with applicable rules of the Securities and Exchange Commission or other relevant governmental authority,” or (ii) “neither the execution system nor the parties to the transaction take into account the identity of the parties in the execution of trades[.]” The transactions covered by ERISA section 408(b)(16) include principal transactions between a plan and an investment advice fiduciary. Code section 4975(d)(19) provides the same relief from the taxes imposed by Code section 4975(a) and (b).
An administrative exemption for certain principal transactions will continue to be available through PTE 75-1.
Further, Part II(1) of PTE 75-1 provides relief from ERISA section 406(a) and Code section 4975(c)(1)(A) through (D) for the purchase or sale of a security in a principal transaction between a plan or IRA and a broker-dealer registered under the Exchange Act or a bank supervised by the United States or a state. However, the exemption permits plans and IRAs to engage in principal transactions with broker-dealers and banks only if the broker-dealers and banks do not have or exercise any discretionary authority or control (except as a directed trustee) with respect to the investment of plan or IRA assets involved in the transaction, and
In connection with the proposed Regulation, the Department recognized the need for additional relief. Accordingly, the Department proposed this exemption for principal transactions in certain debt securities between a plan, participant or beneficiary account, or IRA, and an investment advice fiduciary. The proposed exemption was intended to facilitate continued access by plan and IRA investors to certain types of investments commonly sold in principal transactions.
The Department also proposed the Best Interest Contract Exemption, which is adopted elsewhere in this issue of the
At the same time that the Department has granted these new exemptions, it has also amended existing exemptions to ensure uniform application of the Impartial Conduct Standards, which are fundamental obligations of fair dealing and fiduciary conduct, and include obligations to act in the customer's Best Interest, avoid misleading statements, and receive no more than reasonable compensation.
The amendments also revoke certain existing exemptions, which provided little or no protections to IRA and non-ERISA plan participants, in favor of a more uniform application of the Best Interest Contract Exemption in the market for retail investments. With limited exceptions, it is the Department's intent that investment advice fiduciaries in the retail investment market rely on statutory exemptions, the Best Interest Contract Exemption, or this exemption to the extent that they receive conflicted forms of compensation that would otherwise be prohibited. The new and amended exemptions reflect the Department's view that Retirement Investors should be protected by a more consistent application of fundamental fiduciary standards across a wide range of investment products and advice relationships, and that retail investors, in particular, should be protected by the stringent protections set forth in the Best Interest Contract Exemption and this exemption. When fiduciaries have conflicts of interest, they will uniformly be expected to adhere to fiduciary norms and to make recommendations that are in their customer's Best Interest.
These new and amended exemptions follow a lengthy public notice and comment process, which gave interested persons an extensive opportunity to comment on this proposed exemption, proposed Regulation and other related exemption proposals. The proposals initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department then held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule.
As finalized, this exemption for certain principal transactions and riskless principal transactions retains the core protections of the proposed exemption, but with revisions designed to facilitate implementation and compliance with the exemption's terms. In broadest outline, the exemption permits Advisers and the Financial Institutions that employ or otherwise retain them to enter into principal transactions and riskless principal transactions with plans and IRAs regarding certain investments, provided that they give advice regarding the transactions that is in their customers' Best Interest and the Financial Institution implements basic protections against the dangers posed by conflicts of interest. In particular, to rely on the exemption, Financial Institutions must:
• Acknowledge fiduciary status with respect to any investment advice regarding principal transactions or riskless principal transactions;
• Adhere to Impartial Conduct Standards requiring them to
○ Give advice that is in the Retirement Investor's Best Interest (
○ Seek to obtain the best execution reasonably available under the circumstances with respect to the transaction; and
○ Make no misleading statements about investment transactions, compensation, and conflicts of interest;
• Implement policies and procedures reasonably and prudently designed to prevent violations of the Impartial Conduct Standards;
• Refrain from giving or using incentives for Advisers to act contrary to the customer's Best Interest; and
• Make additional disclosures.
The exemption takes a principles-based approach that permits Financial Institutions and Advisers to enter into transactions that would otherwise be prohibited. The exemption holds Financial Institutions and their Advisers responsible for adhering to fundamental standards of fiduciary conduct and fair dealing, while leaving them the flexibility and discretion necessary to determine how best to satisfy these basic standards in light of the unique attributes of their particular businesses. The exemption's principles-based conditions, which are rooted in the law of trust and agency, have the breadth and flexibility necessary to apply to a large range of investment and compensation practices, while ensuring that Advisers put the interests of Retirement Investors first. When Advisers choose to give advice regarding principal transactions and riskless principal transactions to Retirement Investors, they must protect their customers from the dangers posed by conflicts of interest.
In order to ensure compliance with the exemption's broad protective standards and purposes, the exemption gives special attention to the enforceability of the exemption's terms by Retirement Investors. When Financial Institutions and Advisers breach their obligations under the exemption and cause losses to Retirement Investors, it is generally critical that the investors have a remedy to redress the injury. The existence of enforceable rights and remedies gives Financial Institutions and Advisers a powerful incentive to comply with the exemption's standards, implement policies and procedures that are more than window-dressing, and carefully police conflicts of interest to ensure that the conflicts of interest do not taint the advice.
Thus, in the case of IRAs and non-ERISA plans, the exemption requires the Financial Institution to commit to the Impartial Conduct Standards in an enforceable contract with Retirement Investor customers. The exemption does not similarly require the Financial Institution to execute a separate contract with ERISA investors (plan participants, beneficiaries, and fiduciaries), but the Financial Institution must acknowledge its fiduciary status and that of its Advisers, and ERISA investors can directly enforce their rights to proper fiduciary conduct under ERISA section 502(a)(2) and (3). In addition, the exemption safeguards Retirement Investors' enforcement rights by providing that Financial Institutions and Advisers may not rely on the exemption if they include contractual provisions disclaiming liability for compensatory remedies or waiving or qualifying Retirement Investors' right to pursue a class action or other representative action in court. However, the exemption does permit Financial Institutions to include provisions waiving the right to punitive damages or rescission as contract remedies to the extent permitted by other applicable laws. In the Department's view, the availability of make-whole relief for such claims is sufficient to protect Retirement Investors and incentivize compliance with the exemption's conditions.
While the final exemption retains the proposed exemption's core protections, the Department has revised the exemption to ease implementation in response to commenters' concerns about the exemption's workability. Thus, for example, the final exemption eliminates the contract requirement altogether in the ERISA context and simplifies the mechanics of contract-formation for IRAs and plans not covered by Title I of ERISA. For new customers, the final exemption provides that the required contract terms may simply be incorporated in the Financial Institution's account opening documents and similar commonly-used agreements. The exemption additionally permits reliance on a negative consent process for existing contract holders. The Department recognizes that Retirement Investors may talk to numerous Advisors in numerous settings over the course of their relationship with a Financial Institution. Accordingly, the exemption also simplifies execution of the contract by simply requiring the Financial Institution to execute the contract, rather than each of the individual Advisers from whom the Retirement Investor receives advice. For similar reasons, the exemption does not require execution of the contract at the start of Retirement Investors' conversations with Advisers, as long as it is entered into prior to or at the same time as the recommended transaction.
As a means of facilitating use of the exemption, the Department also reduced compliance burdens by eliminating some of the conditions that were not critical to the exemption's protective purposes, and expanding the scope of the exemption's coverage (
While making these changes to facilitate the implementation of the exemption, the Department emphasizes that the exemption is limited because of the severity of the conflicts of interest associated with principal transactions. When acting as a principal in a transaction involving a plan, participant or beneficiary account, or IRA, a fiduciary can have difficulty reconciling its duty to avoid conflicts of interest with its concern for its own financial interests as the Retirement Investor's counterparty. Of primary concern are issues involving liquidity, pricing, transparency, and the fiduciary's possible incentive to “dump” unwanted assets. The scope of this exemption balances the Department's significant concerns regarding principal transactions with the need to preserve market choice for plans, participants and beneficiary accounts, and IRAs.
The comments on this exemption, the Best Interest Contract Exemption, the Regulation, and related exemptions have helped the Department improve this exemption, while preserving and enhancing its protections. As described above, the Department has revised the exemption to facilitate implementation and compliance with the exemption, without diluting its core protections, which are critical to reducing the harm caused by conflicts of interest in the marketplace for advice. The tax-preferred investments covered by the exemption are critical to the financial security and physical health of investors. After consideration of the comments, the Department remains convinced of the importance of the exemption's core protections.
ERISA and the Code are rightly skeptical of the dangers posed by conflicts of interest, and generally prohibit conflicted advice. Before granting exemptive relief, the Department has a statutory obligation to ensure that the exemption is in the interests of plan and IRA investors and protective of their rights. Adherence to the fundamental fiduciary norms and basic protective conditions of this exemption helps ensure that investment recommendations are not driven by Adviser conflicts, but by the Best Interest of the Retirement Investor. The
The preamble sections that follow provide a much more detailed discussion of the exemption's terms, comments on the exemption, and the Department's responses to those comments. After a discussion of the exemption's scope and limitations, the preamble discusses the conditions of the exemptions.
The exemption provides relief for “Advisers” and “Financial Institutions” to enter into “principal transactions” and “riskless principal transactions” in “principal traded assets” with plans and IRAs. For purposes of the exemption, a principal transaction is a transaction in which an Adviser or Financial Institution is purchasing from or selling to the plan, participant or beneficiary account, or IRA on behalf of the account of the Financial Institution or the account of any person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with the Financial Institution. The term principal transaction does not include a riskless principal transaction as defined in the exemption. A riskless principal transaction is defined as a transaction in which a Financial Institution, after having received an order from a Retirement Investor to buy or sell a principal traded asset, purchases or sells the asset for the Financial Institution's own account to offset the contemporaneous transaction with the Retirement Investor.
The exemption uses the term “Retirement Investor” to describe the types of persons who can be investment advice recipients under the exemption, and the term “Affiliate” to describe people and entities with a connection to the Adviser or Financial Institution. These terms are defined in Section VI of this exemption. The following sections discuss the scope and conditions of the exemption as well as key definitional terms.
The exemption provides relief for principal transactions and riskless principal transactions involving certain investments, referred to as “principal traded assets,” between a plan, participant or beneficiary account, or IRA, and an Adviser, Financial Institution or an entity in a control relationship with the Financial Institution, when the transaction is a result of an Adviser's or Financial Institution's provision of investment advice. Relief is provided from ERISA sections 406(a)(1)(A) and (D), and 406(b)(1) and (2), and the taxes imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(A), (D) and (E). Relief has not been provided in this exemption from ERISA section 406(b)(3) and Code section 4975(c)(1)(F), which prohibit a fiduciary from receiving any consideration for its own personal account from any party dealing with the plan or IRA in connection with a transaction involving the assets of the plan or IRA.
The principal traded assets that are permitted to be
In addition, the final exemption includes a feature under which the definition of principal traded asset can be expanded without amending the class exemption. Under the definition of principal traded asset, investments can be added to the class exemption in the future based on an individual exemption granted by the Department. Accordingly, a principal traded asset for purposes of the class exemption also includes an investment that is permitted to be purchased under an individual exemption granted by the Department after the issuance date of this exemption, that provides relief for investment advice fiduciaries to engage in the purchase of the investment in a principal transaction or riskless principal transaction with a plan or IRA under the same conditions as this exemption. To the extent parties wish to expand the definition of principal traded asset in the future, they can submit a request for an individual exemption to the Department setting forth the specific attributes of the principal traded asset, the sales and compensation practices, and how conflicts of interest will be mitigated with respect to principal transactions and riskless principal transactions in that principal traded asset. If the exemption is granted, the class exemption will expand to include that investment within the definition of principal traded asset.
The exemption's definition of principal traded assets is more expansive with respect to the
As proposed, the exemption limited the types of assets that could be traded (both bought and sold) on a principal basis to corporate debt securities offered pursuant to a registration statement under the Securities Act of 1933, treasury securities, and agency securities. The Department received many comments regarding this limitation and the general intent of the exemption. Supporting comments emphasized that the exemption's limited scope and conditions were appropriate for the mitigation of conflicts of interest and the protection of plans and IRAs. One commenter particularly supported the exemption's approach of granting relief only to those securities least likely to be subject to principal trading abuses. The commenter supported, in particular, the exclusion of municipal securities.
Others urged the Department to broaden the scope of the exemption. Many of these commenters argued that principal transactions are necessary for the maintenance of inventory, liquidity, access to investments, and best execution. They contended that the failure to provide broader relief would drive up the cost to investors, and hinder normal transactions that are generally classified as facilitation trades or riskless principal transactions. Commenters took the position that the Department should not substitute its judgment for the judgment of investors and advisers. In particular, commenters
A number of comments noted that the proposal did not specifically address riskless principal transactions. In a riskless principal transaction, according to a commenter, a Financial Institution, after receiving an order to purchase or sell a security from a customer, purchases or sells the investment for its own account to offset the contemporaneous transaction with the customer. Commenters argued that riskless principal transactions are the functional equivalent of agency transactions. A commenter asserted that for this reason, riskless principal transactions would not involve the incentive to dump unwanted investments on Retirement Investors, which was one of the Department's concerns. Another commenter indicated that without wider availability of riskless principal transactions, many investments would not be available at all to plans and IRAs because it is typical for broker-dealers to engage in transactions with third parties on a riskless principal basis rather than a pure agency basis. One commenter stated that this is because counterparties may not want to assume settlement risk with an investor.
After consideration of these comments, the Department concurs with commenters that broader relief in this area is appropriate. The Department intended that the proposal cover riskless principal transactions within the general meaning of principal transactions, but the transactions would have been limited to the debt securities covered under the proposed exemption. The Department agrees with commenters that, to the extent a Financial Institution engages in a transaction based on an existing customer order, the riskless principal transaction can be viewed as functionally similar to an agency transaction, and the Department accepts the position of commenters that some investments may not be functionally available without this relief. For this reason, the Department expanded the scope of the companion Best Interest Contract Exemption to permit riskless principal transactions in all investments, and provide relief for compensation received in connection with such transactions, subject to the conditions of that exemption.
The Department also clarified that this exemption is available for riskless principal transactions involving principal traded assets. The definition of a principal transaction now explicitly excludes riskless principal transactions, and the exemption's scope specifically encompasses both principal transactions and separately-defined riskless principal transactions. In this manner, the exemption now clearly draws a distinction between principal transactions and riskless principal transactions and provides relief for both with respect to principal traded assets.
This approach results in some overlap between coverage of riskless principal transactions in the Best Interest Contract Exemption and this exemption. With respect to a recommended purchase of an investment that occurs in a riskless principal transaction, this exemption is available for principal traded assets. The Best Interest Contract Exemption, however, provides broader relief for all recommended purchases. In addition,
This approach is intended to provide flexibility to Financial Institutions relying on the exemptions. The Department believes that some Financial Institutions have business models that involve only riskless principal transactions. These Financial Institutions may not, as a general matter, hold investments in inventory to sell in principal transactions, but they may execute certain transactions as riskless principal transactions. Financial Institutions that do not engage in principal transactions, as defined in the exemptions, do not have to rely on this exemption at all, and can organize their practices to comply with the Best Interest Contract Exemption alone.
On the other hand, Financial Institutions that engage in both principal transactions and riskless principal transactions may want to organize their practices to comply with this exemption. They may not be certain at the outset whether a particular purchase by a plan or IRA will be executed as a principal transaction or a riskless principal transaction. Those Financial Institutions can rely on this exemption for principal traded assets that may be sold to plans and IRAs without concern for whether the transaction is, in fact a riskless principal transaction or principal transaction.
Some commenters requested that this exemption extend to principal transactions in specific additional types of securities or investments, including municipal securities, currency, agency debt securities, CDs (including brokered CDs), asset backed securities, unit investment trusts (UITs), equities (including new issue and initial public offerings), new issue of debt securities, preferred securities, foreign corporate securities, foreign sovereign debt, debt of a charitable organization, derivatives, bank note offerings and wrap or other contracts that are not insurance products.
In response, the Department added to this final exemption CDs, UITs, and asset backed securities guaranteed by an agency or GSE. Both CDs and UITs were included as investments permitted to be sold under the proposed Best Interest Contract Exemption, and commenters informed us that these investments are typically sold in principal transactions. Without relief for CDs and UITs in this exemption, commenters asserted that Retirement Investors might lose access to such investments. Commenters indicated that these investments were common investments in ERISA plans, IRAs and non-ERISA plans. The Department therefore included them in this final exemption. As with the exemptive relief originally proposed regarding principal transactions in debt securities, the Department believes that the conflicts of interest created by principal transactions in CDs and UITs are effectively addressed by the conditions of this exemption so as to protect the interests of Retirement Investors while maintaining Retirement Investors' access to these investments.
Agency and GSE guaranteed asset backed securities were always intended to be included in the definition of debt security. The proposal provided that agency debt securities were defined by reference to the Financial Industry Regulatory Authority (FINRA) rule 6710(l).
Reflecting this expansion of relief to CDs, UITs and agency and GSE guaranteed asset backed securities, the final exemption uses the term “principal traded asset,” rather than “debt security” to describe the
As explained in greater detail below, the Department did not expand the purchase provisions of the exemption, as some commenters suggested, to include other investments such as municipal securities, currency, asset backed securities, equities (including new issue and initial public offerings), new issue of debt securities, preferred securities, foreign corporate securities, foreign sovereign debt, debt of a charitable organization, derivatives, bank note offerings and wrap or other contracts that are not insurance products. The Department determined that the conditions of this exemption may not be appropriately tailored to these types of investments. The Department invites interested parties to request an individual exemption for other investments that they would like to see included in this class exemption. This will provide the Department with the opportunity to gain additional information about those investments, their sales practices and associated conflicts of interest.
Other commenters sought to more generally expand the scope of the exemption. Some commenters felt that unrestricted relief should be provided with respect to all principal transactions with few, if any, conditions. Some of these commenters took issue with the Department's decision to place any limitations at all on investments that can be purchased or sold in a principal transaction. The commenters expressed the view that the Department was substituting its judgment for those of individual investors and their advisers.
In support of their approach, a few commenters urged the Department to more closely hew to the approach taken under the securities laws, citing Temporary Rule 206(3)-3T issued by the Securities and Exchange Commission (SEC) under the Investment Advisers Act of 1940.
Commenters also focused on principal transactions involving sales by plans and IRAs. Commenters indicated that broader relief was necessary to provide liquidity for Retirement Investors. They said that Financial Institutions serve an essential function in purchasing securities from their clients who need such liquidity.
The Department did not accept the commenters' call for relief for all principal transactions. The Department's approach in the proposal of this exemption was intentionally narrow, based on the potentially acute conflicts of interest associated with principal transactions that are recommended by fiduciaries. The Department believes that broad relief for all principal transactions, without tailored conditions, is inconsistent with longstanding principles that fiduciaries must act with loyalty to Retirement Investors. Because the fiduciary is on both sides of a principal transaction, the fiduciary duty of loyalty is sorely tested. In addition, the securities typically traded in principal transactions often lack objective market prices and Retirement Investors may have difficulty evaluating the fairness of a particular transaction. Principal traded investments also can be associated with low liquidity, low transparency and the possible incentive to dump unwanted investments.
Therefore, although the Department's approach harmonizes in many ways, as discussed below, with the disclosures required by the SEC's Temporary Rule 206(3)-3T, the Department did not adopt an exemption that is as broad in scope. The Department also notes in this respect that the SEC has not yet finalized its approach to rule 206(3)-3T, and the SEC has indicated the delay is related to the SEC's consideration of regulatory standards of care for broker-dealers and investment advisers under section 913 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act). In the most recent release proposing to extend the Temporary Rule, the SEC stated:
As part of our broader consideration of the regulatory requirements applicable to broker-dealers and investment advisers, we intend to carefully consider principal trading by advisers, including whether rule 206(3)-3T should be substantively modified, supplanted, or permitted to sunset.
Although the Department retained the limited definition of principal traded asset, as discussed above, for recommendations that a plan or IRA
The Department also notes that the final Regulation provides additional ways in which parties can engage in principal transactions and riskless principal transactions and avoid prohibited transactions. The Regulation provides that a person is not a fiduciary when the person engages in an arm's length transaction with an independent plan fiduciary with financial expertise, as defined in the Regulation. Financial professionals that engage in such transactions are not considered fiduciaries, and may rely on other exemptions such as PTE 75-1, Part II, or ERISA section 408(b)(17) and Code section 4975(d)(20), for a broader range of principal transactions and riskless principal transactions. Therefore, the concerns of commenters such as the Stable Value Investment Association, about principal transactions involving a stable value fund managed by a professional investment manager, should be addressed in that fashion.
Finally, this exemption does not affect the ability of a self-directed investor to obtain the services of a financial professional to effect or execute a transaction involving any type of investment, in the absence of investment advice. In that sense, the Department is not limiting investment opportunities for individual investors or substituting the Department's judgment for theirs. Instead, the exemption is aimed squarely at conflicted investment advice by fiduciaries and is intended to minimize the harms of such conflicts of interest.
In this regard, one commenter requested a clarification as to whether an exemption is necessary for the provision of principal transaction services where the services do not involve the provision of individual recommendations to a plan or IRA. In
The exclusions set forth in Section I(c) of the proposal remain a part of the final exemption. First, under Section I(c)(1), Advisers who have or exercise discretionary authority or discretionary control with respect to management of the assets of a plan, participant or beneficiary account, or IRA or who exercise any discretionary authority or control respecting management or the disposition of the assets, or have any discretionary authority or discretionary responsibility in the administration of the plan, participant or beneficiary account, or IRA, may not take advantage of relief under the exemption to engage in principal transactions and riskless principal transactions with such investors.
A comment related to this provision asked that the limitation on investment managers be modified so that Financial Institutions that sponsor separately managed accounts that use independent, individual investment managers should be permitted to engage in principal transactions on behalf of their managed plans and IRAs with the sponsor. The Department did not adopt this suggestion. Instead, the Department notes that the Regulation was revised to provide that a person does not act as a fiduciary when engaged in an arm's length transaction with a plan fiduciary with financial expertise under the circumstances set forth in the Regulation. In such circumstances, the financial professionals may, therefore, rely on existing exemptions for non-fiduciary principal transactions and riskless principal transactions.
Second, under Section I(c)(2), the exemption is not available for a principal transaction involving a plan covered by Title I of ERISA if the Adviser or Financial Institution, or any Affiliate is the employer of employees covered by the plan. In accordance with this condition, the exemption is not available for a principal transaction entered into as part of a rollover from such a plan to an IRA, where the principal transaction is being executed by the plan, not the IRA. This restriction on employers does not apply in the case of an IRA or other similar plan that is not covered by Title I of ERISA. Accordingly, an Adviser or Financial Institution may provide advice to the beneficial owner of an IRA who is employed by the Adviser, its Financial Institution or an Affiliate, and receive compensation as a result, provided the IRA is not covered by Title I of ERISA.
No comments were received specific to the principal transactions exemption on proposed Section I(c)(2). Comments were received, however, on the same language, proposed in Section I(c)(1), of the Best Interest Contract Exemption. Specifically, industry commenters requested elimination of this exclusion in the Best Interest Contract Exemption. In particular, they said that Financial Institutions in the business of providing investment advice should not be compelled to hire a competitor to provide services to the Financial Institution's own plan. They warned that the exclusion could effectively prevent these Financial Institutions from providing any investment advice to their employees. Some commenters additionally stated that for compliance reasons, employees of a Financial Institution are often required to maintain their financial assets with that Financial Institution. As a result, they argued employees of Financial Institutions could be denied access to investment advice on their retirement savings.
As with the Best Interest Contract Exemption, the Department has not scaled back the exclusion. As noted above, the Department did not receive comments requesting that Financial Institutions be able to engage in principal transactions with their in-house plans. More generally, however, the Department continues to be concerned that the danger of abuse is compounded when the advice recipient receives recommendations from the employer, upon whom he or she depends for a job, to make investments in which the employer has a financial interest. To protect employees from abuse, employers generally should not be in a position to use their employees' retirement benefits as potential revenue or profit sources, without stringent safeguards. See,
Section I(c)(2) further provides that the exemption is unavailable if the Adviser or Financial Institution is a named fiduciary or plan administrator, as defined in ERISA section 3(16)(A) with respect to an ERISA plan, or an Affiliate thereof, that was selected to provide advice to the plan by a fiduciary who is not independent of them. This provision is intended to disallow the selection of Advisers and Financial Institutions by named fiduciaries or plan administrators that have a significant financial stake in the selection and was adopted in the final exemption unchanged from the proposal.
Section I, discussed above, establishes the scope of relief provided by this Principal Transactions Exemption. Sections II-V set forth the conditions of the exemption. All applicable conditions must be satisfied in order to avoid application of the specified prohibited transaction provisions of ERISA and the Code. The Department finds that, subject to these conditions, the exemption is administratively feasible, in the interests of plans and of their participants and beneficiaries, and IRA owners and protective of the rights of the participants and beneficiaries of such plans and IRA owners. Under ERISA section 408(a), and Code section 4975(c)(2), the Secretary may not grant an exemption without making such findings. The conditions of the exemption, comments on those conditions, and the Department's responses, are described below.
Section II of the exemption sets forth the requirements that establish the Retirement Investor's enforceable right
The contract with Retirement Investors regarding IRAs and non-ERISA plans must include the Financial Institution's acknowledgment of its fiduciary status and that of its Advisers, as required by Section II(b); the Financial Institution's agreement that it and its Advisers will adhere to the Impartial Conduct Standards, including a Best Interest standard, as required by Section II(c); the Financial Institution's warranty that it has adopted and will comply with certain policies and procedures, including anti-conflict policies and procedures reasonably and prudently designed to ensure that Advisers adhere to the Impartial Conduct Standards, as required by Section II(d). The Financial Institution's disclosure of information about Material Conflicts of Interest associated with principal transactions and riskless principal transactions, as required by Section II(e), may be provided in the contract or in a separate single written disclosure. Section II(f) generally provides that the exemption is unavailable if the contract includes exculpatory provisions or provisions waiving the rights and remedies of the plan, IRA or Retirement Investor, including their right to participate in a class action in court. The contract may, however, provide for binding arbitration of individual claims, and may waive contractual rights to punitive damages or rescission.
The contract between the IRA or non-ERISA plan, and the Financial Institution, forms the basis of the IRA's or non-ERISA plan's enforcement rights. The Department intends that all the contractual obligations imposed on the Financial Institution (the Impartial Conduct Standards and warranties) will be actionable by the IRAs and non-ERISA plans. Because these standards are contractually imposed, an IRA or non-ERISA plan has a contract claim if, for example, its Adviser recommends an investment product that is not in the Best Interest of the IRA or other non-ERISA plan.
In the Department's view, these contractual rights serve a critical function for IRA owners and participants and beneficiaries of non-ERISA plans. Unlike participants and beneficiaries in plans covered by Title I of ERISA, IRA owners and participants and beneficiaries in non-ERISA plans do not have an independent statutory right to bring suit against fiduciaries for violation of the prohibited transaction rules. Nor can the Secretary of Labor bring suit to enforce the prohibited transactions rules on their behalf.
Under Section II(g), however, the written contract requirement does not apply to advice to Retirement Investors regarding transactions with plans that are covered by Title I of ERISA (ERISA plans) in light of the existing statutory framework which provides a pre-existing enforcement mechanism for these investors and the Department. Instead, Advisers and Financial Institutions must satisfy the provisions in Section II(b)-(e) as conditions of the exemption when transacting with such Retirement Investors. Under the terms of the exemptions, the Financial Institution must provide a written acknowledgment of its and its Advisers' fiduciary status prior to or at the same time as the execution of the transaction, although it does not have to be part of a contract, as required by Section II(b); the Financial Institution and its Advisers must comply with the Impartial Conduct Standards, as required by Section II(c); the Financial Institutions must establish and comply with certain policies and procedures, as required by Section II(d); and they must provide the disclosures required by Section II(e).
If these conditions are not satisfied with respect to an ERISA plan engaging in a principal transaction or a riskless principal transaction, the Adviser and Financial Institution would be unable to rely on the exemption for relief from ERISA's prohibited transactions restrictions. An Adviser's failure to comply with the exemption would result in a non-exempt prohibited transaction under ERISA section 406 and would likely constitute a fiduciary breach under ERISA section 404. As a result, a plan, plan participant or beneficiary would be able to sue under ERISA section 502(a)(2) or (3) to recover any loss in value to the plan (including the loss in value to an individual account), or to obtain disgorgement of any wrongful profits or unjust enrichment. In addition, the Secretary of Labor can enforce ERISA's prohibited transaction and fiduciary duty provisions with respect to these ERISA plans, and an excise tax under the Code, as described above, applies.
In this regard, under Section II(g)(5) of the exemption, the Financial Institution and Adviser may not rely on the exemption if, in any contract, instrument, or communication they disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by ERISA section 410, waive or qualify the right of the Retirement Investor to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or require arbitration or mediation of individual claims in locations that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption. The exemption's enforceability, and the potential for liability, is critical to ensuring adherence to the exemption's stringent standards and protections, notwithstanding the competing pull of the conflicts of interest associated with principal transactions and riskless principal transactions.
The Department expects claims of Retirement Investors regarding investments in ERISA plans to be brought under ERISA's enforcement provisions, discussed above. In general, ERISA section 410 invalidates
A number of comments were received on the contract requirement as it was proposed. The comments, and the Department's responses, are discussed below. The Department notes that some of the commenters simply cross-referenced their comments, in the entirety, with respect to the same provisions in the proposed Best Interest Contract Exemption. Additionally, some commenters focused their comments solely on the Best Interest Contract Exemption. The Department determined it was important that the contract provisions in the Best Interest Contract Exemption be compatible with the contract provisions in this exemption, so that the two exemptions can easily be used together. For this reason, the Department considered all comments made on either exemption on a consolidated basis, and made corresponding changes in the two exemptions. For ease of use, the Department has included in this preamble the same general discussion of comments as in the Best Interest Contract Exemption, despite the fact that some comments discussed below were not made directly with respect to this exemption.
In this regard, one commenter inquired as to whether the contract required in this exemption could be combined with the contract required by the Best Interest Contract Exemption, or whether two contracts would be needed. It was the Department's intent in crafting this exemption that it could be used in connection with the Best Interest Contract Exemption, and it is the Department's view that there need only be one contract. If parties wish to give themselves flexibility to engage in principal transactions and riskless principal transactions with Retirement Investors, they can include the contract provisions that are specific to principal transactions and riskless principal transactions and obtain the Retirement Investor's consent to participate in such transactions.
A number of commenters took the position that the consumer protections afforded by the contract requirement are an essential feature of the exemption, particularly in the IRA market. Commenters indicated that enforceability is critical in the IRA market because of IRA owners' lack of a statutory right to enforce prohibited transactions provisions. Commenters said that, in order to achieve the goal of providing meaningful new protections to Retirement Investors, the exemption must provide a mechanism by which Advisers and Financial Institutions can be held legally accountable for the retirement recommendations they make.
Many other commenters, however, raised significant objections to the contract requirement. Commenters pointed to certain conditions of the exemption that they found ambiguous or subjective and indicated that these conditions could form the basis of class action lawsuits by disappointed investors. Some commenters said the contract requirement and associated litigation exposure will cause investment advice providers to cease serving Retirement Investors or provide only fee-based accounts that do not vary on the basis of the advice provided, resulting in the loss of services to retirement investors with smaller account balances. These commenters stated that investment advice fiduciaries would not risk the anticipated legal liability for Retirement Investors, or at least with respect to small accounts. Commenters also indicated that the SEC's Temporary Rule 206(3)-3T already addresses the issues regarding principal transactions that the Department is attempting to address.
In the final exemption, the Department retained the contract requirement with respect to IRAs and non-ERISA plans. The contractual commitment provides an administrable means of ensuring fiduciary conduct, eliminating ambiguity about the fiduciary nature of the relationship, and enforcing the exemption's conditions, thereby assuring compliance. The existence of enforceable rights and remedies gives Financial Institutions and Advisers a powerful incentive to comply with the exemption's standards, implement effective anti-conflict policies and procedures, and carefully police conflicts of interest. The enforceable contract gives clarity to the fiduciary nature of the undertaking, and ensures that Advisers and Financial Institutions do not subordinate the interests of the Retirement Investor to their own competing financial interests. The contract effectively aligns the interests of Retirement Investor, Advisers, and the Financial Institution, and gives the Retirement Investor the means to redress injury when violations occur.
Without a contract, the possible imposition of an excise tax provides an additional, but inadequate incentive to ensure compliance with the exemption's standards-based approach. This is particularly true because imposition of the excise tax critically depends on fiduciaries' self-reporting of violations, rather than independent investigations and litigation by the IRS. In contrast, contract enforcement does not rely on conflicted fiduciaries' assessment of their own adherence to fiduciary norms or require the creation and expansion of a government enforcement apparatus. The contract provides an administrable way of ensuring adherence to fiduciary standards, broadly applicable to an enormous range of investments and advice relationships.
The enforceability of the exemption's provisions enables the Department to grant exemptive relief based upon broad protective standards rather than rely exclusively upon highly proscriptive conditions. In the context of this exemption, the risk of litigation and enforcement serves many of the same functions that it has for hundreds of years under the law of trust and agency. It gives fiduciaries a powerful incentive to adhere to broad, flexible, and protective standards applicable to principal transactions and riskless principal transactions by imposing liability and providing a remedy when fiduciaries fail to comply with those standards.
In addition, a number of features of this final exemption, discussed more fully below, should temper commenters' concerns about the risk of excessive litigation. In particular, the exemption permits Advisers and Financial Institutions to require mandatory arbitration of individual claims, so that claims that do not involve systemic abuse or entire classes of participants can be resolved outside of court. Similarly, the exemption permits waivers of the right to obtain punitive damages or rescission based on violation of the contract. In the Department's view, make-whole compensatory relief is sufficient to incentivize compliance and redress injury caused by fiduciary misconduct. The Department has also clarified a number of the exemption's conditions and simplified the disclosure and
The core principles of the exemption are well-established under trust law, ERISA and the Code, and have a long history of interpretations in court. Moreover, the Impartial Conduct Standards are measured based on the circumstances existing at the time of the recommendation, not based on the ultimate performance of the investment with the benefit of hindsight. It is well settled as a legal matter that fiduciary advisers are not guarantors of the success of investments under ERISA or the Code, and this exemption does nothing to change that fact. Finally, the Department added provisions enabling Advisers and Financial Institutions to correct good faith errors in disclosure, without facing loss of the exemption.
The Department did not rely solely on the approach in the SEC's Temporary Rule 206(3)-3T, or another primarily disclosure-based approach, as suggested by some commenters. In the Department's view, disclosure of conflicts is a necessary, but not sufficient, basis for relief in the context of fiduciary self-dealing involving tax-favored accounts.
One commenter asked the Department to address the interaction of the contract cause of action and state securities laws. In this connection, the Department confirms that it is not the Department's intent to preempt or supersede state securities law and enforcement, and the state securities laws remain subject to the ERISA section 514(b)(2)(A) savings clause.
Under Section II(g) of the exemption, there is no contract requirement for transactions involving ERISA plans, but Financial Institutions and their Advisers must satisfy the conditions of Section II(b)-(e), including the conditions requiring written fiduciary acknowledgment, adherence to Impartial Conduct Standards, policies and procedures, and disclosures.
The Department eliminated the proposed contract requirement with respect to ERISA plans in this final exemption in response to public comment on this issue. A number of commenters indicated that the contract requirement was unnecessary for ERISA plans due to the statutory framework that already provides enforcement rights to such plans, their participants and beneficiaries, and the Secretary of Labor. Some commenters additionally questioned the extent to which the contract provided additional rights or remedies, and whether state-law contract claims would be pre-empted under ERISA's pre-emption provisions.
In the Department's view, the requirement that a Financial Institution provide written acknowledgement of fiduciary status for itself and its Advisers provides protections in the ERISA plan context that are comparable to the contract requirement for IRAs and non-ERISA plans. As a result of the written acknowledgment of fiduciary status, the fiduciary nature of the relationship will be clear to the parties both at the time of the investment transaction, and in the event of subsequent disputes over the conduct of the Advisers or Financial Institutions. There will be far less cause for the parties to litigate disputes over fiduciary status, as opposed to the substance of the fiduciaries' recommendations and conduct.
Section II(a) specifies the mechanics of entering into the contract and provides that the contract must be enforceable against the Financial Institution. In addition, the section indicates that the contract may be a master contract covering multiple recommendations, and that it may cover advice that was rendered prior to the execution of the contract as long as the contract is entered into prior to or at the same time as the execution of the recommended transaction.
Section II(a)(1) further describes the methods for obtaining customer assent to the contract. For “new contracts,” the Retirement Investor's assent must be demonstrated through a written or electronic signature. The exemption provides flexibility by permitting the contract terms to be set forth in a standalone document or in an investment advisory agreement, investment program agreement, account opening agreement, insurance or annuity contract or application, or similar document, or amendment thereto.
For Retirement Investors with “existing contracts,” the exemption permits assent to be evidenced either by affirmative consent, as described above, or by a negative consent procedure. Under the negative consent procedure, the Financial Institution delivers a proposed contract amendment along with the disclosure required in Section II(e) to the Retirement Investor prior to January 1, 2018, and if the Retirement Investor does not terminate the amended contract within 30 days, the amended contract is effective. If the Retirement Investor does terminate the contract within that 30-day period, this exemption will provide relief for 14 days after the date on which the termination is received by the Financial Institution.
Finally, Section II(a)(2) of the exemption requires the Financial Institution to maintain an electronic copy of the Retirement Investor's contract on its Web site that is accessible by the Retirement Investor. This condition ensures that the Retirement Investor has ready access to the terms of the contract, and reinforces the exemption's goals of clearly establishing the fiduciary status of the Adviser and Financial Institution and ensuring their adherence to the exemption's conditions.
Comments on specific contract operational issues are discussed below.
As proposed, Section II(a) required that, “[p]rior to recommending that the plan, participant or beneficiary account, or IRA purchase, sell or hold the Asset, the Adviser and Financial Institution enter into a written contract with the Retirement Investor that incorporates the terms required by Section II(b)-(e).” A large number of commenters responded to various aspects of this proposed requirement.
Many commenters objected to the timing of the contract requirement. They said that requiring execution of a contract “prior to” any recommendations would be contrary to existing industry practices. The commenters indicated that preliminary discussions may evolve into recommendations before a Retirement Investor has decided to work with a particular Adviser and Financial Institution. Requiring a contract upfront
In the Department's view, the precise timing of the contract is not critical to the exemption, provided that the parties enter into a contract covering the advice. The Department did not intend to chill developing advice relationships or limit investors' ability to shop around. Therefore, the Department adjusted the exemption on this point by deleting the proposed requirement that the contract be entered into prior to the advice recommendation. Instead, the exemption generally provides that the advice must be subject to an enforceable written contract entered into prior to or at the same time as the execution of the recommended transaction. However, in order for the exemption to be available to recommendations made prior to the contract's formation, the contract's terms must cover the prior recommendations.
A few commenters suggested that the Department require the contract to be a separate document, not combined with any other document. However, other commenters requested that the Department allow Financial Institutions to incorporate the contract terms into other account documents. While the Department believes the contract is critical to IRA and non-ERISA plan investors, the Department recognizes the need for flexibility in its implementation. Therefore, the exemption contemplates that the contract may be incorporated into other documents to the extent desired by the Financial Institution. Additionally, as requested by commenters, the Department confirms that the contract requirement may be satisfied through a master contract covering multiple recommendations and does not require execution prior to each additional recommendation.
A number of commenters questioned the necessity of the proposed requirement that Advisers be parties to the contract. These commenters indicated that the proposed requirement posed significant logistical challenges. For example, commenters stated that Advisers often work in teams and it would be difficult to obtain signatures from all such Advisers. Similarly, if call center representatives made recommendations that include principal transactions and riskless principal transactions, it could be hard to cover them under a contract. Over the course of a Retirement Investor's relationship with a Financial Institution, he or she could receive advice from a number of persons. Requiring that each such person execute a contract could prove difficult and unwieldy.
Based upon these objections, the Department deleted the requirement that individual Advisers be parties to the contract. The Financial Institution must be a party to the contract and take responsibility for satisfying the exemption's conditions, including the obligation to have policies and procedures reasonably and prudently designed to ensure that individual Advisers adhere to the Impartial Conduct Standards, and the obligation to insulate the Adviser from incentives to violate the Best Interest standard. Such Advisers include call center representatives who provide investment advice within the meaning of the Regulation.
Some commenters suggested that the Department provide additional flexibility and allow the individual Adviser to be obligated under the contract instead of the Financial Institution. The Department has not adopted that suggestion. To ensure operation of the exemption as intended, the Financial Institution should be a party to the contract. The supervisory responsibility and liability of the Financial Institution is important to the exemption's protections. In particular, the exemption contemplates that the Financial Institution will adopt and monitor stringent anti-conflict policies and procedures; avoid financial incentives that undermine the Impartial Conduct standards; and take appropriate measures to ensure that it and its representatives adhere to the exemption's conditions. The contract provides both a mechanism for imposing these obligations on the Financial Institution and creates a powerful incentive for the Financial Institution to take the obligations seriously in the management and supervision of investment recommendations.
Section II(a) of the exemption provides that the contract must be enforceable against the Financial Institution. As long as that is the case, the Financial Institution is not required to sign the contract. Section II(a) of the exemption further describes the methods through which customer assent may be achieved, and reflects commenters' requests for greater specificity on this point.
With respect to new contracts, a few commenters asked the Department to confirm that electronic execution by the Retirement Investor is sufficient. Another commenter asked about telephone assent. In the final exemption, the Department specifically permits electronic execution as a form of customer assent. The Department has not permitted telephone assent, however, because of the potential issues of proof regarding the existence and terms of a contract executed in that manner. It is the Department's goal that Retirement Investors obtain clear evidence of the contract terms and their applicability to the Retirement Investor's own account or contract. The exemption will best serve its purpose if the contractual commitments are clear to all the parties, and if ancillary disputes about the fiduciary nature of the advice relationship are avoided. For this same reason, the exemption requires that a copy of the applicable contract be maintained on a Web site accessible to the Retirement Investor.
Commenters also asked for the ability to use a negative consent procedure with respect to existing customers to avoid the expense and difficulty associated with obtaining a large number of client signatures. The Department adjusted the exemption on this point to permit amendment of existing contracts by negative consent, as discussed above. As this approach will still result in the Retirement Investor receiving clear evidence of the contract terms and their applicability to the Retirement Investor's own account or contract, the Department concurred with commenters on its use.
Treating the Retirement Investor's silence as consent after 30 days provides the Retirement Investor a reasonable opportunity to review the new terms and to reject them. The Financial Institution may not use the negative consent procedure, however, to impose new obligations, restrictions or liabilities on the Retirement Investor in connection with this exemption. Any attempt by the Financial Institution to
A number of commenters also asked that the exemption authorize Financial Institutions to satisfy the contract requirement for all Retirement Investors—including new customers after the January 1, 2018—through unilateral contracts or implied or negative consent. Some commenters suggested that the Department should not require a contract at all, but only a “customer bill of rights” or similar disclosure, without any additional signature requirement. Some commenters suggested that the requirement of obtaining signatures could delay execution of time sensitive investment strategies.
Although the final exemption accommodates a wide variety of concerns regarding contract operational issues, the Department did not adopt the alternative approaches suggested by some commenters, such as merely requiring delivery of a customer bill of rights, broader reliance on a unilateral contract approach, or increased reliance on negative consent. The Department intends that Retirement Investors that are new customers of the Financial Institution should enter into an enforceable contract under Section II(a)(1)(i). Consistent with the Department's goal that Retirement Investors obtain clear evidence of the contract terms and their applicability to the Retirement Investor's own account or contract, the exemption limits the negative consent option to existing customers as a form of transitional relief, so that Financial Institutions can avoid the burdens associated with obtaining signatures from a large number of already-existing customers.
Apart from this transitional relief, the Department does not believe it is appropriate to dispense with the clarity, enforceability and legal protections associated with an affirmative contract. Contracts are commonplace in a wide range of commercial transactions occurring in person, on the web, and elsewhere. The Department has facilitated the process by providing that Financial Institutions can incorporate the contract terms into commonplace account opening or similar documents that they already use; by permitting electronic signatures; and by revising the timing rules, so that the contract's execution can follow the provision of advice, as long as it precedes or occurs at the same time as the execution of the recommended transaction.
Section II(b) of the exemption requires the Financial Institution to affirmatively state in writing that the Financial Institution and the Adviser(s) act as fiduciaries under ERISA or the Code, or both, with respect to any investment advice regarding principal transactions and riskless principal transactions provided by the Financial Institution or the Adviser subject to the contract or, in the case of an ERISA plan, with respect to any investment advice regarding the principal transactions and riskless principal transactions between the Financial Institution and the Plan or participant or beneficiary account.
With respect to IRAs and non-ERISA plans, if this acknowledgment of fiduciary status does not appear in a contract with a Retirement Investor, the exemption is not satisfied with respect to transactions involving that Retirement Investor. With respect to ERISA plans, this acknowledgment must be provided to the Retirement Investor prior to or at the same time as the execution of the recommended transaction, but not as part of a contract. This fiduciary acknowledgment is critical to ensuring clarity and certainty with respect to fiduciary status of both the Adviser and Financial Institution under ERISA and the Code with respect to that advice.
The fiduciary acknowledgment provision received significant support from some commenters. Commenters described it as a necessary protection and noted that it would clarify the obligations of the Adviser. One commenter said that facilitating proof of fiduciary status should enhance investors' ability to obtain a remedy for Adviser misconduct in arbitration by eliminating ancillary litigation over fiduciary status. Rather than litigate over fiduciary status, the fiduciary acknowledgment would help ensure that the proceedings focused on the Advisers' compliance with fundamental fiduciary norms.
Some commenters opposed the fiduciary acknowledgment requirement in the proposal, as applicable to Financial Institutions, on the basis that it could force Financial Institutions to take on fiduciary responsibilities, even if they would not otherwise be functional fiduciaries under ERISA or the Code. The commenters pointed out that under the proposed Regulation, the acknowledgment of fiduciary status would have been a factor in imposing fiduciary status on a party. Therefore, Financial Institutions could become fiduciaries by virtue of the fiduciary acknowledgment. To address these concerns, a few commenters suggested language under which a Financial Institution would only be considered a fiduciary to the extent that it is “an affiliate of the Adviser within the meaning of 29 CFR 2510.3-21(f)(7) that, with the Adviser, functions as a fiduciary.”
The Department has not adjusted the exemption as these commenters requested. The exemption requires as a condition of relief that a sponsoring Financial Institution accept fiduciary responsibility for the recommendations of its Adviser(s). The Financial Institution's role in supervising individual Advisers and overseeing their adherence to the Impartial Conduct Standards is a key safeguard of the exemption. The exemption's success critically depends on the Financial Institution's careful implementation of anti-conflict policies and procedures, avoidance of Adviser incentives to violate the Impartial Conduct Standards and broad oversight of Advisers. Accordingly, Financial Institutions that wish to engage in principal transactions and riskless principal transactions that would otherwise be prohibited under ERISA and the Code must agree to take on these responsibilities as a condition of relief under the exemption. To the extent Financial Institutions do not wish to take on this role with their associated responsibilities and liabilities, they may structure their operations to avoid prohibited transactions and the resultant need of the exemption.
Other commenters expressed the view that the fiduciary acknowledgement would potentially require broker-dealers to satisfy the requirements of the Investment Advisers Act of 1940. As described by commenters, the Act does not require broker-dealers to register as investment advisers if they provide advice that is solely incidental to their brokerage services. Commenters expressed concern that acknowledging fiduciary status and providing advice in satisfaction of the Impartial Conduct Standards could call into question whether the advice provided was solely incidental.
The Department does not, however, require the Adviser or Financial Institution to acknowledge fiduciary status under the securities laws, but rather under ERISA or the Code or both. Neither does the Department require Advisers to agree to provide investment advice on an ongoing, rather than transactional, basis. An Adviser's status as an ERISA fiduciary is not dispositive of its obligations under the securities laws, and compliance with the
The Department changed the fiduciary acknowledgment provision in response to several comments requesting revisions to clarify the required extent of the fiduciary acknowledgment. Accordingly, the Department has clarified that the acknowledgment can be limited to investment recommendations subject to the contract or, in the case of an ERISA plan, any investment recommendations regarding the plan or beneficiary or participant account. As discussed in more detail below, the exemption (including the required fiduciary acknowledgment) does not in and of itself, impose an ongoing duty to monitor on the Adviser and Financial Institution. However, there may be some investments which cannot be prudently recommended for purchase to individual Retirement Investors, in the first place, without a mechanism in place for the ongoing monitoring of the investment.
Section II(c) of the exemption requires that the Adviser and Financial Institution comply with fundamental Impartial Conduct Standards. Generally stated, the Impartial Conduct Standards require that Advisers and Financial Institutions provide investment advice regarding the principal transaction or riskless principal transaction that is in the Retirement Investor's Best Interest, seek to obtain the best execution reasonably available under the circumstances with respect to the transaction, and not make misleading statements to the Retirement Investor about the recommended transaction and Material Conflicts of Interest. As defined in the exemption, a Financial Institution and Adviser act in the Best Interest of a Retirement Investor when they provide investment advice that reflects “the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution, any Affiliate or other party.”
The Impartial Conduct Standards represent fundamental obligations of fair dealing and fiduciary conduct. The concepts of prudence, undivided loyalty and reasonable compensation are all deeply rooted in ERISA and the common law of agency and trusts.
Under ERISA section 408(a) and Code section 4975(c)(2), the Department cannot grant an exemption unless it first finds that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of participants and beneficiaries of plans and IRA owners. An exemption permitting transactions that violate the Impartial Conduct Standards would fail these standards.
The Impartial Conduct Standards are conditions of the exemption for the provision of advice with respect to all Retirement Investors. For advice to Retirement Investors in IRAs and non-ERISA plans, the Impartial Conduct Standards must also be included as contractual commitments on the part of the Financial Institution and its Advisers. As noted above, there is no contract requirement for advice with respect Retirement Investors in ERISA plans.
Comments on each of the Impartial Conduct Standards are discussed below. Additionally, in response to commenters' assertion that the exemption is not administratively feasible due to uncertainty regarding some terms and requests for additional clarity, the Department has clarified some key terms in the text and provides additional interpretive guidance in the preamble discussion that follows. Finally, the Department discusses comments on the treatment of the Impartial Conduct Standards as both exemption conditions for all Retirement Investors as well as contractual representations with respect to IRAs and other non-ERISA Plans.
Under Section II(c)(1), the Financial Institution must state that it and its Advisers will comply with a Best Interest standard when providing investment advice to the Retirement Investor with respect to principal transactions and riskless principal transactions, and, in fact, adhere to the standard. Advice in the Retirement Investor's Best Interest means advice that, at the time of the recommendation:
The Best Interest standard set forth in the exemption is based on longstanding
A wide range of commenters indicated support for a broad Best Interest standard. Some comments indicated that the Best Interest standard is consistent with the way Advisers provide investment advice to clients today. However, a number of these commenters expressed misgivings as to the definition used in the proposed exemption, in particular, the “without regard to” formulation. The commenters indicated uncertainty as to the meaning of the phrase, including whether it effectively precluded an Adviser from receiving compensation if a particular investment would generate higher Adviser compensation.
Other commenters asked the Department to use a different definition of Best Interest, or simply use the exact language from ERISA's section 404 duty of loyalty. Others suggested definitional approaches that would require that the Adviser and Financial Institution “not subordinate” their customers' interests to their own interests, or that the Adviser and Financial Institution “put their customers' interests ahead of their own interests,” or similar constructs.
FINRA suggested that the federal securities laws should form the foundation of the Best Interest standard. Specifically, FINRA urged that the Best Interest definition in the exemption incorporate the suitability standard applicable to investment advisers and broker dealers under federal securities laws. According to FINRA, this would facilitate customer enforcement of the Best Interest standard by providing adjudicators with a well-established basis on which to find a violation.
Other commenters found the Best Interest standard to be an appropriate statement of the obligations of a fiduciary investment advice provider and believed it would provide concrete protections against conflicted recommendations. These commenters asked the Department to maintain the Best Interest definition as proposed. One commenter wrote that the term “best interest” is commonly used in connection with a fiduciary's duty of loyalty and cautioned the Department against creating an exemption that failed to include the duty of loyalty. Others urged the Department to avoid definitional changes that would reduce current protections to Retirement Investors. Some commenters also noted that the “without regard to” language is consistent with the recommended standard in the SEC staff Dodd-Frank Study, and suggested that it has added benefit of potentially harmonizing with a future securities law standard for broker-dealers.
In the context of principal transactions, one commenter suggested that the Department make clear that both the advice and the execution of the transaction must be in the Retirement Investor's Best Interest. The Department agrees that the execution of the transaction is an important concern, and has incorporated in Section II(c)(2) of the exemption, a provision requiring Financial Institutions that are FINRA members to agree that they and their Advisers and Financial Institution will comply with the terms of FINRA rule 5310 (Best Execution and Interpositioning).
The final exemption retains the Best Interest definition as proposed, with minor adjustments. The first prong of the standard was revised to more closely track the statutory language of ERISA section 404(a), and, is consistent with the Department's intent to hold investment advice fiduciaries to a prudent investment professional standard. Accordingly, the definition of Best Interest now requires advice that “reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person
The Department has not specifically incorporated the suitability obligation as an element of the Best Interest standard, as suggested by FINRA but many aspects of suitability are also elements of the Best Interest standard. An investment recommendation that is not suitable under the securities laws would not meet the Best Interest standard. Under FINRA's rule 2111(a) on suitability, broker-dealers “must have a reasonable basis to believe that a recommended transaction or investment strategy involving a security or securities is suitable for the customer.” The text of rule 2111(a), however, does not do any of the following: Reference a best interest standard, clearly require brokers to put their client's interests ahead of their own, expressly prohibit the selection of the least suitable (but more remunerative) of available investments, or require them to take the kind of measures to avoid or mitigate conflicts of interests that are required as conditions of this exemption.
The Department recognizes that FINRA issued guidance on rule 2111 in which it explains that “in interpreting the suitability rule, numerous cases explicitly state that a broker's recommendations must be consistent with his customers' best interests,” and provided examples of conduct that would be prohibited under this standard, including conduct that this exemption would not allow.
Moreover, suitability under SEC practice differs somewhat from the FINRA approach. According to the SEC staff Dodd-Frank Study, the SEC requirements are based on the anti-fraud provisions of the Securities Act Section 17(a), the Exchange Act Section 10(b) and Rule 10b-5 thereunder.
The Best Interest standard, as set forth in the exemption, is intended to effectively incorporate the objective standards of care and undivided loyalty that have been applied under ERISA for more than forty years. Under these objective standards, the Adviser must adhere to a professional standard of care in making investment recommendations regarding principal transactions and riskless principal transactions that are in the Retirement Investor's Best Interest. The Adviser may not base his or her recommendations on the Adviser's own financial interest in the transaction. Nor may the Adviser recommend a principal transaction or riskless principal transaction, unless it meets the objective prudent person standard of care. Additionally, the duties of loyalty and prudence embodied in ERISA are objective obligations that do not require proof of fraud or misrepresentation, and full disclosure is not a defense to making an imprudent recommendation or favoring one's own interests at the Retirement Investor's expense.
A few commenters also questioned the requirement in the Best Interest standard that recommendations be made without regard to the interests of the Adviser, Financial Institution, any Affiliate, or other party. The commenters indicated they did not know the purpose of the reference to “other party” and asked that it be deleted. The Department intends the reference to make clear that an Adviser and Financial Institution operating within the Impartial Conduct Standards should not take into account the interests of any party other than the Retirement Investor—whether the other party is related to the Adviser or Financial Institution or not—in making a recommendation regarding a principal transaction or riskless principal transaction. For example, an entity that may be unrelated to the Adviser or Financial Institution but could still constitute an “other party,” for these purposes, is the manufacturer of the investment product being recommended.
Other commenters asked for confirmation that the Best Interest standard is applied based on the facts and circumstances as they existed at the time of the recommendation, and not based on hindsight. Consistent with the well-established legal principles that exist under ERISA today, the Department confirms that the Best Interest standard is not a hindsight standard, but rather is based on the facts as they existed at the time of the recommendation. Thus, the courts have evaluated the prudence of a fiduciary's actions under ERISA by focusing on the process the fiduciary used to reach its determination or recommendation—whether the fiduciary, “at the time they engaged in the challenged transactions, employed the proper procedures to investigate the merits of the investment and to structure the investment.”
This is not to suggest that the ERISA section 404 prudence standard, or Best Interest standard, are solely procedural standards. Thus, the prudence standard, as incorporated in the Best Interest standard, is an objective standard of care that requires investment advice fiduciaries to investigate and evaluate investments, make recommendations, and exercise sound judgment in the same way that knowledgeable and impartial professionals would. “[T]his is not a search for subjective good faith—a pure heart and an empty head are not enough.”
The Department additionally confirms its intent that the phrase “without regard to” be given the same meaning as the language in ERISA section 404 that requires a fiduciary to act “solely in the interest of” participants and
In response to commenter concerns, the Department also confirms that the Best Interest standard does not impose an unattainable obligation on Advisers and Financial Institutions to somehow identify the single “best” investment for the Retirement Investor out of all the investments in the national or international marketplace, assuming such advice or management were even possible. Instead, as discussed above, the Best Interest standard set out in the exemption, incorporates two fundamental and well-established fiduciary obligations: the duties of prudence and loyalty. Thus, the fiduciary's obligation under the Best Interest standard is to give advice or acquire or dispose of investments in a manner that adheres to professional standards of prudence, and to put the Retirement Investor's financial interests in the driver's seat, rather than the competing interests of the Adviser or other parties.
Finally, in response to questions regarding the extent to which this Best Interest standard or other provisions of the exemption impose an ongoing monitoring obligation on Advisers or Financial Institutions, the Department has added specific language in Section II(e) regarding monitoring. The text does not impose a monitoring requirement, but instead requires clarity. As suggested by FINRA, Section II(e) requires Advisers and Financial Institutions to disclose whether or not they will monitor the Retirement Investor's investments and alert the Retirement Investor to any recommended changes to those investments and, if so, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted. This is consistent with the Department's interpretation of an investment advice fiduciary's monitoring responsibility as articulated in the preamble to the Regulation.
The terms of the contract or disclosure along with other representations, agreements, or understandings between the Adviser, Financial Institution and Retirement Investor, will govern whether the nature of the relationship between the parties is ongoing or not. The preamble to the proposed Best Interest Contract Exemption stated that adherence to a Best Interest standard did not mandate an ongoing or long-term relationship, but instead left the determination of whether to enter into such a relationship to the parties.
Section II(c)(2) of the exemption requires that the Adviser and Financial Institution seek to obtain the best execution reasonably available under the circumstances with respect to the principal transaction or riskless principal transaction with the plan, participant or beneficiary account or IRA.
Section II(c)(2)(i) further provides that Financial Institutions that are FINRA members may satisfy Section II(c)(2) by complying with the terms of FINRA rules 2121 (Fair Prices and Commissions) and 5310 (Best Execution and Interpositioning), or any successor rules in effect at the time of the transaction,
This provision is revised from the proposal, which provided that the purchase or sales price could not be unreasonable under the circumstances. Commenters on the proposal indicated that they were uncertain as to what an unreasonable price would be and requested additional clarification of the rule.
Further, some commenters indicated that FINRA rule 2121 (Fair Prices and Commissions) should be incorporated in the alternative. According to FINRA, rule 2121 “prohibits a broker-dealer from entering into a transaction with a customer `at any price' that is not reasonably related to the current market price of the security.” FINRA additionally recommended that the Department incorporate FINRA rule 5310 (Best Execution and Interpositioning) instead of its proposed two-quote requirement (discussed below). According to FINRA:
[Rule 5310] uses a “facts and circumstances” analysis by requiring that a firm dedicate reasonable diligence to ascertain the best market for the security and to buy or sell in such market so that the price to the customer is as favorable as possible under the prevailing market conditions. A key determinant in assessing whether a firm has met this reasonable diligence standard is the character of the market for the security itself, which includes an analysis of price, volatility and relative liquidity.
[The] Rule . . . also addresses instances in which there is limited quotation or pricing information available. The rule requires a broker-dealer to have written policies and procedures that address how the firm will determine the best inter-dealer market for such a security in the absence of pricing information or multiple quotations and to document its compliance with those policies and procedures.
After consideration of the comments received, the Department revised the proposed condition to focus on best execution, rather than an unreasonable price. The Department determined that a requirement that Advisers and Financial Institutions seek to obtain the best execution reasonably available under the circumstances with respect to the transaction, particularly as articulated by FINRA in rule 5310, would provide protections that are comparable to the Department's proposed condition but that are more familiar to the parties relying on the exemption.
The Department specifically incorporated FINRA rules 2121 and 5310 for FINRA members, as a method of satisfying this requirement, as suggested by some commenters. For Advisers and Financial Institutions that are not FINRA members, the best execution obligation under the exemption is satisfied if the Adviser and Financial Institution satisfies the best execution obligation as interpreted by their functional regulator. However, to the extent non-FINRA members wish for additional certainty as to their compliance obligations under this exemption, they may comply with the provisions of FINRA rules 2121 and 5310 to satisfy Section II(c)(2).
Under Section II(c)(2)(ii), if the Department expands the scope of this exemption to include additional principal traded assets by individual exemption,
The final Impartial Conduct Standard, set forth in Section II(c)(3), requires that statements by the Financial Institution and its Advisers to the Retirement Investor about the recommended transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's investment decision to engage in a principal transaction or a riskless principal transaction, may not be materially misleading at the time they are made. In response to commenters, the Department adjusted the text to clarify that the standard is measured at the time of the representations,
The Department did not accept certain other comments, however. One commenter requested that the Department add a qualifier providing that the standard is violated only if the statement was “reasonably relied” on by the Retirement Investor. The Department rejected the comment. The Department's aim is to ensure that Financial Institutions and Advisors uniformly adhere to the Impartial Conduct Standards, including the obligation to avoid materially misleading statements, when they give advice. Whether a Retirement Investor relied on a particular statement may be relevant to the question of damages in subsequent arbitration or court proceedings, but it is not and should not be relevant to the question of whether the fiduciary violated the exemption's standards in the first place. Moreover, inclusion of a reasonable reliance standard runs the risk of inviting boilerplate disclaimers of reliance in contracts and disclosure documents precisely so the Adviser can assert that any reliance is unreasonable.
One commenter asked the Department to require only that the Adviser “reasonably believe” the statements are not misleading. The Department is concerned that this standard too could undermine the protections of this condition, by requiring Retirement Investors or the Department to prove the Adviser's actual belief rather than focusing on whether the statement is objectively misleading. However, to address commenters' concerns about the risks of engaging in a prohibited transaction, as noted above, the Department has clarified that the standard is measured at the time of the representations and has added a materiality standard.
The Department believes that Retirement Investors are best served by statements and representations that are free from material misstatements. Financial Institutions and Advisers best avoid liability—and best promote the interests of Retirement Investors—by ensuring that accurate communications are a consistent standard in all their interactions with their customers.
A commenter suggested that the Department adopt FINRA's “Frequently Asked Questions regarding Rule 2210” in this connection.
Commenters expressed a variety of views on whether violations of the Impartial Conduct Standards with respect to advice regarding principal transactions to Retirement Investors regarding IRAs and non-ERISA plans should result in loss of the exemption, violation of the contract, or both.
Other commenters advocated for the opposite result, asserting that the Impartial Conduct Standards should be required for contractual promises only, and not treated as exemption conditions. These commenters asserted that the Impartial Conduct Standards are too vague and would result in uncertainty as to whether an excise tax under the Code, which is self-assessed, is owed. There were also suggestions to limit the contractual representation to the Best Interest standard alone. One commenter asserted that the favorable price requirement and the obligation not to make misleading statements fall within a Best Interest standard, and do not need to be stated separately. There were also suggestions that the Impartial Conduct Standards not apply to ERISA plans because fiduciaries to these plans already are required to adhere to similar statutory fiduciary obligations. In these commenters' views, requiring these standards in an exemption is redundant and inappropriately increases the consequences of any fiduciary breach by imposing an excise tax.
In response to comments, the Department has revised the language of the Impartial Conduct Standards and provided interpretive guidance to alleviate the commenters' concerns about uncertainty and litigation risk. However, the Department has concluded that, failure to adhere to the Impartial Conduct Standards should be both a violation of the contract (where required) and the exemption. Accordingly, the Department has not eliminated any of the conduct standards or, for IRAs and non-ERISA plans, restricted them just to conditions of the exemption for Retirement Investors investing in IRAs or non-ERISA plans. In the Department's view, all the Impartial Conduct Standards form the baseline standards that should be applicable to fiduciaries relying on the exemption; therefore, the Department has not accepted comments suggesting that the contract representation be limited to the Best Interest standard. Making all the Impartial Conduct Standards required contractual promises for dealings with IRAs and other non-ERISA plans creates the potential for contractual liability, incentivizes Financial Institutions to comply, and gives injured Retirement Investors a remedy if those Financial Institutions do not comply. This enforceability is critical to the safeguards afforded by the exemption.
As previously discussed, the Impartial Conduct Standards will not unduly increase litigation risk. The standards are not unduly vague or unknown, but rather track longstanding concepts in law and equity. Also, the Department has simplified execution of the contract, streamlined disclosure, and made certain language changes to address legitimate concerns.
Similarly, the Department has not accepted the comment that the Impartial Conduct Standards should apply only to IRAs and non-ERISA plans. One of the Department's goals is to ensure equal footing for all Retirement Investors. The SEC staff Dodd-Frank Study found that investors were frequently confused by the differing standards of care applicable to broker-dealers and registered investment advisers. The Department hopes to minimize such confusion in the market for retirement advice by holding Advisers and Financial Institutions to similar standards, regardless of whether they are giving the advice to an ERISA plan, IRA, or a non-ERISA plan.
Moreover, inclusion of the standards in the exemption's conditions adds an important additional safeguard for ERISA and IRA investors alike because the party engaging in a prohibited transaction has the burden of showing compliance with an applicable exemption, when violations are alleged.
Moreover, as noted repeatedly, the language for the Impartial Conduct Standards borrows heavily from ERISA and the law of trusts, providing sufficient clarity to alleviate the commenters' concerns. Ensuring that fiduciary investment advisers adhere to the Impartial Conduct Standards and that all Retirement Investors have an effective legal mechanism to enforce the standards are central goals of this regulatory project.
Under Section II(d)(1)-(3) of the exemption, the Financial Institution is required to adopt certain anti-conflict policies and procedures and to insulate Advisers from incentives to violate the Best Interest standard. In order for relief to be available under the exemption, a Financial Institution that meets the definition set forth in the exemption must provide oversight of Advisers' recommendations, as described in this section. The Financial Institution must prepare a written document describing the Financial Institution's policies and procedures, and make copies of the document readily available to Retirement Investors, free of charge, upon request as well as on the Financial Institution's Web site.
These obligations have several important components. First, the Financial Institution must adopt and comply with written policies and procedures reasonably and prudently designed to ensure that its individual Advisers adhere to the Impartial Conduct Standards set forth in Section II(c). Second, the Financial Institution in formulating its policies and procedures, must specifically identify and document its Material Conflicts of Interest associated with principal transactions and riskless principal transactions; adopt measures reasonably and prudently designed to prevent Material Conflicts of Interest from causing violations of the Impartial Conduct Standards set forth in Section II(c); and designate a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards. For purposes of the exemption, a Material Conflict of Interest exists when an Adviser or Financial Institution has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.
Finally, the Financial Institution's policies and procedures must require that, neither the Financial Institution nor (to the best of its knowledge) any Affiliate uses or relies on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause individual Advisers to make recommendations regarding principal transactions and riskless principal transactions that are not in the Best Interest of the Retirement Investor.
In this respect, however, the exemption makes clear that that requirement does not prevent the Financial Institution or its Affiliates from providing Advisers with differential compensation (whether in type or amount, and including, but not limited to, commissions) based on investment decisions by Plans, participant or beneficiary accounts, or IRAs, to the extent that the policies and procedures and incentive practices, when viewed as a whole, are reasonably and prudently designed to avoid a misalignment of the interests of Advisers with the interests of the Retirement Investors they serve as fiduciaries.
The anti-conflict policies and procedures will safeguard the interests of Retirement Investors by causing Financial Institutions to consider the conflicts of interest affecting their provision of advice to Retirement Investors regarding principal transactions and riskless principal transactions and to take action to mitigate the impact of such conflicts. In particular, under the final exemption, Financial Institutions must not use compensation and other employment incentives to the extent they are intended to or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Financial Institutions must also establish a supervisory structure reasonably and prudently designed to ensure the Advisers will adhere to the
Like the proposal, the exemption does not specify the precise content of the anti-conflict policies and procedures. This flexibility is intended to allow Financial Institutions to develop policies and procedures that are effective for their particular business models, while prudently ensuring compliance with their and their Advisers' fiduciary obligations and the Impartial Conduct Standards. The policies and procedures requirement, if taken seriously, can also reduce Financial Institutions' litigation risk by minimizing incentives for Advisers to provide advice that is not in Retirement Investors' Best Interest.
As adopted in the final exemption, the policies and procedures requirement is a condition of the exemption for all Retirement Investors—in ERISA plans, IRAs and non-ERISA plans. Failure to comply could result in liability under ERISA for engaging in a prohibited transaction and the imposition of an excise tax under the Code, payable to the Treasury. Additionally, with respect to Retirement Investors in IRAs and non-ERISA plans, the requirements take the form of a contractual warranty. The Financial Institution must warrant that it has adopted and will comply with the anti-conflict policies and procedures (including the obligation to avoid misaligned incentives). Failure to comply with the warranty could result in contractual liability.
Comments on the proposed policies and procedures requirement are discussed below. As stated above, for ease of use, the Department has included in this preamble the same general discussion of comments as in the Best Interest Contract Exemption, to the extent applicable to principal transactions and riskless principal transactions, despite the fact that some comments discussed below were not made directly with respect to this exemption.
Under the policies and procedures requirement, described in greater detail above, Financial Institutions must adopt and comply with anti-conflict policies and procedures. In addition, neither the Financial Institution nor (to the best of its knowledge) any Affiliates may use or rely on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor.
Some commenters were extremely supportive of the policies and procedures requirement as proposed. They expressed the view that the policies and procedures requirement, and in particular the restrictions on compensation and other employment incentives, was one of the most critical investor protections in the proposal because it would cause Financial Institutions to make specific and necessary changes to their compensation arrangements that would result in significant protections to Retirement Investors.
Some commenters believed that the Department did not go far enough. These commenters indicated that flat compensation arrangements should be required, or at least that the rules applicable to differential compensation should be more specific and stringent.
A few commenters also indicated that, in addition to focusing on the Adviser, the Financial Institution's policies and procedures need to consider the impact of compensation practices on branch managers. A commenter indicated that branch managers have responsibilities under FINRA's supervisory rules to ensure suitability and possibly approve individual transactions. The commenter asserted that branch managers financially benefit from Advisers' recommendations and have a variety of methods of influencing Adviser behavior.
Many others objected to the policies and procedures warranty and requested that it be eliminated in the final exemption. Some commenters believed that compliance would require drastic changes to current compensation arrangements or could possibly result in the complete prohibition of commissions and other transaction-based compensation. Other commenters suggested that the requirement should be eliminated as it would be unnecessary in light of the exemption's Best Interest standard, and because it would unnecessarily increase litigation risk to Financial Institutions. Alternatively, there were requests to clarify specific provisions and provide safe harbors in the policies and procedures requirement.
In the final exemption, the Department has retained the general approach of the proposal. The Department concurs with commenters who view the policies and procedures requirement as an important safeguard for Retirement Investors and as a necessary condition for the Department to make the findings under ERISA section 408(a) and Code section 4975(c)(2) that the exemption is in the interests of, and protective of, Retirement Investors. This provision will require Financial Institutions to take concrete and specific steps to ensure that its individual Advisers adhere to the Impartial Conduct Standards, and in particular, forego compensation practices and employment incentives (quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives) that are intended or would reasonably be expected to cause Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. Strong policies and procedures reduce the temptation (conscious or unconscious) to violate the Best Interest standard in the first place by ensuring that the Advisers' incentives are appropriately aligned with the interests of the customers they serve, and by ensuring appropriate monitoring and supervision of individual Advisers' conduct. While the Department views the Best Interest standard as critical to the protections of the exemption, the policies and procedures requirement is equally critical as a means of supporting Best Interest advice and protecting Retirement Investors from having to enforce the Best Interest standard after the advice has already been rendered and the damage done.
The Department has not made the requirements more stringent, as suggested by some commenters, so as to require completely level compensation. The Department designed the exemption to preserve mark-ups and mark-downs and other payments as applicable to the transaction in connection with principal transactions and riskless principal transactions, thereby preserving existing business models.
The Department also adopted the suggestion of one commenter that the exemption require the Financial
There were also questions and comments on certain language in the proposed policies and procedures requirement. As proposed, the components of the policies and procedures requirement in Section II(d) read as follows:
• The Financial Institution has adopted written policies and procedures reasonably designed to mitigate the impact of Material Conflicts of Interest and to ensure that its individual Advisers adhere to the Impartial Conduct Standards set forth in Section II(c);
• In formulating its policies and procedures, the Financial Institution has specifically identified Material Conflicts of Interest and adopted measures to prevent the Material Conflicts of Interest from causing violations of the Impartial Conduct Standards set forth in Section II(c); and
• Neither the Financial Institution nor (to the best of its knowledge) any Affiliate uses quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives to the extent they would tend to encourage individual Advisers to make recommendations regarding principal transactions that are not in the Best Interest of the Retirement Investor.
A few commenters asked the Department to explain the difference between the first and second prongs of the policies and procedures requirement, as proposed. In response, the first prong of the requirement was intended to establish a general standard, while the second (and third) prongs provided specific rules regarding the policies and procedures requirement. This approach was also adopted in the final exemption. In addition, the language of Section II(d)(3) specifically provides that the third prong of the requirement, requiring Financial Institutions to insulate Advisers from incentives to violate the Best Interest standard, is part of the policies and procedures requirement.
There were also comments on (i) the definition and use of the term “Material Conflicts of Interest;” (ii) the language requiring the policies and procedures to be “reasonably designed” to mitigate the impact of such conflicts of interest, and (iii) the meaning of incentives that “tend to encourage” individual Advisers to make recommendations that are not in the Best Interest of the Retirement Investor. These comments are discussed below.
A number of commenters focused on the definition of Material Conflict of Interest used in the proposal. Under the definition as proposed, a Material Conflict of Interest exists when an Adviser or Financial Institution “has a financial interest that could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.” Some commenters took the position that the proposal did not adequately explain the term “material” or incorporate a materiality standard into the definition. A commenter wrote that the proposed definition was so broad that it would be difficult for Financial Institutions to comply with the various aspects of the exemption related to Material Conflicts of Interest, such as provisions requiring disclosure of Material Conflicts of Interest.
Another commenter indicated that the Department should not use the term “material” in defining conflicts of interest. The commenter believed that it could result in a standard that was too subjective from the perspective of the Adviser and Financial Institution, and could undermine the protectiveness of the exemption.
After consideration of the comments, the Department adjusted the definition of Material Conflict of Interest. In the final exemption, a Material Conflict of Interest exists when an Adviser or Financial Institution has a “financial interest that that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.” This language responds to concerns about the breadth and potential subjectivity of the standard. The Department did not, as some commenters suggested, include the word “material” in the definition of Material Conflict of Interest, to avoid the potential circularity of that approach.
One commenter asked that the Department more broadly use the modifier “reasonably designed” in describing the standard the policies and procedures must meet so as to avoid a construction that required standards that ensured perfect compliance, a potentially unattainable standard. The Department has accepted the comment and adjusted the language in Sections II(d)(1) and (2) to generally use the phrase “reasonably and prudently designed.” Other commenters asked for guidance on the proposed phrasing “reasonably designed to mitigate” the impact of Material Conflicts of Interest. The Department provides additional guidance in this respect in the preamble of the Best Interest Contract Exemption published elsewhere in this issue of the
A number of commenters asked for clarification or revision of the proposed exemption's prohibition of incentives that “tend to encourage” violation of the Best Interest standard, generally to require a tight link between the incentives and the Advisers' recommendations. Commenters argued that the “tend to encourage” language established a standard that could be impossible to meet in the context of differential compensation. Accordingly, they requested that the Department use language such as “intended to encourage,” “does encourage,” “causes,” or similar formulation.
In response to these commenters the Department has adjusted the condition's language as follows:
[N]either the Financial Institution nor (to the best of the Financial Institution's knowledge) any Affiliate uses or relies on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are
This language more accurately captures the Department's intent, which was to require that procedures reasonably address Advisers' incentives,
However, the final exemption provides that the policies and procedures requirement does not:
[P]revent the Financial Institution or its Affiliates from providing Advisers with differential compensation
This language is designed to make clear that differential compensation is permitted, but only if the Financial Institution's policies and procedures, as a whole, are reasonably designed to avoid a misalignment of interests between Advisers and Retirement Investors.
For further guidance, the preamble to the Best Interest Contract Exemption, published in this same issue of the
In the proposal, both the Adviser and Financial Institution had to give a warranty to the Retirement Investor about the adoption and implementation of anti-conflict policies and procedures. A few commenters indicated that the Adviser should not be required to give the warranty, and questioned whether the Adviser would always be in a position to speak to the Financial Institution's incentive and compensation arrangements. The Department agrees that the Financial Institution has the primary responsibility for design and implementation of the policies and procedures requirement and, accordingly, has limited the warranty requirement to the Financial Institution.
Some commenters believed that even if the Department included a policies and procedure requirement in the exemption, it should not require a warranty on implementation and compliance with the requirement. According to some of these commenters the warranty was unnecessary in light of the Best Interest standard, and would unduly contribute to litigation risk. A few commenters also suggested that a Financial Institution's failure to comply with the contractual warranty could give rise to a cause of action to Retirement Investors who had suffered no injuries from failure to implement or comply with appropriate policies and procedures. A few other commenters expressed concern that the provision of a warranty could result in tort liability, rather than just contractual liability.
Other commenters argued that the Department should require Financial Institutions not only to make an enforceable warranty as a condition of the exemption, but also require actual compliance with the warranty as a condition of the exemption. One such commenter argued that it would be difficult for Retirement Investors to prove that policies and procedures were not “reasonably designed” to achieve the required purpose.
As noted above, the final exemption adopts the required policies and procedures as a condition of the exemption. The policies and procedures requirement is a critical part of the exemption's protections. The risk of liability associated with a non-exempt prohibited transaction gives Financial Institutions a strong incentive to design protective policies and procedures in a way that is consistent with the purposes and requirements of this exemption. Of course, the Department does not expect that successful contract claims will be brought by Retirement Investors without a showing of damages.
In addition, the final exemption requires the Financial Institution to make a warranty regarding the policies and procedures in contracts with Retirement Investors regarding IRAs and other non-ERISA plans. The warranty, and potential liability associated with that warranty, gives Financial Institutions both the obligation and the incentive to tamp down harmful conflicts of interest and protect Retirement Investors from misaligned incentives that encourage Advisers to violate the Best Interest standard and other fiduciary obligations and ensures that there is a means to redress the failure to do so. While the warranty exposes Financial Institutions and Advisers to litigation risk, these risks are circumscribed by the availability of binding arbitration for individual claims and the legal restrictions that courts generally use to police class actions.
The Department does not share a commenter's view that it would be too difficult for Retirement Investors to prove that the policies and procedures were not “reasonably designed” to achieve the required purpose. The final exemption requires the Financial Institution to disclose Material Conflicts of Interest associated with the principal transactions and riskless principal transactions to Retirement Investors and to describe its policies and procedures for safeguarding against those conflicts of interest. These disclosures should assist Retirement Investors in assessing the care with which Financial Institutions have designed their procedures, even if they are insufficient to fully convey how vigorously the Financial Institution implements the protections. In some cases, a systemic violation, or the possibility of such a violation, may be apparent on the face of the policies. In other cases, normal discovery in litigation may provide the information necessary. Certainly, if a Financial Institution were to provide significant prizes or bonuses for Advisers to push principal transactions and riskless principal transactions that were not in the Best Interest of Retirement Investors, Retirement Investors would often be in a position to pursue the claim. Most important, however, the enforceable obligation to adopt and comply with the policies and procedures as set forth herein, and to make relevant disclosures of the policies and procedures and of Material Conflicts of Interest, should create a powerful incentive for Financial Institutions to carefully police conflicts of interest, reducing the need for litigation in the first place.
In response to commenters that expressed concern about the specific use of the term “warranty,” the Department intends the term to have its standard meaning as a “promise that something in furtherance of the contract
Additionally, although the policies and procedure requirement applies equally to ERISA plans, the final exemption does not require Financial Institutions to make a warranty with respect to ERISA plans, just as it does not require the execution of a contract with respect to ERISA plans. For these plans, a separate warranty is unnecessary because Title I of ERISA already provides an enforcement mechanism for failure to comply with the policies and procedures requirement. Under ERISA section 502(a), plan participants, fiduciaries, and the Secretary of Labor have ready means to enforce any failure to meet the conditions of the exemption, including a failure to comply with the policies and procedure requirement. A Financial Institution's failure to comply with the exemption's policies and procedure requirements would result in a non-exempt prohibited transaction under ERISA section 406 and would likely constitute a fiduciary breach under ERISA section 404. As a result, a plan participant or beneficiary, plan fiduciary, and the Secretary would be able to sue under ERISA section 502(a)(2), (3), or (5) to recover any loss in value to the plan (including the loss in value to an individual account), or to obtain disgorgement of any wrongful profits or unjust enrichment. Accordingly, the warranty is unnecessary in the context of ERISA plans.
The proposed exemption also contained a requirement that the Adviser and Financial Institution would have had to warrant that they and their Affiliates would comply with all applicable federal and state laws regarding the rendering of the investment advice, the purchase, sale or holding of the Asset and the payment of compensation related to the purchase, sale and holding. While the Department did receive some support for this condition in comments, several commenters opposed this warranty proposal as being overly broad, and urged that it be deleted. The commenters argued that the warranty could create contract claims based on a wide variety of state and federal laws, without regard to the limitations imposed on individual actions under those laws. In addition, commenters suggested that many of the violations associated with these laws could be quite minor or unrelated to the Department's concerns about conflicts of interest. In response to these comments, the Department has eliminated this warranty from the final exemption.
Section II(d)(4) provides that the Financial Institution's written policies and procedures regarding principal transactions and riskless principal transactions must address how the credit risk and liquidity assessments required by Section III(a)(3) of the exemption will be made. This requirement serves as an implementation tool for the exemption condition that a debt security that is purchased by a plan, participant or beneficiary account, or IRA, possess at the time of purchase no greater than moderate credit risk and sufficiently liquidity that it can be sold at or near its carrying value within a reasonably short period of time.
As discussed later in this preamble, when addressing the credit and liquidity conditions set forth in Section III(a) of the exemption, many commenters identified perceived compliance difficulties. Of those comments, one comment was applicable to Section II of the exemption. The commenter suggested that the Financial Institution be required to develop policies and procedures to assist Advisers by specifying how these assessments are to be made. This suggestion addressed some concerns expressed by commenters regarding the credit and liquidity conditions, and the Department concurs with the comment. The Department believes that Financial Institutions will be able to comply with the requirement, in part, by developing, if they do not already exist, policies and procedures to ensure that the credit worthiness and liquidity of debt securities are properly evaluated.
Section II(e) of the exemption obligates the Financial Institution to make specified contract disclosures to Retirement Investors in order to ensure that they have basic information about the scope of Adviser conflicts and that they appropriately authorize principal transactions and riskless principal transactions. For advice to Retirement Investors in IRAs and non-ERISA plans, the disclosures must be provided prior to or at the same time as the recommended transaction either as part of the contract or in a separate written disclosure provided to the Retirement Investor. For advice to Retirement Investors regarding investments in ERISA plans, the disclosures must be provided prior to or at the same time as the execution of the recommended transaction. The disclosure may be provided in person, electronically, or by mail. In the disclosures, the Financial Institution must clearly and prominently in a single written disclosure:
(1) Set forth in writing (i) the circumstances under which the Adviser and Financial Institution may engage in Principal Transactions and Riskless Principal Transactions with the Plan, participant or beneficiary account, or IRA, (ii) a description of the types of compensation that may be received by the Adviser and Financial Institution in connection with Principal Transactions and Riskless Principal Transactions, including any types of compensation that may be received from third parties, and (iii) identify and disclose the Material Conflicts of Interest associated with Principal Transactions and Riskless Principal Transactions;
(2) Except for existing contracts, document the Retirement Investor's affirmative written consent, on a prospective basis, to Principal Transactions and Riskless Principal Transactions between the Adviser or Financial Institution and the Plan, participant or beneficiary account, or IRA;
(3) Inform the Retirement Investor (i) that the consent set forth in Section II(e)(2) is terminable at will upon written notice by the Retirement Investor at any time, without penalty to the Plan or IRA, (ii) of the right to obtain, free of charge, copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as information about the Principal Traded Asset, including its purchase or sales price, and other salient attributes, including, as applicable: The credit quality of the issuer; the effective yield; the call provisions; and the duration, provided that if the Retirement Investor's request is made prior to the transaction, the information must be provided prior to the transaction, and if the request is made after the transaction, the information must be provided within 30 business days after the request, (iii) that model contract disclosures or other model notice of the contractual terms which are reviewed for accuracy no less than quarterly and updated within 30 days as necessary are maintained on the Financial Institution's Web site, and (iv) that the Financial Institution's written description of its policies and procedures adopted in
(4) Describe whether or not the Adviser and Financial Institution will monitor the Retirement Investor's investments that are acquired through a Principal Transaction or Riskless Principal Transaction and alert the Retirement Investor to any recommended change to those investments and, if so, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted.
In addition, Section II(e)(5) of the exemption provides a mechanism for correcting disclosure errors, without losing the exemption. It provides that the Financial Institution will not fail to satisfy Section II(e), or violate a contractual provision based thereon, solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, or if the Web site is temporarily inaccessible, provided that (i) in the case of an error or omission on the web, the Financial Institution discloses the correct information as soon as practicable, but not later than 7 days after the date on which it discovers or reasonably should have discovered the error or omission, and (ii) in the case of other disclosures, the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. Section II(e)(5) further provides that to the extent compliance with the contract disclosure requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
Several commenters supported the proposed disclosures. Commenters recognized that well-designed disclosure can serve multiple purposes, including facilitating informed investment decisions. However, even if investors do not carefully review the disclosures they receive, commenters perceived a benefit to investors from the greater transparency of public disclosure. For example, Financial Institutions may change practices that run contrary to Retirement Investors' interests rather than disclose them publicly. One commenter suggested the disclosures should be strengthened and required for all retirement savings products, even beyond the scope of the Regulation and this exemption.
As proposed, the provision required disclosure of complete information about all the fees and other payments currently associated with the Retirement Investor's investments. Commenters objected to this as overly broad, given the exemption's limitation to principal transactions. The Department accepted this comment, and limited the disclosure to the information about the principal traded asset, including its purchase or sales price and other salient attributes, while still ensuring timely access by the Retirement Investor. By salient attributes, the Department means the credit quality of the issuer, the effective yield, the call provisions, and the duration, among other similar attributes, and the Department recognizes that the salient attributes will differ depending on the principal traded asset. In accepting this comment, the Department did not elect to modify the disclosure requirement further with qualifiers such as “reasonably” or “in the Financial Institution's possession.” The Department believes that no additional limitation need be placed on the rights of the Retirement Investor to request information because, if a Financial Institution is advising a Retirement Investor to enter into a principal transaction or a riskless principal transaction, it should have all of the salient information available when providing that advice. The Department also made a clarification, requested by a commenter, that the Retirement Investor's consent must be withdrawn in writing. The Department concurs that this will provide additional certainty to the parties.
FINRA's suggestion that the parties agree on the extent of monitoring of the Retirement Investor's investments was adopted, in Section II(e)(4). In making this determination, Financial Institutions should carefully consider whether certain investments can be prudently recommended to the individual Retirement Investor, in the first place, without a mechanism in place for the ongoing monitoring of the investment. Finally, a number of commenters requested relief for good faith, inadvertent failure to comply with the exemption. A specific provision applicable to the Section II(e) disclosures is included in Section II(e)(5).
Under Section II(f) of the final exemption, relief is not available if a Financial Institution's contract with Retirement Investors regarding investments in IRAs and non-ERISA plans contains the following:
(1) Exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms;
(2) Except as provided in paragraph (f)(4), a provision under which the Plan, IRA or Retirement Investor waives or qualifies its right to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or in an individual or class claim agrees to an amount representing liquidated damages for breach of the contract; provided that the parties may knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law; or
(3) Agreements to arbitrate or mediate individual claims in venues that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption.
Section II(f)(4) provides that, in the event the provision on pre-dispute arbitration agreements for class or representative claims in paragraph (f)(2) is ruled invalid by a court of competent jurisdiction, this provision shall not be a condition of the exemption with respect to contracts subject to the court's jurisdiction unless and until the court's decision is reversed, but all other terms of the exemption shall remain in effect.
The purpose of Section II(f) is to ensure that Retirement Investors receive the full benefit of the exemption's protections, by preventing them from being contracted away. If an Adviser makes a recommendation regarding a principal transaction or a riskless principal transaction, for compensation, within the meaning of the Regulation, he or she may not disclaim the duties or liabilities that flow from that
The Department's approach in this respect is consistent with FINRA's rules permitting mandatory pre-dispute arbitration for individual claims, but not for class action claims.
A number of commenters addressed the proposed approach to arbitration and the other ineligible provisions of Section II(f). A discussion of the comments and the Department's responses follow.
The Department included Section II(f)(1) in the final exemption without changes from the proposal. Commenters did, however, raise a few questions on the provision. In particular, commenters asked whether the contract could disclaim liability for acts or omissions of third parties, and whether there could be venue selection clauses. In addition, commenters asked whether the contract could require exhaustion of arbitration or mediation before filing in court. Section II(f)(1) does not prevent a Financial Institution's contract with IRA and non-ERISA plan investors from disclaiming liability for acts or omissions of third parties to the extent permissible under applicable law. In addition, for individual claims, reasonable arbitration and mediation requirements are not prohibited. In response to questions about venue selection, the final exemption includes a new Section II(f)(3), which provides that investors may not be required to arbitrate or mediate their individual claims in venues that are distant or that otherwise unreasonably limit their ability to assert the claims safeguarded by this exemption.
The Department has not revised Section II(f) to address every provision that may or may not be included in the contract. While some commenters submitted specific requests regarding specific contract language, and others suggested the Department provide model contracts for Financial Institutions to use, the Department has declined to make these changes in the exemption. The Department notes that Section II(f)(1) prohibits all exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms, and Section II(g)(5) prohibits Financial Institutions and Advisers from purporting to disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by Section 410 of ERISA. Therefore, in response to comments regarding choice of law provisions, modifying ERISA's statute of limitations, and imposing obligations on the Retirement Investor, the Financial Institutions must determine whether their specific provisions are exculpatory and would disclaim or limit their liability under ERISA, or that of their Advisers. If so, they are not permitted. The Department will provide additional guidance in response to questions and enforcement proceedings
Section II(f)(2) of the final exemption adopts the approach, as proposed, that individual claims may be the subject of contractual pre-dispute binding arbitration. Class or other representative claims, however, must be allowed to proceed in court. The final exemption also provides that contract provisions may not limit recoveries to an amount representing liquidated damages for breach of the contract. However, the final exemption expressly permits Retirement Investors to knowingly waive their rights to obtain punitive damages or rescission of recommended transactions to the extent such waivers are permitted under applicable law. Commenters were divided on the approach taken in the proposal, as discussed below.
Some commenters objected to limiting Retirement Investors' right to sue in court on individual claims and specifically focused on the FINRA arbitration process. These commenters described FINRA's process as an unequal playing field, with insufficient protections for individual investors. They asserted that arbitrators are not required to follow federal or state laws, and so would not be required to enforce the terms of the contract. In addition, commenters complained that the decision of an arbitrator generally is not subject to appeal and cannot be overturned by any court. According to these commenters, even when the arbitrators find in favor of the consumer, the consumers often receive significantly smaller recoveries than they deserve. Moreover, some asserted that binding pre-dispute arbitration may be contrary to the legislative intent of ERISA, which provides for “ready access to federal courts.”
Some commenters opposed to arbitration indicated that preserving the right to bring or participate in class actions in court would not give Retirement Investors sufficient access to courts. According to these commenters, allowing Financial Institutions to require resolution of individual claims by arbitration would impose additional and unnecessary hurdles on investors seeking to enforce the Best Interest standard. One commenter warned that the Regulation would make it more difficult for Retirement Investors to pursue class actions because the individualized requirements for proving fiduciary status could undermine any claims about commonality. Commenters said that class action lawsuits tend to be expensive and protracted, and even where successful, investors often recover only a small portion of their losses.
Other commenters just as forcefully supported pre-dispute binding arbitration agreements. Some asserted that arbitration is generally quicker and less costly than judicial proceedings. They argued that FINRA has well-developed protections in place to protect the interests of aggrieved investors. One commenter pointed out that FINRA requires that the arbitration provisions of a contract be highlighted and disclosed to the customer, and that customers be allowed to choose an “all-
A number of commenters argued that arbitration should be available for
After consideration of the comments on this subject, the Department has decided to adopt the general approach taken in the proposal. Accordingly, contracts with Retirement Investors may require pre-dispute binding arbitration of individual disputes with the Adviser or Financial Institution. The contract, however, must preserve the Retirement Investor's right to bring or participate in a class action or other representative action in court in such a dispute in order for the exemption to apply.
The Department recognizes that, for many claims, arbitration can be more cost-effective than litigation in court. Moreover, the exemption's requirement that Financial Institutions acknowledge their own and their Advisers' fiduciary status should eliminate an issue that frequently arises in disputes over investment advice. In addition, permitting individual matters to be resolved through arbitration tempers the litigation risk and expense for Financial Institutions, without sacrificing Retirement Investors' ability to secure judicial relief for systemic violations that affect numerous investors through class actions.
On the other hand, the option to pursue class actions in court is an important enforcement mechanism for Retirement Investors. Class actions address systemic violations affecting many different investors. Often the monetary effect on a particular investor is too small to justify the pursuit of an individual claim, even in arbitration. Exposure to class claims creates a powerful incentive for Financial Institutions to carefully supervise individual Advisers, and ensure adherence to the Impartial Conduct Standards. This incentive is enhanced by the transparent and public nature of class proceedings and judicial opinions, as opposed to arbitration decisions, which are less visible and pose less reputational risk to Financial Institutions or Advisers found to have violated their obligations.
The ability to bar investors from bringing or participating in such claims would undermine important investor rights and incentives for Advisers to act in accordance with the Best Interest standard. As one commenter asserted, courts impose significant hurdles for bringing class actions, but where investors can surmount theses hurdles, class actions are particularly well suited for addressing systemic breaches. Although by definition communications to a specific investor generally must have a degree of specificity in order to constitute fiduciary advice, a class of investors should be able to satisfy the requirements of commonality, typicality and numerosity where there is a systemic or wide-spread problem, such as the adoption or implementation of non-compliant policies and procedures applicable to numerous Retirement Investors, the systematic use of prohibited or misaligned financial incentives, or other violations affecting numerous Retirement Investors in a similar way. Moreover, the judicial system ensures that disputes involving numerous retirement investors and systemic issues will be resolved through a well-established framework characterized by impartiality, transparency, and adherence to precedent. The results and reasoning of court decisions serve as a guide for the consistent application of that law in future cases involving other Retirement Investors and Financial Institutions.
This is consistent with the approach long adopted by FINRA and its predecessor self-regulatory organizations. FINRA Arbitration rule 12204 specifically bars class actions from FINRA's arbitration process and requires that pre-dispute arbitration agreements between brokers and customers contain a notice that class action matters may not be arbitrated. In addition, it provides that a broker may not enforce any arbitration agreement against a member of certified or putative class action, until the certification is denied, the class action is decertified, the class member is excluded from, or elects not participate in, the class. This rule was adopted by the National Association of Securities Dealers and approved by the SEC in 1992.
[T]he NASD believes, and the Commission agrees, that the judicial system has already developed the procedures to manage class action claims. Entertaining such claims through arbitration at the NASD would be difficult, duplicative and wasteful. . . . The Commission agrees with the NASD's position that, in all cases, class actions are better handled by the courts and that investors should have access to the courts to resolve class actions efficiently.
One commenter suggested that if the Department preserved the ability of a Financial Institution to require arbitration of claims, it should consider requiring a series of additional safeguards for arbitration proceedings permitted under the exemption. The commenter suggested that the conditions could state that (i) the arbitrator must be qualified and independent; (ii) the arbitration must be held in the location of the person challenging the action; (iii) the cost of the arbitration must be borne by the Financial Institution; (iv) the Financial Institution's attorneys' fees may not be shifted to the Retirement Investor, even if the challenge is unsuccessful; (v) statutory remedies may not be limited or altered by the contract; (vi) access to adequate discovery must be permitted; (vii) there must be a written record and a written decision; (viii) confidentiality requirements and protective orders which would prohibit the use of evidence in subsequent cases must be prohibited. The commenter said that some, but not all, of these procedures are currently required by FINRA.
The Department declines to mandate additional procedural safeguards for arbitration beyond those already mandated by other applicable federal and state law or self-regulatory organizations. In the Department's view, the FINRA arbitration rules, in particular, provide significant safeguards for fair dispute resolution, notwithstanding the concerns raised by some commenters. FINRA's Code of Arbitration Procedures for Customer Disputes applies when required by written agreement between the FINRA member and the customer, or if the
Some commenters asserted that the Department does not have the authority to include the exemption's provisions on class action waivers under the Federal Arbitration Act (FAA), which they said protects enforceable arbitration agreements and expresses a federal policy in favor of arbitration over litigation. Without clear statutory authority to restrict arbitration, these commenters said, the Department cannot include the provisions on class action waivers.
These comments misconstrue the effect of the FAA on the Department's authority to grant exemptions from prohibited transactions. The FAA protects the validity and enforceability of arbitration agreements. Section 2 of the FAA states: “[a] written provision in any . . . contract . . . to settle by arbitration a controversy thereafter arising out of such contract . . . shall be valid, irrevocable, and enforceable, save upon such grounds as exist at law or in equity for the revocation of any contract.”
Section II(f)(2) of the exemption is fully consistent with the FAA. The exemption does not purport to render an arbitration provision in a contract between a Financial Institution and a Retirement Investor invalid, revocable, or unenforceable. Nor, contrary to the concerns of one commenter, does Section II(f)(2) prohibit such waivers. Both Institutions and Advisers remain free to invoke and enforce arbitration provisions, including provisions that waive or qualify the right to bring a class action or any representative action in court. Instead, such a contract simply does not meet the conditions for relief from the prohibited transaction provisions of ERISA and the Code. As a result, the Financial Institution and Adviser would remain fully obligated under both ERISA and the Code to refrain from engaging in prohibited transactions. In short, Section II(f)(2) does not affect the validity, revocability, or enforceability of a class-action waiver in favor of individual arbitration. This regulatory scheme is thus a far cry from the State judicially created rules that the Supreme Court has held preempted by the FAA,
The Department has broad discretion to craft exemptions subject to the Department's overarching obligation to ensure that the exemptions are administratively feasible, in the interests of plan participants, beneficiaries, and IRA owners, and protective of their interests. In this instance, the Department has concluded that the enforcement rights and protections associated with class action litigation are important to safeguarding the Impartial Conduct Standards and other anti-conflict provisions of the exemption. If a Financial Institution enters into a contract requiring binding arbitration of class claims, the Department would not purport to invalidate the provision, but rather would insist that the Financial Institution fully comply with statutory provisions prohibiting conflicted fiduciary transactions in its dealings with its Retirement Investment customers. The FAA is not to the contrary. It neither limits the Department's express grant of discretionary authority over exemptions, nor entitles parties that enter into arbitration agreements to a pass from the prohibited transaction rules.
While the Department is confident that its approach in the exemption does not violate the FAA, it has carefully considered the position taken by several commenters that the Department exceeded the Department's authority in including provisions in the exemption on class and representative claims, and the possibility that a court might rule that the condition regarding arbitration of class claims in Section II(f)(2) of the exemption is invalid based on the FAA. Accordingly, in an abundance of caution, the Department has specifically provided that Section II(f)(2) can be severable if a court finds it invalid based on the FAA. Specifically, Section II(f)(4) provides that:
In the event that the provision on pre-dispute arbitration agreements for class or representative claims in paragraph (f)(2) of this Section is ruled invalid by a court of competent jurisdiction, this provision shall not be a condition of this exemption with respect to contracts subject to the court's jurisdiction unless and until the court's decision is reversed, but all other terms of the exemption shall remain in effect.
The Department is required to find that the provisions of an exemption are administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of participants and beneficiaries and IRA owners. The Department finds that the exemption with paragraph (f)(2) satisfies these requirements. The Department believes, consistent with the position of the SEC and FINRA, that the courts are generally better equipped to handle class claims than arbitration procedures and that the prohibition on contractual provisions mandating arbitration of such claims helps the Department make the requisite statutory findings for granting an exemption.
Nevertheless, the Department has determined that, based on all the exemption's other conditions, it can still make the necessary findings to grant the exemption even without the condition prohibiting pre-dispute agreements to arbitrate class claims. In particular, if a court were to invalidate the condition, the Department would still find that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries, and protective of the rights of the participants and beneficiaries. It would be less protective, but still sufficient to grant the exemption.
The Department's adoption of the specific severability provision in Section II(f)(4) of the exemption should not be viewed as evidence of the Department's intent that no other conditions of this or the other exemptions granted today are severable if a court were to invalidate them.
Some commenters asked whether the proposal's prohibition of exculpatory clauses would affect the parties' ability to limit remedies under the contract, particularly regarding liquidated damages, punitive damages, consequential damages and rescission. In response, the Department has added text to Section II(f)(2) in the final exemption clarifying that the parties, in an individual or class claim, may not agree to an amount representing liquidated damages for breach of the contract. However, the exemption, as finalized, expressly permits the parties to knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law.
In the Department's view, it is sufficient to the exemptions' protective purposes to permit recovery of actual losses. The availability of such a remedy should ensure that plaintiffs can be made whole for any losses caused by misconduct, and provide an important deterrent for future misconduct. Accordingly, the exemption does not permit the contract to include liquidated damages provisions, which could limit Retirement Investors' ability to obtain make-whole relief.
On the other hand, the exemption permits waiver of punitive damages to the extent permissible under governing law. Similarly, rescission can result in a remedy that is disproportionate to the injury. In cases where an advice fiduciary breached its obligations, but there was no injury to the participant, a rescission remedy can effectively make the fiduciary liable for losses caused by market changes, rather than its misconduct. These new provisions in section II(f)(2) only apply to waiver of the contract claims; they do not qualify or limit statutory enforcement rights under ERISA. Those statutory remedies generally provide for make-whole relief and to rescission in appropriate cases, but they do not provide for punitive damages.
Section III of the exemption sets forth conditions that apply to the terms of each principal transaction or a riskless principal transaction entered into under the exemption. Section III(a) applies only to
Section III(a)(1) and (2) of the exemption provides that the debt security being bought by the Plan, participant or beneficiary account, or IRA must not have been issued or, at the time of the transaction, underwritten by the Financial Institution or any Affiliate. The Department received comments generally objecting to these conditions as unduly limiting investment opportunities to Retirement Investors. Commenters argued that many debt securities will only be available for purchase by a Retirement Investor on a principal basis as part of the initial issuance or underwriting since the debt securities are not frequently resold in small lots to retail investors on either a principal or an agency basis.
The Department is sympathetic to the commenters' position, but has determined to adopt the language without modification. This reflects the Department's concerns that additional conflicts of interest are inherent in transactions where the issuer or underwriter of a security (whether debt or equity) is a fiduciary to a plan or IRA. In such instances, the Financial Institution generally has either been retained by a third party to sell securities as part of an underwriting and has made guarantees as to such sales and will likely profit from such sales more than in a traditional principal transaction or is issuing securities on its own behalf for the specific purposes of benefiting itself. Further, since generally the issued or underwritten securities are being issued or underwritten by the Financial Institution for the first time, heightened issues regarding pricing and liquidity result. Since these unique conflicts exist with respect to both issuance and underwriting transactions, they would require conditions unique to issuance and underwriter principal transactions, respectively. This exemption was not designed to address such conflicts. The Department believes that permitting such transactions without applying additional conditions would not be protective of participants and beneficiaries of plans and IRA owners. Parties seeking relief for such transactions are encouraged to seek an individual exemption from the Department.
Section III(a)(3) of the exemption requires that, using information reasonably available to the Adviser at the time of the transaction, the Adviser must determine that the debt security being purchased by the Plan, participant or beneficiary account, or IRA, possesses no greater than a moderate credit risk and is sufficiently liquid that the debt security could be sold at or near its carrying value within a reasonably short period of time. Debt securities subject to a moderate credit risk should possess at least average credit-worthiness relative to other similar debt issues. Moderate credit risk would denote current low expectations of default risk, with an adequate capacity for payment of principal and interest.
This condition is intended to identify investment grade securities, and avoid the circumstance in which an investment advice fiduciary can recommend speculative debt securities and then sell them to the Plan, participant or beneficiary account, or IRA, from its own inventory. The SEC used similar provisions in setting credit standards in its regulations, including its Rule 6a-5 issued under the Investment Company Act.
Some commenters on this aspect of the proposal generally objected to the condition's lack of objectivity. Some requested that the Department instead specifically condition the exemption on the security's being “investment grade,” rather than the proposed credit and liquidity standards. While the Department generally intends the exemption to be limited to securities that a reasonable investor would treat as investment grade securities, Section 939A of the Dodd-Frank Act provides that the Department may not “reference or rely on” credit ratings—including “investment grade”—in the exemption's conditions. Accordingly, Advisers and Financial Institutions wishing to rely on the exemption must make a reasonable determination of creditworthiness,
Another commenter suggested that the Department replace the liquidity component of the standard with the provision of two quotes or a requirement that the Financial Institution reasonably believe a principal transaction provides a better price than would be available in the absence of a principal transaction. The Department agrees that it is important that the price of the principal transaction or a riskless principal transaction is reasonable and has conditioned the exemption on the Adviser and Financial Institution's commitment to seek to obtain the best execution reasonably available under the circumstances with respect to the transaction (and for FINRA members, specifically on satisfaction of FINRA rules 2121 (Fair Prices and Commissions) and 5310 (Best Execution and Interpositioning)). However, the Department determined not to replace the liquidity component with the two quote requirement in light of commenters' views that the requirement was unlikely to be workable or effective in achieving the Department's aims.
Other commenters focused on the timing associated with the liquidity component of the condition. They expressed concern that the condition may apply throughout the time period in which the security is held by the Retirement Investor. The Department revised the operative text to make clear that the standard must be satisfied based on the information reasonably available to the Adviser at the time of the transaction and not thereafter. Nevertheless, the Department notes that the Adviser's consideration of whether the recommendation is in the Retirement Investor's Best Interest may also need to include consideration of information that is reasonably available regarding restrictions or near term expected performance of the debt security, in light of the Retirement Investor's needs and objectives. The Department additionally eliminated the credit standards with respect to sales from a plan, participant or beneficiary account, or IRA; accordingly, this condition will not stand in the way of a plan or IRA selling a security that no longer meets the credit standards to a Financial Institution in a principal transaction. The purpose of the liquidity condition was to protect Retirement Investors from the dangers associated with a conflicted Adviser saddling them with low-quality securities, not to prevent them from disposing of such securities.
Commenters also argued that although the Department cited the similar credit standards set forth in the SEC's Rule 6a-5 issued under the Investment Company Act, the Department's reliance on SEC language as a template for the credit risk language is not necessarily appropriate because the SEC uses the language for a different purpose unrelated to retail accounts. While in a different context, the SEC's adoption of similar language supports the Department's view that Financial Institutions are capable of implementing the standard. For that reason, the SEC language remains relevant. Further, the Department itself has previously proposed the use of the same language in multiple class exemptions without material objections by the financial services industry to the workability of the language.
Some commenters also indicated that the Department's use of the term “fair market value” in the proposal, in place of the term “carrying value,” that is used in the SEC standard, was confusing. In response, the Department revised the final exemption to use the term “carrying value” rather than “fair market value.” In addition, the Department adopted the suggestion of a commenter that Financial Institutions be required to establish policies and procedures to determine how credit risk and liquidity assessments will be made and to develop standards for such assessments. This requirement is in Section II(d), discussed above, and is intended to provide a mechanism for Financial Institutions to operationalize this requirement. As revised, the Department believes that the credit standards condition can serve a protective role without being too vague or operationally difficult.
In addition to operational concerns, commenters addressed whether credit standards should be part of the exemption at all. Some commenters opposed both the credit and liquidity conditions on the grounds that the Department was substituting the Department's judgment for the judgment of Retirement Investors. Other commenters, however, supported the Department's approach as imposing appropriate safeguards against the added risk associated with investment advice fiduciaries recommending principal transactions and riskless principal transactions involving securities that possess substantial credit risk or are thinly traded.
The Department has decided to retain the credit standards. First, the exemption addresses only those principal transactions and riskless principal transactions that are the result of the provision of fiduciary investment advice. To the extent that a Retirement Investor is truly acting on his or her own without the advice of an investment advice fiduciary, the necessary exemptive relief already exists. As discussed above, Part II of PTE 75-1 currently provides relief from ERISA section 406(a) for principal transactions so long as the broker-dealer or bank does not render investment advice with respect to the assets involved in the principal transaction. Second, the most commonly held categories of debt securities will continue to be available to plans and IRAs.
Most importantly, with respect to investment advice that is being provided by an investment advice fiduciary, the Department believes that inherent conflicts of interest justify the credit and liquidity conditions. As discussed elsewhere in this preamble, principal transactions in particular raise significant conflicts of interest, and are often associated with substantial pricing, transparency and liquidity issues. These concerns are magnified when a debt security is of lesser quality. Further, beyond the Department's heightened concerns regarding pricing, transparency and liquidity, Financial Institutions may generate higher levels of compensation with respect to lower quality debt securities, generating additional conflicts that would otherwise be absent from principal transactions and riskless principal transactions. Finally, the Department notes that other prohibited transaction exemptions granted by the Department permitting principal transactions between plans and plan fiduciaries also contain similar credit standards.
Section III(b) provides that a principal transaction or a riskless principal transaction may not be part of an agreement, arrangement, or understanding designed to evade compliance with ERISA or the Code, or to otherwise impact the value of the principal traded asset. Such a condition protects against the Adviser or Financial Institution manipulating the terms of the principal transaction or a riskless principal transaction, either as an isolated transaction or as a part of a
Section III(c) requires that the purchase or sale of the principal traded asset must be for no consideration other than cash. By limiting a purchase or sale to cash consideration, the Department intends that relief will not be provided for a principal transaction or a riskless principal transaction that is executed on an in-kind basis. The limitation to cash reflects the Department's concern that in-kind transactions create complexity and additional conflicts of interest because of the need to value the in-kind asset involved in the transaction. The Department did not receive comments on this condition, and it was adopted as proposed.
Section III(d) of the proposal addressed the pricing of the principal transaction by proposing that the purchase or sale occur at a price that (1) the Adviser and Financial Institution reasonably believe is at least as favorable to the plan, participant or beneficiary account, or IRA, as the price available in a transaction that is not a principal transaction, and (2) is at least as favorable to the plan, participant or beneficiary account, or IRA, as the contemporaneous price for the security, or a similar security if a price is not available for the same security, offered by two ready and willing counterparties that are not Affiliates of the Adviser or Financial Institution. The proposal further provided that when comparing the prices, the Adviser and Financial Institution could take into account commissions and mark-ups/mark-downs.
Many commenters raised concerns regarding the practicality of the two quote process outlined in proposed Section III(d)(2). A number of commenters did not believe that the two quote process would be workable. They said that two quotes may not be available on all securities, particularly corporate debt securities. They further expressed uncertainty about the meaning of the “similar securities” that could be substituted. In addition, commenters indicated that the time needed to go through the two quote process could interfere with a Financial Institution's duty of best execution under FINRA rule 5310, or in any event could slow the execution of a transaction, to the detriment of the Retirement Investor. FINRA suggested the exemption should be conditioned on FINRA rule 5310 instead of the proposed two quote requirement.
Further, the Department has come to believe that the quotes themselves may not be reliable measure of fair price because they are solicited as comparisons rather than with the intent to purchase or sell. A Financial Institution might be less than rigorous in its solicitation of the two quotes, perhaps seeking quotes that simply validate the Financial Institution's opinion of the appropriate price for the principal transaction. In light of such comments and concerns, the Department did not adopt the two quote requirement.
However, in order to address the Department's concern about the price of the transaction, as discussed in more detail above, the exemption requires that Advisers and Financial Institutions engaging in the transactions seek to obtain the best execution reasonably available under the circumstances. For FINRA members, the final exemption provides that they must comply with FINRA rules 2121 and 5310. These rules provide for best execution and fair pricing, and they will ensure that the Financial Institution does not use its relationship with a plan or IRA to benefit financially to the detriment of the plan or IRA.
One commenter expressed strong support for the intent behind the pricing conditions to protect Retirement Investors. The commenter expressed concern, however, that Financial Institutions could work around the proposed pricing conditions, resulting in the conditions failing to provide the anticipated protections to Retirement Investors. The commenter suggested that Financial Institutions be required to articulate why the principal transaction is in the Retirement Investor's Best Interest and provide current market data, available from FINRA's TRACE system, for example, to back up such articulation. Another commenter also suggested that specific pricing information could be made available on request.
The Department believes that the Department's approach in Section II(c)(2) of the final exemption Impartial Conduct Standards implements the intent of the pricing condition proposed in Section III(d)(1). The Department did not adopt the suggestion to require the provision of current market data based upon its concern that the additional costs would likely outweigh the benefits, particularly for retail investors. Because of the nature of the marketplace for principal traded assets, current market data is often difficult to analyze and apply to an individual transaction involving the same asset. Such difficulties are particularly problematic with respect to less sophisticated Retirement Investors who will not have the analytic tools at their disposal to interpret any market data that could be provided to them. Consequently, disclosure of such data would likely be of limited value to retail investors. To the extent that the information would be useful to more sophisticated Retirement Investors, such Retirement Investors typically have the information and necessary analytic tools already available.
Section IV(a) of the exemption requires that, prior to or at the same time as the execution of the transaction, the Adviser or Financial Institution must provide the Retirement Investor, orally or in writing, a disclosure of the capacity in which the Financial Institution may act with respect to the transaction. By “capacity in which the Financial Institution may act,” the Department means that the Financial Institution must notify the Retirement Investor if it may act as principal in the transaction. This requirement is intended to harmonize with the SEC's Temporary Rule 206(3)-3T, which has a similar pre-transaction requirement. Such a harmonization allows for a streamlined disclosure requirement, which places less burden on the Financial Institutions.
In the proposal, Section IV(a) would have required the Adviser or Financial Institution to provide a statement, prior to engaging in the principal transaction, that the purchase or sale would be executed as a principal transaction. A few commenters indicated that they would not always know if the transaction would be executed as a principal transaction prior to the transaction. These commenters suggested that the Department adopt the approach in the SEC's Temporary Rule 206(3)-3T, which a commenter said, requires that an investment adviser inform the client “of the capacity in which it may act with respect to such transaction.” A commenter said this formulation recognized that the investment adviser may not know at
Some commenters indicated that the Department's requirement in Section IV(a) was burdensome in that they perceived it to require the Retirement Investor's affirmative consent to the specific terms of the transaction in advance of the execution. In response, the Department notes that the proposal did not, and the final exemption does not, contemplate such consent. However, the Department notes that the exemption is limited to Advisers and Financial Institutions that act in a non-discretionary capacity.
The proposed pre-transaction disclosure also would have required disclosure of the two quotes received from unrelated counterparties and the mark-up, mark-down or other payment to be applied to the principal transaction.
The Department was persuaded by the commenters that required disclosure of the mark-up or mark-down might introduce significant complexity to compliance with the exemption, in particular with respect to transactions that could be covered by FINRA's pending disclosure requirement, and therefore has not adopted the mark-up/mark-down disclosure requirement in the final exemption. Commenters' suggestions to require disclosure of the minimum and maximum mark-up/mark-down were not adopted because the Department believes that this disclosure would not be specific enough to benefit Retirement Investors.
Section IV(b) of the proposal would have required a written confirmation in accordance with Rule 10b-10 under the Exchange Act, that also includes disclosure of the mark-up, mark-down or other payment to be applied to the principal transaction. A number of comments noted that Rule 10b-10 does not currently include disclosure of the mark-up or mark-down, and making the change would be costly. There were also significant comments, discussed elsewhere, as to the practicality of the mark-up or mark-down disclosure, such that the Department determined not to require the disclosure as discussed above. As a result, the requirement to include a mark-up or mark-down as part of the confirmation has been eliminated. Section IV(b) now simply requires the issuance of a confirmation of the transaction. The requirement to provide a confirmation may be met by compliance with the existing Rule 10b-10, or any successor rule in effect at the time of the transaction, or for Advisers and Financial Institutions not subject to the Exchange Act, similar requirements imposed by another regulator or self-regulatory organization.
Section IV(c) sets forth a requirement under which the Adviser or Financial Institution must provide certain written information clearly and prominently in a single written disclosure to the Retirement Investor on an annual basis. The annual disclosure must include: (1) A list identifying each principal transaction and riskless principal transaction executed in the Retirement Investor's account in reliance on this exemption during the applicable period and the date and price at which the transaction occurred; and (2) a statement that (i) the consent required pursuant to Section II(e)(2) is terminable at will upon written notice, without penalty to the Plan or IRA, (ii) the right of a Retirement Investor in accordance with Section II(e)(3)(ii) to obtain, free of charge, information about the Principal Traded Asset, including its salient attributes, (iii) model contract disclosures or other model notice of the contractual terms which are reviewed for accuracy no less than quarterly updated within 30 days as necessary are maintained on the Financial Institution's Web site, and (iv) the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) are available free of charge on the Financial Institution's Web site.
With respect to this requirement, Section IV(d) of the exemption includes a good faith compliance provision, under which the Financial Institution will not fail to satisfy Section IV solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information or if the Web site is temporarily inaccessible, provided that (i) in the case of an error or omission on the web, the Financial Institution discloses the correct information as soon as practicable, but not later than 7 days after the date on which it discovers or reasonably should have discovered the error or omission, and (ii) in the case of other disclosures, the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after that date on which it discovers or reasonably should have discovered the error or omission. In addition, to the extent compliance with the annual disclosure requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, the exemption provides that they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
The proposal included an annual disclosure requirement in Section IV(c) that would have included the following elements:
(1) A list identifying each principal transaction engaged in during the applicable period, the prevailing market price at which the Debt Security was purchased or sold, and
(2) A statement that the consent required pursuant to Section II(e)(2) is terminable at will, without penalty to the Plan or IRA.
The disclosure would have been required to be made within 45 days after the end of the applicable year.
As finalized, the annual disclosure now includes a list of the principal transactions and riskless principal transactions entered into in reliance on this exemption, and the date and price at which they occurred. As discussed elsewhere in this preamble, the final exemption does not include the disclosure of the mark-up or mark-down in this final exemption. However, the disclosure in the final exemption includes a reminder of the Retirement Investor's right (in accordance with Section II(e)(3)(ii) of the exemption) to obtain, free of charge, information about the principal traded asset, including its salient attributes.
The final exemption also more closely harmonizes with the SEC's Temporary Rule 206(3)-3T, as requested by some commenters. First, the Department removed the proposed condition that the annual disclosure be provided within 45 days after the end of the applicable year, in favor of the language used in the Temporary Rule that the disclosure be provided “no less frequently than annually.” Second, the Department added the requirement that the annual disclosure provide the date on which the transaction occurred, and a clarification that the disclosure is only required with respect to principal transactions and riskless principal transactions entered into pursuant to this exemption. These elements also harmonize with the SEC's Temporary Rule. As with the pre-transaction disclosure, the harmonization of the annual disclosure should ease compliance for Financial Institutions.
The Department adopted the annual disclosure, despite comments indicating it was unnecessary and duplicative of other disclosures. The annual disclosure provides a summary of the principal transactions and riskless principal transactions entered into during the reporting period and serves a unique purpose in collecting the information provided in the other disclosures. The annual disclosure provides Retirement Investors with the opportunity to review and evaluate all of the principal transactions and riskless principal transactions that occurred under the terms of the exemption during that period. The information provided may give Retirement Investors perspective that they do not gain from the individual confirmations.
Finally, a few commenters objected to Section IV(d) of the proposal, which would have required disclosure of information about the debt security and its purchase or sale, upon reasonable request of the Retirement Investor. Such right of request was viewed as unbounded. The Department concurs with the commenters and has deleted Section IV(d). The Department believes the provision in Section IV(c)(2), that a notice must be provided of the Retirement Investor's right to obtain, free of charge, information about the Principal Traded Asset, including its salient attributes, serves the same function. As discussed above, one commenter requested that the information must be reasonably available and in the Financial Institution's possession. The Department believes that no additional limitation need be placed on the rights of the Retirement Investor to request information because, if a Financial Institution is advising a Retirement Investor to enter into a principal transaction or a riskless principal transaction, it should have all of the salient information available when providing that advice.
Under Section V(a) and (b) of the exemption, the Financial Institution must maintain for six years records necessary for the Department and certain other entities, including plan fiduciaries, participants, beneficiaries and IRA owners, to determine whether the conditions of the exemption have been satisfied. Some commenters stated that they were unsure what information would have to be saved for six years. The Department notes that the language requires that records necessary to demonstrate compliance with the exemption's conditions must be maintained.
The final exemption includes changes to the recordkeeping provision made in accordance with comments on other exemption proposals in connection with the Regulation. First, the text was revised to make clear that the records must be “reasonably accessible for examination,” to remove the subjective views of the person requesting to examine or audit the records. The section also clarifies that fiduciaries, employers, employee organizations, participants and their employees and representatives only have access to information concerning their own plans. In addition, Financial Institutions are not required to disclose privileged trade secrets or privileged commercial or financial information to any of the parties other than the Department, as was also true of the proposal. Financial Institutions are also not required to disclose records if such disclosure would be precluded by 12 U.S.C. 484, relating to visitorial powers over national banks and federal savings associations.
The recordkeeping provision in the exemption is necessary to demonstrate compliance with the terms of the exemption and therefore should represent prudent business practices in any event. The Department notes that similar language is used in many other exemptions and has been the Department's standard recordkeeping requirement for exemptions for some time.
Section VI of the exemption provides definitions of the terms used in the exemption. Most of the definitions received no comment, and they are finalized as proposed. Those terms that have been revised or received comment are below. Additional comments on definitions, such as “Best Interest,” “Principal Transaction” and “Material Conflict of Interest,” are discussed above in their respective sections.
The exemption contemplates that an individual person, an Adviser, will provide advice to the Retirement Investor. An Adviser must be an investment advice fiduciary of a plan or IRA who is an employee, independent contractor, agent, or registered representative of a Financial Institution, and the Adviser must satisfy the applicable federal and state regulatory and licensing requirements of banking and securities laws with respect to the covered transaction.
One commenter suggested that applicable federal and state regulatory and licensing language, similar to that in the Best Interest Contract Exemption proposal, be added to the definition. The Department agrees with the commenter, and the exemption contains the suggested language.
A Financial Institution is the entity that employs an Adviser or otherwise retains the Adviser as an independent contractor, agent or registered representative and customarily purchases or sells Principal Traded Assets for its own account in the ordinary course of its business.
The Department specifically requested comment on whether there are other types of Financial Institutions that should be included in the definition. No comments were received regarding the need for additional entities to be included. The only comments regarding the definition that were received addressed the language in the proposal that would have required that advice by a bank be delivered through the bank's trust department. Commenters indicated that the language serves no material purpose. As a result, the definition is finalized as proposed with the exception of the removal of the trust requirement.
As discussed in detail above with respect to the scope of the exemption, the Department heard from many commenters that wanted to expand the scope of the assets that would be eligible to participate in principal transactions under the exemption. After a review of individual investments, the Department revised the proposal to include asset backed securities, CDs, UITs and additional investments later determined to be added through individual exemptions. Further, with respect to
In addition to the comments discussed above, one commenter stated that requiring that a debt security be offered pursuant to a registration statement under the Securities Act of 1933 was difficult to comply with operationally in the secondary market. The commenter argued that the requirement could be eliminated in reliance on the Best Interest standard. The Department does not agree, and the language is finalized as proposed. Requiring that a security be registered is a straightforward mechanism by which the Department can ensure a base level of regulatory compliance and quality. An Adviser or Financial Institution should be able to verify the registration of a particular debt security by using a variety of sources.
Section VI(b) defines “Affiliate” of an Adviser or Financial Institution as:
(1) Any person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution. For this purpose, the term “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual;
(2) Any officer, director, partner, employee, or relative (as defined in ERISA section 3(15)), of the Adviser or Financial Institution; or
(3) Any corporation or partnership of which the Adviser or Financial Institution is an officer, director, or partner of the Adviser or Financial Institution.
The Department received a comment requesting that this definition adopt a securities law definition. The commenter expressed the view that use of a separate definition would make compliance more difficult for broker-dealers. The Department did not accept this comment. Instead, the Department made minor adjustments so that the definition is identical to the affiliate definition incorporated in prior exemptions under ERISA and the Code, that are applicable to broker dealers,
The term Independent is used in Section I(c)(2)(ii), which precludes Financial Institutions and Advisers from relying on the exemption if they are the named fiduciary or plan administrator, as defined in ERISA section 3(16)(A), with respect to an ERISA-covered plan, unless such Financial Institutions or Advisers are selected to provide advice to the plan by a plan fiduciary that is Independent of the Financial Institutions or Advisers.
In the proposed exemption, the definition of Independent provided that the person (
In response, the Department revised the definition of Independent so that it provides that the person's compensation from the Financial Institution may not be in excess of 2% of the person's annual revenues based on the prior year. This approach is consistent with the Department's general approach to fiduciary independence. For example, the prohibited transaction exemption procedures provide a presumption of independence for appraisers and fiduciaries if the revenue they receive from a party is not more than 2% of their total annual revenue.
Commenters requested that the exemption continue to apply in the event of a Financial Institution's or Adviser's good faith failure to comply with one or more of the conditions. In the commenters' views, the exemption was sufficiently complex and the implementation timeline sufficiently short to justify such a provision. For example, FINRA suggested that the Department include a provision for continued application of the exemption
The Department has reviewed the exemption's requirements with these comments in mind and has included a good faith correction mechanism for the disclosure requirements in the exemption. These provisions take a similar approach to the provisions in the Department's regulations under ERISA sections 404 and 408(b)(2). In addition, as discussed above, the Department has eliminated a condition requiring compliance with other federal and state laws, which many commenters had argued could expose them to loss of the exemption based on small or technical violations. The Department has also facilitated compliance by streamlining the contracting process (and eliminating the contract requirement for ERISA plans), reducing the disclosure burden, and extending the time for compliance with many of the exemption's conditions. These and other changes should reduce the need for a self-correction process for excusing violations.
The Department declines to permanently adopt a broader unilateral good faith provision for Financial Institutions and their Advisers that could undermine fiduciaries' incentive to comply with the fundamental standards imposed by the exemption. The exemption's primary purpose is to combat harmful conflict of interest. If the exemption is too forgiving of abusive conduct, however, it runs the risk of permitting those same conflicts of interest to play a role in the design of policies and procedures, the use and oversight of adviser-incentives, the supervision of Adviser conduct, and the substance of investment recommendations. At the very least, it could encourage Financial Institutions and Advisers to resolve doubts on such questions in favor of their own financial interests rather than the interests of the Retirement Investor. Given the dangers posed by conflicts, the Department has deliberately structured this exemption to provide a strong counter-incentive to such conduct.
Additionally, many of the exemption's standards, such as the Best Interest standard and the pricing condition, already have a built-in reasonableness or prudence standard governing compliance. It would be inappropriate, in the Department's view, to create a self-correction mechanism for conduct that was imprudent or unreasonable. For example, the Best Interest standard requires that the Adviser and Financial Institution providing the advice act with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate, Related Entity, or other party. Similarly, the policies and procedures requirement under Section II(d) turns to a significant degree on adherence to standards of prudence and reasonableness. Thus, under Section II(d)(1), the Financial Institution is required to adopted and comply with written policies and procedures
Additionally, the provision allowing mandatory arbitration of individual claims is also responsive to the practicalities of resolving disputes over small claims. The Department also stresses that violations of the exemption's conditions with respect to a particular Retirement Investor or transaction, eliminates the availability of the exemption for that investor or transaction. Such violations do not render the exemption unavailable with respect to other Retirement Investors or other transactions.
The Department received a number of comments questioning the Department's jurisdiction and legal authority to proceed with the proposal. A number of commenters focused on the Department's authority to impose certain conditions as part of this exemption, specifically including the contract requirement and the Impartial Conduct Standards. Some commenters asserted that by requiring a contract for all Retirement Investors, and thereby facilitating contract claims by such parties, the proposal would expand upon the remedies established by Congress under ERISA and the Code. Commenters stated that ERISA preempts state law actions, including breach-of-contract actions. With respect to IRAs and non-ERISA plans, commenters stated that Congress provided that the enforcement of the prohibited transaction rules should be carried out by the Internal Revenue Service, not private plaintiffs. These commenters argued that the Department's proposal would impermissibly create a private right of action in violation of Congressional intent.
Commenters' arguments regarding the Impartial Conduct Standards were based generally on the fact that the standards, as noted above, are consistent with longstanding principles of prudence and loyalty set forth in ERISA section 404, but which have no counterpart in the Code. Commenters took the position that because Congress did not choose to impose the standards of prudence and loyalty on fiduciaries with respect to IRAs and non-ERISA plans, the Department exceeded its authority in proposing similar standards as a condition of relief in a prohibited transaction exemption.
With respect to ERISA plans, commenters stated that Congress' separation of the duties of prudence and loyalty (in ERISA section 404) from the prohibited transaction provisions (in ERISA section 406), showed an intent that the two should remain separate. Commenters additionally questioned why the conduct standards were necessary for ERISA plans, when such plans already have an enforceable right to fiduciary conduct that is both prudent and loyal. Commenters asserted that imposing the Impartial Conduct Standards as conditions of the exemption improperly created strict liability for prudence violations.
Some commenters additionally took the position that Congress, in the Dodd-Frank Act, gave the SEC the authority to establish standards for broker-dealers and investment advisers and therefore, the Department did not have the authority to act in that area.
The Department disagrees that the exemption exceeds its authority. The Department has clear authority under ERISA section 408(a) and the Reorganization Plan
In addition, this exemption does not create a cause of action for plan fiduciaries, participants or IRA owners to directly enforce the prohibited transaction provisions of ERISA and the Code in a federal or state-law contract action. Instead, with respect to ERISA plans and participants and beneficiaries, the exemption facilitates the existing statutory enforcement framework by requiring Financial Institutions to acknowledge in writing their fiduciary status and the fiduciary status of their Advisers. With respect to IRAs and non-ERISA plans, the exemption requires Advisers and Financial Institutions to make certain enforceable commitments to the advice recipient. Violation of the commitments can result in contractual liability to the Adviser and Financial Institution separate and apart from the legal consequences of a non-exempt prohibited transaction (
There is nothing new about a prohibited transaction exemption requiring certain written documentation between the parties. The Department's widely-used exemption for Qualified Professional Asset Managers (QPAM), requires that an entity acting as a QPAM acknowledge in a written management agreement that it is a fiduciary with respect to each plan that has retained it.
Likewise, the Impartial Conduct Standards represent, in the Department's view, baseline standards of fundamental fair dealing that must be present when fiduciaries make conflicted investment recommendations to Retirement Investors. After careful consideration, the Department determined that broad relief could be provided to investment advice fiduciaries receiving conflicted compensation only if such fiduciaries provided advice in accordance with the Impartial Conduct Standards—
The Department similarly disagrees that Congress' directive to the SEC in the Dodd-Frank Act limits its authority to establish appropriate and protective conditions in the context of a prohibited transaction exemption. Section 913 of the Dodd-Frank Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 of the Dodd-Frank Act authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers.
Additionally, the Department notes that nothing in ERISA or the Code requires any Adviser or Financial Institution to use this exemption. Exemptions, including this class exemption, simply provide a means to engage in a transaction otherwise prohibited by the statutes. The conditions to an exemption are not equivalent to a regulatory mandate that conflicts with or changes the statutory remedial scheme. If Advisers or Financial Institutions do not want to be subject to contract claims, they can (1) change their trading practices and avoid committing a prohibited transaction, (2) use the statutory exemptions in ERISA section 408(b)(14) and section 408(g), or Code section 4975(d)(17) and (f)(8), or (3) apply to the Department for individual exemptions tailored to their particular situations.
Many commenters suggested that a uniform standard applicable to all retail accounts would be preferable to the Department's proposal, and that the Department should work with other
The Department disagrees with the commenters, and believes it is important to move forward with this proposal to remedy the ongoing injury to Retirement Investors as a result of conflicted advice arrangements. ERISA and the Code create special protections applicable to investors in tax qualified plans. The fiduciary duties established under ERISA and the Code are different from those applicable under securities laws, and would continue to differ even if both regimes were interpreted to attach fiduciary status to exactly the same parties and activities. Reflecting the special importance of plan and IRA investments to retirement and health security, this statutory regime flatly prohibits fiduciaries from engaging in transactions involving self-dealing and conflicts of interest unless an exemption applies. Under ERISA and the Code, the Department of Labor has the authority to craft exemptions from these stringent statutory prohibitions, and the Department is specifically charged with ensuring that any exemptions it grants are in the interests of Retirement Investors and protective of these interests. Moreover, the fiduciary provisions of ERISA and the Code broadly protect all investments by Retirement Investors, not just those regulated by the SEC. As a consequence, the Department uniquely has the ability to assure that these fiduciary rules work in harmony for all Retirement Investors, regardless of whether they are investing in securities, insurance products that are not securities, or other types of investments.
The Department has taken very seriously its obligation to harmonize the Department's regulation with other applicable laws, including the securities laws. In pursuing its consultations with other regulators, the Department aimed to coordinate and minimize conflicting or duplicative provisions between ERISA, the Code and federal securities laws. The Department has coordinated—and will continue to coordinate—its efforts with other federal agencies to ensure that the various legal regimes are harmonized to the fullest extent possible. The resulting exemption provides Advisers and Financial Institutions with a choice to provide advice on an unconflicted basis or comply with this exemption or another exemption, which now all require advice to be provided in accordance with basic fiduciary norms. Far from confusing investors, the standards set forth in the exemption ensure that Retirement Investors can uniformly expect to receive advice that is in their best interest with respect to their retirement investments. Moreover, the best interest standard reflects what many investors have believed they were entitled to all along, even though it was not legally required.
In this regard, waiting for the SEC to act, as some commenters suggested, would delay the implementation of these important, updated safeguards to plan and IRA investors, and impose substantial costs on them as current harms from conflicted advice would continue.
The Regulation will become effective June 7, 2016 and this exemption is issued on this same date. The Regulation is effective at the earliest possible date under the Congressional Review Act. For the exemption, the issuance date serves as the date on which the exemption is intended to take effect for purposes of the Congressional Review Act. This date was selected to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the final rule are now officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the rule and exemption are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, an Applicability Date of April 10, 2017, is appropriate for plans and their affected service providers to adjust to the basic change from non-fiduciary to fiduciary status. This exemption has the same Applicability Date; parties may rely on it as of the Applicability Date.
Section VII provides a transition period under which relief from the prohibited transaction provisions of ERISA and the Code is available for Financial Institutions and Advisers during the period between the Applicability Date and January 1, 2018 (the “Transition Period”). For the Transition Period, full relief under the exemption will be available for Financial Institutions and Advisers subject to more limited conditions than the full set of conditions described above. This period is intended to provide Financial Institutions and Advisers time to prepare for compliance with the conditions of Section II-IV set forth above, while safeguarding the interests of Retirement Investors. The Transition Period conditions set forth in Section VII are subject to the same exclusions in Section I(c), for advice from fiduciaries with discretionary authority over the customer's investments and specified advice concerning in-house plans.
The transitional conditions of Section VII require the Financial Institution and its Advisers to comply with the Impartial Conduct Standards when making recommendations regarding principal transactions and riskless principal transactions to Retirement Investors. The Impartial Conduct Standards required in Section VII are the same as required in Section II(c) but are repeated for ease of use.
During the Transition Period, the Financial Institution must additionally provide a written notice to the Retirement Investor prior to or at the same time as the execution of the principal transaction or riskless principal transaction, which may cover multiple transactions or all transactions taking place within the Transition Period, affirmatively stating its and its Adviser(s) fiduciary status under ERISA or the Code or both with respect to the recommendation. The Financial Institution must also state in writing that it and its Advisers will comply with the Impartial Conduct Standards. Further, the Financial Institution's notice must disclose the circumstances under which the Adviser and Financial Institution may engage in principal transactions and riskless principal transactions with the Plan, participant or beneficiary account or IRA, and its Material Conflicts of Interest. The disclosure may be provided in person, electronically or by mail, and it may be provided in the same document as the
Similar to the disclosure provisions of Section II(e), the transitional exemption in Section VII provides for exemptive relief to continue despite errors and omissions in the disclosures, if the Financial Institution acts in good faith and with reasonable diligence.
In addition, the Financial Institution must designate a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards.
Finally, the Financial Institution must comply with the recordkeeping provision of Section V(a) and (b) of the exemption regarding the transactions entered into during the Transition Period.
After the Transition Period, however, the exemption provided in Section VII will no longer be available. After that date, Financial Institutions and Advisers must satisfy all of the applicable conditions described in Sections II-V for the relief in Section I(b) to be available for any prohibited transactions occurring after that date. This includes the requirement to enter into a contract with a Retirement Investor, where required. Financial Institutions relying on the negative consent procedure set forth in Section II(a)(1)(ii) must provide the contractual provisions to Retirement Investors with Existing Contracts prior to January 1, 2018, and allow those Retirement Investors 30 days to terminate the contract. If the Retirement Investor does terminate the contract within that 30-day period, this exemption will provide relief for 14 days after the date on which the termination is received by the Financial Institution.
The proposed exemption, with the proposed Best Interest Contract Exemption, the proposed Regulation and other exemption proposals, generally set forth an Applicability Date of eight months, although the proposals sought comment on a phase in of conditions. As with other sections of this preamble, the Department is addressing comments regarding the Applicability Date as a cohesive whole. Some commenters, concerned about the ongoing harm to Retirement Investors, urged the Department to implement the Regulation and related exemptions quickly. However, the majority of industry commenters requested a two- to three-year transition period. These commenters requested time to enter into contracts with Retirement Investors (including developing and implementing the policies and procedures and incentive practices that meet the terms of Section II(d)). Some commenters requested the Department allow good faith compliance during the transition period. Others requested the Department phase in the requirements over time. One commenter requested the Best Interest standard become effective immediately, with the other conditions becoming effective within one year. Another comment expressed concern about phasing in the conditions over time, referring to this as a “piecemeal” approach, which would not be helpful to implementing a system to protect Retirement Investors. Other commenters wrote that the Department should re-propose the exemption or adopt it as an interim final exemption and seek additional comments.
The transition provisions in Section VII of the final exemption respond to commenters' concerns about ongoing economic harm to Retirement Investors during the period in which Financial Institutions develop systems to comply with the exemption. The provisions require prompt implementation of certain core protections of the exemption in the form of the acknowledgment of fiduciary status, compliance with the Impartial Conduct Standards, and certain important disclosures, to safeguard Retirement Investors' interests. The provisions recognize, however, that the Financial Institutions will need time to develop policies and procedures and supervisory structures that fully comport with the requirements of the final exemption. Accordingly, during the Transition Period, Financial Institutions are not required to execute the contract or give Retirement Investors warranties or disclosures on their anti-conflict policies and procedures. While the Department expects that Advisers and Financial Institutions will, in fact, adopt prudent supervisory mechanisms to prevent violations of the Impartial Conduct Standards (and potential liability for such violations), the exemption will not require the Financial Institutions to make specific representations on the nature or quality of the policies and procedures during this Transition Period. The Department will be available to respond to Financial Institutions' request for guidance during this period, as they develop the systems necessary to comply with the exemption's conditions.
The transition provisions also accommodate Financial Institutions' need for time to prepare for full compliance with the exemption, and therefore full compliance with all the final exemption's applicable conditions is delayed until January 1, 2018. The Department selected that period, rather than two to three years, as requested by some commenters, in light of the significant adjustments in the final exemption that significantly eased compliance burdens. Although the Department believes that the conditions of the exemption set forth in Section II-V are required to support the Department's findings required under ERISA section 408(a), and Code section 4975(c)(2) over the long term, the Department recognizes that Financial Institutions may need time to achieve full compliance with these conditions. The Department therefore finds that the provisions set forth in Section VII satisfy the criteria of ERISA section 408(a) and Code section 4975(c)(2) for the transition period because they provide the significant protections to Retirement Investors while providing Financial Institutions with time necessary to achieve full compliance. A similar transition period is provided for the companion Best Interest Contract Exemption due to the corresponding provisions in that exemption that may require time for Financial Institutions to begin compliance.
The Department considered, but did not elect, delaying the application of the rule defining fiduciary investment advice until such time as Financial Institutions could make the changes to their practices and compensation structures necessary to comply with Sections II through V of this exemption. The Department believed that delaying the application of the new fiduciary rule would inordinately delay the basic protections of loyalty and prudence that the rule provides. Moreover, a long period of delay could incentivize Financial Institutions to increase efforts to provide conflicted advice to Retirement Investors before it becomes subject to the new rule. The Department understands that many of the concerns regarding the applicability date of the rule are related to the prohibited transaction provisions of ERISA and the Code rather than the basic fiduciary standards. This transition period exemption addresses these concerns by giving Financial Institutions and Advisers necessary time to fully comply with Sections II-V of the exemption.
The Department also considered the views of commenters that requested re-proposal of the Regulation and exemptions, or issuing the rule and exemptions as interim final rules with requests for additional comment. After reviewing all the comments on the 2015 proposal, which was itself a re-proposal, the Department has concluded that it is in a position to publish a final rule and
This exemption will not provide relief from a transaction prohibited by ERISA section 406(a)(1)(C), or from the taxes imposed by Code section 4975(a) and (b) by reason of Code section 4975(c)(1)(C), regarding the furnishing of goods, services or facilities between a plan and a party in interest. The provision of investment advice to a plan under a contract with a fiduciary is a service to the plan and compliance with this exemption will not relieve an Adviser or Financial Institution of the need to comply with ERISA section 408(b)(2), Code section 4975(d)(2), and applicable regulations thereunder.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Department solicited comments on the information collections included in the proposed Exemption for Principal Transactions in Certain Debt Securities Between Investment Advice Fiduciaries and Employee Benefit Plans and IRAs. 80 FR 21989 (Apr. 20, 2015). The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposal, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally many comments were submitted, described elsewhere in this preamble and in the preamble to the accompanying final rule, which contained information relevant to the costs and administrative burdens attendant to the proposals. The Department took into account such public comments in connection with making changes to the prohibited transaction exemption, analyzing the economic impact of the proposals, and developing the revised paperwork burden analysis summarized below.
In connection with publication of this prohibited transaction exemption, the Department is submitting an ICR to OMB requesting approval of a new collection of information under OMB Control Number 1210-0157. The Department will notify the public when OMB approves the ICR.
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail below, the class exemption will permit principal transactions and riskless principal transactions in certain principal traded assets between a plan, participant or beneficiary account, or an IRA, and an Adviser or Financial Institution, and the receipt of a mark-up or mark-down or other payment by the Adviser or Financial Institution for themselves or Affiliates as a result of investment advice. The class exemption will require Financial Institutions to enter into a contractual arrangement with Retirement Investors regarding principal transactions and riskless principal transactions with IRAs and plans not subject to Title I of ERISA (non-ERISA plans), adopt written policies and procedures, make disclosures to Retirement Investors (including with respect to ERISA plans), and on a publicly available Web site, and maintain records necessary to prove that the conditions of the exemption have been met for a period of six (6) years from the date of each principal transaction or riskless principal transaction. In addition, the exemption provides a transition period from the Applicability Date, to January 1, 2018. As a condition of relief during the transition period, Financial Institutions must make a disclosure (transition disclosure) to all Retirement Investors (in ERISA plans, IRAs, and non-ERISA plans) prior to or at the same time as the execution of recommended transactions. These requirements are ICRs subject to the PRA.
The Department has made the following assumptions in order to establish a reasonable estimate of the paperwork burden associated with these ICRs:
• 51.8 percent of disclosures to Retirement Investors with respect to ERISA plans
• Financial Institutions will use existing in-house resources to distribute required contracts and disclosures;
• Tasks associated with the ICRs performed by in-house personnel will be performed by clerical personnel at an hourly wage rate of $55.21;
• Financial Institutions will hire outside service providers to assist with nearly all other compliance costs;
• Outsourced legal assistance will be billed at an hourly rate of $335.00;
• Approximately 6,000 Financial Institutions
The Department believes that nearly all Financial Institutions will contract with outside service providers to implement the various compliance requirements of this exemption. As described in the regulatory impact analysis, per-Financial Institution costs for broker-dealers (BDs) were calculated by allocating the total cost reductions in the medium assumptions scenario across the Financial Institution size categories, and then subtracting the cost reductions from the per-Financial Institution average costs derived from the Oxford Economics study. The methodology for calculating the per-Financial Institution costs for registered investment advisers (RIAs) is described in detail in the regulatory impact analysis. The Department is attributing 50 percent of the compliance costs for BDs and RIAs to this Exemption and 50 percent of the compliance costs for BDs and RIAs to the Best Interest Contract Exemption, published elsewhere in today's
In order to engage in transactions and receive compensation covered under this exemption, Section II requires Financial Institutions to acknowledge, in writing, their fiduciary status and adopt written policies and procedures designed to ensure compliance with the Impartial Conduct Standards. Financial Institutions must make certain disclosures to Retirement Investors. Financial institutions must generally enter into a written contract with Retirement Investors with respect to principal transactions and riskless principal transactions with IRAs and non-ERISA plans with certain required provisions, including affirmative agreement to adhere to the Impartial Conduct Standards and, if they are FINRA members, to comply with FINRA rules 2121 and 5310.
Section IV requires Financial Institutions and Advisers to make certain disclosures to the Retirement Investor. These disclosures include: (1) A pre-transaction disclosure; (2) a disclosure, on demand, of information regarding the principal traded asset, including its salient attributes; (3) an annual disclosure; (4) transaction confirmations; and (5) a web-based disclosure.
Section VII requires Financial Institutions to make a transition disclosure, acknowledging their fiduciary status and that of their Advisers with respect to the Advice, stating the Best Interest standard of care, and describing the circumstances under which principal transactions and riskless principal transactions may occur and the associated Material Conflicts of Interest, prior to engaging in any transactions during the transition period from the Applicability Date to January 1, 2018. The transition disclosure can cover multiple transactions, or all transactions occurring in the transition period.
The Department is able to disaggregate an estimate of many of the legal costs from the costs above; however, it is unable to disaggregate any of the other costs. The Department received a comment on the proposed PTE stating that the estimates for legal professional time to draft disclosures were not supported by any empirical evidence. The Department also received multiple comments on the proposed PTE stating that its estimate of 60 hours of legal professional time during the first year a financial institution used the exemption and then no legal professional time in subsequent years was too low.
In response to a recommendation made during the Department's August 2015, public hearing on the proposed rule and exemptions, and in an attempt to create estimates with a clearer empirical evidentiary basis, the Department drafted certain portions of the required disclosures, including a sample contract, the one-time disclosure to the Department, and the transition disclosure. The Department believes that the time spent updating existing contracts and disclosures in future years would be no longer than the time necessary to create the original contracts and disclosures. The Department did not attempt to draft the complete set of required disclosures because it expects that the amount of time necessary to draft such disclosures will vary greatly among firms. For example, the Department did not attempt to draft sample policies and procedures, pre-transaction disclosures, disclosures regarding the principal traded assets, or confirmation slips. The Department expects the amount of time necessary to complete these disclosures will vary significantly based on a variety of factors including the nature of a firm's compensation structure, and the extent to which a firm's policies and procedures require review and signatures by different individuals. The Department further believes that pre-transaction disclosures will be provided orally at de minimis cost, facts and circumstances will vary too widely to accurately depict the disclosures regarding the principal traded assets, and providing confirmation slips is a regular and customary business practice
Considered in conjunction with the estimates provided in the proposal, the Department estimates that outsourced legal assistance to draft standard contracts, contract disclosures, annual disclosures, and transition disclosures will cost an average of $3,676 per Financial Institution for a total of $22.3 million during the first year. In subsequent years, it will cost an average of $2,978 per Financial Institution for a total of $18.1 million annually to update the contracts, contract disclosures, and annual disclosures.
The legal costs of these disclosures were disaggregated from the total compliance costs because these disclosures are expected to be relatively uniform. Although the tested disclosures generally took less time than many of the commenters said they would, the Department acknowledges that the disclosures that were not tested are those that are expected to be the most time consuming. Importantly, as explained in greater detail in section 5.3 of the regulatory impact analysis, the Department is primarily relying on cost data provided by the Securities Industry and Financial Markets Association (SIFMA) and the Financial Services Institute (FSI) to calculate the total cost of the legal disclosures, rather than its own internal drafting of disclosures. Accordingly, in the event that any of the Department's estimates understate the time necessary to create and update the disclosures, it does not impact the total burden estimates. The total burden estimates were derived from SIFMA and FSI's all-inclusive costs. Therefore, in the event that legal costs are understated, other cost estimates in this analysis would be overstated in an equal manner.
In addition to legal costs for creating the contracts and disclosures, the start-up cost estimates include the costs of implementing and updating the IT infrastructure, creating the web disclosures, gathering and maintaining the records necessary to produce the various disclosures, developing policies and procedures, addressing material conflicts of interest, monitoring Advisers' adherence to the Impartial Conduct Standards, and any other steps necessary to ensure compliance with the conditions of the Exemption not described elsewhere. In addition to legal costs for updating the contracts and disclosures, the ongoing cost estimates include the costs of updating the IT infrastructure, updating the web disclosures, reviewing processes for gathering and maintaining the records necessary to produce the various disclosures, reviewing the policies and procedures, producing the detailed disclosures regarding principal traded assets on request, monitoring investments as agreed upon with the Retirement Investor, addressing material conflicts of interest, monitoring Advisers' adherence to the Impartial Conduct Standards, and any other steps necessary to ensure compliance with the conditions of the exemption not described elsewhere. These costs total $1.9 billion during the first year and $412.2 million in subsequent years. These costs do not include the costs of producing of distributing disclosures and contracts, which are discussed below.
The Department estimates that 14,000 Retirement Investors with respect to ERISA plans and 2.4 million Retirement Investors with respect to IRAs and non-ERISA plans will receive a three-page transition disclosure during the first year. Additionally, 14,000 Retirement Investors with respect to ERISA plans will receive a fifteen-page contract disclosure, and 2.4 million Retirement Investors with respect to IRAs and non-ERISA plans will receive a fifteen-page contract during the first year. In subsequent years, 4,000 Retirement Investors with respect to ERISA plans will receive a fifteen-page contract disclosure and 490,000 Retirement Investors with respect to IRAs and non-ERISA plans will receive a fifteen-page contract. To the extent that Financial Institutions use both the Best Interest Contract Exemption and the Principal Transactions Exemption, these estimates may represent overestimates because significant overlap exists between the requirements of the transition disclosure and the contract for both exemptions. If Financial Institutions choose to use both exemptions with the same clients, they will probably combine the documents.
The transition disclosure will be distributed electronically to 51.8 percent of ERISA plan investors and 44.1 percent of IRAs and non-ERISA plan investors during the first year. Paper disclosures will be mailed to the remaining 48.2 percent of ERISA plan investors and 55.9 percent of IRAs and non-ERISA plan investors. The contract disclosure will be distributed electronically to 51.8 percent of the ERISA plan investors during the first year or during any subsequent year in which the plan investor begins a new advisory relationship. Paper contract disclosures will be mailed to 48.2 percent of ERISA plan investors. The contract will be distributed electronically to 44.1 percent of IRAs and non-ERISA plan participants during the first year or during any subsequent year in which the investor begins a new advisory relationship. Paper contracts will be mailed to 55.9 percent of IRAs and non-ERISA plan investors. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $2.5 million during the first year and $342,000 during subsequent years. Paper distribution will also require two minutes of clerical time to print and mail the disclosure or contract,
The Department estimates that 2.5 million Retirement Investors for ERISA plans, IRAs and non-ERISA plans will receive a two-page annual disclosure during the second year and all subsequent years. The disclosure will be distributed electronically to 51.8 percent of ERISA plan investors and 44.1 percent of IRA holders and non-ERISA plan investors. Paper statements will be mailed to 48.2 percent of ERISA plan investors and 55.9 percent of IRA owners and non-ERISA plan participants. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution will cost approximately $812,000.
The Department estimates that Financial Institutions will receive ten requests per year for more detailed principal traded asset information during the second year and all subsequent years. The detailed disclosures will be distributed electronically for 51.8 percent of the ERISA plan investors and 44.1 percent of the IRA holders and non-ERISA plan participants. The Department believes that requests for additional information will be proportionally likely with each Retirement Investor type. Therefore, approximately 34,000 detailed disclosures will be distributed on paper. The Department estimates that electronic distribution will result in de minimis cost, while paper distribution
Overall, the Department estimates that in order to meet the conditions of this Exemption, Financial Institutions and Advisers will distribute approximately 4.9 million disclosures and contracts during the first year and 3.0 million disclosures and contracts during subsequent years. Distributing these disclosures and contracts will result in a total of 85,000 hours of burden during the first year and 56,000 hours of burden in subsequent years. The equivalent cost of this burden is $4.7 million during the first year and $3.1 million in subsequent years. This exemption will result in an outsourced labor, materials, and postage cost burden of $2.0 billion during the first year and $431.5 million during subsequent years.
These paperwork burden estimates are summarized as follows:
This exemption, which is issued pursuant to ERISA section 408(a) and Code section 4975(c)(2), is part of a broader rulemaking that includes other exemptions and a final regulation published in today's
The Secretary has determined that this rulemaking, including this exemption, will have a significant economic impact on a substantial number of small entities. The Secretary has separately published a Regulatory Impact Analysis (RIA) which contains the complete economic analysis for this rulemaking including the Department's FRFA for the rule and the related prohibited transaction exemptions. This section of this preamble sets forth a summary of the FRFA. The RIA is available at
As noted in section 6.1 of the RIA, the Department has determined that regulatory action is needed to mitigate conflicts of interest in connection with investment advice to Retirement Investors. The Regulation is intended to improve plan and IRA investing to the benefit of retirement security. In response to the proposed rulemaking, organizations representing small businesses submitted comments expressing particular concern with three issues: the carve-out for investment education, the Best Interest Contract Exemption, and the carve-out for persons acting in the capacity of counterparties to plan fiduciaries with financial expertise. Section 2 of the RIA contains an extensive discussion of these concerns and the Department's response.
As discussed in section 6.2 of the RIA, the Small Business Administration (SBA) defines a small business in the Financial Investments and Related Activities Sector as a business with up to $38.5 million in annual receipts. In response to a comment received from the SBA's Office of Advocacy on our Initial Regulatory Flexibility Analysis, the Department contacted the SBA, and received from them a dataset containing data on the number of Financial Institutions by NAICS codes, including the number of Financial Institutions in given revenue categories. This dataset would allow the estimation of the number of Financial Institutions with a given NAICS code that fall below the $38.5 million threshold and therefore be considered small entities by the SBA. However, this dataset alone does not provide a sufficient basis for the Department to estimate the number of small entities affected by the rule. Not all Financial Institutions within a given NAICS code would be affected by this rule, because being an ERISA fiduciary relies on a functional test and is not based on industry status as defined by a NAICS code. Further, not all Financial Institutions within a given NAICS code work with ERISA-covered plans and IRAs.
Over 90 percent of broker-dealers, registered investment advisers, insurance companies, agents, and consultants are small businesses according to the SBA size standards (13 CFR 121.201). Applying the ratio of entities that meet the SBA size standards to the number of affected entities, based on the methodology described at greater length in the RIA, the Department estimates that the number of small entities affected by this rule is 2,438 BDs, 16,521 RIAs, 496 Insurers, and 3,358 other ERISA service providers.
For purposes of the RFA, the Department continues to consider an employee benefit plan with fewer than 100 participants to be a small entity. Further, while some large employers may have small plans, in general small employers maintain most small plans. The definition of small entity considered appropriate for this purpose differs, however, from a definition of small business that is based on size standards promulgated by the SBA. These small pension plans will benefit from the rule, because as a result of the rule, they will receive non-conflicted advice from their fiduciary service providers. The 2013 Form 5500 filings show nearly 595,000 ERISA covered retirement plans with less than 100 participants.
Section 6.5 of the RIA summarizes the projected reporting, recordkeeping, and other compliance costs of the rule and exemptions, which are discussed in detail in section 5 of the RIA. Among other things, the Department concludes that it is likely that some small service providers may find that the increased costs associated with ERISA fiduciary status outweigh the benefits of continuing to service the ERISA plan market or the IRA market. The Department does not believe that this outcome will be widespread or that it will result in a diminution of the amount or quality of advice available to small or other retirement savers, because some Financial Institutions will fill the void and provide services the ERISA plan and IRA market. It is also possible that the economic impact of the
Section 5.3.1 of the RIA includes a discussion of the changes to the proposed rule and exemptions that are intended to reduce the costs affecting both small and large business. These include elimination of data collection and annual disclosure requirements in the Best Interest Contract Exemption, and changes to the implementation of the contract requirement in the exemption. Section 7 of the RIA discusses significant regulatory alternatives considered by the Department and the reasons why they were rejected.
This exemption, along with related exemptions and a final rule published elsewhere in this issue of the
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under ERISA section 408(a) and Code section 4975(c)(2) does not relieve a fiduciary or other party in interest or disqualified person with respect to a plan or IRA from certain other provisions of ERISA and the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of ERISA section 404 which require, among other things, that a fiduciary act prudently and discharge his or her duties respecting the plan solely in the interests of the participants and beneficiaries of the plan. Additionally, the fact that a transaction is the subject of an exemption does not affect the requirement of Code section 401(a) that the plan must operate for the exclusive benefit of the employees of the employer maintaining the plan and their beneficiaries;
(2) The Department finds that the exemption is administratively feasible, in the interests of the plan and of its participants and beneficiaries, and protective of the rights of participants and beneficiaries of the plan;
(3) The exemption is applicable to a particular transaction only if the transaction satisfies the conditions specified in the exemption; and
(4) The exemption is supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
(a) In general. ERISA and the Internal Revenue Code prohibit fiduciary advisers to employee benefit plans (Plans) and individual retirement plans (IRAs) from self-dealing, including receiving compensation that varies based on their investment recommendations. ERISA and the Code also prohibit fiduciaries from engaging in securities purchases and sales with Plans or IRAs on behalf of their own accounts (Principal Transactions). This exemption permits certain persons who provide investment advice to Retirement Investors (
(b) Exemption. This exemption permits an Adviser or Financial Institution to engage in the purchase or sale of a Principal Traded Asset in a Principal Transaction or Riskless Principal Transaction with a Plan, participant or beneficiary account, or IRA, and receive a mark-up, mark-down or other similar payment as applicable to the transaction for themselves or any Affiliate, as a result of the Adviser's and Financial Institution's advice regarding the Principal Transaction or Riskless Principal Transaction. As detailed below, Financial Institutions and Advisers seeking to rely on the exemption must acknowledge fiduciary status, adhere to Impartial Conduct Standards in rendering advice, disclose Material Conflicts of Interest associated with Principal Transactions and Riskless Principal Transactions and obtain the consent of the Plan or IRA. In addition, Financial Institutions must adopt certain policies and procedures, including policies and procedures reasonably designed to ensure that individual Advisers adhere to the Impartial Conduct Standards; and retain certain records. This exemption provides relief from ERISA section 406(a)(1)(A) and (D) and section 406(b)(1) and (2), and the taxes imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(A), (D), and (E). The Adviser and Financial Institution must comply with the conditions of Sections II-V.
(c) Scope of this exemption: This exemption does not apply if:
(1) The Adviser: (i) Has or exercises any discretionary authority or discretionary control respecting management of the assets of the Plan, participant or beneficiary account, or IRA involved in the transaction or exercises any discretionary authority or control respecting management or the disposition of the assets; or (ii) has any discretionary authority or discretionary responsibility in the administration of the Plan, participant or beneficiary account, or IRA; or
(2) The Plan is covered by Title I of ERISA and (i) the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the Plan, or (ii) the Adviser or Financial Institution is a named fiduciary or plan administrator (as defined in ERISA section 3(16)(A)) with respect to the Plan, or an Affiliate thereof, that was selected to provide investment advice to the plan by a fiduciary who is not Independent.
The conditions set forth in this section include certain Impartial Conduct Standards, such as a Best Interest standard, that Advisers and Financial Institutions must satisfy to rely on the exemption. In addition, this section requires Financial Institutions to adopt anti-conflict policies and procedures that are reasonably designed to ensure that Advisers adhere to the Impartial Conduct Standards, and requires disclosure of important information about the Principal Transaction or Riskless Principal Transaction. With respect to IRAs and Plans not covered by Title I of ERISA, the Financial Institutions must agree that they and their Advisers will adhere to the exemption's standards in a written contract that is enforceable by the Retirement Investors. To minimize compliance burdens, the exemption provides that the contract terms may be incorporated into account opening
(a) Contracts with Respect to Principal Transactions and Riskless Principal Transactions Involving IRAs and Plans Not Covered by Title I of ERISA. If the investment advice resulting in the Principal Transaction or Riskless Principal Transaction concerns an IRA or a Plan that is not covered by Title I, the advice is subject to an enforceable written contract on the part of the Financial Institution, which may be a master contract covering multiple recommendations, that is entered into in accordance with this Section II(a) and incorporates the terms set forth in Section II(b)-(d). The Financial Institution additionally must provide the disclosures required by Section II(e). The contract must cover advice rendered prior to the execution of the contract in order for the exemption to apply to such advice and related compensation.
(1) Contract Execution and Assent.
(i) New Contracts. Prior to or at the same time as the execution of the Principal Transaction or Riskless Principal Transaction, the Financial Institution enters into a written contract with the Retirement Investor acting on behalf of the Plan, participant or beneficiary account, or IRA, incorporating the terms required by Section II(b)-(d). The terms of the contract may appear in a standalone document or they may be incorporated into an investment advisory agreement, investment program agreement, account opening agreement, insurance or annuity contract or application, or similar document, or amendment thereto. The contract must be enforceable against the Financial Institution. The Retirement Investor's assent to the contract may be evidenced by handwritten or electronic signatures.
(ii) Amendment of Existing Contracts by Negative Consent. As an alternative to executing a contract in the manner set forth in the preceding paragraph, the Financial Institution may amend Existing Contracts to include the terms required in Section II(b)-(d) by delivering the proposed amendment and the disclosure required by Section II(e) to the Retirement Investor prior to January 1, 2018, and considering the failure to terminate the amended contract within 30 days as assent. An Existing Contract is an investment advisory agreement, investment program agreement, account opening agreement, insurance contract, annuity contract, or similar agreement or contract that was executed before January 1, 2018, and remains in effect. If the Financial Institution elects to use the negative consent procedure, it may deliver the proposed amendment by mail or electronically, provided such means is reasonably calculated to result in the Retirement Investor's receipt of the proposed amendment, but it may not impose any new contractual obligations, restrictions, or liabilities on the Retirement Investor by negative consent.
(2) Notice. The Financial Institution maintains an electronic copy of the Retirement Investor's contract on the Financial Institution's Web site that is accessible by the Retirement Investor.
(b) Fiduciary. The Financial Institution affirmatively states in writing that the Financial Institution and the Adviser(s) act as fiduciaries under ERISA or the Code, or both, with respect to any investment advice regarding Principal Transactions and Riskless Principal Transactions provided by the Financial Institution or the Adviser subject to the contract, or in the case of an ERISA Plan, with respect to any investment advice regarding Principal Transactions and Riskless Principal Transactions between the Financial Institution and the Plan or participant or beneficiary account.
(c) Impartial Conduct Standards. The Financial Institution states that it and its Advisers agree to adhere to the following standards and, they in fact, comply with the standards:
(1) When providing investment advice to a Retirement Investor regarding the Principal Transaction or Riskless Principal Transaction, the Financial Institution and Adviser provide investment advice that is, at the time of the recommendation, in the Best Interest of the Retirement Investor. As further defined in Section VI(c), such advice reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution, or any Affiliate or other party;
(2) The Adviser and Financial Institution seek to obtain the best execution reasonably available under the circumstances with respect to the Principal Transaction or Riskless Principal Transaction.
(i) Financial Institutions that are FINRA members shall satisfy this Section II(c)(2) if they comply with the terms of FINRA rules 2121 (Fair Prices and Commissions) and 5310 (Best Execution and Interpositioning), or any successor rules in effect at the time of the transaction, as interpreted by FINRA, with respect to the Principal Transaction or Riskless Principal Transaction.
(ii) The Department may identify specific requirements regarding best execution and/or fair prices imposed by another regulator or self-regulatory organization relating to additional Principal Traded Assets pursuant to Section VI(j)(1)(iv) in an individual exemption that may be satisfied as an alternative to the standard set forth in Section II(c)(2) above.
(3) Statements by the Financial Institution and its Advisers to the Retirement Investor about the Principal Transaction or Riskless Principal Transaction, fees and compensation related to the Principal Transaction or Riskless Principal Transaction, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's decision to engage in the Principal Transaction or Riskless Principal Transaction, will not be materially misleading at the time they are made.
(d) Warranty. The Financial Institution affirmatively warrants, and in fact complies with, the following:
(1) The Financial Institution has adopted and will comply with written policies and procedures reasonably and prudently designed to ensure that its individual Advisers adhere to the Impartial Conduct Standards set forth in Section II(c);
(2) In formulating its policies and procedures, the Financial Institution has specifically identified and documented its Material Conflicts of Interest associated with Principal Transactions and Riskless Principal Transactions;
(3) The Financial Institution's policies and procedures require that neither the Financial Institution nor (to the best of the Financial Institution's knowledge) any Affiliate uses or relies on quotas, appraisals, performance or personnel actions, bonuses, contests, special awards, differential compensation or other actions or incentives that are intended or would reasonably be expected to cause individual Advisers to make recommendations regarding Principal Transactions and Riskless Principal Transactions that are not in the Best Interest of the Retirement Investor. Notwithstanding the foregoing, the requirement of this Section II(d)(3) does not prevent the Financial Institution or its Affiliates from providing Advisers with differential compensation (whether in type or amount, and including, but not limited to, commissions) based on investment decisions by Plans, participant or beneficiary accounts, or IRAs, to the extent that the policies and procedures and incentive practices, when viewed as a whole, are reasonably and prudently designed to avoid a misalignment of the interests of Advisers with the interests of the Retirement Investors they serve as fiduciaries;
(4) The Financial Institution's written policies and procedures regarding Principal Transactions and Riskless Principal Transactions address how credit risk and liquidity assessments for Debt Securities, as required by Section III(a)(3), will be made.
(e) Transaction Disclosures. In the contract, or in a separate single written disclosure provided to the Retirement Investor or Plan prior to or at the same time as the execution of the Principal Transaction or Riskless Principal Transaction, the Financial Institution clearly and prominently:
(1) Sets forth in writing (i) the circumstances under which the Adviser and Financial Institution may engage in Principal Transactions and Riskless Principal Transactions with the Plan, participant or beneficiary account, or IRA, (ii) a description of the types of compensation that may be received by the Adviser and Financial Institution in connection with Principal Transactions and Riskless Principal Transactions, including any types of compensation that may be received from third parties, and (iii) identifies and discloses the Material Conflicts of Interest associated with Principal Transactions and Riskless Principal Transactions;
(2) Except for Existing Contracts, documents the Retirement Investor's affirmative written consent, on a prospective basis, to Principal Transactions and Riskless Principal Transactions between the Adviser or Financial Institution and the Plan, participant or beneficiary account, or IRA;
(3) Informs the Retirement Investor (i) that the consent set forth in Section II(e)(2) is terminable at will upon written notice by the Retirement Investor at any time, without penalty to the Plan or IRA, (ii) of the right to obtain, free of charge, copies of the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d), as well as information about the Principal Traded Asset, including its purchase or sales price, and other salient attributes, including, as applicable: The credit quality of the issuer; the effective yield; the call provisions; and the duration, provided that if the Retirement Investor's request is made prior to the transaction, the information must be provided prior to the transaction, and if the request is made after the transaction, the information must be provided within 30 business days after the request, (iii) that model contract disclosures or other model notice of the contractual terms which are reviewed for accuracy no less than quarterly and updated within 30 days as necessary are maintained on the Financial Institution's Web site, and (iv) that the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) is available free of charge on the Financial Institution's Web site; and
(4) Describes whether or not the Adviser and Financial Institution will monitor the Retirement Investor's investments that are acquired through Principal Transactions and Riskless Principal Transactions and alert the Retirement Investor to any recommended change to those investments and, if so, the frequency with which the monitoring will occur and the reasons for which the Retirement Investor will be alerted.
(5) The Financial Institution will not fail to satisfy this Section II(e), or violate a contractual provision based thereon, solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, or if the Web site is temporarily inaccessible, provided that (i) in the case of an error or omission on the web, the Financial Institution discloses the correct information as soon as practicable, but not later than 7 days after the date on which it discovers or reasonably should have discovered the error or omission, and (ii) in the case of other disclosures, the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. To the extent compliance with this requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(f) Ineligible Contractual Provisions. Relief is not available under the exemption if a Financial Institution's contract contains the following:
(1) Exculpatory provisions disclaiming or otherwise limiting liability of the Adviser or Financial Institution for a violation of the contract's terms;
(2) Except as provided in paragraph (f)(4) of this section, a provision under which the Plan, IRA or the Retirement Investor waives or qualifies its right to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or in an individual or class claim agrees to an amount representing liquidated damages for breach of the contract; provided that, the parties may knowingly agree to waive the Retirement Investor's right to obtain punitive damages or rescission of recommended transactions to the extent such a waiver is permissible under applicable state or federal law; or
(3) Agreements to arbitrate or mediate individual claims in venues that are distant or that otherwise unreasonably limit the ability of the Retirement
(4) In the event provision on pre-dispute arbitration agreements for class or representative claims in paragraph (f)(2) of this section is ruled invalid by a court of competent jurisdiction, this provision shall not be a condition of this exemption with respect to contracts subject to the court's jurisdiction unless and until the court's decision is reversed, but all other terms of the exemption shall remain in effect.
(g) ERISA Plans. For recommendations to Retirement Investors regarding Principal Transactions and Riskless Principal Transactions with Plans that are covered by Title I of ERISA, relief under the exemption is conditioned upon the Adviser and Financial Institution complying with certain provisions of Section II, as follows:
(1) Prior to or at the same time as the execution of the Principal Transaction or Riskless Principal Transaction, the Financial Institution provides the Retirement Investor with a written statement of the Financial Institution's and its Advisers' fiduciary status, in accordance with Section II(b).
(2) The Financial Institution and the Adviser comply with the Impartial Conduct Standards of Section II(c).
(3) The Financial Institution adopts policies and procedures incorporating the requirements and prohibitions set forth in Section II(d)(1)-(4), and the Financial Institution and Adviser comply with those requirements and prohibitions.
(4) The Financial Institution provides the disclosures required by Section II(e).
(5) The Financial Institution and Adviser do not in any contract, instrument, or communication purport to disclaim any responsibility or liability for any responsibility, obligation, or duty under Title I of ERISA to the extent the disclaimer would be prohibited by ERISA section 410, waive or qualify the right of the Retirement Investor to bring or participate in a class action or other representative action in court in a dispute with the Adviser or Financial Institution, or require arbitration or mediation of individual claims in locations that are distant or that otherwise unreasonably limit the ability of the Retirement Investors to assert the claims safeguarded by this exemption.
The Adviser and Financial Institution must satisfy the following conditions to be covered by this exemption:
(a) Debt Security Conditions. Solely with respect to the purchase of a Debt Security by a Plan, participant or beneficiary account, or IRA:
(1) The Debt Security being purchased was not issued by the Financial Institution or any Affiliate;
(2) The Debt Security being purchased is not purchased by the Plan, participant or beneficiary account, or IRA in an underwriting or underwriting syndicate in which the Financial Institution or any Affiliate is an underwriter or a member;
(3) Using information reasonably available to the Adviser at the time of the transaction, the Adviser determines that the Debt Security being purchased:
(i) Possesses no greater than a moderate credit risk; and
(ii) Is sufficiently liquid that the Debt Security could be sold at or near its carrying value within a reasonably short period of time.
(b) Arrangement. The Principal Transaction or Riskless Principal Transaction is not part of an agreement, arrangement, or understanding designed to evade compliance with ERISA or the Code, or to otherwise impact the value of the Principal Traded Asset.
(c) Cash. The purchase or sale of the Principal Traded Asset is for cash.
This section sets forth the Adviser's and the Financial Institution's disclosure obligations to the Retirement Investor.
(a) Pre-Transaction Disclosure. Prior to or at the same time as the execution of the Principal Transaction or Riskless Principal Transaction, the Adviser or the Financial Institution informs the Retirement Investor, orally or in writing, of the capacity in which the Financial Institution may act with respect to such transaction.
(b) Confirmation. The Adviser or the Financial Institution provides a written confirmation of the Principal Transaction or Riskless Principal Transaction. This requirement may be satisfied by compliance with Rule 10b-10 under the Securities Exchange Act of 1934, or any successor rule in effect in effect at the time of the transaction, or for Advisers and Financial Institutions not subject to the Securities Exchange Act of 1934, similar requirements imposed by another regulator or self-regulatory organization.
(c) Annual Disclosure. The Adviser or the Financial Institution sends to the Retirement Investor, no less frequently than annually, written disclosure in a single disclosure:
(1) A list identifying each Principal Transaction and Riskless Principal Transaction executed in the Retirement Investor's account in reliance on this exemption during the applicable period and the date and price at which the transaction occurred; and
(2) A statement that (i) the consent required pursuant to Section II(e)(2) is terminable at will upon written notice, without penalty to the Plan or IRA, (ii) the right of a Retirement Investor in accordance with Section II(e)(3)(ii) to obtain, free of charge, information about the Principal Traded Asset, including its salient attributes, (iii) model contract disclosures or other model notice of the contractual terms, which are reviewed for accuracy no less frequently than quarterly and updated within 30 days if necessary, are maintained on the Financial Institution's Web site, and (iv) the Financial Institution's written description of its policies and procedures adopted in accordance with Section II(d) are available free of charge on the Financial Institution's Web site.
(d) The Financial Institution will not fail to satisfy this Section IV solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, or if the Web site is temporarily inaccessible, provided that (i) in the case of an error or omission on the web, the Financial Institution discloses the correct information as soon as practicable, but not later than 7 days after the date on which it discovers or reasonably should have discovered the error or omission, and (ii) in the case of other disclosures, the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. To the extent compliance with the disclosure requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, the exemption provides that they may rely in good faith on information and assurances from the other entities, as long as they do not know that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(e) The Financial Institution prepares a written description of its policies and
This section establishes record retention and availability requirements that a Financial Institution must meet in order for it to rely on the exemption.
(a) The Financial Institution maintains for a period of six (6) years from the date of each Principal Transaction or Riskless Principal Transaction, in a manner that is reasonably accessible for examination, the records necessary to enable the persons described in Section V(b) to determine whether the conditions of this exemption have been met, except that:
(1) If such records are lost or destroyed, due to circumstances beyond the control of the Financial Institution, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and
(2) No party other than the Financial Institution that is engaging in the Principal Transaction or Riskless Principal Transaction shall be subject to the civil penalty that may be assessed under ERISA section 502(i) or to the taxes imposed by Code sections 4975(a) and (b) if the records are not maintained or are not available for examination as required by Section V(b).
(b)(1) Except as provided in Section V(b)(2) or as precluded by 12 U.S.C. 484, and notwithstanding any provisions of ERISA sections 504(a)(2) and 504(b), the records referred to in Section V(a) are reasonably available at their customary location for examination during normal business hours by:
(i) Any duly authorized employee or representative of the Department or the Internal Revenue Service;
(ii) any fiduciary of the Plan or IRA that was a party to a Principal Transaction or Riskless Principal Transaction described in this exemption, or any duly authorized employee or representative of such fiduciary;
(iii) any employer of participants and beneficiaries and any employee organization whose members are covered by the Plan, or any authorized employee or representative of these entities; and
(iv) any participant or beneficiary of the Plan, or the beneficial owner of an IRA.
(2) None of the persons described in subparagraph (1)(ii) through (iv) are authorized to examine records regarding a Prohibited Transaction involving another Retirement Investor, or trade secrets of the Financial Institution, or commercial or financial information which is privileged or confidential; and
(3) Should the Financial Institution refuse to disclose information on the basis that such information is exempt from disclosure, the Financial Institution must by the close of the thirtieth (30th) day following the request, provide a written notice advising the requestor of the reasons for the refusal and that the Department may request such information.
(4) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
For purposes of this exemption:
(a) “Adviser” means an individual who:
(1) Is a fiduciary of a Plan or IRA solely by reason of the provision of investment advice described in ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B), or both, and the applicable regulations, with respect to the Assets involved in the transaction;
(2) Is an employee, independent contractor, agent, or registered representative of a Financial Institution; and
(3) Satisfies the applicable federal and state regulatory and licensing requirements of banking, and securities laws with respect to the covered transaction.
(b) “Affiliate” of an Adviser or Financial Institution means:
(1) Any person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution. For this purpose, the term “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual;
(2) Any officer, director, partner, employee, or relative (as defined in ERISA section 3(15)) of the Adviser or Financial Institution; or
(3) Any corporation or partnership of which the Adviser or Financial Institution is an officer, director, or partner of the Adviser or Financial Institution.
(c) Investment advice is in the “Best Interest” of the Retirement Investor when the Adviser and Financial Institution providing the advice act with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution, any Affiliate or other party.
(d) “Debt Security” means a “debt security” as defined in Rule 10b-10(d)(4) of the Exchange Act that is:
(1) U.S. dollar denominated, issued by a U.S. corporation and offered pursuant to a registration statement under the Securities Act of 1933;
(2) An “Agency Debt Security” as defined in FINRA rule 6710(l) or its successor;
(3) An “Asset Backed Security” as defined in FINRA rule 6710(m) or its successor, that is guaranteed by an Agency as defined in FINRA rule 6710(k) or its successor, or a Government Sponsored Enterprise as defined in FINRA rule 6710(n) or its successor; or
(4) A “U.S. Treasury Security” as defined in FINRA rule 6710(p) or its successor.
(e) “Financial Institution” means the entity that (i) employs the Adviser or otherwise retains such individual as an independent contractor, agent or registered representative, and (ii) customarily purchases or sells Principal Traded Assets for its own account in the ordinary course of its business, and that is:
(1) Registered as an investment adviser under the Investment Advisers Act of 1940 (15 U.S.C. 80b-1
(2) A bank or similar financial institution supervised by the United States or state, or a savings association (as defined in section 3(b)(1) of the Federal Deposit Insurance Act (12 U.S.C. 1813(b)(1))); and
(3) A broker or dealer registered under the Securities Exchange Act of 1934 (15 U.S.C. 78a
(f) “Independent” means a person that:
(1) Is not the Adviser or Financial Institution or an Affiliate;
(2) Does not receive or is not projected to receive within the current federal income tax year, compensation or other consideration for his or her own account from the Adviser, Financial Institution or an Affiliate in excess of 2% of the person's annual revenues based upon its prior income tax year; and
(3) Does not have a relationship to or an interest in the Adviser, Financial Institution or an Affiliate that might affect the exercise of the person's best judgment in connection with transactions described in this exemption.
(g) “Individual Retirement Account” or “IRA” means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in Code section 408(a) and a health savings account described in Code section 223(d).
(h) A “Material Conflict of Interest” exists when an Adviser or Financial Institution has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Retirement Investor.
(i) “Plan” means an employee benefit plan described in ERISA section 3(3) and any plan described in Code section 4975(e)(1)(A).
(j) “Principal Traded Asset” means:
(1) For purposes of a purchase by a Plan, participant or beneficiary account, or IRA,
(i) a Debt Security, as defined in subsection (d) above;
(ii) a certificate of deposit (CD);
(iii) an interest in a Unit Investment Trust, within the meaning of Section 4(2) of the Investment Company Act of 1940, as amended; or
(iv) an investment that is permitted to be purchased under an individual exemption granted by the Department under ERISA section 408(a) and/or Code section 4975(c), after the effective date of this exemption, that provides relief for investment advice fiduciaries to engage in the purchase of the investment in a Principal Transaction or a Riskless Principal Transaction with a Plan or IRA under the same conditions as this exemption; and
(2) for purposes of a sale by a Plan, participant or beneficiary account, or IRA, securities or other investment property.
(k) “Principal Transaction” means a purchase or sale of a Principal Traded Asset in which an Adviser or Financial Institution is purchasing from or selling to a Plan, participant or beneficiary account, or IRA on behalf of the Financial Institution's own account or the account of a person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with the Financial Institution. For purposes of this definition, a Principal Transaction does not include a Riskless Principal Transaction as defined in Section VI(m).
(l) “Retirement Investor” means:
(1) A fiduciary of a non-participant directed Plan subject to Title I of ERISA or described in Code section 4975(c)(1)(A) with authority to make investment decisions for the Plan;
(2) A participant or beneficiary of a Plan subject to Title I of ERISA or described in Code section 4975(c)(1)(A) with authority to direct the investment of assets in his or her Plan account or to take a distribution; or
(3) The beneficial owner of an IRA acting on behalf of the IRA.
(m) “Riskless Principal Transaction” means a transaction in which a Financial Institution, after having received an order from a Retirement Investor to buy or sell a Principal Traded Asset, purchases or sells the asset for the Financial Institution's own account to offset the contemporaneous transaction with the Retirement Investor.
(a) In general. ERISA and the Internal Revenue Code prohibit fiduciary advisers to employee benefit plans (Plans) and individual retirement plans (IRAs) from receiving compensation that varies based on their investment recommendations. ERISA and the Code also prohibit fiduciaries from engaging in securities purchases and sales with Plans or IRAs on behalf of their own accounts (Principal Transactions). This transition period provides relief from the restrictions of ERISA section 406(a)(1)(A) and (D) and section 406(b)(1) and (2), and the taxes imposed by Code section 4975(a) and (b), by reason of Code section 4975(c)(1)(A), (D), and (E) for the period from April 10, 2017, to January 1, 2018 (the Transition Period) for Advisers and Financial Institutions to engage in certain Principal Transactions and Riskless Principal Transactions with Plans and IRAs subject to the conditions described in Section VII(d).
(b) Covered transactions. This provision permits an Adviser or Financial Institution to engage in the purchase or sale of a Principal Traded Asset in a Principal Transaction or a Riskless Principal Transaction with a Plan, participant or beneficiary account, or IRA, and receive a mark-up, mark-down or other similar payment as applicable to the transaction for themselves or any Affiliate, as a result of the Adviser's and Financial Institution's advice regarding the Principal Transaction or the Riskless Principal Transaction, during the Transition Period.
(c) Exclusions. This provision does not apply if:
(1) The Adviser: (i) Has or exercises any discretionary authority or discretionary control respecting management of the assets of the Plan or IRA involved in the transaction or exercises any discretionary authority or control respecting management or the disposition of the assets; or (ii) has any discretionary authority or discretionary responsibility in the administration of the Plan or IRA; or
(2) The Plan is covered by Title I of ERISA, and (i) the Adviser, Financial Institution or any Affiliate is the employer of employees covered by the Plan, or (ii) the Adviser or Financial Institution is a named fiduciary or plan administrator (as defined in ERISA section 3(16)(A)) with respect to the Plan, or an Affiliate thereof, that was selected to provide advice to the Plan by a fiduciary who is not Independent;
(d) Conditions. The provision is subject to the following conditions:
(1) The Financial Institution and Adviser adhere to the following standards:
(i) When providing investment advice to the Retirement Investor regarding the Principal Transaction or Riskless Principal Transaction, the Financial Institution and the Adviser(s) provide investment advice that is, at the time of the recommendation, in the Best Interest of the Retirement Investor. As further defined in Section VI(c), such advice reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the Retirement Investor, without regard to the financial or other interests of the Adviser, Financial Institution or any Affiliate or other party;
(ii) The Adviser and Financial Institution will seek to obtain the best execution reasonably available under the circumstances with respect to the
(iii) Statements by the Financial Institution and its Advisers to the Retirement Investor about the Principal Transaction or Riskless Principal Transaction, fees and compensation related to the Principal Transaction or Riskless Principal Transaction, Material Conflicts of Interest, and any other matters relevant to a Retirement Investor's decision to engage in the Principal Transaction or Riskless Principal Transaction, are not materially misleading at the time they are made.
(2) Disclosures. The Financial Institution provides to the Retirement Investor, prior to or at the same time as the execution of the recommended Principal Transaction or Riskless Principal Transaction, a single written disclosure, which may cover multiple transactions or all transactions occurring within the Transition Period, that clearly and prominently:
(i) Affirmatively states that the Financial Institution and the Adviser(s) act as fiduciaries under ERISA or the Code, or both, with respect to the recommendation;
(ii) Sets forth the standards in paragraph (d)(1) of this section and affirmatively states that it and the Adviser(s) adhered to such standards in recommending the transaction; and
(iii) Discloses the circumstances under which the Adviser and Financial Institution may engage in Principal Transactions and Riskless Principal Transactions with the Plan, participant or beneficiary account, or IRA, and identifies and discloses the Material Conflicts of Interest associated with Principal Transactions and Riskless Principal Transactions.
(iv) The disclosure may be provided in person, electronically or by mail. It does not have to be repeated for any subsequent recommendations during the Transition Period.
(v) The Financial Institution will not fail to satisfy this Section VII(d)(2) solely because it, acting in good faith and with reasonable diligence, makes an error or omission in disclosing the required information, provided the Financial Institution discloses the correct information as soon as practicable, but not later than 30 days after the date on which it discovers or reasonably should have discovered the error or omission. To the extent compliance with this Section VII(d)(2) requires Advisers and Financial Institutions to obtain information from entities that are not closely affiliated with them, they may rely in good faith on information and assurances from the other entities, as long as they do not know, or unless they should have known, that the materials are incomplete or inaccurate. This good faith reliance applies unless the entity providing the information to the Adviser and Financial Institution is (1) a person directly or indirectly through one or more intermediaries, controlling, controlled by, or under common control with the Adviser or Financial Institution; or (2) any officer, director, employee, agent, registered representative, relative (as defined in ERISA section 3(15)), member of family (as defined in Code section 4975(e)(6)) of, or partner in, the Adviser or Financial Institution.
(3) The Financial Institution must designate a person or persons, identified by name, title or function, responsible for addressing Material Conflicts of Interest and monitoring Advisers' adherence to the Impartial Conduct Standards.
(4) The Financial Institution complies with the recordkeeping requirements of Section V(a) and (b).
Employee Benefits Security Administration (EBSA), U.S. Department of Labor.
Adoption of amendment to PTE 75-1, Part V.
This document contains an amendment to PTE 75-1, Part V, a class exemption from certain prohibited transactions provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code (the Code). The provisions at issue generally prohibit fiduciaries of employee benefit plans and individual retirement accounts (IRAs), from lending money or otherwise extending credit to the plans and IRAs and receiving compensation in return. PTE 75-1, Part V, permits the extension of credit to a plan or IRA by a broker-dealer in connection with the purchase or sale of securities; however, it originally did not permit the receipt of compensation for an extension of credit by broker-dealers that are fiduciaries with respect to the assets involved in the transaction. This amendment permits investment advice fiduciaries to receive compensation when they extend credit to plans and IRAs to avoid a failed securities transaction. The amendment affects participants and beneficiaries of plans, IRA owners, and fiduciaries with respect to such plans and IRAs.
Susan Wilker, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor, (202) 693-8824 (this is not a toll-free number).
The Department is amending PTE 75-1, Part V on its own motion, pursuant to ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637 (October 27, 2011)).
The Department grants this amendment to PTE 75-1, Part V, in connection with its publication today, elsewhere in this issue of the
This amendment to PTE 75-1, Part V, allows broker-dealers that are investment advice fiduciaries to receive compensation when they extend credit to plans and IRAs to avoid failed securities transactions entered into by the plan or IRA. In the absence of an exemption, these transactions would be prohibited under ERISA and the Code. In this regard, ERISA and the Code generally prohibit fiduciaries from lending money or otherwise extending credit to plans and IRAs, and from receiving compensation in return.
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant and amend administrative exemptions from ERISA's prohibited transaction provisions.
The amendment to PTE 75-1, Part V, allows investment advice fiduciaries that are broker-dealers to receive compensation when they lend money or otherwise extend credit to plans or IRAs to avoid the failure of a purchase or sale of a security. The exemption contains conditions that the broker-dealer lending money or otherwise extending credit must satisfy in order to take advantage of the exemption. In particular, the potential failure of the securities transaction may not be caused by the fiduciary or an affiliate, and the terms of the extension of credit must be at least as favorable to the plan or IRA as terms the plan or IRA could obtain in an arm's length transaction with an unrelated party. Certain advance written disclosures must be made to the plan or IRA, in particular, with respect to the rate of interest or other fees charged for the loan or other extension of credit.
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Order and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal agencies to develop a plan under which the agencies will periodically review their existing significant regulations to make the agencies' regulatory programs more effective or less burdensome in achieving their regulatory objectives.
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the OMB. Section 3(f) of Executive Order 12866, defines a “significant regulatory action” as an action that is likely to result in a rule (1) having an annual effect on the economy of $100 million or more, or adversely and materially affecting a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities (also referred to as “economically significant” regulatory actions); (2) creating serious inconsistency or otherwise interfering with an action taken or planned by another agency; (3) materially altering the budgetary impacts of entitlement grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raising novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of the Executive Order, OMB has determined that this action is “significant” within the meaning of Section 3(f)(4) of the Executive Order. Accordingly, the Department has undertaken an assessment of the costs and benefits of the proposal, and OMB has reviewed this regulatory action. The Department's complete Regulatory Impact Analysis is available at
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service. Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violations of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, ERISA section 3(21)(A) and Code section 4975(e)(3) provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of its assets; (ii) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan or IRA, or has any authority or responsibility to do so; or, (iii) has any discretionary authority or discretionary responsibility in the administration of such plan or IRA.
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants, and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, the providers of investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c)(1975), defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of ERISA section 3(21)(A)(ii) (the “1975 regulation”).
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At the same time, the variety and complexity of financial products have increased, widening the information gap between advisers and their clients. Plan fiduciaries, plan participants and IRA investors must often rely on experts for advice, but are unable to assess the quality of the expert's advice or effectively guard against the adviser's conflicts of interest. This challenge is especially true of retail investors with smaller account balances who typically do not have financial expertise, and can ill-afford lower returns to their retirement savings caused by conflicts. The IRA accounts of these investors often account for all or the lion's share of their assets and can represent all of savings earned for a lifetime of work. Losses and reduced returns can be devastating to the investors who depend upon such savings for support in their old age. As baby boomers retire, they are increasingly moving money from ERISA-covered plans, where their employer has both the incentive and the fiduciary duty to facilitate sound investment choices, to IRAs where both good and bad investment choices are myriad and advice that is conflicted is commonplace. These rollovers are expected to approach $2.4 trillion cumulatively from 2016 through 2020.
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the 1975 regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B), (the “Regulation”) which are also published in this issue of the
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, plan participant or beneficiary, IRA or IRA owner, the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage versus advisory), or recommendations with respect to rollovers, transfers or distributions from a plan or IRA, including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also provides that as a threshold matter in order to be fiduciary advice, the communication must be a “recommendation” as defined therein. The Regulation, as a matter of clarification, provides that a variety of other communications do not constitute “recommendations,” including non-fiduciary investment education; general communications; and specified communications by platform providers. These communications which do not rise to the level of “recommendations” under the Regulation are discussed more fully in the preamble to the final Regulation.
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person making the recommendation must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); (2) the person must fairly inform the independent fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and must fairly inform the independent fiduciary of the existence and nature of the person's financial interests in the transaction; (3) the person must know or reasonably believe that the independent fiduciary of the plan or IRA is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); and (4) the person cannot receive a fee or other compensation directly from the plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner for the provision of investment advice (as opposed to other services) in connection with the transaction.
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in ERISA section 3(3)) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Exchange Act (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
The Department anticipates that the Regulation will cover many investment professionals who did not previously consider themselves to be fiduciaries under ERISA or the Code. Under the Regulation, these entities will be subject to the prohibited transaction restrictions in ERISA and the Code that apply specifically to fiduciaries. The lending of money or other extension of credit between a fiduciary and a plan or IRA, and the plan's or IRA's payment of
Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA.
As relevant to this notice, the Department understands that broker-dealers can be required, as part of their relationships with clearing houses, to complete securities transactions entered into by the broker-dealer's customers, even if a particular customer does not perform on its obligations. If a broker-dealer is required to advance funds to settle a trade entered into by a plan or IRA, or purchase a security for delivery on behalf of a plan or IRA, the result can potentially be viewed as a loan of money or other extension of credit to the plan or IRA. Further, in the event a broker-dealer steps into a plan's or IRA's shoes in any particular transaction, it may charge interest or other fees to the plan or IRA. These transactions potentially violate ERISA section 406(a)(1)(B) and Code section 4975(c)(1)(B) and (D).
As reflected in the prohibited transaction provisions, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however, the statutes provide exemptions from the broad prohibitions on conflicts of interest. For example, ERISA section 408(b)(14) and Code section 4975(d)(17) specifically exempt transactions involving the provision of fiduciary investment advice to a participant or beneficiary of an individual account plan or IRA owner, including extensions of short term credit for settlements of securities trades, if the advice, resulting transaction, and the adviser's fees meet stringent conditions carefully designed to guard against conflicts of interest.
In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions. However, when they choose to give advice in which they have a conflict of interest, they must rely upon an exemption.
Pursuant to its exemption authority, the Department has previously granted several conditional administrative class exemptions that are available to fiduciary advisers in defined circumstances. The Department has, for example, permitted investment advice fiduciaries to receive compensation from a plan (
The class exemptions described above do not provide relief for any extensions of credit that may be related to a plan's or IRA's investment transactions. PTE 75-1, Part V,
Relief under PTE 75-1, Part V, was historically limited in that the broker-dealer extending credit was not permitted to have or exercise any discretionary authority or control (except as a directed trustee) with respect to the investment of the plan or IRA assets involved in the transaction,
As part of its development of the Regulation, the Department considered public input indicating the need for
This amended exemption follows a lengthy public notice and comment process, which gave interested persons an extensive opportunity to comment on the proposed Regulation and exemption proposals. The proposals initially provided for 75-day comment periods, ending on July 6, 2015 but the Department extended the comment periods to July 21, 2015. The Department then held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule.
As amended, PTE 75-1, Part V, Section (c) provides that a fiduciary within the meaning of ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B) may receive reasonable compensation for extending credit to a plan or IRA to avoid a failed purchase or sale of securities involving the plan or IRA. One commenter requested that Section (c) be broadened to cover all transactions that are covered by other sections of PTE 75-1, Part V, including short sales, options trading and margin transactions, but did not suggest any additional protective conditions. The commenter stated that extension of credit relief is critical to such transactions.
The Department declined to accept this request. As noted above, this amendment was intended to be a narrow expansion of the existing exemption to permit investment advice fiduciaries to receive compensation for extending credit to avoid a failed securities transaction. As a condition of the exemption, the proposal stated that the potential failure of the transaction could not be the result of the action or inaction by the fiduciary or an affiliate. The proposal further stated that, due to that limitation, the Department considered it unnecessary to condition the amended exemption on the protective impartial conduct standards that were proposed to apply to the other new and amended exemptions applicable to investment advice fiduciaries acting in conflicted transactions.
Extensions of credit entered into in connection with short sales, options trading and margin transactions expose retirement investors to the potential of losses that exceed their account value. Expanding the scope of the exemption to permit investment advice fiduciaries to provide advice on these transactions and earn compensation from the extension of credit would not be protective under the conditions of the amended exemption.
In the Department's view, this relief is not critical to all short sales, options and margin transactions. For example, the Department understands that some options transactions can occur in a cash account that does not involve an extension of credit. In addition, self-directed investors can still engage in the full extent of transactions that were permitted prior to the Applicability Date of the Regulation, and broker-dealers that are not fiduciaries will still be able to rely on the exemption to receive compensation. Finally, investors can receive unconflicted advice from an adviser regarding margin transactions entered into with an unaffiliated broker-dealer.
In conjunction with the expanded relief in the amended exemption, Section (c) includes several conditions. First, the potential failure of the purchase or sale of the securities may not be caused by the broker-dealer or any affiliate. The Department changed the phrasing of this requirement in response to a comment, which said that the proposed phrasing—requiring that the potential failure could not be “the result of action or inaction by such fiduciary or affiliate”—was too vague, possibly overbroad, and would require a fact-intensive inquiry for every failure of the purchase or sale of securities, leading to a chaotic aftermath of each failed transaction and increasing cost to the investor.
According to the commenter, broker-dealers regularly “work out” issues relating to settlement failures and have policies and procedures to allocate costs, including not charging clients when it is the broker-dealer's fault. Thus, the commenter suggested that the language be revised to state that the failure “was not caused” by the fiduciary or an affiliate.
The Department accepted this comment. This condition was intended to ensure that broker-dealers will not profit from charging interest on settlement failures for which they are responsible. The Department has determined that the suggested change in phrasing is sufficiently protective of the plans and IRAs that may be paying interest.
Additionally, under the final amendment, the terms of the extension of credit must be at least as favorable to the plan or IRA as the terms available in an arm's length transaction between unaffiliated parties. The Department did not receive comments on this point and did not make any changes to the proposed requirement.
Finally, the plan or IRA must receive written disclosure of certain terms prior to the extension of credit. This disclosure does not need to be made on a transaction by transaction basis, and can be part of an account opening agreement or a master agreement. The disclosure must include the rate of interest or other fees that will be charged on such extension of credit, and the method of determining the balance upon which interest will be charged.
The required disclosures are intended to be consistent with the requirements of Securities and Exchange Act Rule 10b-16,
Consistent with other class exemptions published elsewhere in this edition of the
In response to comments received specific to some of the other exemptions adopted or amended elsewhere in this edition of the
The amended exemption does not provide relief from a transaction prohibited by ERISA section 406(a)(1)(C), or from the taxes imposed by Code section 4975(a) and (b) by reason of Code section 4975(c)(1)(C), regarding the furnishing of goods, services or facilities between a plan and a party in interest or between an IRA and a disqualified person. The provision of investment advice to a plan or IRA is a service to the plan or IRA and compliance with this exemption will not relieve an investment advice fiduciary of the need to comply with ERISA section 408(b)(2), Code section 4975(d)(2), and applicable regulations thereunder. The disclosure standards under 408(b)(2) were recently finalized, and the Department took care to tailor those disclosure conditions for the plan marketplace. The Department believes that uniform standards are desirable and will promote broad compliance in this respect.
The Regulation will become effective June 7, 2016 and this amended exemption is issued on that same date. The Regulation is effective at the earliest possible effective date under the Congressional Review Act. For the exemption, the issuance date serves as the date on which the amended exemption is intended to take effect for purposes of the Congressional Review Act. This date was selected in order to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the Regulation are officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the rule and amended exemption are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, an Applicability Date of April 10, 2017 is appropriate for plans and their affected financial services and other service providers to adjust to the basic change from non-fiduciary to fiduciary status. This amendment has the same Applicability Date; parties may rely on the amended exemption as of the Applicability Date.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Amendment to Prohibited Transaction Exemption (PTE) 75-1, Part V, Exemptions From Prohibitions Respecting Certain Classes of Transactions Involving Employee Benefit Plans and Certain Broker-Dealers, Reporting Dealers and Banks published as part of the Department's proposal to amend its 1975 rule that defines when a person who provides investment advice to an employee benefit plan or IRA becomes a fiduciary, solicited comments on the information collections included therein. The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposed regulation, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally many comments were submitted, described elsewhere in the preamble to the accompanying final rule, which contained information relevant to the costs and administrative burdens attendant to the proposals. The Department took into account such public comments in connection with making changes to the prohibited transaction exemption, analyzing the economic impact of the proposals, and developing the revised paperwork burden analysis summarized below.
In connection with publication of this final amendment to Prohibited Transaction Exemption (PTE) 75-1, Part V, Exemptions From Prohibitions Respecting Certain Classes of Transactions Involving Employee Benefit Plans and Certain Broker-Dealers, Reporting Dealers and Banks, the Department submitted an ICR to OMB for its request of a revision to OMB Control Number 1210-0059. The
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail below, Section (c)(3) of the amendment requires that prior to the extension of credit, the plan must receive from the fiduciary written disclosure of (i) the rate of interest (or other fees) that will apply and (ii) the method of determining the balance upon which interest will be charged in the event that the fiduciary extends credit to avoid a failed purchase or sale of securities, as well as, prior written disclosure of any changes to these terms. Section (d) requires broker-dealers engaging in the transactions to maintain records demonstrating compliance with the conditions of the PTE. These requirements are information collection requests (ICRs) subject to the Paperwork Reduction Act.
The Department believes that this disclosure requirement is consistent with the disclosure requirement mandated by the Securities and Exchange Commission (SEC) in 17 CFR 240.10b-16(1) for margin transactions. Although the SEC does not mandate any recordkeeping requirement, the Department believes that it would be a usual and customary business practice for financial institutions to maintain any records necessary to prove that required disclosures had been distributed in compliance with the SEC's rule. Therefore, the Department concludes that these ICRs impose no additional burden on respondents.
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under ERISA section 408(a) and Code section 4975(c)(2) does not relieve a fiduciary or other party in interest or disqualified person with respect to a plan from certain other provisions of ERISA and the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of ERISA section 404 which require, among other things, that a fiduciary discharge his or her duties respecting the plan solely in the interests of the plan's participants and beneficiaries and in a prudent fashion in accordance with ERISA section 404(a)(1)(B);
(2) The Department finds that the class exemption as amended is administratively feasible, in the interests of the plan and of its participants and beneficiaries and IRA owners, and protective of the rights of the plan's participants and beneficiaries and IRA owners;
(3) The class exemption is applicable to a particular transaction only if the transaction satisfies the conditions specified in the class exemption; and
(4) This amended class exemption is supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
The restrictions of section 406 of the Employee Retirement Income Security Act of 1974 (the Act) and the taxes imposed by section 4975(a) and (b) of the Internal Revenue Code of 1986 (the Code), by reason of section 4975(c)(1) of the Code, shall not apply to any extension of credit to an employee benefit plan or an individual retirement account (IRA) by a party in interest or a disqualified person with respect to the plan or IRA, provided that the following conditions are met:
(a) The party in interest or disqualified person:
(1) Is a broker or dealer registered under the Securities Exchange Act of 1934; and
(2) Does not have or exercise any discretionary authority or control (except as a directed trustee) with respect to the investment of the plan or IRA assets involved in the transaction, nor does it render investment advice (within the meaning of 29 CFR 2510.3-21) with respect to those assets, unless no interest or other consideration is received by the party in interest or disqualified person or any affiliate thereof in connection with such extension of credit.
(b) Such extension of credit:
(1) Is in connection with the purchase or sale of securities;
(2) Is lawful under the Securities Exchange Act of 1934 and any rules and regulations promulgated thereunder; and
(3) Is not a prohibited transaction within the meaning of section 503(b) of the Code.
(c) Notwithstanding section (a)(2), a fiduciary under section 3(21)(A)(ii) of the Act or Code section 4975(e)(3)(B) may receive reasonable compensation for extending credit to a plan or IRA to avoid a failed purchase or sale of securities involving the plan or IRA if:
(1) The potential failure of the purchase or sale of the securities is not caused by such fiduciary or an affiliate;
(2) The terms of the extension of credit are at least as favorable to the plan or IRA as the terms available in an arm's length transaction between unaffiliated parties;
(3) Prior to the extension of credit, the plan or IRA receives written disclosure of (i) the rate of interest (or other fees) that will apply and (ii) the method of determining the balance upon which interest will be charged, in the event that the fiduciary extends credit to avoid a failed purchase or sale of securities, as well as prior written disclosure of any changes to these terms. This Section (c)(3) will be considered satisfied if the plan or IRA receives the disclosure described in the Securities and Exchange Act Rule 10b-16;
(d) The broker-dealer engaging in the covered transaction maintains or causes to be maintained for a period of six years from the date of such transaction in a manner that is reasonably accessible for examination, such records as are necessary to enable the persons described in paragraph (e) of this exemption to determine whether the conditions of this exemption have been met with respect to a transaction, except that:
(1) No party other than the broker-dealer engaging in the covered transaction shall be subject to the civil penalty which may be assessed under section 502(i) of the Act, or to the taxes imposed by section 4975(a) and (b) of the Code, if such records are not maintained, or are not available for examination as required by paragraph (e) below; and
(2) A prohibited transaction will not be deemed to have occurred if, due to circumstances beyond the control of the broker-dealer, such records are lost or destroyed prior to the end of such six-year period.
(e)(1) Except as provided in paragraph (e)(2) of this exemption, and notwithstanding anything to the contrary in subsections (a)(2) and (b) of section 504 of the Act, the records referred to in paragraph (d) are
(A) An authorized employee or representative of the Department of Labor or the Internal Revenue Service,
(B) Any fiduciary of a plan that engaged in a transaction pursuant to this exemption, or any authorized employee or representative of such fiduciary;
(C) Any contributing employer and any employee organization whose members are covered by a plan described in paragraph (e)(1)(B), or any authorized employee or representative of these entities; or
(D) Any participant or beneficiary of a plan described in paragraph (e)(1)(B), IRA owner or the authorized representative of such participant, beneficiary or owner.
(2) None of the persons described in paragraph (e)(1)(B)-(D) of this exemption are authorized to examine records regarding a recommended transaction involving another investor, or privileged trade secrets or privileged commercial or financial information, of the broker-dealer engaging in the covered transaction, or information identifying other individuals.
(3) Should the broker-dealer engaging in the covered transaction refuse to disclose information on the basis that the information is exempt from disclosure, the broker-dealer must, by the close of the thirtieth (30th) day following the request, provide a written notice advising the requestor of the reasons for the refusal and that the Department may request such information.
(4) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
For purposes of this exemption, the terms “party in interest,” “disqualified person” and “fiduciary” shall include such party in interest, disqualified person, or fiduciary, and any affiliates thereof, and the term “affiliate” shall be defined in the same manner as that term is defined in 29 CFR 2510.3-21 and 26 CFR 54.4975-9. Also for the purposes of this exemption, the term “IRA” means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
Employee Benefits Security Administration (EBSA), Department of Labor.
Adoption of amendment to and partial revocation of PTE 84-24.
This document amends and partially revokes Prohibited Transaction Exemption (PTE) 84-24, an exemption from certain prohibited transaction provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code of 1986 (the Code). The ERISA and Code provisions at issue generally prohibit fiduciaries with respect to employee benefit plans and individual retirement accounts (IRAs) from engaging in self-dealing in connection with transactions involving these plans and IRAs. Non-fiduciary service providers also may not enter into certain transactions with plans and IRAs without an exemption. The amended exemption allows fiduciaries and other service providers to receive compensation when plans and IRAs purchase insurance contracts, “Fixed Rate Annuity Contracts,” as defined in the exemption, securities of investment companies registered under the Investment Company Act of 1940, as well as certain related transactions. The amendments increase the safeguards of the exemption. This document also contains the revocation of the exemption as it applies to plan and IRA purchases of annuity contracts that do not satisfy the definition of a Fixed Rate Annuity Contract, and the revocation of the exemption as it applies to IRA purchases of investment company securities. The amendments and revocations affect participants and beneficiaries of plans, IRA owners, and certain fiduciaries and service providers of plans and IRAs.
Brian Shiker or Brian Mica, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor, 200 Constitution Avenue NW., Suite 400, Washington, DC 20210, (202) 693-8824 (not a toll-free number).
The Department is amending PTE 84-24
The Department grants this amendment to PTE 84-24 in connection with its publication today, elsewhere in this issue of the
PTE 84-24 is an exemption originally granted in 1977, and amended several times over the years. It historically provided relief for certain parties to receive commissions when plans and IRAs purchased recommended insurance and annuity contracts and investment company securities (
This amendment to and partial revocation of PTE 84-24 is part of the Department's regulatory initiative to mitigate the effects of harmful conflicts of interest associated with fiduciary investment advice. In the absence of an exemption, ERISA and the Code generally prohibit fiduciaries from using their authority to affect or increase their own compensation. A new exemption for receipt of compensation by fiduciaries that provide investment advice to IRAs, plan participants and beneficiaries, and certain plan fiduciaries, is adopted elsewhere in this issue of the
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant and amend administrative exemptions from ERISA's prohibited transaction provisions.
PTE 84-24, as amended, provides an exemption for certain prohibited transactions that occur when investment advice fiduciaries and other service providers receive compensation for their recommendation that plans or IRAs purchase “Fixed Rate Annuity Contracts” as defined in the exemption, and insurance contracts. IRAs are defined in the exemption to include other plans described in Code section 4975(e)(1)(B)-(F), such as Archer MSAs, Health Savings Accounts (HSAs), and Coverdell education savings accounts. Relief is also provided for certain prohibited transactions that occur when investment advice fiduciaries and other service providers receive compensation as a result of recommendations that plans purchase investment company securities. The exemption permits insurance agents, insurance brokers, pension consultants and investment company principal underwriters that are parties in interest or fiduciaries with respect to plans or IRAs, as applicable, to effect these purchases and receive a commission on them. The exemption is also available for the prohibited transaction that occurs when an insurance company selling a Fixed Rate Annuity Contract or insurance contract is a party in interest or disqualified person with respect to the plan or IRA.
As amended, the exemption requires fiduciaries engaging in these transactions to adhere to certain “Impartial Conduct Standards,” including acting in the best interest of the plans and IRAs when providing advice. The amendment also more specifically defines the types of payments that are permitted under the exemption and revises the disclosure and recordkeeping requirements of the exemption.
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Orders and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal agencies to develop a plan under which the agencies will periodically review their existing significant regulations to make the agencies' regulatory programs more effective or less burdensome in achieving their regulatory objectives.
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the Office of Management and Budget (OMB). Section 3(f) of Executive Order
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans and their participants and beneficiaries.
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules, and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service (IRS). Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violation of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, section 3(21)(A) of ERISA and section 4975(e)(3) of the Code provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of its assets; (ii) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan or IRA, or has any authority or responsibility to do so; or (iii) has any discretionary authority or discretionary responsibility in the administration of such plan or IRA.
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants, and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, persons who provide investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c), defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of section ERISA 3(21)(A)(ii) (the “1975 regulation”).
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At the same time, the variety and complexity of financial products have increased, widening the information gap between advisers and their clients. Plan fiduciaries, plan participants and IRA investors must often rely on experts for advice, but are unable to assess the quality of the expert's advice or effectively guard against the adviser's
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B) (the “Regulation”), which are also published in this issue of the
The Regulation describes the types of advice that constitute “investment advice” with respect to plan and IRA assets for purposes of the definition of a fiduciary at ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B). The Regulation covers ERISA-covered plans, IRAs, and other plans not covered by Title I of ERISA, such as Keogh plans, and HSAs described in section 223(d) of the Code.
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, a plan participant or beneficiary, IRA or IRA owner, one of the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage versus advisory), or recommendations with respect to rollovers, transfers or distributions from a plan or IRA, including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person making the recommendation must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); (2) the person
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in ERISA section 3(3)) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
ERISA section 406(a)(1)(A)-(D) and Code section 4975(c)(1)(A)-(D) prohibit certain transactions between plans or IRAs and “parties in interest,” as defined in ERISA section 3(14), or “disqualified persons,” as defined in Code section 4975(e)(2). Fiduciaries and other service providers are parties in interest and disqualified persons under ERISA and the Code. As a result, they are prohibited from engaging in (1) the sale, exchange or leasing of property with a plan or IRA, (2) the lending of money or other extension of credit to a plan or IRA, (3) the furnishing of goods, services or facilities to a plan or IRA and (4) the transfer to or use by or for the benefit of a party in interest of plan assets.
ERISA section 406(b) and Code section 4975(c)(1)(E) and (F) are aimed at fiduciaries only. These provisions generally prohibit a fiduciary from dealing with the income or assets of a plan or IRA in his or her own interest or his or her own account and from receiving payments from third parties in connection with transactions involving the plan or IRA. Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA. Under these provisions, a fiduciary may not cause a plan or IRA to pay an additional fee to such fiduciary, or to a person in which such fiduciary has an interest that may affect the exercise of the fiduciary's best judgment.
The receipt of a commission on the sale of an insurance or annuity contract or investment company securities by a fiduciary that recommended the investment violates the prohibited transaction provisions of ERISA section 406(b) and Code section 4975(c)(1)(E) and (F). In addition, the effecting of the sale by a fiduciary or service provider is a service, potentially in violation of ERISA section 406(a)(1)(C) and Code section 4975(c)(1)(C). Finally, the purchase of an insurance or annuity contract by a plan or IRA from an insurance company that is a fiduciary, service provider or other party in interest or disqualified person, violates ERISA section 406(a)(1)(A) and (D) and Code section 4975(c)(1)(A) and (D).
As the prohibited transaction provisions demonstrate, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however, the statutes provide exemptions from their broad prohibitions on conflicts of interest. In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, while fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions, when they choose to give advice in which they have a financial interest, they must rely upon an exemption.
Pursuant to its exemption authority, the Department has previously granted several conditional administrative class exemptions that are available to fiduciary advisers in defined circumstances. PTE 84-24 historically provided an exemption from the prohibited transaction provisions of ERISA and the Code for insurance agents, insurance brokers, pension consultants, insurance companies and investment company principal underwriters to engage in certain transactions involving insurance and annuity contracts, and investment company securities. Prior to this amendment, PTE 84-24 provided relief to these parties in connection with transactions involving ERISA-covered plans, Keogh plans, as well as IRAs and other plans described in Code section 4975, such as Archer MSAs, HSAs and Coverdell education savings accounts.
Specifically, PTE 84-24 permitted insurance agents, insurance brokers and pension consultants to receive, directly or indirectly, a commission for selling insurance or annuity contracts to plans and IRAs. The exemption also permitted the purchase by plans and IRAs of insurance and annuity contracts from insurance companies that are parties in interest or disqualified persons. The term “insurance and annuity contract” included a variable annuity contract.
With respect to transactions involving investment company securities, PTE 84-24 also permitted the investment company's principal underwriter to receive commissions in connection with a plan's or IRA's purchase of investment company securities. The term “principal underwriter” is defined in the same manner as it is defined in the Investment Company Act of 1940. Section 2(a)(29) of the Investment Company Act of 1940
`Principal underwriter' of or for any investment company other than a closed-end company, or of any security issued by such a company, means any underwriter who as principal purchases from such company, or pursuant to contract has the right (whether absolute or conditional) from time to time to purchase from such company, any such security for distribution, or who as agent for such company sells or has the right to sell any such security to a dealer or to the public or both, but does not include a dealer who purchases from such company through a principal underwriter acting as agent for such company.
In connection with the proposed Regulation, the Department proposed an amendment to PTE 84-24 that included several important changes. First, the Department proposed to increase the safeguards of the exemption by requiring fiduciaries that rely on the exemption to adhere to “Impartial Conduct Standards,” including acting in the best interest of the plans and IRAs when providing advice, and by more precisely defining the types of payments that are permitted under the exemption. Second, on a going forward basis, the Department proposed to revoke relief for insurance agents, insurance brokers and pension consultants to receive a commission in connection with the purchase by IRAs of variable annuity contracts and other annuity contracts that are securities under federal securities laws, and for investment company principal underwriters to receive a commission in connection with the purchase by IRAs of investment company securities.
This amended exemption follows a lengthy public notice and comment process, which gave interested persons an extensive opportunity to comment on the proposed Regulation and the related exemption proposals, including the proposed amendment to and partial revocation of PTE 84-24. The proposals initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department then also held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3,000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposals. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule and related exemption proposals.
The final amendment to PTE 84-24 preserves the availability of the exemption for the receipt of commissions by insurance agents, insurance brokers and pension consultants, in connection with the recommendation that plans or IRAs purchase insurance contracts and certain types of annuity contracts defined in the exemption as “Fixed Rate Annuity Contracts.” A Fixed Rate Annuity Contract is a fixed annuity contract issued by an insurance company that is either an immediate annuity contract or a deferred annuity contract that (i) satisfies applicable state standard nonforfeiture laws at the time of issue, or (ii) in the case of a group fixed annuity, guarantees return of principal net of reasonable compensation and provides a guaranteed declared minimum interest rate in accordance with the rates specified in the standard nonforfeiture laws in that state that are applicable to individual annuities; in either case, the benefits of which do not vary, in part or in whole, based on the investment experience of a separate account or accounts maintained by the insurer or the investment experience of an index or investment model. A Fixed Rate Annuity Contract does not include a variable annuity, or an indexed annuity or similar annuity.
The Department's approach to the definition of Fixed Rate Annuity Contract is generally based on satisfaction of applicable state standard nonforfeiture laws at the time of issue. If the applicable law does not have a standard nonforfeiture provision, the definition may be satisfied by compliance with the National Association of Insurance Commissioners (NAIC) Model Standard Nonforfeiture Law. However, for group fixed annuities, which the Department understands are not typically covered by standard nonforfeiture laws, the definition requires the annuity to meet comparable standards. Therefore, the group fixed annuity must guarantee return of principal net of reasonable compensation and provide a guaranteed declared minimum interest rate in accordance with the rates specified in the standard nonforfeiture laws in that state that are applicable to individual annuities (or the NAIC Model Standard Nonforfeiture Law if there is no applicable state standard nonforfeiture law).
By defining a Fixed Rate Annuity Contract in this manner, the Department intends to cover within PTE 84-24 fixed annuities that currently are referred to as immediate annuities, traditional annuities, declared rate annuities or fixed rate annuities (including deferred income annuities). These annuities provide payments that are the subject of insurance companies' contractual guarantees and that are predictable. Permitting such annuities to be recommended under the terms of PTE 84-24 will promote access to these annuity contracts which have important lifetime income guarantees and terms that are more understandable to consumers. As noted by commenters, lifetime income products are increasingly critical for retirement savers due to the shift away from defined benefit plans. The Department notes that the fact that an annuity contract allows for the payment of dividends, allows the insurance company in its discretion to credit a rate higher than the minimum guarantee, or provides for a cost-of-living adjustment does not in and of itself remove an annuity contract from the definition of a Fixed Rate Annuity Contract under the exemption.
On the other hand, the exemption does not cover variable annuities, indexed annuities or similar annuities, in which contract values vary, in whole or in part, based on the investment experience of a separate account or accounts maintained by the insurer or the investment experience of an index or investment model. In this regard, the exemption also does not cover any annuity registered as a security under federal securities laws. These investments typically require the customer to shoulder significant investment risk and do not offer the
The amendment adopts the proposal's approach to the receipt of commissions by investment company principal underwriters. The exemption remains available for these transactions involving ERISA plans and Keogh plans, but not for IRAs and other plans described in Code section 4975(e)(1)(B)-(D), including Archer MSAs, HSAs and Coverdell education savings accounts.
As amended, the exemption requires fiduciaries engaging in these transactions to adhere to certain “Impartial Conduct Standards,” including acting in the best interest of the plans and IRAs when providing advice. The amendment also more specifically defines the types of payments that are permitted under the exemption and revises the disclosure and recordkeeping requirements of the exemption.
The Department amended and revoked PTE 84-24 in these ways only in conjunction with the grant of a new exemption, the Best Interest Contract Exemption, adopted elsewhere in this issue of the
In addition, the Regulation adopted today permits investment professionals—including insurance agents, insurance brokers, pension consultants, and mutual fund principal underwriters—to avoid fiduciary status when they engage in arm's length transactions with plans or IRAs that are independently represented by a fiduciary with financial expertise. Such independent fiduciaries generally include banks, insurance carriers, registered investment advisers, broker-dealers and other fiduciaries with $50 million or more in assets under management or control. This provision in the Regulation complements the limitations in the Best Interest Contract Exemption and is available for transactions involving all insurance and annuity contracts and investment company securities.
A number of commenters objected generally to changes to PTE 84-24 on the basis that the original exemption, in combination with other regulatory safeguards under insurance law or securities law, provides sufficient protections to plans and IRAs. Commenters said there is no demonstrated harm to these consumers under the existing approach.
The Department does not agree. The extensive changes in the retirement plan landscape and the associated investment market in recent decades undermine the continued adequacy of the original approach in PTE 84-24. In the years since the exemption was originally granted in 1977,
Therefore, while the exemption remains available for insurance contracts and Fixed Rate Annuity Contracts, it is revoked for annuity contracts that do not satisfy the definition of Fixed Rate Annuity contracts. Accordingly, the exemption specifically excludes recommendations of variable annuities, indexed annuities and similar annuities. Given the complexity, investment risks, and conflicted sales practices associated with these products, the Department has determined that recommendations to purchase such annuities should be subject to the greater protections of the Best Interest Contract Exemption.
Both the Securities and Exchange Commission (SEC) staff and the Financial Industry Regulatory Authority (FINRA)
The marketing efforts used by some variable annuity sellers deserve scrutiny—especially when seniors are the targeted investors. Sales pitches for these products might attempt to scare or confuse investors. One scare tactic used with seniors is to claim that a variable annuity will protect them from lawsuits or seizures of their assets. Many such claims are not based on facts, but nevertheless help land a sale. While variable annuities can be appropriate as an investment under the right circumstances, as an investor, you should be aware of their restrictive features, understand that substantial taxes and charges may apply if you withdraw your money early, and guard against fear-inducing sales tactics.
Investing in a variable annuity within a tax-deferred account, such as an individual retirement account (IRA) may not be a good idea. Since IRAs are already tax-advantaged, a variable annuity will provide no additional tax savings. It will, however, increase the
Sales of equity-indexed annuities (EIAs) . . . have grown considerably in recent years. Although one insurance company at one time included the word `simple' in the name of its product, EIAs are anything but easy to understand. One of the most confusing features of an EIA is the method used to calculate the gain in the index to which the annuity is linked. To make matters worse, there is not one, but several different indexing methods. Because of the variety and complexity of the methods used to credit interest, investors will find it difficult to compare one EIA to another.”
You can lose money buying an indexed annuity. If you need to cancel your annuity early, you may have to pay a significant surrender charge and tax penalties. A surrender charge may result in a loss of principal, so that an investor may receive less than his original purchase payments. Thus, even with a specified minimum value from the insurance company, it can take several years for an investment in an indexed annuity to `break even.'
It is important to note that indexed annuity contracts commonly allow the insurance company to change the participation rate, cap, and/or margin/spread/asset or administrative fee on a periodic—such as annual—basis. Such changes could adversely affect your return.
Equity indexed annuities are extremely complex investment products that have often been used as instruments of fraud and abuse. For years, they have taken an especially heavy toll on our nation's most vulnerable investors, our senior citizens for whom they are clearly unsuitable.
In the Department's view, the increasing complexity and conflicted payment structures associated with these annuity products have heightened the conflicts of interest experienced by investment advice providers that recommend them. These are complex products requiring careful consideration of their terms and risks. Assessing the prudence of a particular indexed annuity requires an understanding of surrender terms and charges; interest rate caps; the particular market index or indexes to which the annuity is linked; the scope of any downside risk; associated administrative and other charges; the insurer's authority to revise terms and charges over the life of the investment; and the specific methodology used to compute the index-linked interest rate and any optional benefits that may be offered, such as living benefits and death benefits. In operation, the index-linked interest rate can be affected by participation rates; spread, margin or asset fees; interest rate caps; the particular method for determining the change in the relevant index over the annuity's period (annual, high water mark, or point-to-point); and the method for calculating interest earned during the annuity's term (
These developments have undermined the protections of PTE 84-24 as applied to variable and indexed annuities purchased by plans and IRAs. As stated in the accompanying Regulatory Impact Analysis, conflicts of interest in the marketplace for retail investments result in billions of dollars of underperformance to investors saving for retirement. Both categories of annuities, variable and indexed annuities, are susceptible to abuse, and all retirement investors—plans and IRAs alike—would benefit from a requirement that advisers adhere to enforceable standards of fiduciary conduct and fair dealing. The Department has therefore concluded that variable annuities, indexed annuities and similar annuities are properly recommended to both plans and IRAs under the conditions of the Best Interest Contract Exemption.
The Best Interest Contract Exemption's important protections include fiduciary advisers' enforceable contractual commitment to adhere to the Impartial Conduct Standards, such as giving best interest advice; financial institutions' express written acknowledgment of their fiduciary status; and full disclosure of conflicts of interest, compensation practices, and financial arrangements with third parties. As part of the Best Interest Contract Exemption's protections, financial institutions must also adopt and adhere to stringent anti-conflict policies and procedures aimed at ensuring advice that is in the best interest of the retirement investor and avoiding misaligned financial incentives. These protective conditions serve as strong counterweights to the conflicts of interest associated with complex investment products, such as variable and indexed annuities.
However, the Department is not fully revoking PTE 84-24. In this final amendment, the scope of the exemption as applicable to insurance transactions has been narrowed to focus on “Fixed Rate Annuity Contracts,” which are defined as fixed annuity contracts issued by an insurance company that are either immediate annuity contracts or deferred annuity contracts that (i) satisfy applicable state standard nonforfeiture laws at the time of issue, or (ii) in the case of a group fixed annuity, guarantee return of principal net of reasonable compensation and provide a guaranteed declared minimum interest rate in accordance with the rates specified in the standard nonforfeiture laws in that state that are applicable to individual annuities; in either case, the benefits of which do not vary, in part or in whole, based on the investment experience of a separate account or accounts maintained by the insurer or the investment experience of an index or investment model. A Fixed Rate Annuity Contract does not include
Additionally, the Department revokes the exemption for covered mutual fund transactions involving IRAs (as defined in the exemption). The amended exemption incorporates the Impartial Conduct Standards, and applies to narrow categories of payments. The Department finds that the conditions of the amended exemption are appropriate in connection with the narrow scope of relief provided in the amended exemption.
The specific changes to PTE 84-24, and comments received on the proposed amendment and revocation, are discussed below.
Section I(b) of the exemption, as amended, provides relief for six transactions if the conditions of the exemption are satisfied. The exemption provides relief from the application of ERISA section 406(a)(1)(A) though (D) and 406(b) and the taxes imposed by Code section 4975(a) and (b) by reason of Code section 4975(c)(1)(A) through (F). The six transactions are:
(1) The receipt, directly or indirectly, by an insurance agent or broker or a pension consultant of an Insurance Commission and related employee benefits, from an insurance company in connection with the purchase, with assets of a Plan or Individual Retirement Account (IRA),
(2) The receipt of a Mutual Fund Commission by a Principal Underwriter for an investment company registered under the Investment Company Act of 1940 (an investment company) in connection with the purchase, with Plan assets, including through a rollover or distribution, of securities issued by an investment company.
(3)(i) The effecting by an insurance agent or broker, or pension consultant of a transaction for the purchase, with assets of a Plan or IRA, including through a rollover or distribution, of a Fixed Rate Annuity Contract or insurance contract, or (ii) the effecting by a Principal Underwriter of a transaction for the purchase, with assets of a Plan, including through a rollover or distribution, of securities issued by an investment company.
(4) The purchase, with assets of a Plan or IRA, including through a rollover or distribution, of a Fixed Rate Annuity Contract or insurance contract from an insurance company, and the receipt of compensation or other consideration by the insurance company.
(5) The purchase, with assets of a Plan, of a Fixed Rate Annuity Contract or insurance contract from an insurance company which is a fiduciary or a service provider (or both) with respect to the Plan solely by reason of the sponsorship of a Master or Prototype Plan.
(6) The purchase, with assets of a Plan, of securities issued by an investment company from, or the sale of such securities to, an investment company or an investment company Principal Underwriter, when the investment company, Principal Underwriter, or the investment company investment adviser is a fiduciary or a service provider (or both) with respect to the Plan solely by reason of: (A) The sponsorship of a Master or Prototype Plan; or (B) the provision of Nondiscretionary Trust Services to the Plan; or (C) both (A) and (B).
The amended exemption is, therefore, limited to plan and IRA transactions involving Fixed Rate Annuity Contracts and insurance contracts. The exemption's transactions regarding investment company securities are limited to transactions involving plans. Transactions involving advice with respect to annuities that do not meet the definition of Fixed Rate Annuity Contract (
The Department also made certain additional revisions to the description of the covered transactions, as a result of commenters' input. Although the Department intended that the exemption, as amended, cover transactions resulting from a rollover or distribution, some commenters expressed concern about the exemption's applicability in that context, and the text now specifically states that the exemption applies in the context of a rollover or distribution. In addition, in Section I(b)(1), the final exemption explicitly provides that, in addition to Insurance Commissions, the payment of related employee benefits is covered under the exemption. This revision was made in response to comments, discussed in greater detail below, regarding certain types of payments commonly paid to insurance company statutory employees that commenters believed may raise prohibited transactions issues.
Comments on these issues of scope are discussed below. Although the majority of commenters on the proposed revocation focused on the amendment's application to insurance and annuity contracts, some also addressed the proposed revocation of relief for investment company transactions.
In the proposed amendment, the Department proposed to revoke relief for transactions involving IRAs and variable annuities and other annuity contracts that are securities under federal securities laws. As an initial matter, some commenters raised a concern about terminology, noting that all annuity products are securities, but some are “exempt” securities under section 3(a) of the Securities Act of 1933. For purposes of this preamble discussion, the Department has adopted that the “exempt” terminology.
The proposed amendment to PTE 84-24 stated that the proposed Best Interest Contract Exemption was designed for IRA owners and other investors that rely on fiduciary investment advisers in the retail marketplace, and expressed the view that some of the transactions involving IRAs that were permitted under PTE 84-24 should instead occur under the conditions of the Best Interest Contract Exemption, specifically, transactions involving variable annuity contracts and other annuity contracts that are non-exempt securities under federal securities laws, and investment company securities.
The proposed amendment further proposed that transactions involving insurance and annuity contracts that are exempt securities could continue to occur under PTE 84-24, with the added protections of the Impartial Conduct Standards. In taking this approach, the proposal noted that that the Department was not certain that the conditions of the proposed Best Interest Contract Exemption, including some of the disclosure requirements, would be readily applicable to insurance and annuity contracts that are exempt securities, or that the distribution methods and channels of such insurance products would fit within the exemption's framework.
The proposal, therefore, distinguished between transactions that involve insurance products that are exempt securities and those that are non-exempt securities. This distinction was based on the view that annuity contracts that are non-exempt securities and investment company securities are distributed through the same channels as many other investments covered by the Best Interest Contract Exemption, and such investment products have similar disclosure requirements under existing regulations. Accordingly, the conditions of the proposed Best Interest Contract Exemption were viewed as appropriately tailored for such transactions.
The Department considered the contractual enforcement mechanism proposed in the Best Interest Contract Exemption as especially relevant to IRA owners, who do not have a mechanism to enforce the prohibited transactions provisions of ERISA and the Code. However, other conditions of the proposed Best Interest Contract Exemption were equally protective of both plans and IRAs, including the requirement that financial institutions relying on the exemption adopt anti-conflict policies and procedures designed to ensure that advisers satisfy the Impartial Conduct Standards.
The Department sought comment on the distinction drawn in the proposed amendment to PTE 84-24 between exempt and non-exempt securities. In particular, the proposal asked whether revoking relief for non-exempt securities transactions involving IRAs but leaving in place relief for IRA transactions involving insurance products that are exempt securities struck the appropriate balance, and whether that approach would be sufficiently protective of the interests of the IRAs. The Department also sought comment in the proposed Best Interest Contract Exemption on a number of issues related to the workability of that exemption (particularly, the disclosure requirements) for exempt insurance and annuity products. A number of comments on the two proposals addressed this issue of scope.
Some commenters, expressing concern about the risks associated with variable annuities, commended the Department for proposing that variable annuities should be recommended under the conditions of the Best Interest Contract Exemption rather than PTE 84-24. Generally, the commenters argued that due to the complexity, illiquidity and commission and fee structure of variable annuities and similar products, investors should be provided the additional protections of the Best Interest Contract Exemption for transactions involving these investments.
In this regard, commenters argued that variable annuities and investment company securities are similar to the other assets listed in the definition of assets in the proposed Best Interest Contract Exemption in that their value may fluctuate on a daily basis and, as such, variable annuities and investment company securities should be treated consistently with other investments in securities. The comments stated that the Best Interest Contract Exemption would offer protection and a means of redress for investors due to the conflicts of interest created by the commission and fee structure of variable annuities.
In addition to comments on variable annuities, some commenters argued that due to their complexity, fee structure, inherent conflicts of interest, as well as lack of regulation under the securities laws, indexed annuities similarly require heightened regulation. Consistent with this position, commenters argued that indexed annuities should be treated the same as variable annuities under the Department's exemptions. Additionally, one commenter noted that the compensation structure for indexed annuities is similar to that of variable annuities, raising comparable concerns regarding conflicts of interest. As a result, commenters said that recommendations of such products by fiduciaries should be subject to the same protective conditions as those proposed for variable annuities under the Best Interest Contract Exemption.
The Department understands that like Fixed Rate Annuity Contracts, indexed annuities are generally not regulated as registered securities under federal securities laws. Although the SEC issued a rule in 2008 that would have treated certain indexed annuities as securities, the rule was vacated by court order
Despite the fact that the proposed amendment to PTE 84-24 focused on the distinction between exempt and non-exempt securities under federal securities law, some commenters asserted that indexed annuities should also be covered under the Best Interest Contract Exemption in order to enhance retirement investor protection in an area lacking sufficient protections for investors in tax qualified accounts. A commenter argued that IRA owners need greater protections when investing in indexed annuities precisely because such products are not regulated as securities and therefore do not fall within FINRA's jurisdiction.
A few commenters cited statements by the SEC staff, FINRA and the North American Securities Administrators Association, regarding indexed annuities. The statements, quoted at length above, touch upon the risks, complexity and sales tactics associated with these products. In particular, the SEC staff pointed to the possibility of significant surrender charges, and the fact that the insurance company may be permitted to change the terms of the annuity on an annual basis, adversely affecting the return. As noted, the FINRA Investor Alert, “Equity-Indexed Annuities: A Complex Choice,” states that equity-indexed annuities “are anything but easy to understand.”
In this regard, a commenter further argued that there is no difference between the conflicted compensation arrangements of variable annuity contracts and indexed annuity contracts and asserted that typically compensation paid to advisers for sales of indexed annuities is higher than other products, creating an incentive to sell indexed annuities. The commenter noted that requiring indexed annuity transactions to occur under the Best Interest Contract Exemption would result in firms developing policies and procedures that would protect retirement investors from compensation practices that encourage recommendations not in the investor's best interest. The commenter argued that the lack of regulation of indexed annuities under the securities laws supports the argument for applying expanded safeguards under the Best Interest Contract Exemption for recommendations involving these products.
The industry generally opposed the approach taken in the proposal to revoke the relief historically provided by PTE 84-24 for variable annuities and other annuities that are non-exempt securities under federal securities laws. They wrote that the insurance industry should be able to rely on PTE 84-24 for all insurance products, rather than bifurcating relief between two exemptions. A number of commenters asserted that variable annuity contracts were more closely aligned with insurance products than with securities, and that variable annuities were not just a “package” of mutual funds. Commenters argued that, like fixed annuities, variable annuities provide retirement income guarantees and insurance guarantees that distinguish the annuities from other investments that lack such guarantee, and therefore fixed and variable annuities should be treated the same under the Department's exemptions. One commenter stated that federal securities laws recognize that variable annuities are different from mutual funds and the laws accommodate these differences. These commenters disputed the suggestion that the distinction between annuities that are exempt securities and non-exempt securities merited different treatment in the exemptions.
In this regard, some industry commenters focused on indexed annuities, in particular. These commenters asserted that fixed indexed annuities and fixed annuities are identical insurance products except for the method of calculating interest credited to the contract. They said that indexed annuities are treated the same as other fixed annuities under state insurance law and federal securities law, and stated that indexed annuities can offer the same income, insurance and contractual guarantees as fixed annuities. Moreover, some commenters noted that significant investment risk is borne by the insurer and there is no risk of principal loss, assuming that the investor does not incur surrender charges.
Commenters also emphasized the benefit, for compliance purposes, of having one exemption for all insurance products, including variable annuities and indexed annuities. These commenters highlighted the importance of lifetime income options, and the ways the Department, the Treasury Department and the IRS have worked to make annuities more accessible to retirement investors. Many of these commenters took the position that the Department's proposed approach would undermine these efforts by hindering access to lifetime income products by plans and IRAs.
Commenters said that some aspects of the proposed Best Interest Contract Exemption would exacerbate this problem. In particular, they expressed uncertainty as to the extent to which the Best Interest Contract Exemption permitted commission-based compensation for fiduciary advisers. By comparison, it was maintained, PTE 84-24 clearly referenced the receipt of a commission. There were also concerns about the disclosure requirements and certain other requirements as applicable to the insurance industry. Commenters said the burden of complying with the Best Interest Contract Exemption would cause some in the insurance industry to leave the market. Many commenters took the position that existing regulation of these products is sufficient.
After consideration of all of the comments, the Department has made revisions to both PTE 84-24 and the final Best Interest Contract Exemption as applicable to annuity contracts. Under this final amendment to PTE 84-24, the scope of covered annuity transactions is limited to plan and IRA transactions involving Fixed Rate Annuity Contracts. Accordingly, PTE 84-24 now provides a streamlined exemption for relatively straightforward guaranteed lifetime income products such as immediate and deferred income annuities, while leaving coverage of variable annuity contracts, indexed annuity contracts, and similar annuity contracts, to the Best Interest Contract Exemption. Based upon its significant concerns about the complexity, risk, and conflicts of interest associated with recommendations of variable annuity contracts, indexed annuity contracts and similar contracts, the final exemption treats these transactions the
At the same time, the Department revised the Best Interest Contract Exemption in ways that accommodate fiduciary recommendations for both plans and IRAs to purchase variable annuities and indexed annuities. The final Best Interest Contract Exemption contains more streamlined disclosure conditions that are applicable to a wide variety of products. The pre-transaction disclosure does not require a projection of the total cost of the recommended investment, which commenters indicated would be difficult to provide in the insurance context. The final exemption does not include the proposed data collection requirement, which also posed problems for insurance products, according to commenters. Further, the language of the final exemption was adjusted to address industry concerns in other places and the preamble provides interpretations to address the particular questions and concerns raised by the insurance industry. For example, the preamble of the Best Interest Contract Exemption makes clear that commissions are permitted under the exemption and that annuity commissions do not necessarily violate the Impartial Conduct Standards. In addition, the “reasonable compensation” standard adopted in the final exemption addresses comments from the insurance industry. Section IV of that exemption additionally provides specific guidance on the satisfaction of the Best Interest standard by proprietary product providers. Commenters stressed a desire for one exemption covering all insurance and annuity products; the final Best Interest Contract Exemption does just that, while ensuring a greater level of protection to vulnerable retirement investors.
In light of the ways in which these products have developed, and the concerns articulated by other regulators and the commenters regarding the complexity, risks, and enhanced conflicts of interest associated with them, the Department determined that the conditions of PTE 84-24 are insufficiently protective to safeguard the interests of plans and IRAs investing in these products. The Best Interest Contract Exemption's conditions, such as a contractual commitment to adhere to the Impartial Conduct Standards when transacting with IRA owners, the required adoption of and adherence to anti-conflict policies and procedures, and the required disclosures of conflicts of interest, are necessary to address dangerous conflicts present in transactions involving these products. Moreover, this final amendment and partial revocation of PTE 84-24 creates a uniform approach for plans and IRAs under which indexed annuities and variable annuities can be recommended only under the same protective conditions as other investments covered in the Best Interest Contract Exemption and avoids creating a regulatory incentive to preferentially recommend indexed annuities. As a final issue of scope, one commenter stated the Department should add an exclusion to the Regulation that would apply to the recommendation of a Qualified Longevity Annuity Contract as described in Treasury Regulation sections 1.401(a)(9) and 1.408, provided the disclosure requirements found in Treasury Regulation section 1.408-6 are satisfied and any disclosure requirements under applicable state insurance law are met. As an alternative, the commenter recommended that the Department should exclude recommendations on Qualified Longevity Annuity Contracts from PTE 84-24's Impartial Conduct Standards and the recordkeeping requirements.
The Department considered this request but declined to single out Qualified Longevity Annuity Contracts for unique treatment under PTE 84-24. Regardless of the merit of any particular investment in such an annuity, the Department is mindful that the exemption permits investment advice fiduciaries to make recommendations and receive compensation pursuant to conflicted arrangements. The conditions of PTE 84-24, as amended, are streamlined to promote access to such lifetime income products, but the Impartial Conduct Standards and recordkeeping requirements are critical conditions aimed at ensuring that all retirement investors receive basic fiduciary protections, regardless of the particular product the adviser chooses to recommend. The mere fact that a recommended investment is a Qualified Longevity Annuity Contract does not guarantee that the recommendation is prudent, unbiased, or in the customer's best interest. An important goal of this regulatory project is to ensure that all retirement investors receive advice that adheres to these basic standards of prudence, loyalty, honesty, and reasonable compensation.
For the reader's convenience, the chart attached as Appendix I describes some of the basic features and attributes of the different categories of annuities discussed above.
The proposed amendment and partial revocation also applied to investment company transactions historically covered under the exemption. Under the proposed amendment, receipt of compensation by investment company principal underwriters in connection with IRA transactions involving investment company securities would no longer be permitted under PTE 84-24.
A few commenters addressed this aspect of the proposal. The commenters indicated the exemption had long been used by broker-dealers for mutual fund transactions and questioned the basis for the revocation of such relief. In this regard, relief under the exemption was historically limited by the Department to investment company principal underwriters “in the ordinary course of [their] business” as principal underwriters.
One commenter requested that the Department extend relief under the exemption to include Mutual Fund Commissions paid to principal underwriters and their agents. The Department has not revised the exemption in this respect because the
One commenter suggested that “sophisticated” IRA owners should not be subject to the exemption's amendments, but instead should be able to use the exemption under the same conditions applicable to plans. The commenter suggested the Department could rely on the federal securities laws, specifically the accredited investor rules, which the commenter said are commonly used and understood and identify investors who may be financially sophisticated. In response, the Department notes that, as amended, the exemption's conditions do apply equally to plans and IRAs in the context of Fixed Rate Annuity Contracts. With respect to investment company transactions, the Department declines to provide a special rule based on the accredited investor rules or similar criteria. As explained above, the Regulation describes circumstances under which a person will not be a fiduciary when he or she engages in a transaction with an independent plan or IRA fiduciary with financial expertise. This approach in the Regulation does not extend to individual IRA owners or plan participants and beneficiaries. Individuals with large account balances may have reached that point through years of hard work, careful savings, the rollover of an account balance from a defined benefit plan, or from an inheritance. None of these paths necessarily correlate with financial expertise or sophistication, or suggest a reduced need for stringent fiduciary protections. Although relief is no longer available under this exemption for investment company securities transactions with IRA owners, individual plan participants or beneficiaries, the Best Interest Contract Exemption is available for such transactions. The Best Interest Contract Exemption was designed for IRA owners and other investors that rely on fiduciary investment advisers in the retail marketplace.
One commenter indicated that the exemptions uniformly failed to provide relief for non-proprietary mutual fund transactions sold to plans on an agency basis. The Department does not agree with this comment. The existing exemption, PTE 86-128
A new Section II of the exemption requires that insurance agents, insurance brokers, pension consultants, insurance companies and investment company principal underwriters that are fiduciaries engaging in the exempted transactions comply with fundamental Impartial Conduct Standards.
Generally stated, the Impartial Conduct Standards require that when insurance agents, insurance brokers, pension consultants, insurance companies or investment company principal underwriters provide fiduciary investment advice, they act in the plan's or IRA's Best Interest, and not make misleading statements to the plan or IRA about recommended transactions. As defined in the exemption, the insurance agent or broker, pension consultant, insurance company or investment company principal underwriter act in the Best Interest of a plan or IRA when they act “with care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances and needs of the Plan or IRA, without regard to the financial or other interests of the fiduciary, any affiliate or other party.”
It is important to note that, unlike some of the other exemptions finalized today in this issue of the
The Impartial Conduct Standards represent fundamental obligations of fair dealing and fiduciary conduct. The concepts of prudence and undivided loyalty are deeply rooted in ERISA and the common law of agency and trusts.
The Department received many comments on the proposed Impartial Conduct Standards. A number of commenters focused on the Department's authority to impose the Impartial Conduct Standards as conditions of this exemption. Commenters' arguments regarding the Impartial Conduct Standards as applicable to IRAs and non-ERISA plans were based generally on the fact that the standards, as noted above, are consistent with longstanding principles of prudence and loyalty set forth in ERISA section 404, but which have no counterpart in the Code. Commenters took the position that because Congress did not choose to impose the standards of prudence and loyalty on fiduciaries with respect to IRAs and non-ERISA plans, the Department exceeded its authority in proposing similar standards as a condition of relief in a prohibited transaction exemption.
With respect to ERISA plans, commenters stated that Congress' separation of the duties of prudence and loyalty (in ERISA section 404) from the prohibited transaction provisions (in ERISA section 406), showed an intent that the two should remain separate. Commenters additionally questioned why the conduct standards were necessary for ERISA plans, when such plans already have an enforceable right to fiduciary conduct that is both prudent and loyal. Commenters asserted that imposing the Impartial Conduct Standards as conditions of the exemption created strict liability for prudence violations.
Some commenters additionally took the position that Congress, in the Dodd-Frank Act, gave the SEC the authority to establish standards for broker-dealers and investment advisers and therefore, the Department did not have the authority to act in that area. The Department disagrees that the exemption exceeds its authority. The Department has clear authority under ERISA section 408(a) and the Reorganization Plan
The Impartial Conduct Standards represent, in the Department's view, baseline standards of fundamental fair dealing that must be present when fiduciaries make conflicted investment recommendations to retirement investors. After careful consideration, the Department determined that relief should be provided to investment advice fiduciaries receiving conflicted compensation only if such fiduciaries provided advice in accordance with the Impartial Conduct Standards—
These Impartial Conduct Standards are necessary to ensure that advisers' recommendations reflect the best interest of their retirement investor customers, rather than the conflicting financial interests of the advisers and their financial institutions. As a result, advisers and financial institutions bear the burden of showing compliance with the exemption and face liability for engaging in a non-exempt prohibited transaction if they fail to provide advice that is prudent or otherwise in violation of the standards. The Department does not view this as a flaw in the exemption, as commenters suggested, but rather as a significant deterrent to violations of important conditions under an exemption that accommodates a wide variety of potentially dangerous compensation practices. The Department similarly disagrees that Congress' directive to the SEC in the Dodd-Frank Act limits its authority to establish appropriate and protective conditions in the context of a prohibited transaction exemption. Section 913 of that Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers.
Some commenters suggested that it would be unnecessary to impose the Impartial Conduct Standards on advisers with respect to ERISA plans because fiduciaries to these Plans already are required to adhere to these obligations under the provisions of the statute. The Department considered this comment but has determined not to eliminate the conduct standards as conditions of the exemption for ERISA plans. One of the Department's goals is to ensure equal footing for all retirement investors. The SEC staff Dodd-Frank Study found that investors were frequently confused by the differing standards of care applicable to broker-dealers and registered investment advisers. The Department hopes to
Moreover, inclusion of the standards in the exemption's conditions adds an important additional safeguard for ERISA and IRA investors alike because the party engaging in a prohibited transaction has the burden of showing compliance with an applicable exemption, when violations are alleged.
A few commenters also expressed concern that the requirements of this exemption, as proposed, would interfere with state insurance regulatory programs. In particular, one commenter asserted that the Impartial Conduct Standards could usurp state insurance regulations. The Department does not agree with these comments. In addition to consulting with state insurance regulators and the NAIC as part of this project, the Department has also reviewed NAIC model laws and regulations and state reactions to those models in order to ensure the requirements of this exemption work cohesively with the requirements currently in place. The Department has crafted the exemption so that it will work with, and complement, state insurance regulations. In addition, the Department confirms that it is not its intent to preempt or supersede state insurance law and enforcement, and that state insurance laws remain subject to the ERISA section 514(b)(2)(A) savings clause.
Several commenters also raised questions about the role of the McCarran-Ferguson Act
Other commenters generally asserted that some of the exemption's terms were too vague and would result in the exemption failing to meet the “administratively feasible” requirement under ERISA section 408(a) and Code section 4975(c)(2). The Department disagrees with these commenters' suggestion that ERISA section 408(a) and Code section 4975(c)(2) fail to be satisfied by the exemption's principles-based approach or that the exemption's standards are unduly vague. It is worth repeating that the Impartial Conduct Standards are building on concepts that are longstanding and familiar in ERISA and the common law of trusts and agency. Far from requiring adherence to novel standards with no antecedents, these conditions primarily require adherence to fundamental obligations of fair dealing and fiduciary conduct. In addition, the exemption and this preamble includes a section, below, designed to provide specific interpretations and responses to issues raised in connection with the Impartial Conduct Standards.
In this regard, some commenters focused their comments on the Impartial Conduct Standards in the proposed Best Interest Contract Exemption and other proposals, as opposed to the proposed amendment to PTE 84-24. The Department determined it was important that the provisions of the exemptions, including the Impartial Conduct Standards, be uniform and compatible across exemptions. For this reason, the Department considered all comments made on any of the exemption proposals on a consolidated basis, and made corresponding changes across the projects. For ease of use, this preamble includes the same general discussion of comments as in the Best Interest Contract Exemption, despite the fact that some comments discussed below were not made directly with respect to this exemption.
Under Section II(a), the insurance agent or broker, pension consultant, insurance company or investment company principal underwriter must comply with a Best Interest standard when providing investment advice to the plan or IRA. The exemption provides that these parties act in the best interest of the plan or IRA when they:
The Best Interest standard set forth in the amended exemption is based on longstanding concepts derived from ERISA and the law of trusts. It is meant to express the concept, set forth in ERISA section 404, that a fiduciary is required to act “solely in the interest of the participants . . . with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent man acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims.” Similarly, both ERISA section 404(a)(1)(A) and the trust-law duty of loyalty require fiduciaries to put the interests of trust beneficiaries first, without regard to the fiduciaries' own self-interest. Under this standard, for example, an investment advice fiduciary, in choosing between two investments, could not select an investment because it is better for the investment advice fiduciary's bottom line even though it is a worse choice for the plan or IRA.
A wide range of commenters indicated support for a broad “best interest” standard. Some comments indicated that the Best Interest standard is consistent with the way advisers provide investment advice to clients today. However, a number of these commenters expressed misgivings as to the definition used in the proposed exemption, in particular, the “without regard to” formulation. The commenters indicated uncertainty as to the meaning of the phrase, including: whether it permitted the investment advice fiduciary to be paid; whether it permitted investment advice on proprietary products; and whether it effectively precluded recommending annuities if they generate higher commissions than mutual funds.
Other commenters asked that the exemption use a different definition of best interest, or simply use the exact language from ERISA's section 404 duty of loyalty. Others suggested definitional approaches that would require that the investment advice fiduciary “not subordinate” their customers' interests to their own interests, or that the investment advice fiduciary “put their customers' interests ahead of their own interests,” or similar constructs.
FINRA suggested that the federal securities laws should form the foundation of the Best Interest standard. Specifically, FINRA urged that the best interest definition in the exemption incorporate the “suitability” standard applicable to investment advisers and broker-dealers under federal securities laws. According to FINRA, this would facilitate customer enforcement of the Best Interest standard by providing adjudicators with a well-established basis on which to find a violation.
Other commenters found the Best Interest standard to be an appropriate statement of the obligations of a fiduciary investment advice provider and believed it would provide concrete protections against conflicted recommendations. These commenters asked the Department to maintain the best interest definition as proposed. One commenter wrote that the term “best interest” is commonly used in connection with a fiduciary's duty of loyalty and cautioned the Department against creating an exemption that failed to include the duty of loyalty. Others urged the Department to avoid definitional changes that would reduce current protections to plans and IRAs. Some commenters also noted that the “without regard to” language is consistent with the recommended standard in the SEC staff Dodd-Frank Study, and suggested that it had the added benefit of potentially harmonizing with a future securities law standard for broker-dealers.
The final exemption retains the best interest definition as proposed, with minor adjustments. The first prong of the standard was revised to more closely track the statutory language of ERISA section 404(a) and is consistent with the Department's intent to hold investment advice fiduciaries to a prudent investment professional standard. Accordingly, the definition of best interest now requires advice that reflects “the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person
The Department has not specifically incorporated the suitability obligation as an element of the Best Interest standard, as suggested by FINRA but many aspects of suitability are also elements of the Best Interest standard. An investment recommendation that is not suitable under the securities laws would not meet the Best Interest standard. Under FINRA's Rule 2111(a) on suitability, broker-dealers “must have a reasonable basis to believe that a recommended transaction or investment strategy involving a security or securities is suitable for the customer.” The text of rule 2111(a), however, does not do any of the following: reference a best interest standard, clearly require brokers to put their client's interests ahead of their own, expressly prohibit the selection of the least suitable (but more remunerative) of available investments, or require them to take the kind of measures to avoid or mitigate conflicts of interests that are required as conditions of this exemption.
The Department recognizes that FINRA issued guidance on Rule 2111 in which it explains that “in interpreting the suitability rule, numerous cases explicitly state that a broker's recommendations must be consistent with his customers' best interests,” and provided examples of conduct that would be prohibited under this standard, including conduct that this exemption would not allow.
The Best Interest standard, as set forth in the exemption, is intended to effectively incorporate the objective standards of care and undivided loyalty that have been applied under ERISA for more than 40 years. Under these objective standards, the investment advice fiduciary must adhere to a professional standard of care in making investment recommendations that are in the plan's or IRA's best interest. The investment advice fiduciary may not
Several commenters requested additional guidance on the Best Interest standard. Investment advice fiduciaries that are concerned about satisfying the standard may wish to consult the policies and procedures requirement in Section II(d) of the Best Interest Contract Exemption. While these policies and procedures are not a condition of the PTE 84-24, they may provide useful guidance for financial institutions wishing to ensure that individual advisers adhere to the Impartial Conduct Standards. The preamble to the Best Interest Contract Exemption provides examples of policies and procedures prudently designed to ensure that advisers adhere to the Impartial Conduct Standards. The examples are not intended to be exhaustive or mutually exclusive, and they range from examples that focus on eliminating or nearly eliminating compensation differentials to examples that permit, but police, the differentials.
A few commenters also questioned the requirement in the Best Interest standard that recommendations be made without regard to the interests of “
Other commenters asked for confirmation that the Best Interest standard is applied based on the facts and circumstances as they existed at the time of the recommendation, and not based on hindsight. Consistent with the well-established legal principles that exist under ERISA today, the Department confirms that the Best Interest standard is not a hindsight standard, but rather is based on the facts as they existed at the time of the recommendation. Thus, the courts have evaluated the prudence of a fiduciary's actions under ERISA by focusing on the process the fiduciary used to reach its determination or recommendation—whether the fiduciaries, “at the time they engaged in the challenged transactions, employed the proper procedures to investigate the merits of the investment and to structure the investment.”
This is not to suggest that the ERISA section 404 prudence standard or the Best Interest standard are solely procedural standards. Thus, the prudence obligation, as incorporated in the Best Interest standard, is an objective standard of care that requires the fiduciary relying on the exemption to investigate and evaluate investments, make recommendations, and exercise sound judgment in the same way that knowledgeable and impartial professionals would. “[T]his is not a search for subjective good faith—a pure heart and an empty head are not enough.”
The Department additionally confirms its intent that the phrase “without regard to” be given the same meaning as the language in ERISA section 404 that requires a fiduciary to act “solely in the interest of” participants and beneficiaries, as such standard has been interpreted by the Department and the courts. Therefore, the standard would not, as some commenters suggested, foreclose the investment advice fiduciary from being paid. In response to concerns about the satisfaction of the standard in the context of proprietary product recommendations, the Department has provided additional clarity and specific guidance in the preamble on this issue.
In response to commenter concerns, the Department also confirms that the Best Interest standard does not impose an unattainable obligation on investment advice fiduciaries to somehow identify the single “best” investment for the plan or IRA out of all the investments in the national or international marketplace, assuming such advice were even possible. Instead, as discussed above, the Best Interest standard set out in the exemption, incorporates two fundamental and well-established fiduciary obligations: the duties of prudence and loyalty. Thus, the advice fiduciary's obligation under the Best Interest standard is to give advice that adheres to professional standards of prudence, and to put the plan's or IRA's financial interests in the driver's seat, rather than the competing interests of the advice fiduciary or other parties.
To the extent parties want more certainty as to compliance with the Impartial Conduct Standards, the Department refers them to examples provided in the Best Interest Contract Exemption's preamble discussion of policies and procedures that could be adopted to support compliance with the Impartial Conduct Standards.
Finally, in response to questions regarding the extent to which this or other provisions impose an ongoing monitoring obligation on fiduciaries, the text does not impose a monitoring requirement. As noted in the preamble to the Best Interest Contract Exemption, adherence to a Best Interest standard does not mandate an ongoing or long-term relationship, but instead leaves that to agreements, arrangements, and
The second Impartial Conduct Standard, set forth in Section II(b), requires that
The statements by the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter about recommended investments, fees, Material Conflicts of Interest, and any other matters relevant to a Plan's or IRA owner's investment decisions, are not materially misleading at the time they are made.
Section II(b) continues, “[f]or this purpose, the insurance agent's or broker's, pension consultant's, insurance company's or investment company Principal Underwriter's failure to disclose a Material Conflict of Interest relevant to the services it is providing or other actions it is taking in relation to a Plan's or IRA owner's investment decisions is considered a misleading statement.” In response to commenters, the Department adjusted the text to clarify that the standard is measured at the time of the representations,
Some comments focused on the proposed definition of Material Conflict of Interest. As proposed, a Material Conflict of Interest was defined to exist when a person has a financial interest that could affect the exercise of its best judgment as a fiduciary in rendering advice to a plan or IRA. Some commenters took the position that the proposal did not adequately explain the term “material” or incorporate a “materiality” standard into the definition. A commenter wrote that the proposed definition was so broad it would be difficult for financial institutions to comply with the various aspects of the exemption related to Material Conflicts of Interest, such as provisions requiring disclosures of Material Conflicts of Interest.
Another commenter indicated that the Department should not use the term “material” in defining conflicts of interest. The commenter believed that it could result in a standard that was too subjective from the perspective of the investment advice fiduciary, and could undermine the protectiveness of the exemption.
After consideration of the comments, the Department adjusted the definition of Material Conflict of Interest to provide that a material conflict of interest exists when a fiduciary has a “financial interest that
The Department did not accept certain other comments, however. One commenter requested that the Department add a qualifier providing that the standard is violated only if the statement was “reasonably relied” on by the retirement investor. The Department rejected the comment. The Department's aim is to ensure that investment advice fiduciaries uniformly adhere to the Impartial Conduct Standards, including the obligation to avoid materially misleading statements, when they give advice.
One commenter asked the Department to require only that the adviser “reasonably believe” the statements are not misleading. The Department is concerned that this standard too could undermine the protections of this condition by requiring retirement investors or the Department to prove the adviser's actual belief rather than focusing on whether the statement is objectively misleading. However, to address commenters' concerns about the risks of engaging in a prohibited transaction, as noted above, the Department has clarified that the standard is measured at the time of the representations and has added a materiality standard. The Department believes that plans and IRAs are best served by statements and representations that are free from material misstatements. Investment advice fiduciaries best avoid liability—and best promote the interests of plans and IRAs—by making accurate communications a consistent standard in all their interactions with their customers.
Another commenter suggested that the Department adopt FINRA's “Frequently Asked Questions regarding Rule 2210” in this connection.
Some commenters asserted that some of the exemption's terms were too vague and would result in the exemption failing to meet the “administratively feasible” requirement under ERISA section 408(a) and Code section 4975(c)(2). The Department disagrees with these commenters' suggestion that ERISA section 408(a) and Code section 4975(c)(2) fail to be satisfied by this exemption's principles-based approach, or that the exemption's standards are unduly vague. It is worth repeating that the Impartial Conduct Standards are built on concepts that are longstanding and familiar in ERISA and the common law of trusts and agency. Far from requiring adherence to novel standards with no antecedents, the exemption primarily requires adherence to basic well-established obligations of fair dealing and fiduciary conduct. This section is designed to provide specific interpretations and responses to a number of specific issues raised in connection with a number of the Impartial Conduct Standards.
In this regard, the Department received several comments regarding the sale of proprietary insurance products. Generally, commenters expressed concern that the proposed amendments to the exemption appeared to be setting barriers to the sale of proprietary products, and the receipt of differential compensation such as commissions and health benefits and the ability to earn a profit inherent in such sales. Commenters maintained that the advantages of a proprietary sales force include the in-depth training received by such agents on the proprietary products. Comments requested that the Department clarify whether PTE 84-24 continues to cover the sale of proprietary products and the receipt of differential compensation as a result of the sale.
In response to commenters, the Department specifically notes that the Impartial Conduct Standards (either as proposed or finalized) are not properly
The Impartial Conduct Standards also are not properly interpreted to foreclose the receipt of commissions or other transaction-based payments. To the contrary, a significant purpose of granting this amended exemption is to continue to permit such payments, as long as investment advice fiduciaries are willing to adhere to Best Interest standards. In particular, the Department confirms that the receipt of a commission on an annuity product does not result in a per se violation of any of the Impartial Conduct Standards or other conditions of the exemption, even though such a commission may be greater than the commission on a mutual fund purchase of the same amount as long as the commission meets the requirement of “reasonable compensation” and other applicable conditions.
Several commenters stated the Impartial Conduct Standards could be interpreted to exclude any compensation other than commissions paid to the agent, such as employee benefits for agents selling the insurance companies' proprietary products and meeting production goals. The commenters pointed out that many insurance companies use a business model whereby their agents are statutory employees under the Code. In order to receive employee benefits, the agents must predominately sell the employing insurance companies' products. Commenters argued that the provision of employee benefits such as health care and retirement benefits does not create a conflict of interest.
The Department did not intend the exemption to effectively prohibit the receipt of employee benefits by statutory employees. The final exemption makes clear in Section I(b)(1) that such payments can be provided. Additionally, the Department confirms that the receipt by an insurance agent or broker of reasonable and customary deferred compensation or subsidized health or pension benefit arrangements such as typically provided to an “employee” as defined in Code section 3121(d)(3) does not, in and of itself, violate the Impartial Conduct Standards. However, insurance companies providing such payments should take special care that the payments do not undermine such insurance agents' or brokers' ability to adhere to the standards.
Some commenters urged the Department to state that fiduciary status does not apply to the manufacturer company that issues an annuity, insurance or investment product in the ordinary course of its business so long as the company and its employees do not render investment advice for a fee or represent that it is acting as a fiduciary. Another commenter expressed the opinion that the sale of proprietary products should not in and of itself create a fiduciary relationship. The Department responds that application of the Regulation determines the status of investment advice fiduciaries. This exemption provides relief that is necessary for parties with fiduciary status under the Regulation. However, the Department notes that the Best Interest Contract Exemption requires that a financial institution (which could be an insurer) acknowledge fiduciary status, ensure that an appropriate supervisory structure is in place to implement policies and procedures, police incentives, and generally oversee the conduct of individual advisers, so that the conduct comports with the fiduciary norms required in the Impartial Conduct Standards.
While PTE 84-24 provides an exemption for the specified parties to receive commissions in connection with the purchase of insurance or annuity contracts and investment company securities, it did not contain a separate definition of commission. The Department has viewed the exemption as limited to sales commissions on insurance or annuity contracts and investment company securities, as opposed to any related or alternative forms of compensation. This exemption was originally granted in 1977, and the conditions were crafted with simple commission payments in mind. In the interim, the exemption was not amended or formally interpreted to broadly permit more types of payments. To provide certainty with respect to the payments permitted by the exemption, however, the amended exemption now provides a specific definition of Insurance Commission and Mutual Fund Commission.
These definitions should dispel any concern that commissions are no longer permitted under the exemption, or that the Impartial Conduct Standards cannot be satisfied with respect to such commission payments. This exemption remains specifically available for commissions as they are defined herein. Moreover, as noted above, the Department confirms that the receipt of a commission on an annuity product does not, in and of itself, violate any of the Impartial Conduct Standards, even though such a commission would be greater than the commission on a mutual fund purchase of the same amount.
In the final amendment, Section VI(f) defines an Insurance Commission to mean a sales commission paid by the insurance company to the insurance agent, insurance broker or pension consultant for the service of effecting the purchase of an insurance or annuity contract, including renewal fees and trailers that are paid in connection with the purchase of the insurance or annuity contract.
The definition of Insurance Commission in the final amendment was revised slightly from the proposed amendment. As proposed, the definition excluded “revenue sharing payments, administrative fees or marketing payments,
It was not the Department's intent with respect to the Insurance Commission definition to disrupt the practice of paying commissions through a third party, such as an independent marketing organization. Accordingly the final amendment does not include the language “payments from parties other than the insurance company or its Affiliates” from the definition. The Department nevertheless cautions that the change does not extend relief under the exemption to revenue sharing or other payments not within the definition of Insurance Commission.
A few commenters have requested that the Department clarify whether or not “gross dealer concessions” or “overrides” would be considered Insurance Commissions under the new definition. The commenters explained that “gross dealer concessions” and “overrides” are commission payments made to someone who oversees the agent that is working directly with the customer. The Department responds that, as these types of payments generally represent a portion of the overall commission payment associated with an insurance or annuity transaction, they are included within the amended exemption's definition of Insurance Commission. In connection with this clarification, however, the Department revised the disclosure conditions to reflect that both the agent's or broker's commission and the gross dealer concession or override must be disclosed if the exemption is relied upon for such payments.
Many of the comments received from the industry expressed the opinion more generally that the proposed definitions of Insurance Commission and Mutual Fund Commission were too narrow and should be expanded to include the receipt of all types of payments for all sales of annuities and mutual funds such as revenue sharing payments, administrative fees, marketing fees and 12b-1 fees. Commenters stated that due to the increased disclosures required by the Department and the Securities and Exchange Commission's simplification of the disclosures for 12b-1 fees and other mutual fund fees in prospectuses there is no reason why any form of disclosed and agreed upon compensation should not be allowed. Some commenters stated that the definition of Insurance Commission in the proposal would create uncertainty in the industry as to what is permissible compensation under PTE 84-24 and may cause reduction in sales of annuity products that provide valuable lifetime income benefits. These commenters argued that the exclusion of revenue sharing payments, administrative fees or marketing payments is inconsistent with current business models and would create ambiguity with respect to long standing industry practices under which such payments are received. They stated that such restrictions would not be necessary in light of the Best Interest standard.
Some commenters represented that revenue sharing payments are received by the insurance company or financial institution, itself, as opposed to the individual adviser, and are used to offset expenses related to servicing the annuity contract or mutual fund account and therefore do not create a conflict of interest at the agent level or point of sale. Additionally, one commenter asserted that revenue sharing and marketing fees are not retained but instead credited back on a daily basis to the insurance company separate account to offset other fees of the separate account and therefore are credited back to the participants invested in that separate account. A few other commenters argued that the conflicts of interest arising from revenue sharing, administrative fees and marketing fees can be addressed by only allowing the payments when they are paid on the basis of total aggregate sales and are not linked to a specific investment product.
The Department was not persuaded by these comments to expand the definitions of Insurance Commission or Mutual Fund Commission beyond the historical intent of the exemption. The Department specifically provided relief for such payments in the Best Interest Contract Exemption. That exemption addresses the payment structures that have developed since PTE 84-24 was originally adopted. The Department intends that relief for such payments be provided through the Best Interest Contract Exemption on the grounds that that exemption was drafted to specifically address the unique conflicts of interest that are created by these types of payments.
In addition, it is the Department's understanding that third party payments such as revenue sharing and 12b-1 fees generally are not paid in connection with the Fixed Rate Annuity Contracts that are covered by the amended exemption. The expanded definitions are, therefore, unnecessary because the investments that would generate such payments are covered by the Best Interest Contract Exemption, rather than this exemption.
The Department does not believe this exemption was properly interpreted over the years to provide relief for payments such as administrative services fees, which are not akin to a commission. No determination has been made that the conditions of the exemption are protective in the context of such payments. Without further information on these fees, or suggested additional conditions addressed at these types of payments, the Department declines to take such an expansive approach to relief from the prohibited transaction rules under the terms of this exemption. For parties who are interested in broader relief in this area, the Best Interest Contract Exemption is available.
Section III(c) of the amended exemption imposes a reasonable compensation standard as a condition of the exemption. The requirement is that:
The combined total of all fees and compensation received by the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter for their services does not exceed reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
The language of the requirement differs from the definition in the proposal, but it is not intended as a substantive change. The language in the proposal provided:
The combined total of all fees, Insurance Commissions, Mutual Fund Commissions and other consideration received by the insurance agent or broker, pension consultant, insurance company, or investment company Principal Underwriter:
(1) For the provision of services to the plan or IRA; and
(2) In connection with the purchase of insurance or annuity contracts or securities issued by an investment company is not in excess of “reasonable compensation” within the contemplation of section 408(b)(2) and 408(c)(2) of the Act and sections 4975(d)(2)and 4975(d)(10) of the Code. If such total is in excess of “reasonable compensation,” the “amount involved” for purposes of the civil penalties of section 502(i) of the Act and the excise taxes imposed by section 4975 (a) and (b) of the Code is the amount of compensation in excess of “reasonable compensation.”
The language was changed in the amendment to correspond to the same provision in the Best Interest Contract Exemption. Commenters indicated that there should be a common reasonable compensation standard across the exemptions. Commenters on the Best
More generally, commenters asked that the Department provide more certainty as to the meaning of the reasonable compensation standard. There was concern that the standard could be applied retroactively rather than based on the parties' reasonable beliefs as to the reasonableness of the compensation at the time of the recommendation. Commenters also indicated uncertainty as to how to comply with the condition and asked whether it would be necessary to survey the market to determine market rates. Some commenters requested that the Department include the words “and customary” in the reasonable compensation definition, to specifically permit existing compensation arrangements. One commenter raised the concern that the reasonable compensation determination raised antitrust concerns because it would require investment advice fiduciaries to agree upon a market rate and result in anti-competitive behavior.
Commenters also asked how the standard would be satisfied for Proprietary Products, particularly insurance and annuity contracts. In such a case, commenters indicated, the retirement investor is not only paying for a service, but also for insurance guarantees; a standard that appeared to focus solely on services appeared inapposite. Commenters asked about the treatment of the insurance company's spread, which was described, in the case of a fixed annuity, or the fixed component of a variable annuity, as the difference between the fixed return credited to the contract holder and the insurer's general account investment experience. One commenter indicated that the calculation should not include affiliates' or related entities' compensation as this would appear to put them at a comparative disadvantage.
The Department confirms that the standard is the same as the well-established requirement set forth in ERISA section 408(b)(2) and Code section 4975(d)(2), and the regulations thereunder. The reasonableness of the fees depends on the particular facts and circumstances at the time of the recommendation. Several factors inform whether compensation is reasonable including,
Some commenters suggested that the reasonable compensation determination be made by another plan fiduciary. However, the exemption (like the statutory obligation) obligates investment advice fiduciaries to avoid overcharging their plan and IRA customers, despite any conflicts of interest associated with their compensation. Fiduciaries and other service providers may not charge more than reasonable compensation regardless of whether another fiduciary has signed off on the compensation. The reasonable compensation condition has long been required under PTE 84-24 and the approach in the final amendment is consistent with other class exemptions granted and amended today. Nothing in the exemptions, however, precludes fiduciaries from seeking impartial review of their fee structures to safeguard against abuse, and they may well want to include such reviews in their policies and procedures.
Further, the Department disagrees that the requirement is inconsistent with antitrust laws. Nothing in the exemption contemplates or requires that advisers or financial institutions agree upon a price with their competitors. The focus of the reasonable compensation condition is on preventing overcharges to plans and IRAs, not promoting anti-competitive practices. Indeed, if advisers and financial institutions consulted with competitors to set prices, the agreed-upon price could well violate the condition.
In response to concerns about application of the standard to investment products that bundle together services and investment guarantees or other benefits, such as annuities, the Department responds that the reasonable compensation condition is intended to apply to the compensation received by the financial institution, adviser, and any Affiliates in same manner as the reasonable compensation condition set forth in ERISA section 408(b)(2) and Code section 4975(d)(2). Accordingly, the exemption's reasonable compensation standard covers compensation received directly from the plan or IRA and indirect compensation received from any source other than the plan or IRA in connection with the recommended transaction.
A commenter urged the Department to provide that compensation received by an Affiliate would not have to be considered in applying the reasonable compensation standard. According to the commenter, including such compensation in the assessment of reasonable compensation would place proprietary products at a disadvantage. The Department disagrees with the proposition that a proprietary product would be disadvantaged merely because more of the compensation goes to affiliated parties than in the case of competing products, which allocate more of the compensation to non-affiliated parties. The availability of the exemption, however, does not turn on how compensation is allocated between affiliates and non-affiliates. Certainly, the Department would not expect that a proprietary product would be at a disadvantage in the marketplace because it carefully ensures that the associated compensation is reasonable. Assuming the Best Interest standard is satisfied and the compensation is reasonable, the exemption should not impede the recommendation of
The Department declines suggestions to provide specific examples of “reasonable” amounts or specific safe harbors, as requested by some commenters. Ultimately, the “reasonable compensation” standard is a market based standard. At the same time, the Department is unwilling to condone all “customary” compensation arrangements and declines to adopt a standard that turns on whether the agreement is “customary.” For example, it may in some instances be “customary” to charge customers fees that are not transparent or that bear little relationship to the value of the services actually rendered, but that does not make the charges reasonable.
Section IV establishes certain conditions and limitations applicable to the transactions described in Section I(b)(1)-(4). Section IV(a) identifies certain parties that may not rely on the exemption, including discretionary trustees, plan administrators, fiduciaries expressly authorized in writing to manage, acquire or dispose of the asset of the plan or IRA on a discretionary basis, and employers of employees covered by a plan. Section IV(b) and (c) establish pre-transaction disclosures and approval requirements, and Section IV(d) indicates when repeat disclosures must be provided.
One commenter asked about the applicability of these conditions to transactions described in Section I(b)(5) and (6), which generally relate to master and prototype plan sponsors. The commenter expressed the view that these transactions should not be excluded from the conditions of Section IV.
The covered transactions described in Section I(b)(5) and (6) are narrowly tailored to apply to the provider of a master or prototype plan that receives compensation in connection with a transaction involving an insurance or Fixed Rate Annuity Contract, or investment company securities. The preamble to PTE 77-9, the predecessor of PTE 84-24, stated that the transactions are limited to the circumstances where the insurance company, investment company or investment company principal underwriter is a fiduciary or service provider to a plan solely by reason of sponsorship of a master or prototype plan but has no other relationship to the plan, such as being the investment adviser to the plan directly or through an affiliate.
Section IV(b) sets forth disclosure and consent requirements for Fixed Rate Annuity Contracts and insurance contracts. As amended, the exemption imposes the following conditions:
(b)(1) With respect to a transaction involving the purchase with Plan or IRA assets of a Fixed Rate Annuity Contract or insurance contract, or the receipt of an Insurance Commission thereon, the insurance agent or broker or pension consultant provides to an independent fiduciary with respect to the Plan, or in the case of an IRA, to the IRA owner, prior to the execution of the transaction the following information in writing and in a form calculated to be understood by a plan fiduciary or IRA owner who has no special expertise in insurance or investment matters:
(A) If the agent, broker, or consultant is an Affiliate of the insurance company whose contract is being recommended, or if the ability of the agent, broker or consultant to recommend Fixed Rate Annuity Contracts or insurance contracts is limited by any agreement with the insurance company, the nature of the affiliation, limitation, or relationship;
(B) The Insurance Commission, expressed to the extent feasible as an absolute dollar figure, or otherwise, as a percentage of gross annual premium payments, asset accumulation value or contract value, for the first year and for each of the succeeding renewal years, that will be paid directly or indirectly by the insurance company to the agent, broker, or consultant in connection with the purchase of the recommended contract, including, if applicable, separate identification of the amount of the Insurance Commission that will be paid to any other person as a gross dealer concession, override, or similar payment; and
(C) A statement of any charges, fees, discounts, penalties or adjustments which may be imposed under the recommended contract in connection with the purchase, holding, exchange, termination, or sale of the contract.
Subsection (B) of this condition was revised in several respects from the existing language of the exemption. Originally, the exemption provided that disclosure must be made of “[t]he sales commission, expressed as a percentage of gross annual premium payments for the first year and for each of the succeeding renewal years, that will be paid by the insurance company to the agent, broker or consultant in connection with the purchase of the recommended contract.” Some commenters requested that the Insurance Commission be expressed as a percentage of asset accumulation value or contract value, in addition to the gross annual premium payments. Another commenter indicated that in some cases, such as a retirement benefit contribution paid to an agent that is considered an Insurance Commission, it is difficult to represent the Insurance Commission as a percentage and therefore requested that a dollar figure be permitted. The Department accepted these comments, and indicated that all Insurance Commissions should be expressed as a dollar figure unless that is not feasible, in which case a percentage will be permitted. Expression of the Insurance Commission as a dollar amount results in an accurate, salient and simple disclosure that facilitates a clearer understanding of the conflicts associated with the investment. But where it is difficult to express Insurance Commissions in dollars, the disclosure will allow for percentage disclosures.
A commenter also questioned whether the required disclosure for commissions would encompass payments made to the agent indirectly by entities other than the insurance company. The Department revised the language of subsection (B) to indicate disclosure must be made of the Insurance Commission paid directly or indirectly by the insurance company. As explained in the definition of Insurance Commission and discussed above, the amended exemption more clearly sets forth the exemption's historical limitation to such payments.
Subsection (C) was minimally revised to provide that the exemption requires a “statement” of any charges, fees, discounts, penalties or adjustments, rather than a “description.” This change was made to ensure that the level of specificity provided by the disclosures is not limited to an unduly general narrative description but rather to a more precise statement of the amounts of these charges, fees, discounts, penalties or adjustments. However, the statement can reference dollar amounts, percentages, formulas, or other means reasonably designed to present materially accurate disclosure. Similar language is used in the Best Interest Contract Exemption disclosures, and the change was made to correspond to the approach in that exemption.
For consistency across exemptions, the Department made corresponding amendments to the language in Section
Regarding the disclosures, a few commenters stated that the requirement to disclose the gross annual premium payments in year 1 and in succeeding years, as well as to describe any fees, charges, penalties, discounts or adjustments under the contract, would be difficult because independent broker-dealers do not create, maintain, or compile this type of information, and would need to expend significant resources to develop systems to compile or obtain the information to be disclosed. Another commenter argued the Department should limit the disclosure of compensation to the commissions as it would be impossible to disclose all additional forms of compensation.
These disclosure requirements are not new conditions, however, but rather have been a part of this exemption since it was initially granted in 1977,
Additional clarifying changes were also made to Section IV(b)(2) which addresses approval of the transaction following receipt of the disclosure. In the amended exemption, Section IV(b)(2) provides:
Following the receipt of the information required to be disclosed in paragraph (b)(1), and prior to the execution of the transaction, the fiduciary or IRA owner acknowledges in writing receipt of the information and approves the transaction on behalf of the Plan or IRA. The fiduciary may be an employer of employees covered by the Plan but may not be an insurance agent or broker, pension consultant, or insurance company involved in the transaction (
The section in the originally granted exemption referred to acknowledgment of the disclosure and approval by an “independent fiduciary.” The language stated:
Following the receipt of the information required to be disclosed in paragraph (b)(1), and prior to the execution of the transaction, the independent fiduciary acknowledges in writing receipt of such information and approves the transaction on behalf of the plan. Such fiduciary may be an employer of employees covered by the plan, but may not be an insurance agent or broker, pension consultant or insurance company involved in the transaction. Such fiduciary may not receive, directly or indirectly (
Commenters asked for clarification of this requirement in the context of IRAs. The Department revised the language of the section to indicate that the independent fiduciary
This change addresses another issue, raised by commenters, regarding the independence requirement as applicable to IRA owners. Under the original independence requirement, the fiduciary approving the transaction may not be the insurance agent or broker, pension consultant, or insurance company involved in the transaction (or an affiliate, including a family member). The Department did not add “or IRA owner” to this independence requirement and accordingly confirms that the independence requirement does not apply to IRA owners. This allows insurance agents and brokers to recommend Fixed Rate Annuity Contracts and insurance contracts to family members and receive a commission. The Department did not make corresponding changes to Section IV(c)(2) because transactions with IRAs involving investment company securities are not covered by the exemption.
Some commenters asked for a negative consent procedure in Section IV(b)(2) in which consent could be demonstrated by a failure to object to a written disclosure. They referenced Section IV(c)(2), which is applicable to investment company transactions, and states that “[u]nless facts or circumstances would indicate the contrary, the approval may be presumed if the fiduciary permits the transaction to proceed after receipt of the written disclosure.”
The Department declined to adjust the consent procedure in the context of Fixed Rate Annuity Contract and insurance contract sales. The Department believes that investments in these products are significant enough that a negative consent procedure is not warranted.
Finally, a revision was made to Section IV(d), which sets forth the requirement for disclosure to be made in connection with additional purchases of Fixed Rate Annuity Contracts, insurance contracts, or securities issued by an investment company. Under the revised condition, the written disclosure required under Section IV(b) and (c) need not be repeated, unless:
(1) More than one year has passed since the disclosure was made with respect to the purchase of the same kind of contract or security, or
(2) The contract or security being recommended for purchase or the Insurance Commission or Mutual Fund Commission with respect thereto is materially different from that for which the approval described in paragraphs (b) and (c) of this Section was obtained.
This requirement was changed from three years, in the existing exemption, to one year in the final amendment. This change corresponds to the approach taken in the Best Interest Contract Exemption that these types of disclosures should be made on at least an annual basis. For example, in the Best Interest Contract Exemption, the transaction disclosure required by Section III(a) is required to be repeated on an annual basis with respect to additional recommendations of the same investment. This reflects the Department's view that if conflicted arrangements exist, plans and IRAs should receive sufficient notice to enable them to provide informed consent to the transaction, and a one year interval is the appropriate time in which the disclosure should be repeated, under the circumstances of this exemption as well as the Best Interest Contract Exemption.
In addition, the language was revised so that the one year period runs from the purchase of an annuity. If any disclosures were given with respect to a recommendation that was not acted upon by the customer, the one year period does not apply.
In connection with the changes to this section, the Department clarified in the introductory language that these disclosures are required to be made only with respect to additional transactions that are
Section V of the amended exemption includes a recordkeeping requirement under which the insurance agent or broker, pension consultant, insurance company, or investment company principal underwriter engaging in the transaction must maintain records of the
The Department has accepted these comments and made the requested revisions. Thus, the Department specifically clarified that “[f]ailure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.” In addition, in accordance with other exemptions granted and amended today, financial institutions are also not required to disclose records if such disclosure would be precluded by 12 U.S.C. 484, relating to visitorial powers over national banks and federal savings associations.
The definition of “Plan,” set forth in Section VI(l) of the amended exemption, provides that a Plan means any employee benefit plan described in section 3(3) of the Act and any plan described in section 4975(e)(1)(A) of the Code. The proposal did not contain a definition of Plan. This definition was added in response to commenters who questioned the exemption's application to plans such as Simplified Employee Pensions (SEPs), Savings Incentive Match Plans for Employees (SIMPLEs) and Keoghs. The Department intends for the definition of Plan to include all of these plans.
The definition of “relative” set forth in Section VI(n) refers to a “relative” as that term is defined in ERISA section 3(15) (or a “member of the family” as that term is defined in Code section 4975(e)(6)). These provisions include spouses, ancestors, lineal descendants and spouses of a lineal descendant. Originally, the definition used in the exemption was more expansive, and, in addition to these entities also included “a brother, a sister, or a spouse of a brother or a sister.” A commenter stated that this definition was broader than the definition of “relative” in the other exemptions granted and amended today, and asked that the Department eliminate the references to brothers, sisters and their spouses. The Department concurs and has changed the text so that the definitions are consistent across exemptions.
Section VI(d) defines “Individual Retirement Account” or “IRA” as any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and an HSA described in section 223(d) of the Code. This definition is unchanged from the proposal.
The Department received comments on both the application of the proposed Regulation and the exemption proposals to other non-ERISA plans covered by Code section 4975, such as HSAs, Archer Medical Savings Accounts and Coverdell Education Savings Accounts. The Department notes that these accounts are given tax preferences as are IRAs. Further, some of the accounts, such as HSAs, can be used as long term savings accounts for retiree health care expenses. These types of accounts also are expressly defined by Code section 4975(e)(1) as plans that are subject to the Code's prohibited transaction rules. Thus, although they generally may hold fewer assets and may exist for shorter durations than IRAs, there is no statutory reason to treat them differently than other conflicted transactions and no basis for suspecting that the conflicts are any less influential with respect to advice on these arrangements. Accordingly, the Department does not agree with the commenters that the owners of these accounts are entitled to less protection than IRA investors. The Regulation continues to include advisers to these “plans,” and this exemption provides relief to them in the same manner as it does for individual retirement accounts described in section 408(a) of the Code.
The Department received several comments from the industry requesting that the exemption include a grandfathering provision for pre-existing annuity contracts. The commenters stated that the grandfathering provision would help the industry avoid costly unraveling of ongoing client relationships. Many of the commenters requested that the grandfathering provision include coverage for transactions occurring after the Applicability Date of the exemption but based on advice that was given prior to the Applicability Date. The commenters argued that without a grandfathering provision existing relationships will become fiduciary relationships creating undue compliance burdens and costs that were not priced into the contracts and as a result many advisers may be forced to abandon existing IRA relationships.
The Department has not included a grandfathering provision in this amended exemption, however some of the relief requested by commenters is available in the Best Interest Contract Exemption. Specifically, Section VII of the Best Interest Contract Exemption sets forth an exemption for investments that are pre-existing at the time of the Applicability Date and is available for pre-existing insurance and annuity contracts. Under Section VII of the Best Interest Contract Exemption, additional advice may be provided on existing investments after the Applicability Date, and additional compensation may be received, if the advice reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the retirement investor, and the advice is rendered without regard to the financial or other interests of the investment advice fiduciary or any affiliate or other party.
The exemption set forth in Section VII of the Best Interest Contract Exemption is generally limited to securities or other property purchased prior to the Applicability Date, and does not generally extend to advice on additional contributions to an annuity purchased prior to the Applicability Date. Although commenters requested broader relief in this area, the Department has declined to permit advice on additional contributions to existing investments, without compliance with the conditions of this
The Regulation will become effective June 7, 2016 and this amended exemption is issued on that same date. The Regulation is effective at the earliest possible effective date under the Congressional Review Act. For the exemption, the issuance date serves as the date on which the amended exemption is intended to take effect for purposes of the Congressional Review Act. This date was selected in order to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the Regulation are officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the Regulation and amended exemption are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, that an Applicability Date of April 10, 2017, is appropriate for plans and their affected financial services and other service providers to adjust to the basic change from non-fiduciary to fiduciary status. The amendment to and partial revocation of PTE 84-24, as finalized herein, can be relied on beginning on the Applicability Date. For the avoidance of doubt, no revocation will be applicable prior to the Applicability Date.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Department solicited comments on the information collections included in the proposed Amendment to and Partial Revocation of PTE 84-24 for Certain Transactions Involving Insurance Agents and Brokers, Pension Consultants, Insurance Companies, and Investment Company Principal Underwriters. 80 FR 22010 (Apr. 20, 2015). The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposal, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally many comments were submitted, described elsewhere in this preamble and in the preamble to the accompanying final rule, which contained information relevant to the costs and administrative burdens attendant to the proposals. The Department took into account such public comments in connection with making changes to the prohibited transaction exemption, analyzing the economic impact of the proposals, and developing the revised paperwork burden analysis summarized below.
In connection with publication of this final amendment to and partial revocation of PTE 84-24, the Department is submitting an ICR to OMB requesting approval of a new collection of information under a new OMB Control Number. The Department will notify the public when OMB approves the ICR.
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail below, PTE 84-24, as amended, provides an exemption for certain prohibited transactions that occur when investment advice fiduciaries and other service providers receive compensation for their recommendation that plans or IRAs purchase “Fixed Rate Annuity Contracts” and insurance contracts. Relief is also provided for certain prohibited transactions that occur when investment advice fiduciaries and other service providers receive compensation as a result of recommendations that plans purchase securities in an investment company registered under the Investment Company Act of 1940. The amended exemption permits insurance agents, insurance brokers, pension consultants, and investment company principal underwriters that are parties in interest or fiduciaries with respect to plan investors to effect these purchases and receive a commission on them. The amended exemption is also available for the prohibited transaction that occurs when the insurance company selling the Fixed Rate Annuity Contract or insurance contract is a party in interest or disqualified person with respect to the plan or IRA. As amended, the exemption requires fiduciaries engaging in these transactions to adhere to certain Impartial Conduct Standards, including acting in the best interest of the plans and IRAs when providing advice.
The amendment revises the disclosure and recordkeeping requirements of the exemption by requiring insurance agents and brokers, pension consultants, insurance companies, and investment company principal underwriters to make certain disclosures to and receive an advance authorization from plan fiduciaries or, as applicable, IRA owners, in order to receive relief from ERISA's and the Code's prohibited transaction rules for the receipt of compensation when plans and IRAs enter into certain recommended insurance and mutual fund transactions. The amendment will require insurance agents and brokers, pension consultants, insurance companies, and investment company principal underwriters relying on PTE 84-24 to maintain records necessary to demonstrate that the conditions of the exemption have been met. These requirements are ICRs subject to the PRA.
The Department has made the following assumptions in order to establish a reasonable estimate of the paperwork burden associated with these ICRs:
• 51.8 percent of disclosures to and advance authorizations from plans
• Insurance agents and brokers, pension consultants, insurance companies, investment company principal underwriters, and plans will use existing in-house resources to prepare the legal authorizations and disclosures, and maintain the recordkeeping systems necessary to meet the requirements of the exemption;
• A combination of personnel will perform the tasks associated with the ICRs at an hourly wage rate of $167.32 for a financial manager, $55.21 for clerical personnel, and $133.61 for a legal professional;
• Three percent of plans and three percent of IRAs will engage in covered transactions with insurance agents and brokers, pension consultants, and insurance companies annually;
• Approximately 1,500 insurance agents and brokers, pension consultants, and insurance companies will take advantage of this exemption with all of their client plans and IRAs;
• Ten investment company principal underwriters will take advantage of this exemption and each will do so once with one client plan annually.
In order to receive commissions in conjunction with the purchase of insurance contracts or Fixed Rate Annuity Contracts, Section IV(b) of PTE 84-24 as amended requires the insurance agent or broker or pension consultant to obtain advance written authorization from a plan fiduciary independent of the insurance company (the independent fiduciary), or, in the case of an IRA, the IRA owner, following certain disclosures, including: If the agent, broker, or consultant is an Affiliate of the insurance company whose contract is being recommended, or if the ability of the agent, broker, or consultant to recommend insurance or Fixed Rate Annuity Contracts is limited by any agreement with the insurance company, the nature of the affiliation, limitation, or relationship; the insurance commission; and a statement of any charges, fees, discounts, penalties, or adjustments which may be imposed under the recommended contract in connection with the purchase, holding, exchange, termination, or sale of the contract.
In order to receive commissions in conjunction with the purchase of securities issued by an investment company, Section IV(c) of PTE 84-24 as amended requires the investment company principal underwriter to obtain approval from an independent plan fiduciary following certain disclosures: If the person recommending securities issued by an investment company is the principal underwriter of the investment company whose securities are being recommended, the nature of the relationship and of any limitation it places upon the principal underwriter's ability to recommend investment company securities; the Mutual Fund Commission; and a statement of any charges, fees, discounts, penalties, or adjustments which may be imposed under the recommended securities in connection with the purchase, holding, exchange, termination, or sale of the securities. Unless facts or circumstances would indicate the contrary, the approval required under Section IV(c) may be presumed if the independent plan fiduciary permits the transaction to proceed after receipt of the written disclosure.
According to 2013 Annual Return/Report of Employee Benefit (Form 5500) data and IRS Statistics of Income data, the Department estimates that there are approximately 681,000 ERISA covered pension plans and approximately 54.4 million IRAs. Of these plans and IRAs, the Department assumes that, as stated previously, three percent of these plans and three percent of these IRAs will engage in transactions covered under PTE 84-24 annually with insurance agents or brokers and pension consultants. In the plan universe, the Department assumes that a legal professional will spend five hours per plan reviewing the disclosures and preparing an authorization form for each of the approximately 20,000 plans engaging in covered transactions each year. In the IRA universe, IRA holders are also required to provide an authorization, but the Department assumes that a legal professional working on behalf of each of the 1,500 insurance companies or pension consultants will spend three hours drafting a standard authorization form for IRA holders to sign and return. The Department also estimates that it will take two hours of legal time for each of the approximately 1,500 insurance companies and pension consultants, and one hour of legal time for each of the 10 investment company principal underwriters, to produce the disclosures.
The Department estimates that approximately 20,000 plans and 1.6 million IRAs have engage in covered transactions with insurance agents or brokers and pension consultants under this exemption each year. The Department assumes that 10 plans engage in covered transactions with investment company principal underwriters under this exemption each year.
The Department estimates that 20,000 plans will send insurance agents or brokers and pension consultants a two-page authorization letter and 1.6 million IRAs will receive a two-page authorization letter from insurance agents or brokers and pension consultants to sign and return each year. Prior to obtaining authorization, insurance companies and pension consultants will send the same 20,000 plans and 1.6 million IRAs a seven-page pre-authorization disclosure. Paper copies of the authorization letter and the pre-authorization disclosure will be mailed for 48.2 percent of the plans and distributed electronically for the remaining 51.8 percent. Paper copies of the authorization letter and the pre-authorization disclosure will be mailed to 55.9 percent of the IRAs and distributed electronically to the remaining 44.1 percent. The Department estimates that electronic distribution will result in a de minimis cost, while paper distribution will cost approximately $1.3 million. Paper distribution of the letter and disclosure will also require two minutes of clerical preparation time
The Department estimates that 10 plans will receive the seven-page pre-transaction disclosure from investment company principal underwriters; 51.8 percent will be distributed electronically and 48.2 percent will be mailed. The Department estimates that electronic distribution will result in a de minimis cost, while the paper distribution will cost $4. Paper distribution will also require two minutes of clerical preparation time resulting in a total of 10 minutes at an equivalent cost of $9. Approval to investment company principal underwriters will be granted orally at de minimis cost.
Section V of PTE 84-24, as amended, requires insurance agents and brokers, insurance companies, pension consultants, and investment company principal underwriters to maintain or cause to be maintained for six years and disclosed upon request the records necessary for the Department, IRS, plan fiduciary, contributing employer or employee organization whose members are covered by the plan, plan participant, beneficiary or IRA owner, to determine whether the conditions of this exemption have been met.
The Department assumes that each institution will maintain these records in their normal course of business. Therefore, the Department has estimated that the additional time needed to maintain records consistent with the exemption will only require about one-half hour, on average, annually for a financial manager to organize and collate the documents or else draft a notice explaining that the information is exempt from disclosure, and an additional 15 minutes of clerical time to make the documents available for inspection during normal business hours or prepare the paper notice explaining that the information is exempt from disclosure. Thus, the Department estimates that a total of 45 minutes of professional time (30 minutes of financial manager time and 15 minutes of clerical time) per financial institution per year would be required for a total hour burden of 1,000 hours at an equivalent cost of $147,000.
In connection with the recordkeeping and disclosure requirements discussed above, Section V(b) (2) and (3) of PTE 84-24 provides that parties relying on the exemption do not have to disclose trade secrets or other confidential information to members of the public (
Overall, the Department estimates that in order to meet the conditions of this amended exemption, almost 22,000 financial institutions and plans will produce 3.3 million disclosures and notices annually. These disclosures and notices will result in over 172,000 burden hours annually, at an equivalent cost of $18.2 million. This amended exemption will also result in a total annual cost burden of over $1.3 million.
These paperwork burden estimates are summarized as follows:
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under ERISA section 408(a) and Code section 4975(c)(2) does not relieve a fiduciary or other party in interest or disqualified person with respect to a plan from certain other provisions of ERISA and the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of ERISA section 404 which require, among other things, that a fiduciary discharge his or her duties respecting the plan solely in the interests of the plan's participants and beneficiaries and in a prudent fashion in accordance with ERISA section 404(a)(1)(B);
(2) The Department finds that the class exemption as amended is administratively feasible, in the interests of the plan and of its
(3) The class exemption is applicable to a particular transaction only if the transaction satisfies the conditions specified in the class exemption; and
(4) This amended class exemption is supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
(a) In general. ERISA and the Code prohibit fiduciary advisers to employee benefit plans and IRAs from self-dealing, including receiving compensation that varies based on their investment advice, and from receiving compensation from third parties in connection with their advice. ERISA and the Code also prohibit fiduciaries and other parties related to plans and IRAs from engaging in purchases and sales of products with the plans and IRAs. This exemption permits certain, specified persons, including specified persons who are fiduciaries due to their provision of investment advice to plans and IRAs, to receive these types of compensation in connection with transactions involving insurance contracts, specified annuity contracts, and investment company securities, as described below.
(b) Exemptions. The restrictions of ERISA section 406(a)(1)(A) through (D) and 406(b) and the taxes imposed by Code section 4975(a) and (b) by reason of Code section 4975(c)(1)(A) through (F), do not apply to any of the following transactions if the conditions set forth in Sections II, III, IV, and V, as applicable, are met:
(1) The receipt, directly or indirectly, by an insurance agent or broker or a pension consultant of an Insurance Commission and related employee benefits from an insurance company in connection with the purchase, with assets of a Plan or IRA, including through a rollover or distribution, of an insurance contract or a Fixed Rate Annuity Contract. A Fixed Rate Annuity Contract is a fixed annuity contract issued by an insurance company that is either an immediate annuity contract or a deferred annuity contract that (i) satisfies applicable state standard nonforfeiture laws at the time of issue, or (ii) in the case of a group fixed annuity, guarantees return of principal net of reasonable compensation and provides a guaranteed declared minimum interest rate in accordance with the rates specified in the standard nonforfeiture laws in that state that are applicable to individual annuities; in either case, the benefits of which do not vary, in part or in whole, based on the investment experience of a separate account or accounts maintained by the insurer or the investment experience of an index or investment model. A Fixed Rate Annuity Contract does not include a variable annuity or an indexed annuity or similar annuity.
(2) The receipt of a Mutual Fund Commission by a Principal Underwriter for an investment company registered under the Investment Company Act of 1940 (an investment company) in connection with the purchase, with Plan assets, including through a rollover or distribution, of securities issued by an investment company.
(3)(i) The effecting by an insurance agent or broker, or pension consultant of a transaction for the purchase, with assets of a Plan or IRA, including through a rollover or distribution, of a Fixed Rate Annuity Contract or insurance contract, or (ii) the effecting by a Principal Underwriter of a transaction for the purchase, with assets of a Plan, including through a rollover or distribution, of securities issued by an investment company.
(4) The purchase, with assets of a Plan or IRA, including through a rollover or distribution, of a Fixed Rate Annuity Contract or insurance contract from an insurance company, and the receipt of compensation or other consideration by the insurance company.
(5) The purchase, with assets of a Plan, of a Fixed Rate Annuity Contract or insurance contract from an insurance company which is a fiduciary or a service provider (or both) with respect to the Plan solely by reason of the sponsorship of a Master or Prototype Plan.
(6) The purchase, with assets of a Plan, of securities issued by an investment company from, or the sale of such securities to, an investment company or an investment company Principal Underwriter, when the investment company, Principal Underwriter, or the investment company investment adviser, is a fiduciary or a service provider (or both) with respect to the Plan solely by reason of: (A) The sponsorship of a Master or Prototype Plan; or (B) the provision of Nondiscretionary Trust Services to the Plan; or (C) both (A) and (B).
(c) Scope of these Exemptions.
(1) The exemptions set forth in Section I(b) do not apply to the purchase by a Plan or IRA, each as defined in Section VI, of a variable annuity contract, indexed annuity contract, or similar contract; and
(2) The exemptions set forth in Section I(b) do not apply to the purchase by an IRA of investment company securities.
If the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter is a fiduciary within the meaning of ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B) with respect to the assets involved in the transaction, the following conditions must be satisfied with respect to the transaction to the extent they are applicable to the fiduciary's actions:
(a) When exercising fiduciary authority described in ERISA section 3(21)(A)(ii) or Code section 4975(e)(3)(B) with respect to the assets involved in the transaction, the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter acts in the Best Interest of the Plan or IRA at the time of the transaction; and
(b) The statements by the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter about recommended investments, fees, Material Conflicts of Interest, and any other matters relevant to a Plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. For this purpose, the insurance agent's or broker's, pension consultant's, insurance company's or investment company Principal Underwriter's failure to disclose a Material Conflict of Interest relevant to the services it is providing or other actions it is taking in relation to a Plan's or IRA owner's investment decisions is considered a misleading statement.
(a) The transaction is effected by the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter in the ordinary course of its business as such a person.
(b) The transaction is on terms at least as favorable to the Plan or IRA as an arm's length transaction with an unrelated party would be.
(c) The combined total of all fees and compensation received by the insurance agent or broker, pension consultant,
The following conditions apply solely to a transaction described in paragraphs (b)(1), (2), (3) or (4) of Section I:
(a) The insurance agent or broker, pension consultant, insurance company, or investment company Principal Underwriter is not (1) a trustee of the Plan or IRA (other than a Nondiscretionary Trustee who does not render investment advice with respect to any assets of the Plan), (2) a plan administrator (within the meaning of ERISA section 3(16)(A) and Code section 414(g)), (3) a fiduciary who is expressly authorized in writing to manage, acquire, or dispose of the assets of the Plan or IRA on a discretionary basis, or (4) an employer any of whose employees are covered by the Plan. Notwithstanding the above, an insurance agent or broker, pension consultant, insurance company, or investment company Principal Underwriter that is Affiliated with a trustee or an investment manager (within the meaning of Section VI(e)) with respect to a Plan or IRA may engage in a transaction described in Section I(b)(1)-(4) of this exemption (if permitted under Section I(b)) on behalf of the Plan or IRA if the trustee or investment manager has no discretionary authority or control over the Plan's or IRA's assets involved in the transaction other than as a Nondiscretionary Trustee.
(b)(1) With respect to a transaction involving the purchase with Plan or IRA assets of a Fixed Rate Annuity Contract or insurance contract, or the receipt of an Insurance Commission thereon, the insurance agent or broker or pension consultant provides to an independent fiduciary with respect to the Plan, or in the case of an IRA, to the IRA owner, prior to the execution of the transaction the following information in writing and in a form calculated to be understood by a plan fiduciary or IRA owner who has no special expertise in insurance or investment matters:
(A) If the agent, broker, or consultant is an Affiliate of the insurance company whose contract is being recommended, or if the ability of the agent, broker, or consultant to recommend Fixed Rate Annuity Contracts or insurance contracts is limited by any agreement with the insurance company, the nature of the affiliation, limitation, or relationship;
(B) The Insurance Commission, expressed to the extent feasible as an absolute dollar figure, or otherwise, as a percentage of gross annual premium payments, asset accumulation value, or contract value, for the first year and for each of the succeeding renewal years, that will be paid directly or indirectly by the insurance company to the agent, broker, or consultant in connection with the purchase of the recommended contract, including, if applicable, separate identification of the amount of the Insurance Commission that will be paid to any other person as a gross dealer concession, override, or similar payment; and
(C) A statement of any charges, fees, discounts, penalties or adjustments which may be imposed under the recommended contract in connection with the purchase, holding, exchange, termination, or sale of the contract.
(2) Following the receipt of the information required to be disclosed in paragraph (b)(1), and prior to the execution of the transaction, the fiduciary or IRA owner acknowledges in writing receipt of the information and approves the transaction on behalf of the Plan or IRA. The fiduciary may be an employer of employees covered by the Plan but may not be an insurance agent or broker, pension consultant, or insurance company involved in the transaction (
(c)(1) With respect to a transaction involving the purchase with plan assets of securities issued by an investment company or the receipt of a Mutual Fund Commission thereon by an investment company Principal Underwriter, the investment company Principal Underwriter provides to an independent fiduciary with respect to the Plan, prior to the execution of the transaction, the following information in writing and in a form calculated to be understood by a plan fiduciary who has no special expertise in insurance or investment matters:
(A) If the person recommending securities issued by an investment company is the Principal Underwriter of the investment company whose securities are being recommended, the nature of the relationship and of any limitation it places upon the Principal Underwriter's ability to recommend investment company securities;
(B) The Mutual Fund Commission, expressed to the extent feasible, as an absolute dollar figure, or otherwise, as a percentage of the dollar amount of the Plan's gross payment and of the amount actually invested, that will be received by the Principal Underwriter in connection with the purchase of the recommended securities issued by the investment company; and
(C) A statement of any charges, fees, discounts, penalties, or adjustments which may be imposed under the recommended securities in connection with the purchase, holding, exchange, termination, or sale of the securities.
(2) Following the receipt of the information required to be disclosed in paragraph (c)(1), and prior to the execution of the transaction, the independent fiduciary approves the transaction on behalf of the Plan. Unless facts or circumstances would indicate the contrary, the approval may be presumed if the fiduciary permits the transaction to proceed after receipt of the written disclosure. The fiduciary may be an employer of employees covered by the Plan, but may not be a Principal Underwriter involved in the transaction. The independent fiduciary may not receive, directly or indirectly (
(d) With respect to additional recommendations regarding purchases of Fixed Rate Annuity Contracts, insurance contract, or securities issued by an investment company, the written disclosure required under paragraphs (b) and (c) of this Section IV need not be repeated, unless:
(1) More than one year has passed since the disclosure was made with respect to the purchase of the same kind of contract or security, or
(2) The contract or security being recommended for purchase or the Insurance Commission or Mutual Fund Commission with respect thereto is materially different from that for which the approval described in paragraphs (b) and (c) of this Section was obtained.
(a) The insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter engaging in the covered transactions maintains or causes to be maintained for a period of six years, in a manner that is reasonably accessible for audit and examination, the records necessary to enable the persons described in Section V(b) to determine
(1) If the records necessary to enable the persons described in Section V(b) below to determine whether the conditions of the exemption have been met are lost or destroyed, due to circumstances beyond the control of the insurance agent or broker, pension consultant, insurance company, or investment company Principal Underwriter, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and
(2) No party in interest, other than the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter shall be subject to the civil penalty that may be assessed under ERISA section 502(i) or the taxes imposed by Code section 4975(a) and (b) if the records are not maintained or are not available for examination as required by paragraph (b) below; and
(b)(1) Except as provided below in subparagraph (2) or as precluded by 12 U.S.C. 484, and notwithstanding any provisions of ERISA section 504(a)(2) and (b), the records referred to in the above paragraph are reasonably available at their customary location for examination during normal business hours by—
(A) Any duly authorized employee or representative of the Department or the IRS;
(B) Any fiduciary of the Plan or any duly authorized employee or representative of the fiduciary;
(C) Any contributing employer and any employee organization whose members are covered by the Plan, or any authorized employee or representative of these entities; or
(D) Any participant or beneficiary of the Plan or the duly authorized representative of the participant or beneficiary or IRA owner; and
(2) None of the persons described in subparagraph (1)(B)-(D) above shall be authorized to examine records regarding a transaction involving a Plan or IRA unrelated to the person, or trade secrets or commercial or financial information of the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter which is privileged or confidential.
(3) Should the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter refuse to disclose information on the basis that the information is exempt from disclosure, the insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter shall, by the close of the thirtieth (30th) day following the request, provide a written notice advising that person of the reasons for the refusal and that the Department may request the information.
(c) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
For purposes of this exemption:
(a) The term “Affiliate” of a person means:
(1) Any person directly or indirectly controlling, controlled by, or under common control with the person;
(2) Any officer, director, employee (including, in the case of Principal Underwriter, any registered representative thereof, whether or not the person is a common law employee of the Principal Underwriter), or relative of any such person, or any partner in such person; or
(3) Any corporation or partnership of which the person is an officer, director, or employee, or in which the person is a partner.
(b) The insurance agent or broker, pension consultant, insurance company or investment company Principal Underwriter that is a fiduciary acts in the “Best Interest” of the Plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances and needs of the Plan or IRA, without regard to the financial or other interests of the fiduciary, any affiliate or other party.
(c) The term “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual.
(d) The terms “Individual Retirement Account” or “IRA” mean any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and an HSA described in section 223(d) of the Code.
(e) The terms “insurance agent or broker,” “pension consultant,” “insurance company,” “investment company,” and “Principal Underwriter” mean such persons and any Affiliates thereof.
(f) The term “Insurance Commission” mean a sales commission paid by the insurance company to the insurance agent or broker or pension consultant for the service of effecting the purchase of a Fixed Rate Annuity Contract or insurance contract, including renewal fees and trailers, but not revenue sharing payments, administrative fees, or marketing payments.
(g) The term “Master or Prototype Plan” means a Plan which is approved by the Service under Rev. Proc. 2011-49, 2011-44 I.R.B. 608 (10/31/2011), as modified, or its successors.
(h) A “Material Conflict of Interest” exists when a person has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a Plan or IRA.
(i) The term “Mutual Fund Commission” means a commission or sales load paid either by the Plan or the investment company for the service of effecting or executing the purchase of investment company securities, but does not include a 12b-1 fee, revenue sharing payment, administrative fee, or marketing fee.
(j) The term “Nondiscretionary Trust Services” means custodial services, services ancillary to custodial services, none of which services are discretionary, duties imposed by any provisions of the Code, and services performed pursuant to directions in accordance with ERISA section 403(a)(1). The term “Nondiscretionary Trustee” of a Plan or IRA means a trustee whose powers and duties with respect to the Plan are limited to the provision of Nondiscretionary Trust Services. For purposes of this exemption, a person who is otherwise a Nondiscretionary Trustee will not fail to be a Nondiscretionary Trustee solely by reason of his having been delegated, by the sponsor of a Master or Prototype Plan, the power to amend the Plan.
(k) The term “Fixed Rate Annuity Contract” means a fixed annuity contract issued by an insurance company that is either an immediate annuity contract or a deferred annuity contract that (i) satisfies applicable state standard nonforfeiture laws at the time of issue, or (ii) in the case of a group fixed annuity, guarantees return of principal net of reasonable compensation and provides a guaranteed declared minimum interest rate in accordance with the rates specified in the standard nonforfeiture laws in that state that are applicable to individual annuities; in either case, the
(l) The term “Plan” means any employee benefit plan described in section 3(3) of the Act and any plan described in section 4975(e)(1)(A) of the Code.
(m) The term “Principal Underwriter” is defined in the same manner as that term is defined in section 2(a)(29) of the Investment Company Act of 1940 (15 U.S.C. 80a-2(a)(29)).
(n) The term “relative” means a “relative” as that term is defined in ERISA section 3(15) (or a “member of the family” as that term is defined in Code section 4975(e)(6)).
Employee Benefits Security Administration (EBSA), Department of Labor.
Adoption of amendments to and partial revocations of PTEs 86-128 and 75-1.
This document contains amendments to Prohibited Transaction Exemptions (PTEs) 86-128 and 75-1, exemptions from certain prohibited transaction provisions of the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code of 1986 (the Code). The ERISA and Code provisions at issue generally prohibit fiduciaries with respect to employee benefit plans and individual retirement accounts (IRAs) from engaging in self-dealing in connection with transactions involving plans and IRAs. PTE 86-128 allows fiduciaries to receive compensation in connection with certain securities transactions entered into by plans and IRAs. The amendments increase the safeguards of the exemption. This document also contains a revocation of PTE 86-128 with respect to transactions involving investment advice fiduciaries and IRAs, and of PTE 75-1, Part II(2), and PTE 75-1, Parts I(b) and I(c), in light of existing or newly finalized relief, including the relief provided in the “Best Interest Contract Exemption,” published elsewhere in this issue of the
Brian Shiker or Erin Hesse, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor, 200 Constitution Avenue NW., Suite 400, Washington DC 20210, (202) 693-8540 (not a toll-free number).
The Department is amending and partially revoking PTEs 86-128 and 75-1 on its own motion, pursuant to ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637 (October 27, 2011)).
These amendments and revocations are being granted in connection with its publication today, elsewhere in this issue of the
PTE 86-128 permits certain fiduciaries to receive fees in connection with certain mutual fund and other securities transactions entered into by plans and IRAs. A number of changes are finalized with respect to the scope of the exemption and of another existing exemption, PTE 75-1, including revocation of many transactions originally permitted with respect to IRAs. These amendments and revocations affect the conditions under which fiduciaries may receive fees and compensation when they transact with plans and IRAs.
The amendments and the partial revocations to PTEs 86-128 and 75-1 are part of the Department's regulatory initiative to mitigate the effects of harmful conflicts of interest associated with fiduciary investment advice. In the absence of an exemption, ERISA and the Code generally prohibit fiduciaries from using their authority to affect or increase their own compensation. A new exemption for receipt of compensation by fiduciaries that provide investment advice to IRA owners,
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant administrative exemptions from ERISA's prohibited transaction provisions.
PTE 86-128, as amended, permits certain fiduciaries, including both investment advice fiduciaries as defined under the Regulation and fiduciaries with discretionary authority or control over plan assets (
The Department has amended the exemption to protect IRA investors from the harmful impact of conflicts of interest. Before these amendments, the exemption granted broad relief to transactions involving IRAs, without protective conditions. We have determined that this approach is unprotective of these retirement investors and incompatible with this regulatory initiative's goal of guarding retirement investors against the harms caused by conflicts of interest. Therefore, the amendment requires investment managers to meet the terms of the exemption before engaging in covered transactions with respect to IRAs, and revokes relief for investment advice fiduciaries with respect to IRAs. Investment advice fiduciaries with respect to IRAs may rely instead on the Best Interest Contract Exemption finalized today elsewhere in this issue of the
The amendment requires fiduciaries relying on PTE 86-128 to adhere to “Impartial Conduct Standards,” including acting in the best interest of plans and IRAs, when they exercise their fiduciary authority. The amendment also adopts the proposed definition of Commission which sets forth the limited types of payments that are permitted under the exemption, and revises the disclosure and recordkeeping requirements under the exemption.
Finally, other changes are adopted with respect to PTE 75-1. PTE 75-1, Part II, is amended to revise the recordkeeping requirement of that exemption. Part I(b) and (c) of PTE 75-1, which provided relief for certain non-fiduciary services to plans and IRAs, is revoked. Upon revocation, persons seeking to engage in such transactions should look to the existing statutory exemptions provided in ERISA section 408(b)(2) and Code section 4975(d)(2), and the Department's implementing regulations at 29 CFR 2550.408b-2, for relief.
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Order and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal agencies to develop a plan under which the agencies will periodically review their existing significant regulations to make the agencies' regulatory programs more effective or less burdensome in achieving their regulatory objectives.
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the Office of Management and Budget (OMB). Section 3(f) of Executive Order 12866, defines a “significant regulatory action” as an action that is likely to result in a rule (1) having an annual effect on the economy of $100 million or more, or adversely and materially affecting a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities (also referred to as “economically significant” regulatory actions); (2) creating serious inconsistency or otherwise interfering with an action taken or planned by another agency; (3) materially altering the budgetary impacts of entitlement grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raising novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of the Executive Order, OMB has determined that this action is “significant” within the meaning of Section 3(f)(4) of the Executive Order. Accordingly, the Department has undertaken an assessment of the costs and benefits of the proposal, and OMB has reviewed this regulatory action. The Department's complete Regulatory Impact Analysis is available at
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans and their participants and beneficiaries.
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service. Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violation of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, ERISA section 3(21)(A) and Code section 4975(e)(3) provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (i) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of its assets; (ii) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan or IRA, or has any authority or responsibility to do so; or, (iii) has any discretionary authority or discretionary responsibility in the administration of such plan or IRA.
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants, and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, the providers of investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c)(1975), defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of ERISA section 3(21)(A)(ii) (the “1975 regulation”).
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At the same time, the variety and complexity of financial products have increased, widening the information gap between advisers and their clients. Plan fiduciaries, plan participants and IRA investors must often rely on experts for advice, but are unable to assess the quality of the expert's advice or effectively guard against the adviser's conflicts of interest. This challenge is especially true of retail investors who typically do not have financial expertise, and can ill-afford lower returns to their retirement savings caused by conflicts. The IRA accounts of these investors often account for all or the lion's share of their assets, and can represent all of savings earned for a lifetime of work. Losses and reduced returns can be devastating to the investors who depend upon such savings for support in their old age. As baby boomers retire, they are increasingly moving money from ERISA-covered plans, where their employer has both the incentive and the fiduciary duty to facilitate sound investment choices, to IRAs where both good and bad investment choices are myriad and advice that is conflicted is commonplace. These rollovers are expected to approach $2.4 trillion cumulatively from 2016 through 2020.
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries, and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B), (the “Regulation”) which are also published in this issue of the
The Regulation describes the types of advice that constitute “investment advice” with respect to plan or IRA assets for purposes of the definition of a fiduciary at ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B). The Regulation covers ERISA-covered plans, IRAs, and other plans not covered by Title I, such as Keogh plans, and health savings accounts described in section 223(d) of the Code.
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, plan participant or beneficiary, IRA or IRA owner, the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage vs. advisory); or recommendations with respect to rollovers, transfers or distributions from a plan or IRA including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also provides that as a threshold matter in order to be fiduciary advice, the communication must be a “recommendation” as defined therein. The Regulation, as a matter of clarification, provides that a variety of other communications do not constitute “recommendations,” including non-fiduciary investment education; general communications; and specified communications by platform providers. These communications which do not rise to the level of “recommendations” under the regulation are discussed more fully in the preamble to the final Regulation.
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person making the recommendation must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); (2) the person must fairly inform the independent fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and must fairly inform the independent fiduciary of the existence and nature of the person's financial interests in the transaction; (3) the person must know or reasonably believe that the independent fiduciary of the plan or IRA is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); and (4) the person cannot receive a fee or other compensation directly from the plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner for the provision of investment advice (as opposed to other services) in connection with the transaction.
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in section 3(3) of ERISA) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Securities Exchange Act of 1934 (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
The Department anticipates that the Regulation will cover many investment professionals who did not previously consider themselves to be fiduciaries under ERISA or the Code. Under the Regulation, these entities will be subject to the prohibited transaction restrictions in ERISA and the Code that apply specifically to fiduciaries. ERISA section 406(b)(1) and Code section 4975(c)(1)(E) prohibit a fiduciary from dealing with the income or assets of a plan or IRA in his own interest or his own account. ERISA section 406(b)(2), which does not apply to IRAs, provides that a fiduciary shall not “in his individual or in any other capacity act in any transaction involving the plan on behalf of a party (or represent a party) whose interests are adverse to the interests of the plan or the interests of its participants or beneficiaries.” ERISA
Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA.
Investment professionals are often compensated on a commission basis for effecting or executing securities transactions for plans, plan participants and beneficiaries, and IRAs. Because such payments vary based on the advice provided, the Department views a fiduciary that recommends to a plan or IRA a securities transaction and then receives a commission for itself or a related party as violating the prohibited transaction provisions of ERISA section 406(b) and Code section 4975(c)(1)(E).
As the prohibited transaction provisions demonstrate, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however, the statutes provide exemptions from their broad prohibitions on conflicts of interest. For example, ERISA section 408(b)(14) and Code section 4975(d)(17) specifically exempt transactions involving the provision of fiduciary investment advice to a participant or beneficiary of an individual account plan or IRA owner if the advice, resulting transaction, and the adviser's fees meet stringent conditions carefully designed to guard against conflicts of interest.
In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions. However, when they choose to give advice in which they have a conflict of interest, they must rely upon an exemption.
Pursuant to its exemption authority, the Department has previously granted several conditional administrative class exemptions that are available to fiduciary advisers in defined circumstances. PTE 86-128
As originally granted, the exemption in PTE 86-128 could be used only by fiduciaries who were not discretionary trustees, plan administrators, or employers of any employees covered by the plan.
Prohibited Transaction Exemption 75-1, Part II(2), provided relief for the purchase or sale by a plan of securities issued by an open-end investment company registered under the Investment Company Act of 1940 (15 U.S.C. 80a-1
The conditions of the exemption required that the fiduciary customarily purchase and sell securities for its own account in the ordinary course of its business, that the transaction occur on terms at least as favorable to the plan as an arm's length transaction with an unrelated party, and that records be maintained. Contrary to our current approach to recordkeeping, the exemption imposed the recordkeeping burden on the plan or IRA involved in the transaction, rather than the fiduciary.
In connection with the proposed Regulation, the Department proposed an amendment to PTE 86-128. First, the Department proposed to increase the safeguards of the exemption by requiring fiduciaries that rely on the exemption to adhere to certain “Impartial Conduct Standards,” including acting in the best interest of the plans and IRAs when exercising fiduciary authority, and by more precisely defining the types of payments that are permitted under the exemption.
The Department also proposed that PTE 86-128 would apply to the transactions originally permitted under PTE 75-1, Part II(2). In this connection, we proposed to revoke PTE 75-1, Part II(2). We also proposed to revoke PTE 75-1, Part I(b) and (c), which provided relief for certain non-fiduciary services to plans and IRAs, in light of the existing statutory exemptions provided in ERISA section 408(b)(2) and Code section 4975(d)(2) and the Department's implementing regulations at 29 CFR 2550.408b-2.
These amendments and partial revocations follow a lengthy public notice and comment period, which gave interested persons an extensive opportunity to comment on the proposed Regulation, amendments and other related exemption proposals. The proposals initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department then held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule.
The Department has reviewed all comments, and after careful consideration of comments received, has decided to grant the amendments to and partial revocations of PTEs 86-128 and 75-1, Part II, as described below.
As amended, PTE 86-128 preserves originally granted relief for mutual fund and securities transactions involving plans, with the added safeguards of the Impartial Conduct Standards and a clearer definition of the types of payments that are permitted. The amendment also adopts the proposed approach to relief for fiduciaries with respect to IRAs, which significantly increased the safeguards to these retirement investors. Investment management fiduciaries to IRAs may rely on Section I(a) of PTE 86-128 if they satisfy the conditions of the exemption, including the Impartial Conduct Standards, the disclosures and the authorizations. However, relief for investment advice fiduciaries is revoked. Also revoked is PTE 75-1, Part II(2), which permitted fiduciaries to receive compensation in connection with certain mutual fund transactions, under very few applicable safeguards, and PTE 75-1, Part I(b) and (c), in light of the statutory exemptions in ERISA section 408(b)(2) and Code section 4975(d)(2).
The Department revised PTE 86-128 and 75-1, Part II, in these ways in conjunction with the grant of a new exemption, the Best Interest Contract Exemption, adopted elsewhere in this issue of the
With respect to IRA owners and participants and beneficiaries in non-ERISA plans, the Best Interest Contract Exemption requires the investment advice fiduciary to contractually acknowledge fiduciary status and commit to adhere to the Impartial Conduct Standards. As a result, the Best Interest Contract Exemption ensures that IRA owners and the non-ERISA plan participants and beneficiaries have a contract-based claim if their advisers violate the fundamental fiduciary obligations of prudence and loyalty, a protection that is not present in PTE 86-128 and 75-1, Part II.
More generally, the Best Interest Contract Exemption includes safeguards that are uniquely protective of both plans and IRAs in today's complex financial marketplace, including the requirement that financial institutions relying on the exemption adopt anti-conflict policies and procedures designed to ensure that advisers satisfy the Impartial Conduct Standards. The Best Interest Contract Exemption is specifically tailored to address, among other things, the particular conflicts of interest associated with third party payments such as revenue sharing and 12b-1 fees that may not be readily apparent to the retirement investor but can provide powerful incentives to investment advice fiduciaries.
In addition to the Best Interest Contract Exemption, the Regulation adopted today makes provision for certain parties to avoid fiduciary status when they engage in arm's length transactions with plans or IRAs that are independently represented by a fiduciary with financial expertise. Such independent fiduciaries generally include banks, insurance carriers, registered investment advisers, broker-dealers and other fiduciaries with $50 million or more in assets under management or control. This provision in the Regulation complements the limitations in the Best Interest Contract Exemption and is available for transactions involving mutual fund and other securities transactions.
A number of commenters objected generally to changes to PTE 86-128 and PTE 75-1, Part II(2), on the basis that the originally granted exemptions provided sufficient protections to retirement investors. Commenters said there is no demonstrated harm to these consumers under the existing approach. The Department does not agree. The extensive changes in the retirement plan landscape and the associated investment market in recent decades undermine the continued adequacy of our original approach in PTE 86-128 and PTE 75-1, Part II(2). As noted in the accompanying Regulatory Impact Analysis, the Department has determined that investors saving for retirement lose billions of dollars each year as a result of conflicts of interest. PTE 86-128 and PTE 75-1 did not adequately safeguard against these losses, and indeed, in some cases, imposed no protective conditions whatsoever with respect to conflicted investment advice. The changes to these exemptions, discussed below, respond to the ongoing harms caused by conflicts of interest.
The Department did not fully revoke PTE 86-128 and PTE 75-1, Part II, however, where it determined that the conditions of those exemptions continued to be appropriate in connection with the narrow scope of relief provided. PTE 75-1, Part II, remains available for transactions involving non-fiduciary service providers and PTE 86-128 continues to provide narrow relief for commission payments to fiduciaries, in transactions involving ERISA plans and managed
As amended, PTE 86-128 applies to the following transactions set forth in Section I of the exemption:
(a) (1) A plan fiduciary's using its authority to cause a plan to pay a Commission directly to that person or a Related Entity as agent for the plan in a securities transaction, but only to the extent that the securities transactions are not excessive, under the circumstances, in either amount or frequency; and (2) A plan fiduciary's acting as the agent in an agency cross transaction for both the plan and one or more other parties to the transaction and the receipt by such person of a Commission from one or more other parties to the transaction; and
(b) A plan fiduciary's using its authority to cause the plan to purchase shares of an open end investment company registered under the Investment Company Act of 1940 (15 U.S.C. 80a-1
Thus, Section I(a) provides relief for transactions involving securities where a Commission, as defined in the exemption, is paid directly by the plan or IRA. Section I(b) provides relief for mutual fund transactions where a Commission is received but it does not have to be paid directly by the plan; the relief in Section I(b) extends to Commissions paid by a mutual fund or its affiliate. The final exemption makes clear that the relief provided in Section I(b) was intended to apply to broker-dealers acting in their capacity as broker-dealers.
Section I(c) establishes certain limitations on the relief provided, with respect to transactions involving IRAs. Section I(c)(1) provides that the exemption in Section I(a) does not apply if (A) the plan is an IRA
Section I(c) was revised from the proposal, which stated: “The exemptions set forth in Section I(a) and (b) do not apply to a transaction if (1) the plan is an Individual Retirement Account and (2) the fiduciary engaging in the transaction is a fiduciary by reason of the provision of investment advice for a fee, as described in Code section 4975(e)(3)(B) and the applicable regulations.” The revision was made to clarify the intent of the proposal that, as amended, the exemption should be relied on for transactions involving IRAs only by fiduciaries with full investment discretion. As a result, the exemption in Section I(b) effectively would have been unavailable with respect to IRAs, since Section I(b) provides relief only to broker-dealers acting in their capacities as broker dealers. The final exemption makes that restriction explicit.
In addition, the exclusion from conditions of the exemption for certain plans not covering employees, including IRAs, contained in Section IV(a), was eliminated. Therefore, while investment advice fiduciaries to IRAs must rely on another exemption, fiduciaries that exercise full discretionary authority or control with respect to IRAs as described in Code section 4975(e)(3)(A) (
The Department notes that the transaction description set forth in Section I(a) of the proposal has been revised to refer to a “securities transaction.” The addition of the language is simply to ensure clarity with respect to the scope of the relief. PTE 86-128 has always been limited to securities transactions, and the Department added the language to remove any doubt that may have been created by its absence from the proposed language. Comments on issues of scope are discussed below.
Commenters have broadly argued that no changes should be made with respect to the relief originally provided to and conditions imposed on IRA fiduciaries. The commenters stated that the Department has offered no evidence that a change is necessary. Further, they argued that excluding only certain IRA fiduciaries from PTE 86-128 will increase cost and create confusion.
As reflected in the Regulatory Impact Analysis, the prevalence of conflicts of interest in the marketplace for retirement investments is causing ongoing harm to retirement investors. Developments since the Department granted PTE 86-128, and its predecessor PTE 75-1, Part I, have exacerbated the dangers posed by conflicts of interest in the IRA marketplace. The amount of assets held in IRAs has grown dramatically, as the financial services marketplace and financial products have become more complex, and compensation structures have become increasingly conflicted.
To put the changes in the market place in context, IRAs were only established in 1975 (the same year as PTE 75-1 was issued). By 1984, IRAs still held just $159 billion in assets, compared with $589 billion in private-sector defined benefit plans and $287 billion in private-sector defined contribution plans. By the end of the 2014 third quarter, in contrast, IRAs held $6.3 trillion, far surpassing both defined benefit plans ($3.0 trillion) and defined contribution plans ($5.3 trillion). If current trends continue, defined benefit plans' role will decline further, and IRA growth will continue to outstrip that of defined contribution plans, as the workforce ages and the baby boom generation retires and more defined contribution accounts (and sometimes lump sum payouts of defined benefit benefits) are rolled into IRAs. Almost $2.5 trillion is projected to be rolled over from ERISA plans to IRAs between 2015 and 2019. The growth of IRAs has made more middle- and lower-income families into investors, and sound investing more critical to such families' retirement security.
Further, as more families have invested, investing has become more complicated. As IRAs grew during the 1980s and 1990s, their investment pattern changed, shifting away from bank products and toward mutual funds. Bank products typically provide a specified investment return, and perhaps charge an explicit fee. Single issue securities lack diversification and have uncertain returns, but the expenses associated with acquiring and holding them typically take the form of explicit up-front commissions and perhaps some ongoing account fees. Mutual funds are more diversified (and in this respect can simplify investing), but also have uncertain returns, and their fee arrangements can be more complex, and can include a variety of revenue sharing and other arrangements that can introduce conflicts into investment advice and that usually are not fully transparent to investors. The growth in IRAs and the shift in how IRA assets are invested point toward a growing risk that conflicts of interest will taint investment advice regarding IRAs and thereby compromise retirement security.
Prior to these amendments, PTE 86-128 did not protect IRA investors with respect to the transactions it covered, but rather gave fiduciaries a broad unconditional pass from the prohibited transaction rules, which Congress enacted to protect retirement investors from the dangers posed by conflicts of interest. Continuing to give free reign to conflicts of interest in this manner cannot be squared with the important anti-conflict purposes of the prohibited transaction rules, nor would it be in the interests of the IRAs or protective of the rights of IRA owners.
The amendments to PTE 86-128, by incorporating the same Impartial Conduct Standards as are required in the Best Interest Contract Exemption, will result in fiduciaries adhering to a common set of fiduciary norms across exemptions, covering multiple products and types of transactions. The uniform imposition of the standards will also reduce confusion to those consumers who already think their advisers owe them a fiduciary duty.
One commenter suggested that “sophisticated” IRA owners should not be subject to the exemption's amendments. The commenter argued that large or sophisticated investors are not in need of the protections and disclosures the amended exemption provides to IRAs, whether through PTE 86-128 or the Best Interest Contract Exemption. The Department does not agree, however, that the size of the account balance or the wealth of the retirement invest are strong indicators of investment expertise. Nor does the Department believe that large accounts or wealthy investors are less deserving of protection from losses caused by imprudent or disloyal advice. Individuals may have large account balances as a result of years of hard work and careful savings, rollover of an account balance from a defined benefit plan, or inheritance. None of these pathways to large accounts necessarily correlate with financial acumen or the ability to bear losses. Similarly, the Department does not believe that any particular level of income or amount of net assets renders disclosures of fees and conflicts of interest unnecessary or negates the importance of adherence to basic fiduciary norms when giving advice. In the Department's view, all IRAs would benefit from consistent adherence to fiduciary norms and basic disclosure.
Finally, a commenter requested assurances that this revocation of relief with respect to IRA investment advisers was not applicable to investment advice fiduciaries that provide advice to non-IRA plan clients. The language of Section I(c)(1) and (2) is specifically limited to IRAs (as defined in the exemption). If a plan is not an IRA, it is not subject to the exclusion set forth in that section, and the fiduciary may rely upon the exemption to the extent the transaction falls within the exemption's scope and the fiduciary complies with the exemption's conditions, further described below, such as the Impartial Conduct Standards, disclosure, and consent requirements. However, the Department notes the exemption, as amended, will not provide relief for a recommended rollover from an ERISA plan to an IRA, where the resulting compensation is a Commission on the IRA investments.
Section I(b) of PTE 86-128, as amended, includes relief for mutual fund transactions, originally permitted under PTE 75-1, Part II(2). Granted under the heading “Principal transactions,” PTE 75-1, Part II(2) contained an exemption for mutual fund purchases between fiduciaries and plans or IRAs. Although it provided relief for fiduciary self-dealing and conflicts of interest, the exemption was only available if the fiduciary who decides on behalf of the plan or IRA to enter into the transaction was not a principal underwriter for, or affiliated with, the mutual fund. As set forth above, it was subject to minimal safeguards for retirement investors.
The new covered transaction in Section I(b) applies to broker-dealers acting in their capacity as broker-dealers. The exemption is subject to the general prohibition in PTE 86-128 on churning, and the new Impartial Conduct Standards in Section II. In addition, a new Section IV to PTE 86-128 sets forth conditions applicable solely to the proposed new covered transaction. The new Section IV incorporates conditions originally applicable to PTE 75-1, Part II(2).
Specifically, the conditions applicable to the new covered transaction in Section I(b), as set forth in Section IV, are: (1) The fiduciary customarily sells securities for its own account in the ordinary course of its business as a broker-dealer; (2) the transaction is at least as favorable to the plan or IRA as an arm's length transaction with an unrelated party would be; and (3) unless
One commenter expressed the broad belief that no changes should be made to the existing exemptive relief. The commenter indicated that no evidence of harm exists and no policy reason could justify the change, arguing that the only result will be increased burdens and costs. The Department disagrees. As outlined in the proposal and as described above, the movement of the existing exemption from PTE 75-1, Part II(2), to PTE 86-128 for plans, or the Best Interest Contract Exemption, for IRAs, is fitting based on the nature of the transaction, the ongoing injury that conflicts of interest cause to retirement investors, and the additional protections that can be provided to retirement investors. The Department's accompanying Regulatory Impact Analysis indicates that the status quo is harming investors.
Beyond a general objection, the same commenter suggested that the scope of the relief provided by Section I(b) should be significantly expanded. As originally proposed, Section I(b) was limited to transactions involving shares in an open end investment company registered under the Investment Company Act of 1940, in which the fiduciary was acting as “principal.” The commenter indicated that the exemption should include Unit Investment Trusts, which are registered investment companies but not open end investment companies, as well as other products that are traded on a principal basis.
The Department does not disagree with the commenter's premise that relief may be necessary for certain principal transactions and transactions involving Unit Investment Trusts. However, such relief is provided through separate exemptions under specifically tailored conditions, the Best Interest Contract Exemption and the Principal Transactions Exemption, published elsewhere in this issue of the
One commenter reacted to the Department's description of the transaction described in PTE 75-1, Part II(2) as a “riskless principal” transaction. The commenter indicated that the language of proposed Section I(b) required the transaction to be a “principal” transaction and would require the fiduciary engaged in the transaction to report the transaction as a principal transaction, while some market participants confirm these sales as agency trades. Although agency trades are covered by the relief in Section I(a), the relief in Section I(b) is broader in the sense that it covers the receipt of a commission from either the plan or the mutual fund.
The Department has revised the language of Section I(b) to eliminate the reference to the fiduciary acting as “principal.” The Department did not intend to require market participants to change the nomenclature in their confirmations or to exclude any transactions based solely on the nomenclature. To avoid any resulting confusion, the mutual fund exemption in PTE 86-128, as amended, is not limited to riskless principal transactions, and provides relief with respect to covered transactions regardless of whether they are technically confirmed as “principal” transactions.
In connection with the new covered transaction, the Department is revoking PTE 75-1, Part II(2), which had provided relief for a plan fiduciary's using its authority to cause the plan to purchase shares of a mutual fund from the fiduciary, because those transactions are now covered by PTE 86-128.
As originally promulgated, PTE 86-128 provided relief for a fiduciary to use its authority to cause a plan or IRA to pay a fee to
In the amended exemption, relief extends beyond the person and its affiliates, to “related entities.”
Accordingly, the Department proposed revising the exemption to encompass such related parties, and requested comment on the necessity of incorporating relief for related entities in PTE 86-128, and the approach taken in the proposal to do so. A single commenter responded to the Department's call for comment, and it supported incorporating relief for related entities and expressed its general agreement with the necessity of such action. The Department has finalized these amendments without change.
Section II of PTE 86-128, as amended, requires that the fiduciary engaging in a covered transaction comply with fundamental Impartial Conduct Standards. Generally stated, the Impartial Conduct Standards require that, with respect to the transaction, the fiduciary must act in the plan's or IRA's Best Interest; receive no more than reasonable compensation, and make no misleading statements to the plan or IRA. As defined in the exemption, a fiduciary acts in the Best Interest of a
The Impartial Conduct Standards represent fundamental obligations of fair dealing and fiduciary conduct. The concepts of prudence, undivided loyalty and reasonable compensation are all deeply rooted in ERISA and the common law of agency and trusts.
Under ERISA section 408(a) and Code section 4975(c)(2), the Department cannot grant an exemption unless it first finds that the exemption is administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of participants and beneficiaries of plans and IRA owners. Imposition of the Impartial Conduct Standards as a condition of this exemption is critical to the Department's ability to make these findings.
The Impartial Conduct Standards are conditions of the amended exemption for the provision of advice with respect to all plans and IRAs. However, in contrast to the Best Interest Contract Exemption and the Principal Transactions Exemption, there is no contract requirement for advice to plans or IRAs under this amended exemption.
The Department received many comments on the proposal to include the Impartial Conduct Standards as part of these existing exemptions. A number of commenters focused on the Department's authority to impose the Impartial Conduct Standards as conditions of the exemption. Commenters' arguments regarding the Impartial Conduct Standards as applicable to IRAs and non-ERISA plans were based generally on the fact that the standards, as noted above, are consistent with longstanding principles of prudence and loyalty set forth in ERISA section 404, but which have no counterpart in the Code. Commenters took the position that because Congress did not choose to impose the standards of prudence and loyalty on fiduciaries with respect to IRAs and non-ERISA plans, the Department exceeded its authority in proposing similar standards as a condition of relief in a prohibited transaction exemption.
With respect to ERISA plans, commenters stated that Congress' separation of the duties of prudence and loyalty (in ERISA section 404) from the prohibited transaction provisions (in ERISA section 406), showed an intent that the two should remain separate. Commenters additionally questioned why the conduct standards were necessary for ERISA plans, when such plans already have an enforceable right to fiduciary conduct that is both prudent and loyal. Commenters asserted that imposing the Impartial Conduct Standards as conditions of the exemption created strict liability for prudence violations.
Some commenters additionally took the position that Congress, in the Dodd-Frank Act, gave the SEC the authority to establish standards for broker-dealers and investment advisers and therefore, the Department did not have the authority to act in that area.
The Department disagrees that this amendment to the exemption exceeds its authority. The Department has clear authority under ERISA section 408(a) and the Reorganization Plan
The Impartial Conduct Standards represent, in the Department's view, baseline standards of fundamental fair dealing that must be present when fiduciaries make conflicted investment recommendations to retirement investors. After careful consideration, the Department determined that broad relief could be provided to investment advice fiduciaries receiving conflicted compensation only if such fiduciaries provided advice in accordance with the Impartial Conduct Standards—
These Impartial Conduct Standards are necessary to ensure that advisers' recommendations reflect the best interest of their retirement investor customers, rather than the conflicting financial interests of the advisers and their financial institutions. As a result, advisers and financial institutions bear the burden of showing compliance with the exemption and face liability for engaging in a non-exempt prohibited
The Department similarly disagrees that Congress' directive to the SEC in the Dodd-Frank Act limits its authority to establish appropriate and protective conditions in the context of a prohibited transaction exemption. Section 913 of that Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers.
Some commenters suggested that it would be unnecessary to impose the Impartial Conduct Standards on advisers with respect to ERISA plans, as fiduciaries to these Plans already are required to operate within similar statutory fiduciary obligations. The Department considered this comment but has determined not to eliminate the conduct standards as conditions of the exemptions for ERISA plans. One of the Department's goals is to ensure equal footing for all retirement investors. The SEC staff study required by section 913 of the Dodd-Frank Act found that investors were frequently confused by the differing standards of care applicable to broker-dealers and registered investment advisers. The Department hopes to minimize such confusion in the market for retirement advice by holding fiduciaries to similar standards, regardless of whether they are giving the advice to an ERISA plan, IRA, or a non-ERISA plan.
Moreover, inclusion of the standards as conditions of these existing exemptions adds an important additional safeguard for ERISA and IRA investors alike because the party engaging in a prohibited transaction has the burden of showing compliance with an applicable exemption, when violations are alleged.
Other commenters generally asserted that the Impartial Conduct Standards were too vague and would result in the exemption failing to meet the “administratively feasible” requirement under ERISA section 408(a) and Code section 4975(c)(2). The Department disagrees with these commenters' suggestion that ERISA section 408(a) and Code section 4975(c)(2) fail to be satisfied by a principles-based approach, or that standards are unduly vague. It is worth repeating that the Impartial Conduct Standards are built on concepts that are longstanding and familiar in ERISA and the common law of trusts and agency. Far from requiring adherence to novel standards with no antecedents, the exemptions primarily require adherence to well-established fundamental obligations of fair dealing and fiduciary conduct. This preamble provides specific interpretations and responses to a number of issues raised in connection with a number of the Impartial Conduct Standards.
Comments on each of the Impartial Conduct Standards are discussed below. In this regard, some commenters focused their comments on the Impartial Conduct Standards in the proposed Best Interest Contract Exemption and other proposals, as opposed to the proposed amendment to PTE 86-128. The Department determined it was important that the provisions of the exemptions, including the Impartial Conduct Standards, be uniform and compatible across exemptions. For this reason, the Department considered all comments made on any of the exemption proposals on a consolidated basis, and made corresponding changes across the projects. For ease of use, this preamble includes the same general discussion of comments as in the Best Interest Contract Exemption, despite the fact that some comments discussed below were not made directly with respect to this exemption.
Under Section II(a), when exercising fiduciary authority described in ERISA section 3(21)(A)(i) or (ii), or Code section 4975(e)(3)(A) or (B), with respect to the assets involved in the transaction, a fiduciary relying on the amended exemption must act in the Best Interest of the plan or IRA, at the time of the exercise of authority (including, in the case of an investment advice fiduciary, the recommendation). A fiduciary acts in the Best Interest of the plan or IRA when:
This Best Interest standard set forth in the final amendment is based on longstanding concepts derived from ERISA and the law of trusts. It is meant to express the concept, set forth in ERISA section 404, that a fiduciary is required to act “solely in the interest of the participants . . . with the care, skill, prudence, and diligence under the circumstances then prevailing that a
A wide range of commenters indicated support for a broad “best interest” standard. Some comments indicated that the best interest standard is consistent with the way advisers provide investment advice to clients today. However, a number of these commenters expressed misgivings as to the definition used in the proposed amendment, in particular, the “without regard to” formulation. The commenters indicated uncertainty as to the meaning of the phrase, including whether it permitted the fiduciary engaging the in the transaction to be paid.
Other commenters asked the Department to use a different definition of Best Interest, or simply use the exact language from ERISA's section 404 duty of loyalty. Others suggested definitional approaches that would require that the fiduciary “not subordinate” their customers' interests to their own interests, or that the fiduciary “put their customers' interests ahead of their own interests,” or similar constructs.
The Financial Industry Regulatory Authority (FINRA)
Other commenters found the Best Interest standard to be an appropriate statement of the obligations of a fiduciary investment advice provider and believed it would provide concrete protections against conflicted recommendations. These commenters asked the Department to maintain the Best Interest definition as proposed. One commenter wrote that the term “best interest” is commonly used in connection with a fiduciary's duty of loyalty and cautioned the Department against creating an exemption that failed to include the duty of loyalty. Others urged the Department to avoid definitional changes that would reduce current protections to plans and IRAs. Some commenters also noted that the “without regard to” language is consistent with the recommended standard in the SEC staff Dodd-Frank Study, and suggested that it had the added benefit of potentially harmonizing with a future securities law standard for broker-dealers.
The final amendment retains the Best Interest definition as proposed, with minor adjustments. The first prong of the standard was revised to more closely track the statutory language of ERISA section 404(a), and, is consistent with the Department's intent to hold investment advice fiduciaries to a prudent investment professional standard. Accordingly, the definition of Best Interest now requires advice that reflects “the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person
The Department continues to believe that the “without regard to” language sets forth the appropriate, protective standard under which a fiduciary investment adviser should act. Although the exemption provides broad relief for fiduciaries to receive commissions and other payments based on their advice, the standard ensures that the advice will not be tainted by self-interest. Many of the alternative approaches suggested by commenters pose their own ambiguities and interpretive challenges, and lower standards run the risk of undermining this regulatory initiative's goal of reducing the impact of conflicts of interest on plans and IRAs.
The Department has not specifically incorporated the suitability obligation as an element of the Best Interest standard, as suggested by FINRA, but many aspects of suitability are also elements of the Best Interest standard. An investment recommendation that is not suitable under the securities laws would not meet the Best Interest standard. Under FINRA's Rule 2111(a) on suitability, broker-dealers “must have a reasonable basis to believe that a recommended transaction or investment strategy involving a security or securities is suitable for the customer.” The text of rule 2111(a), however, does not do any of the following: Reference a best interest standard, clearly require brokers to put their client's interests ahead of their own, expressly prohibit the selection of the least suitable (but more remunerative) of available investments, or require them to take the kind of measures to avoid or mitigate conflicts of interests that are required as conditions of this amended exemption.
The Department recognizes that FINRA issued guidance on Rule 2111 in which it explains that “in interpreting the suitability rule, numerous cases explicitly state that a broker's recommendations must be consistent with his customers' best interests,” and provided examples of conduct that would be prohibited under this standard, including conduct that this exemption would not allow.
The Best Interest standard, as set forth in the exemption, is intended to effectively incorporate the objective
Several commenters requested additional guidance on the Best Interest standard. Investment advice fiduciaries that are concerned about satisfying the standard may wish to consult the policies and procedures requirement in Section II(d) of the Best Interest Contract Exemption. While these policies and procedures are not an express condition of PTE 86-128, they may provide useful guidance for financial institutions wishing to ensure that individual advisers adhere to the Impartial Conduct Standards. The preamble to the Best Interest Contract Exemption provides examples of policies and procedures prudently designed to ensure that advisers adhere to the Impartial Conduct Standards. The examples are not intended to be exhaustive or mutually exclusive, and range from examples that focus on eliminating or nearly eliminating compensation differentials to examples that permit, but police, the differentials.
A few commenters also questioned the requirement in the Best Interest standard that the fiduciary's actions be made without regard to the interest of the fiduciary, its affiliate, a Related Entity or “
Other commenters asked for confirmation that the Best Interest standard is applied based on the facts and circumstances as they existed at the time of the recommendation, and not based on hindsight. Consistent with the well-established legal principles that exist under ERISA today, the Department confirms that the Best Interest standard is not a hindsight standard, but rather is based on the facts as they existed at the time of the recommendation. Thus, the courts have evaluated the prudence of a fiduciary's actions under ERISA by focusing on the process the fiduciary used to reach its determination or recommendation—whether the fiduciaries, “at the time they engaged in the challenged transactions, employed the proper procedures to investigate the merits of the investment and to structure the investment.”
This is not to suggest that the ERISA section 404 prudence standard or Best Interest standard, are solely procedural standards. Thus, the prudence standard, as incorporated in the Best Interest standard, is an objective standard of care that requires fiduciaries to investigate and evaluate investments, make recommendations, and exercise sound judgment in the same way that knowledgeable and impartial professionals would. “[T]his is not a search for subjective good faith—a pure heart and an empty head are not enough.”
The Department additionally confirms its intent that the phrase “without regard to” be given the same meaning as the language in ERISA section 404 that requires a fiduciary to act “solely in the interest of” participants and beneficiaries, as such standard has been interpreted by the Department and the courts. Accordingly, the standard would not, as some commenters suggested, foreclose the fiduciary from being paid “reasonable compensation,” and the exemption specifically contemplates such compensation.
In response to commenter concerns, the Department also confirms that the Best Interest standard does not impose an unattainable obligation on fiduciaries to somehow identify the single “best” investment for the plan or IRA out of all the investments in the national or international marketplace, assuming such advice were even possible. Instead, as discussed above, the Best Interest standard set out in the exemption, incorporates two fundamental and well-established fiduciary obligations: The duties of prudence and loyalty. Thus, the fiduciary's obligation under the Best Interest standard is to manage or give advice that adheres to professional standards of prudence, and to put the plan's or IRA's financial interests in the driver's seat, rather than the competing interests of the fiduciary or other parties.
Finally, in response to questions regarding the extent to which this Best Interest standard or other provisions of the exemption impose an ongoing monitoring obligation on fiduciaries, the text does not impose a monitoring requirement, but instead leaves that to the parties' arrangements, agreements, and understandings. This is consistent with the Department's interpretation of an investment advice fiduciary's monitoring responsibility as articulated in the preamble to the Regulation.
The Impartial Conduct Standards also include the reasonable compensation standard, set forth in Section II(b). Under this standard, the fiduciary engaging in the covered transaction and any Related Entity must not receive compensation in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
The obligation to pay no more than reasonable compensation to service providers is long recognized under ERISA and the Code. ERISA section 408(b)(2) and Code section 4975(d)(2) require that services arrangements involving plans and IRAs result in no more than reasonable compensation to the service provider. Accordingly, fiduciaries—as service providers—have long been subject to this requirement, regardless of their fiduciary status. At bottom, the standard simply requires that compensation not be excessive relative to the value of the particular services, rights, and benefits the fiduciary is delivering to the plan or IRA. Given the conflicts of interest associated with the commissions, it is particularly important that fiduciaries adhere to these statutory standards which are rooted in common law principles.
Several commenters supported this standard and said that the reasonable compensation requirement is an important and well-established protection. A number of other commenters requested greater specificity as to the meaning of the reasonable compensation standard. As proposed, the standard stated:
All compensation received by the [fiduciary] and any Related Entity in connection with the transaction is reasonable in relation to the total services the person and any Related Entity provide to the plan.
Some commenters stated that the proposed reasonable compensation standard was too vague. Because the language of the proposal did not reference ERISA section 408(b)(2) and Code section 4975(d)(2), commenters asked whether the standard differed from those statutory provisions. In particular, a commenter questioned the meaning of the proposed language “in relation to the total services the person and any Related Entity provide to the plan.” The commenter indicated that the proposal did not adequately explain this formulation of reasonable compensation.
There was concern that the standard could be applied retroactively rather than based on the parties' reasonable beliefs as to the reasonableness of the compensation as determined at the time the fiduciary exercised authority over plan assets or made an investment recommendation. Commenters also indicated uncertainty as to how to comply with the condition and asked whether it would be necessary to survey the market to determine market rates. Some commenters requested that the Department include the words “and customary,” in the reasonable compensation definition, to specifically permit existing compensation arrangements. One commenter raised the concern that the reasonable compensation determination raised antitrust concerns because it would require investment advice fiduciaries to agree upon a market rate and result in anti-competitive behavior.
Commenters also asked the Department to provide examples of scenarios that met the reasonable compensation standard and safe harbors and others requested examples of scenarios that would fail to meet these standards. FINRA and other commenters suggested that the Department incorporate existing FINRA rules 2121 and 2122, and NASD rule 2830 regarding the reasonableness of compensation for broker-dealers.
Finally, a few commenters took the position that the reasonable compensation determination should not be a requirement of the exemption. In their view, a plan fiduciary that is not the fiduciary engaging in the covered transaction (perhaps the authorizing fiduciary) should decide the reasonableness of the compensation. Another commenter suggested that if an independent plan fiduciary sets the menu this should be sufficient to comply with the reasonable compensation standard.
In response to comments on this requirement, the Department has retained the reasonable compensation standard as a condition of the exemption. As noted above, the obligation that service providers receive no more than “reasonable compensation” for their services is already established by ERISA and the Code, and has long applied to financial services providers, whether fiduciaries or not. The condition is also consistent with other class exemptions granted and amended today. It is particularly important that fiduciaries adhere to these standards when engaging in the transactions covered under this exemption, so as to avoid exposing plans and IRAs to harms associated with conflicts of interest.
Some commenters suggested that the reasonable compensation determination be made by another plan fiduciary. However, the exemption (like the statutory obligation) obligates investment advice fiduciaries to avoid overcharging their plan and IRA customers, despite any conflicts of interest associated with their compensation. Fiduciaries and other service providers may not charge more than reasonable compensation regardless of whether another fiduciary has signed off on the compensation. Nothing in the exemption, however, precludes fiduciaries from seeking impartial review of their fee structures to safeguard against abuse, and they may well want to include such reviews as part of their supervisory practices.
Further, the Department disagrees that the requirement is inconsistent with antitrust laws. Nothing in the exemption contemplates or requires that Advisers or Financial Institutions agree upon a price with their competitors. The focus of the reasonable compensation condition is on preventing overcharges to Retirement Investors, not promoting anti-competitive practices. Indeed, if Advisors and Financial Institutions consulted with competitors to set prices, the agreed-upon prices could well violate the condition.
In response to comments, however, the operative text of the final exemption was clarified to adopt the well-established reasonable compensation standard, as set out in ERISA section 408(b)(2) and Code section 4975(d)(2), and the regulations thereunder. The reasonableness of the fees depends on the particular facts and circumstances at the time of the fiduciary investment recommendation or exercise of fiduciary authority. Several factors inform whether compensation is reasonable including,
In response to concerns about application of the standard to investment products that bundle together services and investment guarantees or other benefits, the Department responds that the reasonable compensation condition is intended to apply to the compensation received by the Financial Institution, Adviser, Affiliates, and Related Entities in same manner as the reasonable compensation condition set forth in ERISA section 408(b)(2) and Code section 4975(d)(2). Accordingly, the exemption's reasonable compensation standard covers compensation received directly from the plan or IRA and indirect compensation received from any source other than the plan or IRA in connection with the recommended transaction.
The Department declines suggestions to provide specific examples of “reasonable” amounts or specific safe harbors. Ultimately, the “reasonable compensation” standard is a market based standard. As noted above, the standard incorporates the familiar ERISA section 408(b)(2) and Code section 4975(d)(2) standards. The Department is unwilling to condone all “customary” compensation arrangements and declines to adopt a standard that turns on whether the agreement is “customary.” For example, it may in some instances be “customary” to charge customers fees that are not transparent or that bear little relationship to the value of the services actually rendered, but that does not make the charges reasonable. Similarly, the Department declines to provide that the reasonable compensation condition is automatically satisfied as long as the charges do not exceed specific pricing ceilings or restrictions imposed by other regulators or self-regulatory organizations. Certainly, charging an investor even more than permitted under such a ceiling or restriction would generally violate the prohibition on “unreasonable compensation.” But the reasonable compensation standard does not merely forbid fiduciaries from charging amounts that are per se illegal under other regulatory regimes. Finally, the Department notes that all recommendations are subject to the overarching Best Interest standard, which incorporates the fundamental fiduciary obligations of prudence and loyalty. An imprudent recommendation for an investor to overpay for an investment transaction would violate that standard, regardless of whether the overpayment was attributable to compensation for services, a charge for benefits or guarantees, or something else.
The final Impartial Conduct Standard, set forth in Section II(c), requires that the fiduciary's statements about the transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a plan's or IRA's investment decisions, may not be materially misleading at the time they are made. For this purpose, a fiduciary's failure to disclose a Material Conflict of Interest relevant to the services the fiduciary is providing or other actions it is taking in relation to a plan's investment decisions is deemed to be a misleading statement. In response to commenters, the Department adjusted the text to clarify that the standard is measured at the time of the representations,
Some comments focused on the proposed definition of Material Conflict of Interest. As proposed, a Material Conflict of Interest was defined to exist when a person has a financial interest that could affect the exercise of its best judgment as a fiduciary in rendering advice to a plan or IRA. Some commenters took the position that the proposal did not adequately explain the term “material” or incorporate a “materiality” standard into the definition. A commenter wrote that the proposed definition was so broad it would be difficult for financial institutions to comply with the various aspects of the exemption related to Material Conflicts of Interest, such as provisions requiring disclosures of Material Conflicts of Interest.
Another commenter indicated that the Department should not use the term “material” in defining conflicts of interest. The commenter believed that it could result in a standard that was too subjective from the perspective of the fiduciary and could undermine the protectiveness of the exemption.
After consideration of the comments, the Department adjusted the definition of Material Conflict of Interest to provide that a material conflict of interest exists when a fiduciary has a “financial interest that
The Department did not accept certain other comments, however. One commenter requested that the Department add a qualifier providing that the standard is violated only if the statement was “reasonably relied” on by the retirement investor. The Department rejected the comment. The Department's aim is to ensure that fiduciaries uniformly adhere to the Impartial Conduct Standards, including the obligation to avoid materially misleading statements.
One commenter asked the Department to require only that the fiduciary “reasonably believe” the statements are not misleading. The Department is concerned that this standard too could undermine the protections of this condition, by requiring retirement investors to prove the fiduciary's actual knowledge rather than focusing on whether the statement is objectively misleading. However, to address commenters' concerns about the risks of engaging in a prohibited transaction, as noted above, the Department has clarified that the standard is measured at the time of the representations and has added a materiality standard.
The Department believes that plans and IRAs are best served by statements and representations that are free from material misstatements. Fiduciaries best avoid liability—and best promote the interests of plans and IRA—by ensuring that accurate communications are a consistent standard in all their interactions with their customers.
A commenter suggested that the Department adopt FINRA's “Frequently Asked Questions regarding Rule 2210” regarding the term misleading.
To provide certainty with respect to the payments permitted by the exemption in both Section I(a) and new Section I(b), the amendment adds a new defined term “Commission.” This term replaces the language originally in the exemption that permits a fiduciary to cause a plan or IRA to pay a “fee for effecting or executing securities transactions.” The term “Commission” is defined to mean a brokerage commission or sales load paid for the service of effecting or executing the transaction, but not a 12b-1 fee, revenue sharing payment, marketing fee, administrative fee, sub-TA fee, or sub-accounting fee.
In connection with this clarifying amendment to the definition of commission, two commenters requested that the Commission definition specifically include, not exclude, 12b-1 fees, revenue sharing payments, marketing fees, administrative fees, sub-TA fees, sub-accounting fees and other consideration. The commenters indicate that these forms of compensation are inherent to agency transactions and without documented harm. Further, these forms of compensation are used to pay for services. Without this compensation, the commenters argue, brokers will cease offering agency services to plans and IRAs.
The Department agrees that many of these forms of compensation may be commonly associated with agency transactions, particularly with respect to mutual fund purchases, holdings and sales. However, as stated above, such forms of compensation do raise substantial conflict of interest concerns that are not addressed by this exemption. PTE 86-128 was originally granted in 1975 and amended several times over the years. The exemption narrowly applied to fees from a plan or IRA for effecting or executing securities transactions. The Department has never formally interpreted or amended PTE 86-128 to provide relief for the forms of indirect compensation suggested by commenters, such as 12b-1 fees and revenue sharing payments. In the Department's view, it does not contain conditions that adequately address the particular conflicts associated with such payments. On the other hand, the Best Interest Contract Exemption was designed for such payments and includes conditions to address them. The Department intends that parties seeking a wider scope of relief should rely on the Best Interest Contract Exemption as opposed to PTE 86-128, as amended.
Section III of the exemption establishes conditions applicable to the covered transactions. Among the conditions is the requirement in Section III(b) that the covered transaction occur under a written authorization executed in advance by an independent fiduciary of each plan whose assets are involved in the transaction. A commenter asked us to clarify whether an IRA owner could satisfy the authorization requirements applicable to the independent plan fiduciary. In response, we have added “or IRA owner” throughout the requirements in Section III related to plan fiduciary authorization, to make clear that an IRA owner may authorize the covered transaction with respect to the IRA. We did not, however, add the IRA owner to the provision requiring the plan fiduciary to be “independent” of the person engaging in the covered transaction. Therefore, an IRA owner employed by the investment management fiduciary relying on the exemption will still be able to satisfy the authorization requirement. This reflects the Department's view that the interaction of the employer and employee with regard to an IRA that is not employer sponsored is likely to be voluntary and less likely to have the heightened conflicts of interest associated with an employer providing advice to an employer-sponsored plan, and earning a profit. Accordingly, an investment management fiduciary may provide advice to the beneficial owner of an IRA who is employed by the fiduciary and receive prohibited compensation as a result, provided the IRA is not covered by Title I of ERISA.
For IRAs and non-ERISA plans that are existing customers as of the Applicability Date of this amendment, the Department has provided that the fiduciary engaging in the transaction need not receive the affirmative consent generally required by Section III(b), but may instead rely on the IRA's or non-ERISA plan's negative consent, as long as the disclosures and consent termination form are provided to the IRA or non-ERISA plan by the Applicability Date.
The Department received other comments on conditions in Section III of PTE 86-128 that touch on discreet concerns. One commenter raised the bulk of these concerns. The comments related to the annual reauthorization requirement in Section III(c) and the portfolio turnover ratio requirement in Section III(f)(4), and are discussed below.
Section III(c) provides that an annual reauthorization is necessary for a fiduciary to engage in transactions pursuant to the exemption. As an alternative to affirmative reauthorization, the fiduciary may supply a form expressly providing an election to terminate the authorization with instructions on the use of the form. The instructions must provide for a 30-day window after which failure to return the form or some other written notification of the plan's intent to terminate the authorization will result in continued authorization.
A commenter first asked for clarification regarding the ability of a fiduciary to rely on the exemption's relief during the 30-day reauthorization window established in Section III(c). In response, the Department states that relief is available until the point at which a fiduciary fails to comply with a condition of the exemption. Since a fiduciary will not be in breach of a condition until the expiration of the 30-day window, the fiduciary may rely on the exemption's relief until the closing of that window, and it will not retroactively lose the relief relied upon by the fiduciary during the 30-day window.
Second, the commenter argued that the termination notice contemplated by Section III(c) should be effective only if the customer uses a specific termination form. The Department disagrees. The exemption provides that the termination notice must be a written notice (whether first class mail, personal delivery or email). Requiring a written notice should avoid the problems created by oral notices (
Section III(f)(4) establishes the requirement that the fiduciary provide a portfolio turnover ratio at least once per year. The portfolio turnover ratio is a disclosure designed to assist the authorizing fiduciary or IRA owner by disclosing the amount of turnover or churning in the portfolio during the applicable period. Section III(f)(4)(B) describes the “annualized portfolio turnover ratio” as calculated as a percentage of the plan assets over which the fiduciary had discretionary investment authority at any time during the period covered by the report.
The commenter addressed the application of the portfolio turnover ratio disclosure requirement to investment advice fiduciaries. The commenter argued that the provision of the portfolio turnover ratio was not originally required under the exemption and was not workable in the investment adviser context since the adviser does not manage the investor's portfolio.
The Department acknowledges that Section III(f), prior to the amendment, included potentially contradictory language regarding the applicability of the portfolio turnover ratio disclosure to investment advice fiduciaries. In addition, the Department concurs with the commenter that the portfolio turnover ratio may not be as necessary to plans and participants and beneficiaries in the context of an investment advice relationship, as opposed to an investment management relationship where the fiduciary is making discretionary investment decisions. As a result, the final exemption makes clear that the portfolio turnover ratio is not required from fiduciaries that have not exercised discretionary authority over trading in the plan's account during the applicable year.
Section V(b) of the amended exemption provides that certain conditions in Section III do not apply in any case where the person who is engaging in a covered transaction returns or credits to the plan all profits earned by that person and any Related Entity in connection with the securities transactions associated with the covered transaction. This provision is referred to as the recapture of profits exception. The Department provided an exception from the conditions in Section III for the recapture of profits due to the benefits to the plans and IRAs of such arrangements.
As explained above, discretionary trustees were first permitted to rely on PTE 86-128 without meeting the “recapture of profits” provision pursuant to an amendment in 2002 (2002 Amendment). The 2002 Amendment imposed additional conditions on such trustees. However, the 2002 Amendment also introduced uncertainty as to whether trustees could continue to rely on the recapture of profits exception instead of complying with the additional conditions. The Department did not intend to call such arrangements into question, and, accordingly, has modified the exemption to permit trustees to utilize the exception as originally permitted in PTE 86-128 for the recapture of profits.
The Department received a supportive comment on these provisions and has finalized the amendments as proposed.
Section V(c) provides special rules for pooled funds. Under that provision, the disclosure and authorization conditions set forth in Section III(b), (c) and (d) do not apply to pooled funds, if the alternate conditions in Section V(c) are satisfied. One such condition, in Section V(c)(1)(B), is that
The proposed amendment to PTE 86-128 included a revision to this provision, under which the authorizing fiduciary would be furnished with information “reasonably necessary” to determine whether the authorization should be given or continued, rather than “reasonably available information” that the investment advice fiduciary or investment management fiduciary reasonably believed is necessary to determine whether the authorization should be given or continued. One commenter objected to this proposed revision, on the basis that this new standard might require the fiduciary to provide information not in its possession or to prove that it had provided all information others might find relevant, and as a result, could cause fiduciaries to stop relying on the exemption.
The Department proposed the revision with a “reasonableness” qualifier to avoid overbroad application. However, the Department understands market participants' preference for a longstanding standard. As a practical matter, the Department does not believe that there will be much difference in the materials provided under this standard than under the one proposed. The authorizing fiduciary must still review sufficient information to determine whether the authorization should be given or continued. The Department, therefore, has accepted the comment, and the final amendment reverts back to the original language.
A new Section VI to PTE 86-128 requires the fiduciary engaging in a transaction covered by the exemption to maintain for six years records necessary to enable certain persons (described in Section VI(b)) to determine whether the conditions of this exemption have been
One commenter addressed the proposed record keeping requirement. The commenter suggested that the requirement should contain a “reasonableness” standard. The commenter also suggested that the exemption make clear that access by plans and participants and beneficiaries is limited to their own plans and their own accounts, and that any failure to maintain the required records with respect to a given transaction or set of transactions does not affect exemptive relief for other transactions. Lastly, the commenter indicated that the 30 day requirement for notice with respect to a refusal of disclosure of records, on the basis that the records involve privileged trade secrets or other privileged commercial or financial information, was not sufficient. The commenter sought a 90-day period.
The Department has modified the recordkeeping provision to include a reasonableness standard for making the records available, and clarify which parties may view the records that are maintained by the fiduciary engaging in the covered transaction. As revised, the exemption requires the records be “reasonably” available, rather than “unconditionally available” and does not authorize plan fiduciaries, participants, beneficiaries, contributing employers, employee organizations with members covered by the plan, and IRA owners to examine records regarding another plan or IRA. In addition, fiduciaries are not required to disclose privileged trade secrets or privileged commercial or financial information to any of the parties other than the Department, as was also true of the proposal.
The Department also added new language to the recordkeeping condition to indicate that the consequences of failure to comply with the recordkeeping requirement are limited to the transactions affected by the failure. Therefore, a new Section VI(b)(4) provides that
Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
Finally, in accordance with other exemptions granted and amended today, Financial Institutions are also not required to disclose records if such disclosure would be precluded by 12 U.S.C. 484, relating to visitorial powers over national banks and federal savings associations.
Section VII of PTE 86-128 sets forth definitions applicable to the exemption. One commenter suggested revisions to the definition of “independent” in Section VII(f). This term is used in connection with the authorization requirements under the exemption and it requires that the person making the authorizations be independent of the investment advice fiduciary or investment management fiduciary seeking to rely on the exemption. As proposed, the definition of independent would have precluded the authorizing entity from receiving any compensation or other consideration for his or her own account from the investment advice fiduciary or investment management fiduciary.
A commenter indicated that the definition might inadvertently disqualify certain entities that provide services (
The Department agrees with the commenter; provided, however, that the expanded definition is determined based on the current tax year and may not be in excess of 2% of the fiduciary's annual revenues based on the prior year. This approach is consistent with the Department's general approach to fiduciary independence. For example, the prohibited transaction exemption procedures provide a presumption of independence for appraisers and fiduciaries if the revenue they receive from a party is not more than 2% of their total annual revenue.
The same commenter indicated that the exemption's definition of IRA in Section VII(k) should not include other non-ERISA plans covered by Code section 4975, such as Health Savings Accounts (HSAs), Archer Medical Savings Accounts and Coverdell Education Savings Accounts. However, in response, the Department notes that these accounts, like IRAs, are tax-preferred. Further, some of the accounts, such as HSAs, can be used as long term savings accounts for retiree health care expenses. These types of accounts also are expressly defined by Code section 4975(e)(1) as plans that are subject to the Code's prohibited transaction rules. Thus, although they generally may hold fewer assets and may exist for shorter durations than IRAs, there is no statutory reason to treat them differently than other conflicted transactions and no basis for suspecting that the conflicts are any less influential with respect to advice with respect to these arrangements. Accordingly, the Department does not agree with the commenters that the owners of these accounts are entitled to less protection than IRA investors. The Regulation continues to include advisers to these “plans,” and this exemption provides relief to them in the same manner it does for individual retirement accounts described in section 408(a) of the Code.
The Department is revoking Part I(b) and I(c) of PTE 75-1, and Part II(2) of PTE 75-1. Part I(b) of PTE 75-1 provided relief from ERISA section 406 and the taxes imposed by Code section 4975(a) and (b), for the effecting of securities transactions, including clearance, settlement or custodial functions incidental to effecting the transactions, by parties in interest or disqualified persons other than fiduciaries. Part I(c) of PTE 75-1 provided relief from ERISA section 406
PTE 75-1 was granted shortly after ERISA's passage in order to provide certainty to the securities industry over the nature and extent to which ordinary and customary transactions between broker-dealers and plans or IRAs would be subject to the ERISA prohibited transaction rules. Paragraphs (b) and (c) in Part I of PTE 75-1, specifically, served to provide exemptive relief for certain non-fiduciary services provided by broker-dealers in securities transactions. Code section 4975(d)(2), ERISA section 408(b)(2) and regulations thereunder, have clarified the scope of relief for service providers to plans and IRAs.
As noted earlier, the exemption in PTE 75-1, Part II(2), is being incorporated into PTE 86-128. Accordingly, the Department is revoking PTE 75-1, Part II(2). In connection with the revocation of PTE 75-1, Part II(2), the Department is amending Section (e) of the remaining exemption in PTE 75-1, Part II, the recordkeeping provisions of the exemption, to place the recordkeeping responsibility on the broker-dealer, reporting dealer, or bank engaging in transactions with the plan or IRA, as opposed to the plan or IRA itself.
A few commenters suggested that the Department should not revoke PTE 75-1, Part II(2). They argued that that exemption provides needed relief for consideration received in connection with mutual fund share transactions.
As stated above, the Department disagrees. PTE 75-1, Part II(2) was an exemption that was broadly interpreted beyond what was intended, and that contained minimal safeguards. Providing an exemption for fiduciaries to receive compensation under the conditions of PTE 75-1, Part II(2) is not protective of retirement investors. Instead, the Department has provided relatively limited relief for mutual fund transactions in Section I(b) of the amended PTE 86-128 and much broader relief in the Best Interest Contract Exemption. The Best Interest Contract Exemption, as stated above, imposes more appropriate conditions on the receipt of compensation that goes beyond simple commissions.
The Regulation will become effective June 7, 2016 and these amended exemptions are issued on that same date. The Regulation is effective at the earliest possible effective date under the Congressional Review Act. For the exemptions, the issuance date serves as the date on which the amended exemptions are intended to take effect for purposes of the Congressional Review Act. This date was selected in order to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the Regulation are officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the Regulation and amended exemptions are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, that an Applicability Date of April 10, 2017, is adequate time for plans and their affected financial services and other service providers to adjust to the basic change from non-fiduciary to fiduciary status. The amendments to and partial revocations of PTEs 86-128 and 75-1, Part II, as finalized herein have the same Applicability Date; parties may therefore rely on the amended exemptions beginning on the Applicability Date. For the avoidance of doubt, no revocation will be applicable prior to the Applicability Date.
In accordance with the requirements of the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)), the Amendment to and Partial Revocation of Prohibited Transaction Exemption (PTE) 86-128 for Securities Transactions Involving Employee Benefit Plans and Broker-Dealers; and the Amendment to and Partial Revocation of PTE 75-1, Exemptions From Prohibitions Respecting Certain Classes of Transactions Involving Employee Benefits Plans and Certain Broker-Dealers, Reporting Dealers and Banks published as part of the Department's proposal to amend its 1975 rule that defines when a person who provides investment advice to an employee benefit plan or IRA becomes a fiduciary, solicited comments on the information collections included therein. The Department also submitted an information collection request (ICR) to OMB in accordance with 44 U.S.C. 3507(d), contemporaneously with the publication of the proposed regulation, for OMB's review. The Department received two comments from one commenter that specifically addressed the paperwork burden analysis of the information collections. Additionally, many comments were submitted, described elsewhere in the preamble to the accompanying final rule, which contained information relevant to the costs and administrative burdens attendant to the proposals. The Department took into account such public comments in connection with making changes to the prohibited transaction exemption, analyzing the economic impact of the proposals, and developing the revised paperwork burden analysis summarized below.
In connection with publication of this final amendment to and partial revocation of PTE 86-128 and this final amendment to and partial revocation of PTE 75-1, the Department is submitting an ICR to OMB requesting approval of a revision to OMB Control Number 1210-0059. The Department will notify the public when OMB approves the revised ICR.
A copy of the ICR may be obtained by contacting the PRA addressee shown below or at
As discussed in detail below, as amended, PTE 86-128 will require financial firms to make certain disclosures to plan fiduciaries and owners of managed IRAs in order to receive relief from ERISA's and the Code's prohibited transaction rules for the receipt of commissions and to engage in transactions involving mutual
The Department has made the following assumptions in order to establish a reasonable estimate of the paperwork burden associated with these ICRs:
• 51.8 percent of disclosures to retirement investors with respect to ERISA plans
• Financial institutions will use existing in-house resources to prepare the legal authorizations and disclosures, and maintain the recordkeeping systems necessary to meet the requirements of the exemption;
• A combination of personnel will perform the tasks associated with the ICRs at an hourly wage rate of $167.32 for a financial manager, $55.21 for clerical personnel, and $133.61 for a legal professional;
• Approximately 2,800 financial institutions
In order to receive commissions in conjunction with the purchase of mutual fund shares and other securities, sections III(b) and III(d) of PTE 86-128 as amended require financial institutions to obtain advance written authorization from a plan fiduciary independent of the financial institutions (the authorizing fiduciary), or managed IRA owner, and furnish the authorizing fiduciary or managed IRA owner with information necessary to determine whether an authorization should be made, including a copy of the exemption, a form for termination, a description of the financial institution's brokerage placement practices, and any other reasonably available information regarding the matter that the authorizing fiduciary or managed IRA owner requests.
Section III(c) requires financial institutions to obtain annual written reauthorization or provide the authorizing fiduciary or managed IRA owner with an annual termination form explaining that the authorization is terminable at will, without penalty to the plan or IRA, and that failure to return the form will result in continued authorization for the financial institution to engage in covered transactions on behalf of the plan or IRA. Furthermore, Section III(e) requires the financial institution to provide the authorizing fiduciary with either (a) a confirmation slip for each individual securities transaction within 10 days of the transaction containing the information described in Rule 10b-10(a)(1-7) under the Securities Exchange Act of 1934, 17 CFR 240.10b-10 or (b) a quarterly report containing certain financial information including the total of all transaction-related charges incurred by the plan. The Department assumes that financial institutions will meet this requirement for 40 percent of plans and IRAs through the provision of a confirmation slip, which already is provided to their clients in the normal course of business, while financial institutions will meet this requirement for 60 percent of plans and IRAs through provision of the quarterly report.
Finally, Section III(f) requires the financial institution to provide the authorizing fiduciary or managed IRA owner with an annual summary of the confirmation slips or quarterly reports. The summary must contain the following information: The total of all securities transaction-related charges incurred by the plan or IRA during the period in connection with the covered securities transactions; the amount of the securities transaction-related charges retained by the authorized person and the amount of these charges paid to other persons for execution or other services; a description of the financial institution's brokerage placement practices if such practices have materially changed during the period covered by the summary; and a
According to the 2013 Form 5500, approximately 681,000 plans exist in the United States that could enter into relationships with financial institutions. The Department lacks reliable data on the number of managed IRA and non-ERISA plans with relationships with broker-dealers, but estimates that they number less than 10,000. Of these plans and managed IRAs, the Department assumes that 6.5 percent are new plans, managed IRAs and non-ERISA plans, or plans, managed IRAs or non-ERISA plans entering into relationships with new financial institutions
The Department estimates that approximately 161,000 plans and 2,000 managed IRAs and non-ERISA plans have relationships with financial institutions and are likely to engage in transactions covered under this exemption. Of these 161,000 plans and 2,000 managed IRAs and non-ERISA plans, approximately 11,000 plans, managed IRAs, and non-ERISA plans, are new clients to the financial institutions each year.
The Department estimates that 11,000 plans, managed IRAs and non-ERISA plans will send financial institutions a two page authorization letter each year. Prior to obtaining authorization, financial institutions will send the same 11,000 plans, managed IRAs and non-ERISA plans a seven page pre-authorization disclosure.
The Department estimates that all of the 161,000 plans and 2,000 managed IRAs and non-ERISA plans will receive a two-page annual termination form from financial institutions; 51.8 percent will be distributed electronically to plans and 44.1 percent will be distributed electronically to managed IRAs and non-ERISA plans, while 48.2 percent and 55.9 percent, respectively, will be mailed. The Department estimates that electronic distribution will result in a de minimis cost, while the paper distribution will cost $47,000. Paper distribution will also require two minutes of clerical preparation time per form resulting in a total of 3,000 hours at an equivalent cost of $146,000.
The Department estimates that 60 percent of plans, managed IRAs and non-ERISA plans (approximately 97,000 plans and 1,000 managed IRAs and non-ERISA plans) will receive quarterly two-page transaction reports from financial institutions four times per year; 51.8 percent will be distributed electronically to plans and 44.1 percent will be distributed electronically to managed IRAs and non-ERISA plans, while 48.2 percent and 55.9 percent, respectively, will be mailed. The Department estimates that electronic distribution will result in a de minimis cost, while paper distribution will cost $112,000. Paper distribution will also require two minutes of clerical preparation time per statement resulting in a total of 6,000 hours at an equivalent cost of $349,000.
The Department estimates that all of the 161,000 plans and 2,000 managed IRAs and non-ERISA plans will receive a five-page annual statement with a two-page summary of commissions paid from financial institutions; 51.8 percent will be distributed electronically to plans and 44.1 percent will be distributed electronically to managed IRAs and non-ERISA plans, while 48.2 percent and 55.9 percent, respectively, will be mailed. The Department assumes that these disclosures will be distributed with the annual termination form, resulting in no further clerical hour burden or postage cost. Electronic distribution will result in a de minimis cost, while the paper distribution will cost $28,000 in materials costs.
The Department received one comment suggesting that the burden analysis in the proposal did not account for any costs to compile data necessary to produce the quarterly transaction reports, annual statements, and report of commissions paid. In fact, this burden was taken into account in the proposal and has been updated here. The Department estimates that it will cost financial institutions $3.30 per plan,
Section VI of PTE 86-128, as amended, and condition (e) of PTE 75-1, Part II, as amended, will require financial institutions to maintain or cause to be maintained for six years and disclosed upon request the records necessary for the Department, Internal Revenue Service, plan fiduciary, contributing employer or employee organization whose members are covered by the plan, participants and beneficiaries and managed IRA owners to determine whether the conditions of this exemption have been met.
The Department assumes that each financial institution will maintain these records in their normal course of business. Therefore, the Department has estimated that the additional time needed to maintain records consistent with the exemption will only require about one-half hour, on average, annually for a financial manager to organize and collate the documents or else draft a notice explaining that the information is exempt from disclosure, and an additional 15 minutes of clerical time to make the documents available for inspection during normal business hours or prepare the paper notice explaining that the information is exempt from disclosure. Thus, the Department estimates that a total of 45 minutes of professional time (30 minutes of financial manager time and 15 minutes of clerical time) per financial institution per year will be required for a total hour burden of 2,100 hours at an equivalent cost of $273,000.
In connection with the recordkeeping and disclosure requirement discussed above, Section VI(b) of PTE 86-128 and Section (f) of PTE 75-1, Part II, provide that parties relying on the exemption do not have to disclose trade secrets or other confidential information to members of the public (
Overall, the Department estimates that in order to meet the conditions of this amended class exemption, over 13,000 financial institutions and plans will produce 910,000 disclosures and notices during the first year and 906,000 disclosures and notices during subsequent years. These disclosures and notices will result in approximately 71,000 burden hours during the first year and 67,000 burden hours during subsequent years, at an equivalent cost of $8.7 million and $8.3 million respectively. This exemption will also result in a total annual cost burden of almost $736,000 during the first year and $734,000 during subsequent years.
These paperwork burden estimates are summarized as follows:
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under ERISA section 408(a) and Code section 4975(c)(2) does not relieve a fiduciary or other party in interest or disqualified person with respect to a plan from certain other provisions of ERISA and the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of ERISA section 404 which require, among other things, that a fiduciary discharge his or her duties respecting a plan solely in the interests of the participants and beneficiaries of the plan. Additionally, the fact that a transaction is the subject of an exemption does not affect the requirement of Code section 401(a) that the plan must operate for the exclusive benefit of the employees of the employer maintaining the plan and their beneficiaries;
(2) In accordance with ERISA section 408(a) and Code section 4975(c)(2), and based on the entire record, the Department finds that the amendments are administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of plan participants and beneficiaries and IRA owners;
(3) These amendments are applicable to a particular transaction only if the transaction satisfies the conditions specified in the amended exemptions; and
(4) These amended exemptions will be supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
Under section 408(a) of the Employee Retirement Income Security Act of 1974, as amended (ERISA) and section 4975(c)(2) of the Internal Revenue Code of 1986, as amended (the Code), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, 66644 (October 27, 2011)), the Department amends and restated PTE 86-128 as set forth below:
(a)
(b)
(c)
(2) The exemption set forth in Section I(b) does not apply to transactions involving IRAs.
If the fiduciary engaging in the covered transaction is a fiduciary within the meaning of ERISA section 3(21)(A)(i) or (ii), or Code section 4975(e)(3)(A) or (B), with respect to the assets involved in the transaction, the following conditions must be satisfied with respect to such transaction to the extent they are applicable to the fiduciary's actions:
(a) When exercising fiduciary authority described in ERISA section 3(21)(A)(i) or (ii), or Code section 4975(e)(3)(A) or (B), with respect to the assets involved in the transaction, the fiduciary acts in the Best Interest of the plan at the time of the transaction.
(b) All compensation received by the person and any Related Entity in connection with the transaction is not in excess of reasonable compensation within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(c) The fiduciary's statements about the transaction, fees and compensation, Material Conflicts of Interest, and any other matters relevant to a plan's investment decisions, are not materially misleading at the time they are made. For this purpose, a fiduciary's failure to disclose a Material Conflict of Interest relevant to the services the fiduciary is providing or other actions it is taking in relation to a plan's investment decisions is deemed to be a misleading statement.
Except to the extent otherwise provided in Section V of this exemption, Section I(a) of this exemption applies only if the following conditions are satisfied:
(a) The person engaging in the covered transaction is not a trustee (other than a nondiscretionary trustee), an administrator of the plan, or an employer any of whose employees are covered by the plan. Notwithstanding the foregoing, this condition does not apply to a trustee that satisfies Section III(h) and (i).
(b)(1) The covered transaction is performed under a written authorization executed in advance by a fiduciary of each plan whose assets are involved in the transaction or, in the case of an IRA, the IRA owner. The plan fiduciary is independent of the person engaging in the covered transaction. The authorization is terminable at will by the plan, without penalty to the plan, upon receipt by the authorized person of written notice of termination.
(2) Notwithstanding subsection (1), with respect to IRA owners or non-ERISA plans that are existing customers as of the Applicability Date, a person relying on this exemption may satisfy this Section III(b) and Section III(d) if, no later than the Applicability Date, the person provides the disclosures required by Section III(d) and a form expressly providing an election to terminate the services arrangement, with instructions on the use of the form, to the IRA owner or plan fiduciary. The instructions for such form must include the following information:
(A) The arrangement is terminable at will by the IRA or non-ERISA plan, without penalty to the IRA or non-ERISA plan, when the authorized person receives (via first class mail, personal delivery, or email) from the IRA owner or plan fiduciary, a written notice of the intent of the IRA or non-ERISA plan to terminate the arrangement; and
(B) Failure to return the form or some other written notification of the IRA's or non-ERISA plan's intent to terminate the arrangement within thirty (30) days from the date the termination form is sent to the IRA owner or non-ERISA plan fiduciary will result in the continued authorization of the authorized person to engage in the covered transactions on behalf of the IRA or non-ERISA plan.
(c) The authorized person obtains annual reauthorization to engage in transactions pursuant to the exemption in the manner set forth in Section III(b). Alternatively, the authorized person may supply a form expressly providing an election to terminate the authorization described in Section III(b) with instructions on the use of the form to the authorizing fiduciary or IRA owner no less than annually. The instructions for such form must include the following information:
(1) The authorization is terminable at will by the plan, without penalty to the plan, when the authorized person receives (via first class mail, personal delivery, or email) from the authorizing fiduciary or other plan official having authority to terminate the authorization, or in the case of an IRA, the IRA owner, a written notice of the intent of the plan to terminate authorization; and
(2) Failure to return the form or some other written notification of the plan's intent to terminate the authorization within thirty (30) days from the date the termination form is sent to the authorizing fiduciary or IRA owner will result in the continued authorization of the authorized person to engage in the covered transactions on behalf of the plan.
(d) Within three months before an initial authorization is made pursuant to Section III(b), the authorizing fiduciary or, in the case of an IRA, the IRA owner is furnished with a copy of this exemption, the form for termination of authorization described in Section III(c), a description of the person's brokerage placement practices, and any other reasonably available information
(e) The person engaging in a covered transaction furnishes the authorizing fiduciary or IRA owner with either:
(1) A confirmation slip for each securities transaction underlying a covered transaction within ten business days of the securities transaction containing the information described in Rule 10b-10(a)(1-7) under the Securities Exchange Act of 1934; or
(2) at least once every three months and not later than 45 days following the period to which it relates, a report disclosing:
(A) A compilation of the information that would be provided to the plan pursuant to Section III(e)(1) during the three-month period covered by the report;
(B) the total of all securities transaction-related charges incurred by the plan during such period in connection with such covered transactions; and
(C) the amount of the securities transaction-related charges retained by such person, and the amount of such charges paid to other persons for execution or other services. For purposes of this paragraph (e), the words “incurred by the plan” shall be construed to mean “incurred by the pooled fund” when such person engages in covered transactions on behalf of a pooled fund in which the plan participates.
(f) The authorizing fiduciary or IRA owner is furnished with a summary of the information required under Section III(e)(1) at least once per year. The summary must be furnished within 45 days after the end of the period to which it relates, and must contain the following:
(1) The total of all securities transaction-related charges incurred by the plan during the period in connection with covered securities transactions.
(2) The amount of the securities transaction-related charges retained by the authorized person and the amount of these charges paid to other persons for execution or other services.
(3) A description of the brokerage placement practices of the person that is engaging in the covered transaction, if such practices have materially changed during the period covered by the summary.
(4)(A) A portfolio turnover ratio, calculated in a manner which is reasonably designed to provide the authorizing fiduciary with the information needed to assist in making a prudent determination regarding the amount of turnover in the portfolio. The requirements of this paragraph (f)(4)(A) will be met if the “annualized portfolio turnover ratio,” calculated in the manner described in paragraph (f)(4)(B), is contained in the summary.
(B) The “annualized portfolio turnover ratio” shall be calculated as a percentage of the plan assets consisting of securities or cash over which the authorized person had discretionary investment authority (the portfolio) at any time or times (management period(s)) during the period covered by the report. First, the “portfolio turnover ratio” (not annualized) is obtained by dividing (i) the lesser of the aggregate dollar amounts of purchases or sales of portfolio securities during the management period(s) by (ii) the monthly average of the market value of the portfolio securities during all management period(s). Such monthly average is calculated by totaling the market values of the portfolio securities as of the beginning and end of each management period and as of the end of each month that ends within such period(s), and dividing the sum by the number of valuation dates so used. For purposes of this calculation, all debt securities whose maturities at the time of acquisition were one year or less are excluded from both the numerator and the denominator. The “annualized portfolio turnover ratio” is then derived by multiplying the “portfolio turnover ratio” by an annualizing factor. The annualizing factor is obtained by dividing (iii) the number twelve by (iv) the aggregate duration of the management period(s) expressed in months (and fractions thereof). Examples of the use of this formula are provided in Section VIII.
(C) The information described in this paragraph (f)(4) is not required to be furnished in any case where the authorized person has not exercised discretionary authority over trading in the plan's account during the period covered by the report.
For purposes of this paragraph (f), the words “incurred by the plan” shall be construed to mean “incurred by the pooled fund” when such person engages in covered transactions on behalf of a pooled fund in which the plan participates.
(g) If an agency cross transaction to which Section V(a) does not apply is involved, the following conditions must also be satisfied:
(1) The information required under Section III(d) or Section V(c)(1)(B) of this exemption includes a statement to the effect that with respect to agency cross transactions, the person effecting or executing the transactions will have a potentially conflicting division of loyalties and responsibilities regarding the parties to the transactions;
(2) The summary required under Section III(f) of this exemption includes a statement identifying the total number of agency cross transactions during the period covered by the summary and the total amount of all commissions or other remuneration received or to be received from all sources by the person engaging in the transactions in connection with the transactions during the period;
(3) The person effecting or executing the agency cross transaction has the discretionary authority to act on behalf of, and/or provide investment advice to, either (A) one or more sellers or (B) one or more buyers with respect to the transaction, but not both.
(4) The agency cross transaction is a purchase or sale, for no consideration other than cash payment against prompt delivery of a security for which market quotations are readily available; and
(5) The agency cross transaction is executed or effected at a price that is at or between the independent bid and independent ask prices for the security prevailing at the time of the transaction.
(h) Except pursuant to Section V(b), a trustee (other than a non-discretionary trustee) may engage in a covered transaction only with a plan that has total net assets with a value of at least $50 million and in the case of a pooled fund, the $50 million requirement will be met if 50 percent or more of the units of beneficial interest in such pooled fund are held by plans having total net assets with a value of at least $50 million.
For purposes of the net asset tests described above, where a group of plans is maintained by a single employer or controlled group of employers, as defined in ERISA section 407(d)(7), the $50 million net asset requirement may be met by aggregating the assets of such plans, if the assets are pooled for investment purposes in a single master trust.
(i) The trustee described in Section III(h) engaging in a covered transaction furnishes, at least annually, to the authorizing fiduciary of each plan the following:
(1) The aggregate brokerage commissions, expressed in dollars, paid by the plan to brokerage firms affiliated with the trustee;
(2) the aggregate brokerage commissions, expressed in dollars, paid by the plan to brokerage firms unaffiliated with the trustee;
(3) the average brokerage commissions, expressed as cents per share, paid by the plan to brokerage firms affiliated with the trustee; and
(4) the average brokerage commissions, expressed as cents per share, paid by the plan (to brokerage firms unaffiliated with the trustee.
For purposes of this paragraph (i), the words “paid by the plan” shall be construed to mean “paid by the pooled fund” when the trustee engages in covered transactions on behalf of a pooled fund in which the plan participates.
(j) In the case of securities transactions involving shares of Mutual Funds, other than exchange traded funds, at the time of the transaction, the shares are purchased or sold at net asset value (NAV) plus a commission, in accordance with applicable securities laws and regulations.
Section I(b) of this exemption applies only if the following conditions are satisfied:
(a) The fiduciary engaging in the covered transaction customarily purchases and sells securities for its own account in the ordinary course of its business as a broker-dealer.
(b) At the time the transaction is entered into, the terms are at least as favorable to the plan as the terms generally available in an arm's length transaction with an unrelated party.
(c) Except to the extent otherwise provided in Section V, the requirements of Section III(a) through III(f), III(h) and III(i) (if applicable), and III(j) are satisfied with respect to the transaction.
(a) Certain agency cross transactions. Section III of this exemption does not apply in the case of an agency cross transaction, provided that the person effecting or executing the transaction:
(1) Does not render investment advice to any plan for a fee within the meaning of ERISA section 3(21)(A)(ii) with respect to the transaction;
(2) is not otherwise a fiduciary who has investment discretion with respect to any plan assets involved in the transaction,
(3) does not have the authority to engage, retain or discharge any person who is or is proposed to be a fiduciary regarding any such plan assets.
(b) Recapture of profits. Sections III(a) and III(i) do not apply in any case where the person who is engaging in a covered transaction returns or credits to the plan all profits earned by that person and any Related Entity in connection with the securities transactions associated with the covered transaction.
(c) Special rules for pooled funds. In the case of a person engaging in a covered transaction on behalf of an account or fund for the collective investment of the assets of more than one plan (a pooled fund):
(1) Sections III(b), (c) and (d) of this exemption do not apply if—
(A) the arrangement under which the covered transaction is performed is subject to the prior and continuing authorization, in the manner described in this paragraph (c)(1), of a plan fiduciary with respect to each plan whose assets are invested in the pooled fund who is independent of the person. The requirement that the authorizing fiduciary be independent of the person shall not apply in the case of a plan covering only employees of the person, if the requirements of Section V(c)(2)(A) and (B) are met.
(B) The authorizing fiduciary is furnished with any reasonably available information that the person engaging or proposing to engage in the covered transaction reasonably believes to be necessary to determine whether the authorization should be given or continued, not less than 30 days prior to implementation of the arrangement or material change thereto, including (but not limited to) a description of the person's brokerage placement practices, and, where requested any other reasonably available information regarding the matter upon the reasonable request of the authorizing fiduciary at any time.
(C) In the event an authorizing fiduciary submits a notice in writing to the person engaging in or proposing to engage in the covered transaction objecting to the implementation of, material change in, or continuation of, the arrangement, the plan on whose behalf the objection was tendered is given the opportunity to terminate its investment in the pooled fund, without penalty to the plan, within such time as may be necessary to effect the withdrawal in an orderly manner that is equitable to all withdrawing plans and to the nonwithdrawing plans. In the case of a plan that elects to withdraw under this subparagraph (c)(1)(C), the withdrawal shall be effected prior to the implementation of, or material change in, the arrangement; but an existing arrangement need not be discontinued by reason of a plan electing to withdraw.
(D) In the case of a plan whose assets are proposed to be invested in the pooled fund subsequent to the implementation of the arrangement and that has not authorized the arrangement in the manner described in Section V(c)(1)(B) and (C), the plan's investment in the pooled fund is subject to the prior written authorization of an authorizing fiduciary who satisfies the requirements of subparagraph (c)(1)(A).
(2) Section III(a) of this exemption, to the extent that it prohibits the person from being the employer of employees covered by a plan investing in a pool managed by the person, does not apply if—
(A) The person is an “investment manager” as defined in section 3(38) of ERISA, and
(B) Either (i) the person returns or credits to the pooled fund all profits earned by the person and any Related Entity in connection with all covered transactions engaged in by the fund, or (ii) the pooled fund satisfies the requirements of paragraph V(c)(3).
(3) A pooled fund satisfies the requirements of this paragraph for a fiscal year of the fund if—
(A) On the first day of such fiscal year, and immediately following each acquisition of an interest in the pooled fund during the fiscal year by any plan covering employees of the person, the aggregate fair market value of the interests in such fund of all plans covering employees of the person does not exceed twenty percent of the fair market value of the total assets of the fund; and
(B) The aggregate brokerage commissions received by the person and any Related Entity, in connection with covered transactions engaged in by the person on behalf of all pooled funds in which a plan covering employees of the person participates, do not exceed five percent of the total brokerage commissions received by the person and any Related Entity from all sources in such fiscal year.
(a) The plan fiduciary engaging in a covered transaction maintains or causes to be maintained for a period of six years, in a manner that is reasonably accessible for examination, the records necessary to enable the persons described in Section VI(b) to determine whether the conditions of this exemption have been met, except that:
(1) If such records are lost or destroyed, due to circumstances beyond the control of the such plan fiduciary, then no prohibited transaction will be considered to have occurred solely on the basis of the unavailability of those records; and
(2) No party in interest, other than such plan fiduciary who is responsible for complying with this paragraph (a), will be subject to the civil penalty that may be assessed under ERISA section
(b)(1) Except as provided below in subparagraph (2), or as precluded by 12 U.S.C. 484, and notwithstanding any provisions of ERISA section 504(a)(2) and (b), the records referred to in the above paragraph are reasonably available at their customary location for examination during normal business hours by—
(A) Any duly authorized employee or representative of the Department or the Internal Revenue Service;
(B) Any fiduciary of the plan or any duly authorized employee or representative of such fiduciary;
(C) Any contributing employer and any employee organization whose members are covered by the plan, or any authorized employee or representative of these entities; or
(D) Any participant or beneficiary of the plan or the authorized representative of such participant or beneficiary.
(2) None of the persons described in subparagraph (1)(B)-(D) above are authorized to examine privileged trade secrets or privileged commercial or financial information of such fiduciary or are authorized to examine records regarding a plan or IRA other than the plan or IRA with which they are the fiduciary, contributing employer, employee organization, participant, beneficiary or IRA owner.
(3) Should such plan fiduciary refuse to disclose information on the basis that such information is exempt from disclosure, such plan fiduciary must, by the close of the thirtieth (30th) day following the request, provide a written notice advising the requestor of the reasons for the refusal and that the Department may request such information.
(4) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the exemption only for the transaction or transactions for which records are missing or have not been maintained. It does not affect the relief for other transactions.
The following definitions apply to this exemption:
(a) The term “person” includes the person and affiliates of the person.
(b) An “affiliate” of a person includes the following:
(1) Any person directly or indirectly, through one or more intermediaries, controlling, controlled by, or under common control with, the person;
(2) Any officer, director, partner, employee, or relative (as defined in ERISA section 3(15)), of the person; and
(3) Any corporation or partnership of which the person is an officer, director or in which such person is a partner.
A person is not an affiliate of another person solely because one of them has investment discretion over the other's assets. The term “control” means the power to exercise a controlling influence over the management or policies of a person other than an individual.
(c) An “agency cross transaction” is a securities transaction in which the same person acts as agent for both any seller and any buyer for the purchase or sale of a security.
(d) The term “covered transaction” means an action described in Section I of this exemption.
(e) The term “effecting or executing a securities transaction” means the execution of a securities transaction as agent for another person and/or the performance of clearance, settlement, custodial or other functions ancillary thereto.
(f) A plan fiduciary is “independent” of a person if it (1) is not the person, (2) does not receive or is not projected to receive within the current federal income tax year, compensation or other consideration for his or her own account from the person in excess of 2% of the fiduciary's annual revenues based upon its prior income tax year, and (3) does not have a relationship to or an interest in the person that might affect the exercise of the person's best judgment in connection with transactions described in this exemption. Notwithstanding the foregoing, if the plan is an individual retirement account not subject to title I of ERISA, and is beneficially owned by an employee, officer, director or partner of the person engaging in covered transactions with the IRA pursuant to this exemption, such beneficial owner is deemed “independent” for purposes of this definition.
(g) The term “profit” includes all charges relating to effecting or executing securities transactions, less reasonable and necessary expenses including reasonable indirect expenses (such as overhead costs) properly allocated to the performance of these transactions under generally accepted accounting principles.
(h) The term “securities transaction” means the purchase or sale of securities.
(i) The term “nondiscretionary trustee” of a plan means a trustee or custodian whose powers and duties with respect to any assets of the plan are limited to (1) the provision of nondiscretionary trust services to the plan, and (2) duties imposed on the trustee by any provision or provisions of ERISA or the Code. The term “nondiscretionary trust services” means custodial services and services ancillary to custodial services, none of which services are discretionary. For purposes of this exemption, a person does not fail to be a nondiscretionary trustee solely by reason of having been delegated, by the sponsor of a master or prototype plan, the power to amend such plan.
(j) The term “plan” means an employee benefit plan described in ERISA section 3(3) and any plan described in Code section 4975(e)(1) (including an Individual Retirement Account as defined in VII(k)).
(k) The terms “Individual Retirement Account” or “IRA” mean any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
(l) The term “Related Entity” means an entity, other than an affiliate, in which a person has an interest which may affect the person's exercise of its best judgment as a fiduciary.
(m) A fiduciary acts in the “Best Interest” of the plan when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the plan, without regard to the financial or other interests of the fiduciary, its affiliate, a Related Entity or other party.
(n) The term “Commission” means a brokerage commission or sales load paid for the service of effecting or executing the transaction, but not a 12b-1 fee, revenue sharing payment, marketing fee, administrative fee, sub-TA fee or sub-accounting fee.
(o) A “Material Conflict of Interest” exists when a person has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to a plan.
(a) M, an investment manager affiliated with a broker dealer that M uses to effect securities transactions for the accounts that it manages, exercises
Aggregate purchases during the 6-month period were $850,000; aggregate sales were $1,000,000, excluding in each case debt securities having a maturity of one year or less at the time of acquisition.
For purposes of Section III(f)(4) of this exemption, M computes the annualized portfolio turnover as follows:
(b) Same facts as (a), except that M manages the portfolio through July 15, 2014, and, in addition, resumes management of the portfolio on November 10, 2014, through the end of the year. The additional relevant valuation dates and portfolio values are:
During the periods July 1, 2014, through July 15, 2014, and November 10, 2014, through December 31, 2014, there were an additional $650,000 of purchases and $400,000 of sales. Thus, total purchases were $1,500,000 (
The Department is proposing to revoke Parts I(b), I(c) and II(2) of PTE 75-1. In connection with the proposed revocation of Part II(2), the Department is republishing Part II of PTE 75-1. Part II of PTE 75-1 shall read as follows:
The restrictions of section 406(a) of the Employee Retirement Income Security Act of 1974 (the Act) and the taxes imposed by section 4975(a) and (b) of the Internal Revenue Code of 1986 (the Code), by reason of section 4975(c)(1)(A) through (D) of the Code, shall not apply to any purchase or sale of a security between an employee benefit plan and a broker-dealer registered under the Securities Exchange Act of 1934 (15 U.S.C. 78a
(a) In the case of such broker-dealer, it customarily purchases and sells securities for its own account in the ordinary course of its business as a broker-dealer.
(b) In the case of such reporting dealer or bank, it customarily purchases and sells Government securities for its own account in the ordinary course of its business and such purchase or sale between the plan and such reporting dealer or bank is a purchase or sale of Government securities.
(c) Such transaction is at least as favorable to the plan as an arm's length transaction with an unrelated party would be, and it was not, at the time of such transaction, a prohibited transaction within the meaning of section 503(b) of the Code.
(d) Neither the broker-dealer, reporting dealer, bank, nor any affiliate thereof has or exercises any discretionary authority or control (except as a directed trustee) with respect to the investment of the plan assets involved in the transaction, or renders investment advice (within the meaning of 29 CFR 2510.3-21(c)) with respect to those assets.
(e) The broker-dealer, reporting dealer, or bank engaging in the covered transaction maintains or causes to be maintained for a period of six years from the date of such transaction such records as are necessary to enable the persons described in paragraph (f) of this exemption to determine whether the conditions of this exemption have been met, except that:
(1) No party in interest other than the broker-dealer, reporting dealer, or bank engaging in the covered transaction, shall be subject to the civil penalty, which may be assessed under section 502(i) of the Act, or to the taxes imposed by section 4975(a) and (b) of the Code, if such records are not maintained, or are not available for examination as required by paragraph (f) below; and
(2) A prohibited transaction will not be deemed to have occurred if, due to circumstances beyond the control of the broker-dealer, reporting dealer, or bank, such records are lost or destroyed prior to the end of such six year period.
(f)(1) Notwithstanding anything to the contrary in subsections (a)(2) and (b) of section 504 of the Act, the records referred to in paragraph (e) are reasonably available for examination during normal business hours by:
(A) Any duly authorized employee or representative of the Department or the Internal Revenue Service;
(B) Any fiduciary of the plan or any duly authorized employee or representative of such fiduciary;
(C) Any contributing employer and any employee organization whose members are covered by the plan, or any authorized employee or representative of these entities; or
(D) Any participant or beneficiary of the plan, or IRA owner, or the duly authorized representative of such participant or beneficiary; and
(2) None of the persons described in subparagraph (1)(B)-(D) above shall be authorized to examine trade secrets or commercial or financial information of the broker-dealer, reporting dealer, or bank which is privileged or confidential, or records regarding a plan or IRA other than the plan or IRA with respect to which they are the fiduciary, contributing employer, employee organization, participant, beneficiary, or IRA owner.
(3) Should such broker-dealer, reporting dealer, or bank refuse to disclose information on the basis that such information is exempt from disclosure, the broker-dealer, reporting dealer, or bank shall, by the close of the thirtieth (30th) day following the request, provide a written notice advising that person of the reasons for the refusal and that the Department may request such information.
(4) Failure to maintain the required records necessary to determine whether the conditions of this exemption have been met will result in the loss of the
For purposes of this exemption, the terms “broker-dealer,” “reporting dealer” and “bank” shall include such persons and any affiliates thereof, and the term “affiliate” shall be defined in the same manner as that term is defined in 29 CFR 2510.3-21(e) and 26 CFR 54.4975-9(e).
Employee Benefits Security Administration (EBSA), U.S. Department of Labor.
Adoption of Amendments to Class Exemptions.
This document contains amendments to prohibited transaction exemptions (PTEs) 75-1, 77-4, 80-83 and 83-1. Generally, the Employee Retirement Income Security Act of 1974 (ERISA) and the Internal Revenue Code (the Code) prohibit fiduciaries with respect to employee benefit plans and individual retirement accounts (IRAs) from engaging in self-dealing, including using their authority, control or responsibility to affect or increase their own compensation. These exemptions generally permit fiduciaries to receive compensation or other benefits as a result of the use of their fiduciary authority, control or responsibility in connection with investment transactions involving plans or IRAs. The amendments require the fiduciaries to satisfy uniform Impartial Conduct Standards in order to obtain the relief available under each exemption. The amendments affect participants and beneficiaries of plans, IRA owners, and fiduciaries with respect to such plans and IRAs.
Brian Shiker, Linda Hamilton or Susan Wilker, Office of Exemption Determinations, Employee Benefits Security Administration, U.S. Department of Labor, (202) 693-8824 (this is not a toll-free number).
The Department is amending the class exemptions on its own motion, pursuant to ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637 (October 27, 2011)).
The Department grants these amendments to PTEs 75-1, 77-4, 80-83 and 83-1 in connection with its publication today, elsewhere in this issue of the
In connection with the adoption of the Regulation, PTEs 75-1, Part III, 75-1, Part IV, 77-4, 80-83 and 83-1 are amended to increase the safeguards of the exemptions. As amended, new “Impartial Conduct Standards” are made conditions of the exemptions. Fiduciaries are required to act in accordance with these standards in transactions permitted by the exemptions. The standards are incorporated in multiple class exemptions, including the exemptions that are the subject of this notice, other existing exemptions, and two new exemptions published elsewhere in this issue of the
ERISA section 408(a) specifically authorizes the Secretary of Labor to grant and amend administrative exemptions from ERISA's prohibited transaction provisions.
This notice amends prohibited transaction exemptions 75-1, Part III,
Under Executive Orders 12866 and 13563, the Department must determine whether a regulatory action is “significant” and therefore subject to the requirements of the Executive Order and subject to review by the Office of Management and Budget (OMB). Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing and streamlining rules, and of promoting flexibility. It also requires federal agencies to develop a plan under which the agencies will periodically review their existing significant regulations to make the agencies' regulatory programs more effective or less burdensome in achieving their regulatory objectives.
Under Executive Order 12866, “significant” regulatory actions are subject to the requirements of the Executive Order and review by the OMB. Section 3(f) of Executive Order 12866, defines a “significant regulatory action” as an action that is likely to result in a rule (1) having an annual effect on the economy of $100 million or more, or adversely and materially affecting a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local or tribal governments or communities (also referred to as “economically significant” regulatory actions); (2) creating serious inconsistency or otherwise interfering with an action taken or planned by another agency; (3) materially altering the budgetary impacts of entitlement grants, user fees, or loan programs or the rights and obligations of recipients thereof; or (4) raising novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order. Pursuant to the terms of the Executive Order, OMB has determined that this action is “significant” within the meaning of Section 3(f)(4) of the Executive Order. Accordingly, the Department has undertaken an assessment of the costs and benefits of the proposal, and OMB has reviewed this regulatory action. The Department's complete Regulatory Impact Analysis is available at
As explained more fully in the preamble to the Regulation, ERISA is a comprehensive statute designed to protect the interests of plan participants and beneficiaries, the integrity of employee benefit plans, and the security of retirement, health, and other critical benefits. The broad public interest in ERISA-covered plans is reflected in its imposition of fiduciary responsibilities on parties engaging in important plan activities, as well as in the tax-favored status of plan assets and investments. One of the chief ways in which ERISA protects employee benefit plans is by requiring that plan fiduciaries comply with fundamental obligations rooted in the law of trusts. In particular, plan fiduciaries must manage plan assets prudently and with undivided loyalty to the plans and their participants and beneficiaries.
The Code also has rules regarding fiduciary conduct with respect to tax-favored accounts that are not generally covered by ERISA, such as IRAs. In particular, fiduciaries of these arrangements, including IRAs, are subject to the prohibited transaction rules, and, when they violate the rules, to the imposition of an excise tax enforced by the Internal Revenue Service. Unlike participants in plans covered by Title I of ERISA, IRA owners do not have a statutory right to bring suit against fiduciaries for violations of the prohibited transaction rules.
Under this statutory framework, the determination of who is a “fiduciary” is of central importance. Many of ERISA's and the Code's protections, duties, and liabilities hinge on fiduciary status. In relevant part, ERISA section 3(21)(A) and Code section 4975(e)(3) provide that a person is a fiduciary with respect to a plan or IRA to the extent he or she (1) exercises any discretionary authority or discretionary control with respect to management of such plan or IRA, or exercises any authority or control with respect to management or disposition of its assets; (2) renders investment advice for a fee or other compensation, direct or indirect, with respect to any moneys or other property of such plan or IRA, or has any authority or responsibility to do so; or, (3) has any discretionary authority or discretionary responsibility in the administration of such plan or IRA.
The statutory definition deliberately casts a wide net in assigning fiduciary responsibility with respect to plan and IRA assets. Thus, “any authority or control” over plan or IRA assets is sufficient to confer fiduciary status, and any persons who render “investment advice for a fee or other compensation, direct or indirect” are fiduciaries, regardless of whether they have direct control over the plan's or IRA's assets and regardless of their status as an investment adviser or broker under the federal securities laws. The statutory definition and associated responsibilities were enacted to ensure that plans, plan participants, and IRA owners can depend on persons who provide investment advice for a fee to provide recommendations that are untainted by conflicts of interest. In the absence of fiduciary status, the providers of investment advice are neither subject to ERISA's fundamental fiduciary standards, nor accountable under ERISA or the Code for imprudent, disloyal, or biased advice.
In 1975, the Department issued a regulation, at 29 CFR 2510.3-21(c) defining the circumstances under which a person is treated as providing “investment advice” to an employee benefit plan within the meaning of ERISA section 3(21)(A)(ii) (the “1975
The market for retirement advice has changed dramatically since the Department first promulgated the 1975 regulation. Individuals, rather than large employers and professional money managers, have become increasingly responsible for managing retirement assets as IRAs and participant-directed plans, such as 401(k) plans, have supplanted defined benefit pensions. At the same time, the variety and complexity of financial products have increased, widening the information gap between advisers and their clients. Plan fiduciaries, plan participants and IRA investors must often rely on experts for advice, but are unable to assess the quality of the expert's advice or effectively guard against the adviser's conflicts of interest. This challenge is especially true of retail investors with smaller account balances who typically do not have financial expertise, and can ill-afford lower returns to their retirement savings caused by conflicts. The IRA accounts of these investors often account for all or the lion's share of their assets and can represent all of savings earned for a lifetime of work. Losses and reduced returns can be devastating to the investors who depend upon such savings for support in their old age. As baby boomers retire, they are increasingly moving money from ERISA-covered plans, where their employer has both the incentive and the fiduciary duty to facilitate sound investment choices, to IRAs where both good and bad investment choices are myriad and advice that is conflicted is commonplace. These rollovers are expected to approach $2.4 trillion cumulatively from 2016 through 2020.
As the marketplace for financial services has developed in the years since 1975, the five-part test has now come to undermine, rather than promote, the statutes' text and purposes. The narrowness of the 1975 regulation has allowed advisers, brokers, consultants and valuation firms to play a central role in shaping plan and IRA investments, without ensuring the accountability that Congress intended for persons having such influence and responsibility. Even when plan sponsors, participants, beneficiaries and IRA owners clearly relied on paid advisers for impartial guidance, the 1975 regulation has allowed many advisers to avoid fiduciary status and disregard basic fiduciary obligations of care and prohibitions on disloyal and conflicted transactions. As a consequence, these advisers have been able to steer customers to investments based on their own self-interest (
In the Department's amendments to the 1975 regulation defining fiduciary advice within the meaning of ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B) (the “Regulation”) which are also published in this issue of the
The Regulation describes the types of advice that constitute “investment advice” with respect to plan or IRA assets for purposes of the definition of a fiduciary at ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B). The Regulation covers ERISA-covered plans, IRAs, and other plans not covered by Title I of ERISA, such as Keogh plans, and health savings accounts described in section 223(d) of the Code.
As amended, the Regulation provides that a person renders investment advice with respect to assets of a plan or IRA if, among other things, the person provides, directly to a plan, a plan fiduciary, plan participant or beneficiary, IRA or IRA owner, the following types of advice, for a fee or other compensation, whether direct or indirect:
(i) A recommendation as to the advisability of acquiring, holding, disposing of, or exchanging, securities or other investment property, or a recommendation as to how securities or other investment property should be invested after the securities or other investment property are rolled over, transferred or distributed from the plan or IRA; and
(ii) A recommendation as to the management of securities or other investment property, including, among other things, recommendations on investment policies or strategies, portfolio composition, selection of other persons to provide investment advice or investment management services, types of investment account arrangements (brokerage versus advisory), or recommendations with respect to rollovers, transfers or distributions from a plan or IRA, including whether, in what amount, in what form, and to what destination such a rollover, transfer or distribution should be made.
In addition, in order to be treated as a fiduciary, such person, either directly or indirectly (
The Regulation also provides that as a threshold matter in order to be fiduciary advice, the communication must be a “recommendation” as defined therein. The Regulation, as a matter of clarification, provides that a variety of other communications do not constitute “recommendations,” including non-fiduciary investment education; general communications; and specified communications by platform providers. These communications which do not rise to the level of “recommendations” under the Regulation are discussed more fully in the preamble to the final Regulation.
The Regulation also specifies certain circumstances where the Department has determined that a person will not be treated as an investment advice fiduciary even though the person's activities technically may satisfy the definition of investment advice. For example, the Regulation contains a provision excluding recommendations to independent fiduciaries with financial expertise that are acting on behalf of plans or IRAs in arm's length transactions, if certain conditions are met. The independent fiduciary must be a bank, insurance carrier qualified to do business in more than one state, investment adviser registered under the Investment Advisers Act of 1940 or by a state, broker-dealer registered under the Securities Exchange Act of 1934 (Exchange Act), or any other independent fiduciary that holds, or has under management or control, assets of at least $50 million, and: (1) The person making the recommendation must know or reasonably believe that the independent fiduciary of the plan or IRA is capable of evaluating investment risks independently, both in general and with regard to particular transactions and investment strategies (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); (2) the person must fairly inform the independent fiduciary that the person is not undertaking to provide impartial investment advice, or to give advice in a fiduciary capacity, in connection with the transaction and must fairly inform the independent fiduciary of the existence and nature of the person's financial interests in the transaction; (3) the person must know or reasonably believe that the independent fiduciary of the plan or IRA is a fiduciary under ERISA or the Code, or both, with respect to the transaction and is responsible for exercising independent judgment in evaluating the transaction (the person may rely on written representations from the plan or independent fiduciary to satisfy this condition); and (4) the person cannot receive a fee or other compensation directly from the plan, plan fiduciary, plan participant or beneficiary, IRA, or IRA owner for the provision of investment advice (as opposed to other services) in connection with the transaction.
Similarly, the Regulation provides that the provision of any advice to an employee benefit plan (as described in ERISA section 3(3)) by a person who is a swap dealer, security-based swap dealer, major swap participant, major security-based swap participant, or a swap clearing firm in connection with a swap or security-based swap, as defined in section 1a of the Commodity Exchange Act (7 U.S.C. 1a) and section 3(a) of the Exchange Act (15 U.S.C. 78c(a)) is not investment advice if certain conditions are met. Finally, the Regulation describes certain communications by employees of a plan sponsor, plan, or plan fiduciary that would not cause the employee to be an investment advice fiduciary if certain conditions are met.
The Department anticipates that the Regulation will cover many investment professionals who did not previously consider themselves to be fiduciaries under ERISA or the Code. Under the Regulation, these entities will be subject to the prohibited transaction restrictions in ERISA and the Code that apply specifically to fiduciaries. ERISA section 406(a)(1)(A)-(D) and Code section 4975(c)(1)(A)-(D) prohibit certain transactions between plans or IRAs and “parties in interest,” as defined in ERISA section 3(14), or “disqualified persons,” as defined in Code section 4975(e)(2). Fiduciaries and other service providers are parties in interest and disqualified persons under ERISA and the Code. As a result, they are prohibited from engaging in (1) the sale, exchange or leasing of property with a plan or IRA, (2) the lending of money or other extension of credit to a plan or IRA, (3) the furnishing of goods, services or facilities to a plan or IRA and (4) the transfer to or use by or for the benefit of a party in interest of plan assets.
ERISA section 406(b)(1) and Code section 4975(c)(1)(E) prohibit a fiduciary from dealing with the income or assets of a plan or IRA in his or her own interest or his or her own account. ERISA section 406(b)(2), which does not apply to IRAs, provides that a fiduciary shall not “in his individual or in any other capacity act in any transaction involving the plan on behalf of a party (or represent a party) whose interests are adverse to the interests of the plan or the interests of its participants or beneficiaries.” ERISA section 406(b)(3) and Code section 4975(c)(1)(F) prohibit a fiduciary from receiving any consideration for his own personal account from any party dealing with the plan or IRA in connection with a transaction involving assets of the plan or IRA.
Parallel regulations issued by the Departments of Labor and the Treasury explain that these provisions impose on fiduciaries of plans and IRAs a duty not to act on conflicts of interest that may affect the fiduciary's best judgment on behalf of the plan or IRA.
Investment professionals typically receive compensation for services to retirement investors in the retail market through a variety of arrangements, which would typically violate the prohibited transaction rules applicable to plan fiduciaries. These include commissions paid by the plan, participant or beneficiary, or IRA, or commissions, sales loads, 12b-1 fees, revenue sharing and other payments from third parties that provide investment products. A fiduciary's receipt of such payments would generally violate the prohibited transaction provisions of ERISA section 406(b) and Code section 4975(c)(1)(E) and (F) because the amount of the fiduciary's compensation is affected by the use of its authority in providing investment advice, unless such payments meet the requirements of an exemption.
As the prohibited transaction provisions demonstrate, ERISA and the Code strongly disfavor conflicts of interest. In appropriate cases, however,
In addition, the Secretary of Labor has discretionary authority to grant administrative exemptions under ERISA and the Code on an individual or class basis, but only if the Secretary first finds that the exemptions are (1) administratively feasible, (2) in the interests of plans and their participants and beneficiaries and IRA owners, and (3) protective of the rights of the participants and beneficiaries of such plans and IRA owners. Accordingly, fiduciary advisers may always give advice without need of an exemption if they avoid the sorts of conflicts of interest that result in prohibited transactions. However, when they choose to give advice in which they have a conflict of interest, they must rely upon an exemption.
Pursuant to its exemption authority, the Department has previously granted several conditional administrative class exemptions that are available to fiduciary advisers in defined circumstances. As a general proposition, these exemptions focused on specific advice arrangements and provided relief for narrow categories of compensation. Reliance on these exemptions is subject to certain conditions that the Department has found necessary to protect the interests of plans and IRAs.
In connection with the development of the Department's Regulation under ERISA section 3(21)(A)(ii) and Code section 4975(e)(3)(B), the Department considered public input indicating the need for additional prohibited transaction relief for the wide variety of compensation structures that exist today in the marketplace for investment transactions. After consideration of the issue, the Department proposed two new class exemptions and proposed amendments to a number of existing exemptions. As part of this initiative, the Department proposed to incorporate the Impartial Conduct Standards, described in greater detail below, in the new and certain existing exemptions. In this regard, the Department proposed to incorporate the Impartial Conduct Standards in PTEs 75-1, Part III, 75-1, Part IV, 77-4, 80-83 and 83-1. These exemptions provide relief for the following specific transactions:
• PTE 75-1, Part III
• PTE 75-1, Part IV
• PTE 77-4
• PTE 80-83
• PTE 83-1
The Department's intent in proposing the amendments was to provide additional protections for all plans, but most particularly for IRA owners. That is because fiduciaries' dealings with IRAs are governed by the Code, not by ERISA,
These amended exemptions follow a lengthy public notice and comment process, which gave interested persons an extensive opportunity to comment on the proposed Regulation and exemption proposals. The proposals initially provided for 75-day comment periods, ending on July 6, 2015, but the Department extended the comment periods to July 21, 2015. The Department then held four days of public hearings on the new regulatory package, including the proposed exemptions, in Washington, DC from August 10 to 13, 2015, at which over 75 speakers testified. The transcript of the hearing was made available on September 8, 2015, and the Department provided additional opportunity for interested persons to comment on the proposals or hearing transcript until September 24, 2015. A total of over 3000 comment letters were received on the new proposals. There were also over 300,000 submissions made as part of 30 separate petitions submitted on the proposal. These comments and petitions came from consumer groups, plan sponsors, financial services companies, academics, elected government officials, trade and industry associations, and others, both in support and in opposition to the rule.
These amended exemptions require fiduciaries relying on the exemptions to comply with fundamental Impartial Conduct Standards. Generally stated, the Impartial Conduct Standards require that, in connection with the transactions
The Impartial Conduct Standards represent fundamental obligations of fair dealing and fiduciary conduct. The concepts of prudence, undivided loyalty and reasonable compensation are all deeply rooted in ERISA and the common law of agency and trusts.
Under the amendments, the Impartial Conduct Standards are conditions of the exemptions with respect to all plans and IRAs. Transactions that violate the requirements would not be in the interests of or protective of plans and their participants and beneficiaries and IRA owners. However, unlike some of the other exemptions finalized today in this issue of the
The Department received many comments on the proposal to include the Impartial Conduct Standards as part of these existing exemptions. A number of commenters focused on the Department's authority to impose the Impartial Conduct Standards as conditions of the exemptions. Commenters' arguments regarding the Impartial Conduct Standards as applicable to IRAs and non-ERISA plans were based generally on the fact that the standards, as noted above, are consistent with longstanding principles of prudence and loyalty set forth in ERISA section 404, but which have no counterpart in the Code. Commenters took the position that because Congress did not choose to impose the standards of prudence and loyalty on fiduciaries with respect to IRAs and non-ERISA plans, the Department exceeded its authority in proposing similar standards as a condition of relief in a prohibited transaction exemption.
With respect to ERISA plans, commenters stated that Congress' separation of the duties of prudence and loyalty (in ERISA section 404) from the prohibited transaction provisions (in ERISA section 406), showed an intent that the two should remain separate. Commenters additionally questioned why the conduct standards were necessary for ERISA plans, when such plans already have an enforceable right to fiduciary conduct that is both prudent and loyal. Commenters asserted that imposing the Impartial Conduct Standards as conditions of the exemptions created strict liability for prudence violations.
Some commenters additionally took the position that Congress, in the Dodd-Frank Act, gave the SEC the authority to establish standards for broker-dealers and investment advisers and therefore, the Department did not have the authority to act in that area.
The Department disagrees that these amendments to the exemptions exceed its authority. The Department has clear authority under ERISA section 408(a) and the Reorganization Plan
The Impartial Conduct Standards represent, in the Department's view, baseline standards of fundamental fair dealing that must be present when fiduciaries make conflicted investment recommendations to retirement investors. After careful consideration, the Department determined that broad relief could be provided to investment advice fiduciaries receiving conflicted compensation only if such fiduciaries provided advice in accordance with the
These Impartial Conduct Standards are necessary to ensure that advisers' recommendations reflect the best interest of their retirement investor customers, rather than the conflicting financial interests of the advisers and their financial institutions. As a result, advisers and financial institutions bear the burden of showing compliance with the exemption and face liability for engaging in a non-exempt prohibited transaction if they fail to provide advice that is prudent or otherwise in violation of the standards. The Department does not view this as a flaw in the exemptions, as commenters suggested, but rather as a significant deterrent to violations of important conditions under the exemptions.
The Department similarly disagrees that Congress' directive to the SEC in the Dodd-Frank Act limits its authority to establish appropriate and protective conditions in the context of a prohibited transaction exemption. Section 913 of that Act directs the SEC to conduct a study on the standards of care applicable to brokers-dealers and investment advisers, and issue a report containing, among other things:
Section 913 authorizes, but does not require, the SEC to issue rules addressing standards of care for broker-dealers and investment advisers for providing personalized investment advice about securities to retail customers.
Some commenters suggested that it would be unnecessary to impose the Impartial Conduct Standards on advisers with respect to ERISA plans, as fiduciaries to these plans already are required to operate within similar statutory fiduciary obligations. The Department considered this comment but has determined not to eliminate the conduct standards as conditions of the exemptions for ERISA plans.
One of the Department's goals is to ensure equal footing for all retirement investors. The SEC staff Dodd-Frank Study required by section 913 of the Dodd-Frank Act found that investors were frequently confused by the differing standards of care applicable to broker-dealers and registered investment advisers. The Department hopes to minimize such confusion in the market for retirement advice by holding fiduciaries to similar standards, regardless of whether they are giving the advice to an ERISA plan, IRA, or a non-ERISA plan.
Moreover, inclusion of the standards as conditions of these existing exemptions adds an important additional safeguard for ERISA and IRA investors alike because the party engaging in a prohibited transaction has the burden of showing compliance with an applicable exemption, when violations are alleged.
Other commenters generally asserted that the Impartial Conduct Standards were too vague and would result in the exemption failing to meet the “administratively feasible” requirement under ERISA section 408(a) and Code section 4975(c)(2). The Department disagrees with these commenters' suggestions that ERISA section 408(a) and Code section 4975(c)(2) fail to be satisfied by a principles-based approach, or that standards are unduly vague. It is worth repeating that the Impartial Conduct Standards are built on concepts that are longstanding and familiar in ERISA and the common law of trusts and agency. Far from requiring adherence to novel standards with no antecedents, the exemptions primarily require adherence to well-established fundamental obligations of fair dealing and fiduciary conduct. This preamble provides specific interpretations and responses to a number of issues raised in connection with a number of the Impartial Conduct Standards.
Comments on each of the Impartial Conduct Standards are discussed below. In this regard, the Department notes that some commenters focused their comments on the Impartial Conduct Standards in the other exemption proposals, including the proposed Best Interest Contract Exemption, which is finalized elsewhere in this issue of the
Under the first Impartial Conduct Standard, fiduciaries relying on the amended exemptions must act in the best interest of the plan or IRA at the time of the exercise of authority (including, in the case of an investment advice fiduciary, the recommendation). Best interest is defined to mean acting with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such
The Best Interest standard set forth in the amended exemptions is based on longstanding concepts derived from ERISA and the law of trusts. It is meant to express the concept, set forth in ERISA section 404 that a fiduciary is required to act “solely in the interest of the participants . . . with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent man acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims.” Similarly, both ERISA section 404(a)(1)(A) and the trust-law duty of loyalty require fiduciaries to put the interests of trust beneficiaries first, without regard to the fiduciaries' own self-interest. Under this standard, for example, a fiduciary, in choosing between two investments, could not select an investment because it is better for the fiduciary's bottom line, even though it is a worse choice for the plan or IRA.
A wide range of commenters indicated support for a broad “best interest” standard. Some comments indicated that the best interest standard is consistent with the way advisers provide investment advice to clients today. However, a number of these commenters expressed misgivings as to the definition used in the proposed amendments, in particular, the “without regard to” formulation. The commenters indicated uncertainty as to the meaning of the phrase, including: Whether it permitted the fiduciary to be paid; and whether it permitted investment advice on proprietary products. One commenter was especially concerned that the amendments might restrict fiduciaries' ability to sell proprietary products, which are specifically permitted in PTE 77-4.
Other commenters asked the Department to use a different definition of “Best Interest” or simply use the exact language from ERISA's section 404 duty of loyalty. Others suggested definitional approaches that would require that the fiduciary “not subordinate” its customers' interests to its own interests, or that the fiduciary put its customers' interests ahead of its own interests, or similar constructs.
The Financial Industry Regulatory Authority (FINRA)
Other commenters found the Best Interest standard to be an appropriate statement of the obligations of a fiduciary investment advice provider and believed it would provide concrete protections against conflicted recommendations. These commenters asked the Department to maintain the Best Interest definition as proposed. One commenter wrote that the term “best interest” is commonly and used in connection with a fiduciary's duty of loyalty and cautioned the Department against creating exemptions that failed to include the duty of loyalty. Others urged the Department to avoid definitional changes that would reduce current protections to plans and IRAs. Some commenters also noted that the “without regard to” language is consistent with the recommended standard in the SEC staff Dodd-Frank Study, and suggested that it had the added benefit of potentially harmonizing with a future securities law standard for broker-dealers.
The final amendments retain the Best Interest definition as proposed, with minor adjustments. The first prong of the standard was revised in each amended exemption to more closely track the statutory language of ERISA section 404(a), and, is consistent with the Department's intent to hold investment advice fiduciaries to a prudent investment professional standard. Accordingly, the definition of Best Interest now requires advice that “reflects the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person
The Department has not specifically incorporated the suitability obligation as an element of the Best Interest standard, as suggested by FINRA but many aspects of suitability are also elements of the Best Interest standard. An investment recommendation that is not suitable under the securities laws would not meet the Best Interest standard. Under FINRA's rule 2111(a) on suitability, broker-dealers “must have a reasonable basis to believe that a recommended transaction or investment strategy involving a security or securities is suitable for the customer.” The text of rule 2111(a), however, does not do any of the following: Reference a best interest standard, clearly require brokers to put their client's interests ahead of their own, expressly prohibit the selection of the least suitable (but more remunerative) of available investments, or require them to take the kind of measures to avoid or mitigate conflicts of interests that are required as conditions of these amended exemptions.
The Department recognizes that FINRA issued guidance on rule 2111 in which it explains that “in interpreting the suitability rule, numerous cases explicitly state that a broker's recommendations must be consistent with his customers' best interests,” and provided examples of conduct that would be prohibited under this standard, including conduct that these amended exemptions would not allow.
Accordingly, after review of the issue, the Department has decided not to accept the comment. The Department has concluded that its articulation of a clear loyalty standard within the exemption, rather than by reference to the FINRA guidance, will provide clarity and certainty to investors and better protect their interests.
The Best Interest standard, as set forth in the exemptions, is intended to effectively incorporate the objective standards of care and undivided loyalty that have been applied under ERISA for more than forty years. Under these objective standards, the fiduciary must adhere to a professional standard of care in making investments or investment recommendations that are in the plan's or IRA's Best Interest. The fiduciary may not base his or her discretionary acquisitions or recommendations on the fiduciary's own financial interest in the transaction. Nor may the fiduciary acquire or recommend the investment unless it meets the objective prudent person standard of care. Additionally, the duties of loyalty and prudence embodied in ERISA are objective obligations that do not require proof of fraud or misrepresentation, and full disclosure is not a defense to making imprudent acquisitions or recommendations or favoring one's own interests at the plan's or IRA's expense.
Several commenters requested additional guidance on the Best Interest standard. Fiduciaries that are concerned about satisfying the standard may wish to consult the policies and procedures requirement in Section II(d) of the Best Interest Contract Exemption. While these policies and procedures are not a condition of these amended exemptions, they may provide useful guidance for financial institutions wishing to ensure that individual advisers adhere to the Impartial Conduct Standards. The preamble to the Best Interest Contract Exemption provides examples of policies and procedures prudently designed to ensure that advisers adhere to the Impartial Conduct Standards. The examples are not intended to be exhaustive or mutually exclusive, and range from examples that focus on eliminating or nearly eliminating compensation differentials to examples that permit, but police, the differentials.
A few commenters also questioned the requirement in the Best Interest standard that recommendations be made without regard to the interests of the fiduciary, any affiliate or “
Other commenters asked for confirmation that the Best Interest standard is applied based on the facts and circumstances as they existed at the time of the fiduciary's action, and not based on hindsight. Consistent with the well-established legal principles that exist under ERISA today, the Department confirms that the Best Interest standard is not a hindsight standard, but rather is based on the facts as they existed at the time of the transaction. Thus, the courts have evaluated the prudence of a fiduciary's actions under ERISA by focusing on the process the fiduciary used to reach its determination or recommendation—whether the fiduciary, “at the time they engaged in the challenged transactions, employed the proper procedures to investigate the merits of the investment and to structure the investment.”
This is not to suggest that the ERISA section 404 prudence standard or Best Interest standard, are solely procedural standards. Thus, the prudence standard, as incorporated in the Best Interest standard, is an objective standard of care that requires investment advice fiduciaries to investigate and evaluate investments, make recommendations, and exercise sound judgment in the same way that knowledgeable and impartial professionals would. “[T]his is not a search for subjective good faith—a pure heart and an empty head are not enough.”
The Department additionally confirms its intent that the phrase “without regard to” be given the same meaning as the language in ERISA section 404 that requires a fiduciary to act “solely in the interest of” participants and beneficiaries, as such standard has been interpreted by the Department and the courts. Therefore, the standard would not, as some commenters suggested, foreclose the fiduciary from being paid. In response to concerns about the satisfaction of the standard in the context of proprietary product recommendations or investment menus limited to proprietary products and/or investments that generate third party payments, the Department has revised Section IV of the Best Interest Contract Exemption to provide additional clarity and specific guidance on this issue.
In response to commenter concerns, the Department also confirms that the
Finally, in response to questions regarding the extent to which this Best Interest standard or other provisions of the amendments impose an ongoing monitoring obligation on fiduciaries, the text does not impose a monitoring requirement, but instead leaves that to the parties. This is consistent with the Department's interpretation of an investment advice fiduciary's monitoring responsibility as articulated in the preamble to the Regulation.
The Impartial Conduct Standards also include the reasonable compensation standard. Under this standard, compensation received by the fiduciary and its affiliates in connection with the applicable transaction may not exceed compensation for services that is reasonable within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
The obligation to pay no more than reasonable compensation to service providers is long recognized under ERISA and the Code. ERISA section 408(b)(2) and Code section 4975(d)(2), require that services arrangements involving plans and IRAs result in no more than reasonable compensation to the service provider. Accordingly fiduciaries—as service providers—have long been subject to this requirement, regardless of their fiduciary status. At bottom, the standard simply requires that compensation not be excessive, as measured by the market value of the particular services, rights, and benefits the fiduciary is delivering to the plan or IRA. Given the conflicts of interest associated with the commissions and other payments covered by the exemptions, and the potential for self-dealing, it is particularly important that fiduciaries adhere to these statutory standards, which are rooted in common law principles.
Several commenters supported this standard. The requirement that compensation be limited to what is reasonable is an important protection of the exemptions and a well-established standard, they said. A number of other commenters requested greater specificity as to the meaning of the reasonable compensation standard. As proposed, the standard stated that all compensation received by the fiduciary and its affiliates in connection with the transaction must be reasonable in relation to the total services the fiduciary and its affiliates provide to the plan or IRA. Some commenters stated that the proposed reasonable compensation standard was too vague. Because the language of the proposal did not reference ERISA section 408(b)(2) and Code section 4975(d)(2), commenters asked whether the standard differed from those statutory provisions. In particular, some commenters questioned the meaning of the proposed language “in relation to the total services the fiduciary provides to the plan or IRA.” The commenters indicated that the proposal did not adequately explain this formulation of the reasonable compensation standard.
There was concern that the standard could be applied retroactively rather than based on the parties' reasonable beliefs as to the reasonableness of the compensation at the time of the recommendation. Commenters also indicated uncertainty as to how to comply with the condition and asked whether it would be necessary to survey the market to determine market rates. Some commenters requested that the Department include the words “and customary” in the reasonable compensation definition, to specifically permit existing compensation arrangements. One commenter raised the concern that the reasonable compensation determination raised antitrust concerns because it would require investment advice fiduciaries to agree upon a market rate and result in anti-competitive behavior.
Commenters also asked the Department to provide examples of scenarios that met the reasonable compensation standard and safe harbors and others requested examples of scenarios that would fail to meet these standards. FINRA and other commenters suggested that the Department incorporate existing FINRA rules 2121 and 2122, and NASD rule 2830 regarding the reasonableness of compensation for broker-dealers.
Commenters also asked how the standard would be satisfied for proprietary products. One commenter indicated that the calculation should not include affiliates' or related entities' compensation as this would appear to put them at a comparative disadvantage.
Finally, a few commenters took the position that the reasonable compensation determination should not be a requirement of an exemption. In their view, a plan fiduciary that is not providing investment advice or exercising investment discretion should decide the reasonableness of the compensation paid to the one who is. Another commenter suggested that if an independent plan fiduciary sets the menu of investment options this should be sufficient to comply with the reasonable compensation standard.
In response to comments on this requirement, the Department has retained the reasonable compensation standard as a condition of the amended exemptions. As noted above, the “reasonable compensation” obligation is a feature of ERISA and the Code under current law that has long applied to financial services providers, whether fiduciaries or not. The standard is also applicable to fiduciaries under the common law of agency and trusts. It is particularly important that fiduciaries adhere to these standards when engaging in the transactions covered under these amended exemptions, so as to avoid exposing plans and IRAs to harms associated with conflicts of interest.
Although some commenters suggested that the reasonable compensation determination be made by another plan fiduciary, the exemptions (like the statutory obligation) obligate fiduciaries to avoid overcharging their plan and IRA customers, despite the conflicts of interest associated with their compensation. Fiduciaries and other services providers may not charge more than reasonable compensation regardless of whether another fiduciary has signed off on the compensation. Nothing in the exemptions, however, precludes fiduciaries from seeking impartial review of their fee structures to safeguard against abuse, and they may well want to include such reviews in their policies and procedures.
Further, the Department disagrees that the requirement is inconsistent with antitrust laws. Nothing in the exemption contemplates or requires that Advisers or Financial Institutions agree upon a price with their competitors. The focus of the reasonable compensation condition is on preventing overcharges to retirement investors, not promoting anti-competitive practices. Indeed, if Advisors and Financial Institutions consulted with competitors to set prices, the agreed-upon prices could well violate the condition.
In response to comments, however, the operative text of the final amendments was clarified to provide that, to the extent it applies to services, the reasonable compensation standard is the same as the well-established requirement set forth in ERISA section 408(b)(2) and Code section 4975(d)(2), and the regulations thereunder. The reasonableness of the fees depends on the particular facts and circumstances at the time of the recommendation. Several factors inform whether compensation is reasonable including,
In response to concerns about application of the standard to investment products that bundle together services and investment guarantees or other benefits, the Department responds that the reasonable compensation condition is intended to apply to the compensation received by the Financial Institution, Adviser, Affiliates, and Related Entities in same manner as the reasonable compensation condition set forth in ERISA section 408(b)(2) and Code section 4975(d)(2). Accordingly, the exemption's reasonable compensation standard covers compensation received directly from the plan or IRA and indirect compensation received from any source other than the plan or IRA in connection with the recommended transaction.
A commenter urged the Department to provide that compensation received by an Affiliate would not have to be considered in applying the reasonable compensation standard. According to the commenter, including such compensation in the assessment of reasonable compensation would place proprietary products at a disadvantage. The Department disagrees with the proposition that a proprietary product would be disadvantaged merely because more of the compensation goes to affiliated parties than in the case of competing products, which allocate more of the compensation to non-affiliated parties. The availability of the exemptions, however, does not turn on how compensation is allocated between affiliates and non-affiliates. Certainly, the Department would not expect that a proprietary product would be at a disadvantage in the marketplace because it carefully ensures that the associated compensation is reasonable. Assuming the Best Interest standard is satisfied and the compensation is reasonable, the exemption should not impede the recommendation of proprietary products. Accordingly, the Department disagrees with the commenter. The Department declines suggestions to provide specific examples of “reasonable” amounts or specific safe harbors. Ultimately, the “reasonable compensation” standard is a market based standard. As noted above, the standard incorporates the familiar ERISA section 408(b)(2) and Code section 4975(d)(2) standards The Department is unwilling to condone all “customary” compensation arrangements and declines to adopt a standard that turns on whether the agreement is “customary.” For example, it may in some instances be “customary” to charge customers fees that are not transparent or that bear little relationship to the value of the services actually rendered, but that does not make the charges reasonable. Finally, the Department notes that all recommendations are subject to the overarching Best Interest standard, which incorporates the fundamental fiduciary obligations of prudence and loyalty. An imprudent recommendation for an investor to overpay for an investment transaction would violate that standard, regardless of whether the overpayment was attributable to compensation for services, a charge for benefits or guarantees, or something else.
The final Impartial Conduct Standard requires that statements by the fiduciaries to the plans and IRAs about the recommended transaction, fees and compensation, material conflicts of interest, and any other matters relevant to a plan's or IRA owner's investment decisions, may not be materially misleading at the time they are made.
In response to commenters, the Department added a materiality standard to the definition of material conflict of interest and adjusted the text to clarify that the standard is measured at the time of the representations,
A number of commenters focused on the definition of material conflict of interest used in the proposals. As proposed, a material conflict of interest would have existed when a fiduciary “has a financial interest that could affect the exercise of its best judgment as a fiduciary in rendering advice to a plan or IRA owner.” Some commenters took the position that the proposal did not adequately explain the term “material” or incorporate a “materiality” standard into the definition.
However, another commenter indicated that the Department should not use the term “material” in the definition of conflict of interest. The commenter believed that it could result in a standard that was too subjective from the perspective of the fiduciary relying on the exemption, and could undermine the protectiveness of the exemption.
After consideration of the comments, the Department adjusted the definition of material conflict of interest to provide that a material conflict of interest exists when the fiduciary has a “financial interest that
The Department did not accept certain other comments. One commenter requested that the standard indicate that the statements must have been reasonably relied on by the plan or IRA. The Department rejected the comment. The Department's aim is to ensure that fiduciaries uniformly adhere to the Impartial Conduct Standards, including the obligation to avoid materially misleading statements, when they exercise discretion or provide investment advice to plans and IRAs.
One commenter asked the Department to require only that the fiduciary “reasonably believe” the statements are not misleading. The Department is concerned that this standard could undermine the protections of this condition, by requiring plans and IRAs to prove the fiduciary's actual belief rather than focusing on whether the statement is objectively misleading. However, to address commenters' concerns about the risks of engaging in a prohibited transaction, as noted above, the Department has clarified that the standard is measured at the time of the representations and has added a materiality standard.
The Department believes that plans and IRAs are best served by statements and representations that are free from material misstatements. Fiduciaries best avoid liability—and best promote the interests of the plans and IRAs—by ensuring that accurate communications are a consistent standard in all their interactions with their customers.
A commenter suggested that the Department adopt FINRA's “Frequently Asked Questions regarding Rule 2210” in this connection.
Commenters expressed concern about the statement in the third Impartial Conduct Standard that “failure to disclose a material conflict of interest . . . is deemed to be a misleading statement.” The commenters indicated that, without a materiality standard, this language would result in an overly broad and uncertain disclosure requirement. The requirement would be especially burdensome in light of the potential consequences of engaging in a non-exempt prohibited transaction, including rescission, repayment of lost earnings, excise tax, and personal liability, commenters said. One commenter stated that this was effectively a change to the existing disclosure requirements of the exemptions, particularly PTE 77-4.
The Department has considered these comments. As noted above, the amended exemptions include a materiality standard in the definition of material conflict of interest. Nevertheless, the Department was persuaded by commenters to eliminate the statement from the third Impartial Conduct Standard. When viewed as a whole, the Department believes the conditions already existing in these exemptions, with the addition of the Impartial Conduct Standards adopted in these final amendments, provide sufficient protections to retirement investors without this additional disclosure provision.
The Department received some comments specific to PTE 77-4 that were generally outside the scope of these amendments. A few commenters requested that PTE 77-4 be amended to permit fiduciaries to rely on negative consent under the exemption. Another commenter requested amendments or interpretations relating to the extent of relief provided by the exemption. For example, one commenter requested that the Department clarify that the prospectus delivery requirement found at PTE 77-4 section II(d) may be satisfied by identifying a Web site address where investment materials can be obtained. This commenter also requested that PTE 77-4 be expanded to include investments in commingled trusts and exchange-traded funds.
Regardless of possible merit, these requests raise issues outside the scope of these amendments. The amendments were focused on the implementation of the Impartial Conduct Standards with respect to these existing class exemptions, and were not intended to address other issues with respect to these exemptions. The issues raised in these comments were not proposed and commenters did not have the opportunity to address them. Therefore, the comments were not accepted at this time. Parties wishing to pursue these comments may seek an advisory opinion or an amendment to PTE 77-4 from the Department.
The Regulation will become effective June 7, 2016 and these amended exemptions are issued on that same date. The Regulation is effective at the earliest possible effective date under the Congressional Review Act. For the exemptions, the issuance date serves as the date on which the amended exemptions are intended to take effect for purposes of the Congressional Review Act. This date was selected in order to provide certainty to plans, plan fiduciaries, plan participants and beneficiaries, IRAs, and IRA owners that the new protections afforded by the Regulation are officially part of the law and regulations governing their investment advice providers, and to inform financial services providers and other affected service providers that the Regulation and amended exemptions are final and not subject to further amendment or modification without additional public notice and comment. The Department expects that this effective date will remove uncertainty as an obstacle to regulated firms allocating capital and other resources toward transition and longer term compliance adjustments to systems and business practices.
The Department has also determined that, in light of the importance of the Regulation's consumer protections and the significance of the continuing monetary harm to retirement investors without the rule's changes, that an Applicability Date of April 10, 2017, is appropriate for plans and their affected financial services and other service providers to adjust to the basic change from non-fiduciary to fiduciary status. The amendments as finalized herein have the same Applicability Date; parties may therefore rely on the amended exemptions beginning on the Applicability Date.
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under ERISA section 408(a) and Code section 4975(c)(2) does not relieve a fiduciary or other party in interest or disqualified
(2) The Department finds that the amended exemptions are administratively feasible, in the interests of plans and their participants and beneficiaries and IRA owners, and protective of the rights of plans' participants and beneficiaries and IRA owners;
(3) The amended exemptions are applicable to a particular transaction only if the transactions satisfy the conditions specified in the amendments;
(4) The amended exemptions are supplemental to, and not in derogation of, any other provisions of ERISA and the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction.
The Department amends Prohibited Transaction Exemption 75-1, Part III, under the authority of ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, October 27, 2011).
A. A new section III(f) is inserted to read as follows:
(f)
(1) The fiduciary acts in the Best Interest of the plan or IRA at the time of the transaction.
(2) All compensation received by the fiduciary in connection with the transaction neither exceeds compensation for services that is reasonable within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(3) The fiduciary's statements about recommended investments, fees and compensation, material conflicts of interest, and any other matters relevant to the plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. A “material conflict of interest” exists when a fiduciary has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to the plan or IRA owner.
For purposes of this section, a fiduciary acts in the “Best Interest” of the plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the plan or IRA, without regard to the financial or other interests of the fiduciary or any other party. Also for the purposes of this section, the term IRA means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
B. Sections III(f) and III(g) are redesignated, respectively, as sections III(g) and III(h).
The Department amends Prohibited Transaction Exemption 75-1, Part IV, under the authority of ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, October 27, 2011).
A. A new section IV(e) is inserted to read as follows:
(e)
(1) The fiduciary acts in the Best Interest of the plan or IRA at the time of the transaction.
(2) All compensation received by the fiduciary in connection with the transaction neither exceeds compensation for services that is reasonable within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(3) The fiduciary's statements about recommended investments, fees and compensation, material conflicts of interest, and any other matters relevant to the plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. A “material conflict of interest” exists when a fiduciary has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to the plan or IRA owner.
For purposes of this section, a fiduciary acts in the “Best Interest” of the plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the plan or IRA, without regard to the financial or other interests of the fiduciary or any other party. Also for the purposes of this section, the term IRA means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
B. Sections IV(e) and IV(f) are redesignated, respectively, as sections IV(f) and IV(g).
The Department amends Prohibited Transaction Exemption 77-4 under the authority of ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, October 27, 2011).
A new section II(g) is inserted to read as follows:
(g)
(1) The fiduciary acts in the Best Interest of the plan or IRA at the time of the transaction.
(2) All compensation received by the fiduciary and its affiliates in connection with the transaction neither exceeds
(3) The fiduciary's statements about recommended investments, fees and compensation, material conflicts of interest, and any other matters relevant to the plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. A “material conflict of interest” exists when a fiduciary has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to the plan or IRA owner.
For purposes of this section, a fiduciary acts in the “Best Interest” of the plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the plan or IRA, without regard to the financial or other interests of the fiduciary, any affiliate or other party. Also for the purposes of this section, the term IRA means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
The Department amends Prohibited Transaction Exemption 80-83 under the authority of ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, October 27, 2011).
A. A new section II(A)(2) is inserted to read as follows:
(2)
(a) The fiduciary acts in the Best Interest of the plan or IRA at the time of the transaction.
(b) All compensation received by the fiduciary and its affiliates in connection with the transaction neither exceeds compensation for services that is reasonable within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(c) The fiduciary's statements about recommended investments, fees and compensation, material conflicts of interest, and any other matters relevant to the plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. A “material conflict of interest” exists when a fiduciary has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to the plan or IRA owner.
For purposes of this section, a fiduciary acts in the “Best Interest” of the employee benefit plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the employee benefit plan or IRA, without regard to the financial or other interests of the fiduciary, any affiliate or other party. Also for the purposes of this section, the term IRA means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
B. Section II(A)(2) is redesignated as section II(A)(3).
The Department amends Prohibited Transaction Exemption 83-1 under the authority of ERISA section 408(a) and Code section 4975(c)(2), and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, October 27, 2011).
A. A new section II(B) is inserted to read as follows:
(B)
(1) The fiduciary acts in the Best Interest of the plan or IRA at the time of the transaction.
(2) All compensation received by the fiduciary and its affiliates in connection with the transaction neither exceeds compensation for services that is reasonable within the meaning of ERISA section 408(b)(2) and Code section 4975(d)(2).
(3) The fiduciary's statements about recommended investments, fees and compensation, material conflicts of interest, and any other matters relevant to the plan's or IRA owner's investment decisions, are not materially misleading at the time they are made. A “material conflict of interest” exists when a fiduciary has a financial interest that a reasonable person would conclude could affect the exercise of its best judgment as a fiduciary in rendering advice to the plan or IRA owner.
For purposes of this section, a fiduciary acts in the “Best Interest” of the plan or IRA when the fiduciary acts with the care, skill, prudence, and diligence under the circumstances then prevailing that a prudent person acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, based on the investment objectives, risk tolerance, financial circumstances, and needs of the plan or IRA, without regard to the financial or other interests of the plan or IRA to the financial interests of the fiduciary, any affiliate or other party. Also for the purposes of this section, the term IRA means any account or annuity described in Code section 4975(e)(1)(B) through (F), including, for example, an individual retirement account described in section 408(a) of the Code and a health savings account described in section 223(d) of the Code.
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