| Page Range | 15885-16247 | |
| FR Document |
| Page and Subject | |
|---|---|
| 80 FR 15998 - Sunshine Act Meetings | |
| 80 FR 16031 - Sunshine Act Meetings; National Science Board | |
| 80 FR 16044 - Sunshine Act Meeting | |
| 80 FR 16043 - In the Matter of Winsonic Digital Media Group, Ltd.; Order of Suspension of Trading Pursuant to Section 12(K) of the Securities Exchange Act of 1934 | |
| 80 FR 16023 - Sunshine Act Meeting | |
| 80 FR 16022 - Public Land Order No. 7831; Transfer of Administrative Jurisdiction, Wind Cave National Park Addition; South Dakota | |
| 80 FR 15993 - BE-9: Quarterly Survey of Foreign Airline Operators' Revenues and Expenses in the United States | |
| 80 FR 15953 - Kentucky Regulatory Program | |
| 80 FR 16077 - Advisory Committee on International Economic Policy; Notice of Open Meeting | |
| 80 FR 15987 - Antidumping Duty Investigation of Certain Passenger Vehicle and Light Truck Tires From the People's Republic of China: Amended Affirmative Preliminary Determination | |
| 80 FR 16080 - Signal Specialties, Inc.-Acquisition and Operation Exemption-Line in Buchanan County, MO | |
| 80 FR 15991 - Mid-Atlantic Fishery Management Council (MAFMC); Fisheries of the Northeastern United States; Scoping Process | |
| 80 FR 15985 - BE-45: Quarterly Survey of Insurance Transactions by U.S. Insurance Companies With Foreign Persons | |
| 80 FR 15951 - Privacy Act of 1974; Implementation | |
| 80 FR 15997 - President's Advisory Commission on Educational Excellence for Hispanics | |
| 80 FR 16007 - Privacy Act System of Records | |
| 80 FR 16025 - Privacy Act of 1974; System of Records | |
| 80 FR 15963 - Approval and Promulgation of Air Quality Implementation Plans; State of New Mexico; Infrastructure SIP Requirements for the 2008 Ozone and 2010 Nitrogen Dioxide National Ambient Air Quality Standards; Interstate Transport of Fine Particulate Matter Air Pollution Affecting Visibility | |
| 80 FR 16005 - Environmental Protection Agency; Notice of Public Meeting | |
| 80 FR 16016 - Agency Forms Undergoing Paperwork Reduction Act Review | |
| 80 FR 15891 - Fisheries of the Exclusive Economic Zone Off Alaska; Bering Sea and Aleutian Islands Crab Rationalization Program | |
| 80 FR 15984 - Endangered and Threatened Species; Take of Anadromous Fish | |
| 80 FR 15986 - Endangered and Threatened Species; Notice of Intent To Withdraw Existing Draft Environmental Impact Statement | |
| 80 FR 16010 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
| 80 FR 16011 - Mid-Tier Bank Holding Company To Conduct a Minority Stock Issuance | |
| 80 FR 16011 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
| 80 FR 16001 - Energy Conservation Program for Consumer Products: Decision and Order Granting a Waiver to Empire Comfort Systems From the Department of Energy Vented Home Heating Equipment Test Procedure | |
| 80 FR 16000 - American LNG Marketing LLC; Application for Long-Term, Multi-Contract Authorization To Export Liquefied Natural Gas to Non-Free Trade Agreement Nations | |
| 80 FR 16004 - Agency Information Collection Extension | |
| 80 FR 15994 - Establishment of the National Commission on the Future of the Army | |
| 80 FR 15998 - Environmental Management Site-Specific Advisory Board, Paducah | |
| 80 FR 16028 - Office of the Associate Attorney General; Pilot Project for Tribal Jurisdiction Over Crimes of Domestic Violence | |
| 80 FR 15999 - Combined Notice of Filings #1 | |
| 80 FR 16013 - Agency Information Collection Activities: Submission for OMB Review; Comment Request | |
| 80 FR 16019 - Wildlife and Hunting Heritage Conservation Council | |
| 80 FR 16004 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; NESHAP for the Secondary Lead Smelter Industry (Renewal) | |
| 80 FR 16018 - Notice of Public Meetings, Twin Falls District Resource Advisory Council, Idaho | |
| 80 FR 16023 - Notice of Filing of Plats of Survey; Colorado | |
| 80 FR 16030 - Agency Information Collection Activities: Comment Request | |
| 80 FR 16007 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; Effluent Guidelines and Standards for the Airport Deicing Category (Renewal) | |
| 80 FR 16019 - Information Collection Activities: Operations for Minerals Other Than Oil, Gas, and Sulphur in the OCS; Proposed Collection; Comment Request | |
| 80 FR 16006 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; EPA's Light-Duty In-Use Vehicle Testing Program (Renewal) | |
| 80 FR 16029 - Agency Information Collection Activities: Proposed eCollection eComments Requested; eForm Access Request | |
| 80 FR 16022 - Notice of Public Meeting: Resource Advisory Council to the Boise District, Bureau of Land Management, U.S. Department of the Interior | |
| 80 FR 16011 - BMW of North America, LLC; Proposed Consent Order To Aid Public Comment | |
| 80 FR 16079 - Reports, Forms, and RecordKeeping Requirements | |
| 80 FR 15993 - Proposed Information Collection; Comment Request; Marine Mammal Health and Stranding Response Program, Level A Stranding and Rehabilitation Disposition Data Sheet | |
| 80 FR 16023 - Certain Loom Kits for Creating Linked Articles: Commission Determination To Review an Initial Determination in Part and, on Review, To Affirm a Finding of Violation With Modifications; Request for Written Submissions on Remedy, the Public Interest, and Bonding | |
| 80 FR 16078 - Recommendations for Facilities Realignments To Support Transition to NextGen as Part of Section 804 of the FAA Modernization and Reform Act of 2012; Request for Comments | |
| 80 FR 15958 - Digital Performance Right in Sound Recordings and Ephemeral Recordings | |
| 80 FR 15887 - Prohibition of Fixed-Wing Special Visual Flight Rules Operations at Washington-Dulles International Airport | |
| 80 FR 15979 - Order Temporarily Denying Export Privileges; Flider Electronics, LLC, Pavel Semenovich Flider, Gennadiy Semenovich Flider, et al. | |
| 80 FR 16040 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to the Solicitation Auction Mechanism | |
| 80 FR 16047 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Designation of a Longer Period for Commission Action on Proceedings To Determine Whether To Approve or Disapprove a Proposed Rule Change, as Modified by Amendment No. 1 Thereto, Relating To Listing and Trading of Shares of the SPDR SSgA Global Managed Volatility ETF Under NYSE Arca Equities Rule 8.600 | |
| 80 FR 16050 - Self-Regulatory Organizations; The NASDAQ Stock Market, LLC; Notice of Proposed Rule Change To Amend and Restate Certain Nasdaq Rules That Govern the Nasdaq Market Center | |
| 80 FR 16031 - Self-Regulatory Organizations; BATS Exchange, Inc.; Notice of Filing of Amendment No. 2, and Order Granting Accelerated Approval of a Proposed Rule Change, as Modified by Amendment Nos. 1 and 2 Thereto, to BATS Rules 20.3 and 20.6 | |
| 80 FR 16044 - Self-Regulatory Organizations; Miami International Securities Exchange, LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Its Fee Schedule | |
| 80 FR 16048 - Self-Regulatory Organizations; Miami International Securities Exchange, LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Its Fee Schedule | |
| 80 FR 16072 - Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Relating to Surveillance Agreements | |
| 80 FR 16046 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Order Approving a Proposed Rule Change To Amend Rules 6.41 and 24.8 | |
| 80 FR 15996 - Judicial Proceedings Since Fiscal Year 2012 Amendments Panel (Judicial Proceedings Panel); Notice of Federal Advisory Committee Meeting | |
| 80 FR 15990 - Proposed Information Collection; Comment Request; Current Population Survey, Annual Social and Economic Supplement | |
| 80 FR 15994 - Privacy Act of 1974; System of Records | |
| 80 FR 16031 - Product Change-Parcel Return Service Negotiated Service Agreement | |
| 80 FR 16018 - Notice To Extend the Comment Period for the Proposed Revised Guidelines for Implementing Executive Order 11988, Floodplain Management, as Revised Through the Federal Flood Risk Management Standard | |
| 80 FR 15992 - Marine Mammals; File No. 18890 | |
| 80 FR 15981 - Supercalendered Paper From Canada: Initiation of Countervailing Duty Investigation | |
| 80 FR 16029 - Comment Request for Information Collection for YouthBuild (YB) Reporting System, Extension Without Revisions | |
| 80 FR 15916 - Payment Limitation and Payment Eligibility; Actively Engaged in Farming | |
| 80 FR 15913 - Federal Motor Carrier Safety Regulations; Regulatory Guidance Concerning Crashes Involving Vehicles Striking Attenuator Trucks Deployed at Construction Sites | |
| 80 FR 15922 - Energy Conservation Program for Consumer Products: Energy Conservation Standards for Direct Heating Equipment and Pool Heaters | |
| 80 FR 15915 - Retrospective Review and Regulatory Flexibility | |
| 80 FR 15912 - Defense Federal Acquisition Regulation Supplement; Technical Amendments | |
| 80 FR 15909 - Defense Federal Acquisition Regulation Supplement: Use of Military Construction Funds (DFARS Case 2015-D006) | |
| 80 FR 15912 - Defense Federal Acquisition Regulation Supplement: Deletion of Text Implementing 10 U.S.C. 2323 (DFARS Case 2011-D038) | |
| 80 FR 15931 - Federal Agricultural Mortgage Corporation General Provisions; Federal Agricultural Mortgage Corporation Governance; Federal Agricultural Mortgage Corporation Risk Management; Federal Agricultural Mortgage Corporation Disclosure and Reporting; Farmer Mac Corporate Governance and Standards of Conduct | |
| 80 FR 15947 - Airworthiness Directives; The Boeing Company Airplanes | |
| 80 FR 15972 - National Priorities List | |
| 80 FR 15885 - Housing Trust Fund | |
| 80 FR 15899 - Approval, Disapproval, and Limited Approval and Disapproval of Air Quality Implementation Plans; California; Monterey Bay Unified Air Pollution Control District; Stationary Source Permits | |
| 80 FR 15901 - Approval and Promulgation of Air Quality Implementation Plans; New Mexico; Albuquerque/Bernalillo County; Revisions to Emission Inventory Requirements, and General Provisions | |
| 80 FR 15901 - National Priorities List | |
| 80 FR 16127 - Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands | |
| 80 FR 15906 - Connect America Fund; Developing a Unified Intercarrier Compensation Regime | |
| 80 FR 15885 - Rural Development Regulations-Update to FmHA References and to Census References | |
| 80 FR 15930 - Guidance for Conducting Technical Analyses for Low-Level Radioactive Waste Disposal | |
| 80 FR 16223 - Proposed Expansion, Regulatory Revision and New Management Plan for the Hawaiian Islands Humpback Whale National Marine Sanctuary | |
| 80 FR 16081 - Low-Level Radioactive Waste Disposal |
Commodity Credit Corporation
Rural Utilities Service
Census Bureau
Economic Analysis Bureau
Industry and Security Bureau
International Trade Administration
National Oceanic and Atmospheric Administration
Air Force Department
Defense Acquisition Regulations System
Energy Efficiency and Renewable Energy Office
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Substance Abuse and Mental Health Services Administration
Federal Emergency Management Agency
Bureau of Safety and Environmental Enforcement
Land Management Bureau
Surface Mining Reclamation and Enforcement Office
Employment and Training Administration
Copyright Royalty Board
Federal Aviation Administration
Federal Motor Carrier Safety Administration
National Highway Traffic Safety Administration
Surface Transportation Board
Consult the Reader Aids section at the end of this page for phone numbers, online resources, finding aids, reminders, and notice of recently enacted public laws.
To subscribe to the Federal Register Table of Contents LISTSERV electronic mailing list, go to http://listserv.access.thefederalregister.org and select Online mailing list archives, FEDREGTOC-L, Join or leave the list (or change settings); then follow the instructions.
Rural Business-Cooperative Service, Rural Housing Service, Rural Utilities Service, Farm Service Agency, U.S. Department of Agriculture (USDA).
Correction; direct final rule.
This document corrects technical errors in the direct final rule that appeared in the
This document is effective April 27, 2015.
Kenneth Meardon, Policy Advisor, Rural Business-Cooperative Service, U.S. Department of Agriculture, STOP 3201, 1400 Independence Avenue SW., Washington, DC 20250-3225; email:
In the FR Doc. 2015-01571 of February 24, 2015 (80 FR 9856), there are four technical errors and they are being corrected through this notice as found in the Correction of Errors section below.
On page 9856, first column, we inadvertently used the incorrect RIN number. The correct RIN number is 0570-AA91, not 0570-AA30.
On page 9912, we inadvertently updated an “outdated” definition of “Rural area” found in 7 CFR 4274.302. The subject definition (Rural or rural area) had already been updated in a June 3, 2014
On page 9913, we inadvertently used an older version of the definition of “Rural area” found in 7 CFR 4280.3. The subject definition had already been updated in a May 30, 2007
On page 9913, we unnecessarily made edits to two definitions (Long-term and Rural and rural areas) as the entire subpart in which these definitions are found is being replaced with a new regulation.
In FR Doc. 2015-01571 of February 24, 2015 (80 FR 9856), make the following corrections:
1. On page 9856, in the first column, remove “RIN 0570-AA30” and insert “RIN 0570-AA91” in its place.
2. On page 9912, in the third column, remove amendatory Instruction 417 in its entirety.
3. On page 9913, in the second column, remove amendatory Instruction 422 in its entirety.
4. On page 9913, in the third column, remove amendatory Instruction 429 in its entirety.
Federal Housing Finance Agency.
Final rule.
The Federal Housing Finance Agency (FHFA) is issuing a final rule setting forth requirements related to allocations by the Federal National Mortgage Association (Fannie Mae) and the Federal Home Loan Mortgage Corporation (Freddie Mac) (together, the Enterprises) to the Housing Trust and Capital Magnet Funds created by the Housing and Economic Recovery Act of 2008. The rule implements a statutory prohibition against the Enterprises passing the cost of such allocations through to the originators of loans they purchase or securitize, and finalizes and continues an interim final rule FHFA issued on December 16, 2014.
Effective March 26, 2015.
Alfred M. Pollard, General Counsel, (202) 649-3050 (not a toll-free number), Federal Housing Finance Agency, Eighth Floor, 400 Seventh Street SW., Washington, DC 20024. The telephone number for the Telecommunications Device for the Hearing Impaired is (800) 877-8339.
Section 1338 of the Federal Housing Enterprises Financial Safety and Soundness Act of 1992 (Safety and Soundness Act), as added by section 1131(b) of the Housing and Economic
Separately, section 1339 of the Safety and Soundness Act, as added by section 1131(b) of HERA, establishes the Capital Magnet Fund (CMF) within the U.S. Treasury as a special account within the Community Development Financial Institutions Fund.
Though the HTF is administered by the Secretary of HUD and the CMF is administered by the Secretary of the Treasury, Fannie Mae and Freddie Mac are supervised by FHFA.
The Enterprises' allocation obligations to support the HTF and CMF (together, the Funds) and related requirements are set forth at section 1337 of the Safety and Soundness Act.
Section 1337 requires the Director to issue a regulation regarding the prohibition against passing costs of the allocations required under the section to originators and how compliance with the requirements of the regulation and statute is to be enforced. Pursuant to section 1337 and the Director's general regulatory authority, the Director determined to issue an interim final rule with a request for comments to provide transparency on the prohibition and its implementation. The interim final rule itself is not a legislative rule but is procedural and thus would be excepted from the normal notice and comment requirements of the Administrative Procedures Act, 5 U.S.C. 553(b) and 5 U.S.C. 553(d)(3).
Though the substantive provisions of the interim final rule were established by statute and did not deviate from or add to the statutory requirements, the Director determined that issuing an interim final rule would support the implementation of the process of setting aside and allocating monies for the Funds and assure that the prohibition on pass through of costs accompanies the planning and deployment of funds. Further, the interim final rule would support the development of regulatory oversight mechanisms to be put in place to assure compliance with the prohibition.
FHFA invited comments on all aspects of the interim final rule and received 74 comments during the comment period, which closed on January 15, 2015. Two trade associations, Opportunity Finance Network (OFN), a U.S.-based membership organization of community development financial institutions, and Independent Community Bankers of America (ICBA), a member organization of U.S. community banks, provided comments. The remainder of the comments were from private citizens.
Only one commenter addressed the subject of the interim final rule, stating that costs of allocations to the Funds should be passed through to the originators of mortgages the Enterprises purchase or securitize while the Enterprises are in conservatorships. Since the prohibition against redirection or pass-through is established by statute, FHFA has not made any change to the interim final rule in response to this comment.
Twenty-one comments did not address any issues related to the interim final rule but instead addressed aspects of Enterprise business or the conservatorships. Roughly half of the comments indicated support for Enterprise allocations to the Funds, and OFN supported allocations to the CMF in particular. Some commenters who were supportive nonetheless expressed concern about lifting the suspension on allocations while the Enterprises are in conservatorships, and others suggested that the lifting of the suspension is an indication that the Enterprises should no longer be in conservatorships. Other commenters, including ICBA, objected to Enterprise allocations to the Funds as long as the Enterprises are in conservatorships.
In light of the comments received, FHFA is adopting the language of the interim final rule without change in this final rule.
The final rule does not contain any information collection requirement that requires the approval of OMB under the
The Regulatory Flexibility Act (5 U.S.C. 601
Administrative practice and procedure, Capital Magnet Fund, Government-sponsored enterprises, Housing Trust Fund, Reporting and recordkeeping requirements.
Accordingly, for the reasons stated in the Supplementary Information, under the authority of 12 U.S.C. 4567, the Federal Housing Finance Agency adopts as final the interim final rule published at 79 FR 74595, December 16, 2014, without change
Federal Aviation Administration (FAA), DOT.
Direct final rule; request for comments.
This action prohibits fixed-wing special visual flight rules operations at Washington-Dulles International Airport. This action is necessary to support aviation safety and the efficient use of the navigable airspace by managing operations in the busy and complex airspace around the airport.
This action becomes effective May 26, 2015.
Submit comments on or before April 27, 2015. If the FAA receives an adverse comment or notice of intent to file an adverse comment, the FAA will publish a document in the
You may send comments identified by docket number FAA-2015-0190 using any of the following methods:
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For technical questions concerning this action, contact David Maddox, Airspace Policy and Regulation Group, AJV-113, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591; telephone (202) 267-8783; email
For legal questions concerning this action, contact Robert Hawks, Office of the Chief Counsel, AGC-200, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591; telephone (202) 267-3073; email
The FAA's authority to issue rules on aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106 describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority.
This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103, Sovereignty and use of airspace, and Subpart III, Section 44701, General requirements. Under section 40103, the FAA is charged with prescribing regulations to ensure the safety of aircraft and the efficient use of the navigable airspace. Under section 44701, the FAA is charged with prescribing regulations to ensure safety in air commerce.
This regulation is within the scope of sections 40103 and 44701 because prohibiting fixed-wing SVFR operations in busy and complex airspace supports aviation safety and the efficient use of navigable airspace.
The FAA is adopting this direct final rule without prior notice and public comment because it formalizes current FAA practice at Washington-Dulles International Airport (IAD). Given the volume and complexity of instrument flight rules (IFR) traffic, a request to operate special visual flight rules (SVFR) would be denied. However, no such clearances have been requested for at least several years. Therefore, the FAA does not anticipate any negative comments to this direct final rule.
The Regulatory Policies and Procedures of the Department of Transportation (DOT) (44 FR 11034; Feb. 26, 1979) provide that to the maximum extent possible, operating administrations for DOT should provide an opportunity for public comment on regulations issued without prior notice. Accordingly, the FAA invites interested persons to participate in this rulemaking by submitting written comments, data, or views. The Agency also invites comments relating to the economic, environmental, energy, or federalism
A direct final rule will take effect on a specified date unless the FAA receives an adverse comment or notice of intent to file an adverse comment within the comment period. An adverse comment explains why a rule would be inappropriate, or would be ineffective or unacceptable without a change. It may challenge the rule's underlying premise or approach. Under the direct final rule process, the FAA does not consider the following types of comments to be adverse:
(1) A comment recommending another rule change, in addition to the change in the direct final rule at issue. The comment is adverse, however, if the commenter states why the direct final rule would be ineffective without the change.
(2) A frivolous or insubstantial comment.
If the FAA receives an adverse comment or notice of intent to file an adverse comment, it will publish a document in the
If the FAA receives no adverse comments or notices of intent to file an adverse comment, it will publish a confirmation document in the
See the “Additional Information” section for information on how to comment on this direct final rule and how the FAA will handle comments received. The “Additional Information” section also contains related information about the docket, privacy, and the handling of proprietary or confidential business information. In addition, there is information on obtaining copies of related rulemaking documents.
This direct final rule prohibits fixed-wing SVFR operations at IAD, one of the busiest airports in the United States. The FAA has determined this action is necessary due to the volume and complexity of IFR traffic in the IAD surface area of the Washington Tri-Area Class B airspace.
SVFR operations are defined in the Aeronautical Information Manual (AIM) as aircraft operating in accordance with air traffic control (ATC) clearances in Class B, C, D, and E surface areas in conditions less than the basic VFR weather minimums of three miles and 1,000 feet. Such operations are requested by pilots and approved by ATC. Pilots operating under SVFR must have at least one mile of flight visibility and remain clear of clouds. ATC predicate separation of aircraft on known performance and expected routes of flight. Since controllers do not know the exact weather conditions where an SVFR pilot is operating, they generally do not issue control instructions to the SVFR pilot so that the aircraft is not inadvertently placed in clouds. ATC often will increase standard separation distances for other aircraft operating in proximity, which can result in a loss of efficiency and capacity at airports.
The FAA previously has prohibited fixed-wing SVFR operations at airports with high traffic volumes. Section 3 of part 91, Appendix D, lists the locations where these operations are prohibited. The FAA first prohibited the operation of fixed-wing aircraft under SVFR weather minimums within specifically designated control zones (now designated as surface areas) in 1968.
The volume and complexity of IFR operations at IAD now indicate that use of SVFR operations can potentially affect the safe and efficient movement of traffic in the IAD Class B surface area. IAD is located within the Washington Tri-Area Class B airspace. In that same airspace, Baltimore/Washington International Thurgood Marshall Airport (BWI), Ronald Reagan Washington National Airport (DCA), and Andrews Air Force Base (ADW) are included in section 3 of Appendix D. From January 1 to December 31, 2013, there were 329,910 IFR operations at IAD, which included: 162,730 air carrier; 128,636 air taxi; and 38,236 general aviation operations.
Aircraft intending to enter the IAD surface area under SVFR would sometimes be operating at altitudes used by IFR arrivals to and departures from IAD. This interference can cause delays for IFR operations.
In addition to its location in the Class B airspace, IAD is also located within the Washington Special Flight Rules Area (SFRA) and is adjacent to the Washington Flight Restricted Zone (FRZ), both of which were established after September 11, 2001, and severely limit flexibility for VFR and SVFR operations to the east of IAD.
Although IAD has experienced increasing volume and complexity of IFR operations since opening, and has been acknowledged on numerous occasions as qualifying for inclusion in section 3, no rulemaking action has been completed prior to this direct final rule. The FAA believes that the volume and complexity of IFR traffic, along with the safety implications of these situations, require the prohibition of SVFR operations in the IAD Class B Surface Area.
The FAA is amending part 91, Appendix D, section 3, to add Washington-Dulles International Airport to an existing list of airports for which fixed-wing SVFR operations are prohibited. Currently, air traffic controllers at IAD deny requests for SVFR transitions through Class B airspace due to the volume and complexity of IFR traffic around IAD. This direct final rule formalizes the current practice.
The FAA has determined this action is necessary because of the increasing volume and complexity of IFR operations at IAD. Fixed-wing SVFR operations may interfere with the safe, orderly, and expeditious flow of aircraft operating under IFR in the IAD surface area. This prohibition also improves efficient use of airspace by reducing workload for air traffic controllers during IFR conditions and reducing delays for IFR operations.
Changes to Federal regulations must undergo several economic analyses. First, Executive Order 12866 and Executive Order 13563 direct that each Federal agency shall propose or adopt a regulation only upon a reasoned determination that the benefits of the intended regulation justify its costs. Second, the Regulatory Flexibility Act of 1980 (Public Law 96-354) requires agencies to analyze the economic impact of regulatory changes on small entities. Third, the Trade Agreements Act (Public Law 96-39) prohibits agencies from setting standards that create unnecessary obstacles to the foreign commerce of the United States. In developing U.S. standards, the Trade Act requires agencies to consider international standards and, where appropriate, that they be the basis of U.S. standards. Fourth, the Unfunded Mandates Reform Act of 1995 (Public Law 104-4) requires agencies to prepare a written assessment of the costs, benefits, and other effects of proposed or final rules that include a Federal mandate likely to result in the expenditure by State, local, or tribal governments, in the aggregate, or by the private sector, of $100 million or more annually (adjusted for inflation with base year of 1995). This portion of the preamble summarizes the FAA's analysis of the economic impacts of this direct final rule.
Department of Transportation Order DOT 2100.5 prescribes policies and procedures for simplification, analysis, and review of regulations. If the expected cost impact is so minimal that a proposed or final rule does not warrant a full evaluation, this order permits that a statement to that effect and the basis for it be included in the preamble if a full regulatory evaluation of the cost and benefits is not prepared. Such a determination has been made for this direct final rule. The reasoning for this determination follows:
This direct final rule formalizes and codifies current FAA practice at IAD. Since this direct final rule merely clarifies and codifies existing FAA procedures, the expected outcome will be a minimal impact with positive net benefits, and a full regulatory evaluation was not prepared. Any comments concerning the FAA determination should include supporting justification.
The FAA has, therefore, determined that this final rule is not a “significant regulatory action” as defined in section 3(f) of Executive Order 12866, and is not “significant” as defined in DOT's Regulatory Policies and Procedures.
The Regulatory Flexibility Act of 1980 (Public Law 96-354) (RFA) establishes “as a principle of regulatory issuance that agencies shall endeavor, consistent with the objectives of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the businesses, organizations, and governmental jurisdictions subject to regulation. To achieve this principle, agencies are required to solicit and consider flexible regulatory proposals and to explain the rationale for their actions to assure that such proposals are given serious consideration.” The RFA covers a wide-range of small entities, including small businesses, not-for-profit organizations, and small governmental jurisdictions.
Agencies must perform a review to determine whether a rule will have a significant economic impact on a substantial number of small entities. If the agency determines that it will, the agency must prepare a regulatory flexibility analysis as described in the RFA.
However, if an agency determines that a rule is not expected to have a significant economic impact on a substantial number of small entities, section 605(b) of the RFA provides that the head of the agency may so certify and a regulatory flexibility analysis is not required. The certification must include a statement providing the factual basis for this determination, and the reasoning should be clear.
This direct final rule merely formalizes and codifies existing FAA procedures; the expected outcome will have only a minimal impact on any small entity affected by this final rule.
If an agency determines that a rulemaking will not result in a significant economic impact on a substantial number of small entities, the head of the agency may so certify under section 605(b) of the RFA. Therefore, as provided in section 605(b), the head of the FAA certifies that this rulemaking will not result in a significant economic impact on a substantial number of small entities.
The Trade Agreements Act of 1979 (Public Law 96-39), as amended by the Uruguay Round Agreements Act (Public Law 103-465), prohibits Federal agencies from establishing standards or engaging in related activities that create unnecessary obstacles to the foreign commerce of the United States. Pursuant to these Acts, the establishment of standards is not considered an unnecessary obstacle to the foreign commerce of the United States, so long as the standard has a legitimate domestic objective, such as the protection of safety, and does not operate in a manner that excludes imports that meet this objective. The statute also requires consideration of international standards and, where appropriate, that they be the basis for U.S. standards. The FAA has assessed the potential effect of this direct final rule and determined that it will have only a domestic operational impact and therefore will not affect international trade.
Title II of the Unfunded Mandates Reform Act of 1995 (Public Law 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 (in 1995 dollars) 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 FAA currently uses an inflation-adjusted value of $151 million in lieu of $100 million. This direct final rule does not contain such a mandate; therefore, the requirements of Title II of the Act do not apply.
The Paperwork Reduction Act of 1995 (44 U.S.C. 3507(d)) requires that the FAA consider the impact of paperwork and other information collection burdens imposed on the public. The FAA has determined that there is no new requirement for information collection associated with this direct final rule.
In keeping with U.S. obligations under the Convention on International Civil Aviation, it is FAA policy to conform to International Civil Aviation Organization (ICAO) Standards and Recommended Practices to the maximum extent practicable. The FAA has determined that there are no ICAO Standards and Recommended Practices that correspond to this regulation.
FAA Order 1050.1E identifies FAA actions that are categorically excluded from preparation of an environmental assessment or environmental impact statement under the National Environmental Policy Act in the absence of extraordinary circumstances. The FAA has determined this
The FAA has analyzed this final rule under the principles and criteria of Executive Order 13132, Federalism. The agency determined that this action will not have a substantial direct effect on the States, or the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the various levels of government, and, therefore, does not have Federalism implications.
The FAA analyzed this final rule under Executive Order 13211, Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use (May 18, 2001). The agency has determined that it is not a “significant energy action” under the executive order and it is not likely to have a significant adverse effect on the supply, distribution, or use of energy.
Executive Order 13609, Promoting International Regulatory Cooperation, (77 FR 26413, May 4, 2012) promotes international regulatory cooperation to meet shared challenges involving health, safety, labor, security, environmental, and other issues and reduce, eliminate, or prevent unnecessary differences in regulatory requirements. The FAA has analyzed this action under the policies and agency responsibilities of Executive Order 13609 and has determined that this action would have no effect on international regulatory cooperation.
The FAA invites interested persons to participate in this rulemaking by submitting written comments, data, or views. The agency also invites comments relating to the economic, environmental, energy, or federalism impacts that might result from adopting the rulemaking action in this document. The most helpful comments reference a specific portion of the rulemaking action, explain the reason for any recommended change, and include supporting data. To ensure the docket does not contain duplicate comments, commenters should send only one copy of written comments, or if comments are filed electronically, commenters should submit only one time.
The FAA will file in the docket all comments it receives, as well as a report summarizing each substantive public contact with FAA personnel concerning this rulemaking. The FAA will consider all comments it receives on or before the closing date for comments. The FAA will consider comments filed after the comment period has closed if it is possible to do so without incurring expense or delay.
As stated earlier, if the FAA receives an adverse comment or notice of intent to file an adverse comment, it will publish a document in the
Proprietary or Confidential Business Information: Do not file proprietary or confidential business information in the docket. Such information must be sent or delivered directly to the person identified in the
Under 14 CFR 11.35(b), if the FAA is aware of proprietary information filed with a comment, the agency does not place it in the docket. It is held in a separate file to which the public does not have access, and the FAA places a note in the docket that it has received it. If the FAA receives a request to examine or copy this information, it treats it as any other request under the Freedom of Information Act (5 U.S.C. 552). The FAA processes such a request under Department of Transportation procedures found in 49 CFR part 7.
An electronic copy of rulemaking documents may be obtained from the Internet by—
1. Searching the Federal eRulemaking Portal (
2. Visiting the FAA's Regulations and Policies Web page at
3. Accessing the Government Printing Office's Web page at
Copies may also be obtained by sending a request to the Federal Aviation Administration, Office of Rulemaking, ARM-1, 800 Independence Avenue SW., Washington, DC 20591, or by calling (202) 267-9680. Commenters must identify the docket or amendment number of this rulemaking.
All documents the FAA considered in developing this rulemaking action, including economic analyses and technical reports, may be accessed from the Internet through the Federal eRulemaking Portal referenced in item (1) above.
Air traffic control, Aircraft, Airmen, Airports, Aviation safety.
In consideration of the foregoing, the Federal Aviation Administration amends chapter I of title 14, Code of Federal Regulations as follows:
49 U.S.C. 106(f), 106(g), 1155, 40101, 40103, 40105, 40113, 40120, 44101, 44111, 44701, 44704, 44709, 44711, 44712, 44715, 44716, 44717, 44722, 46306, 46315, 46316, 46504, 46506-46507, 47122, 47508, 47528-47531, 47534, articles 12 and 29 of the Convention on International Civil Aviation (61 Stat. 1180), (126 Stat. 11).
Section 3. * * *
Chantilly, VA (Washington-Dulles International Airport)
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule.
NMFS issues regulations to implement Amendment 31 to the Fishery Management Plan for Bering Sea/Aleutian Islands King and Tanner Crabs (FMP). These regulations revise the rules governing the acquisition, use, and retention of quota share established for captains and crew, known as crew quota share or C shares, under the Crab Rationalization Program (CR Program). Regulations implementing Amendment 31 temporarily expand the eligibility requirements for individuals wishing to acquire C share Quota Share (QS) by transfer; establish minimum participation requirements for C share QS holders to be eligible to receive an annual allocation of Individual Fishing Quota (IFQ); establish minimum participation requirements for C share QS holders to be eligible to retain their C share QS and an administrative process for revocation of an individual's C share QS if he or she fails to satisfy the minimum participation requirements; establish a regulatory mechanism to ensure that three percent of the total allowable catch (TAC) for each CR Program crab fishery is allocated as IFQ to holders of C share QS; and remove the prohibition on leasing C share IFQ. In addition, this final rule implements a regulatory amendment to the CR Program that: Establishes an earlier deadline for filing annual IFQ, individual processing quota (IPQ), and crab harvesting cooperative IFQ applications, which increases the amount of time during which NMFS will suspend the processing of IFQ and IPQ transfer applications; shortens the amount of time in which to appeal an initial administrative determination to withhold issuance of IFQ or IPQ; and provides that an applicant's proof of timely filing for IFQ, IPQ, or cooperative IFQ creates a presumption of timely filing. Finally, this final rule revises the reporting period and due date for CR Program registered crab receiver (RCR) Ex-vessel Volume and Value Reports. This final rule is necessary to ensure that individuals who hold C shares are active in the CR Program fisheries and to ensure that application deadlines provide adequate time to resolve disputes. This final rule is intended to promote the goals and objectives of the Magnuson-Stevens Fishery Conservation and Management Act (MSA), the FMP, and other applicable laws.
Effective May 1, 2015.
Electronic copies of Amendment 31 to the FMP, the Regulatory Impact Review (RIR)/Initial Regulatory Flexibility Analysis (IRFA), and the Categorical Exclusion prepared for this action may be obtained from
Written comments regarding the burden-hour estimates or other aspects of the collection-of-information requirements contained in this rule may be submitted to NMFS Alaska Region, P.O. Box 21668, Juneau, AK 99802, Attn: Ellen Sebastian, Records Officer; in person at NMFS Alaska Region, 709 West 9th Street, Room 420A, Juneau, AK; and by email to
Rachel Baker, 907-586-7228.
This final rule implements Amendment 31 to the FMP and regulatory amendments to the CR Program. NMFS published a notice of availability (NOA) for Amendment 31 on December 15, 2014 (79 FR 74058). The comment period on the NOA for Amendment 31 ended on February 13, 2015. The Secretary approved Amendment 31 on March 12, 2015, after accounting for information from the public, and determining that Amendment 31 is consistent with the FMP, the MSA, and other applicable law. NMFS published a proposed rule to implement Amendment 31 and the regulatory amendments on December 24, 2014 (79 FR 77427). The comment period on the proposed rule ended on January 23, 2015. NMFS received three comment letters during the comment periods on Amendment 31 and the proposed rule. The letters contained three unique comments. A summary of these comments and NMFS's responses are provided in the Comments and Responses section of this preamble.
Below is a brief description of the CR Program and the elements of that Program that apply to Amendment 31 and this final rule. For a more detailed description of the CR Program, please see section 2.3 of the RIR/IRFA (see
Under the CR Program, NMFS issued four types of QS based on qualifying harvest histories in certain BSAI crab fisheries during a specific period of time defined under the CR Program. Two of these types of QS were issued as C share QS to holders of State of Alaska Commercial Fisheries Entry Commission Interim Use Permits, generally vessel captains who met specific historic and recent participation requirements in CR Program fisheries. Vessel captains who did not meet both the historic and recent participation criteria did not receive initial allocations of C share QS. Three-percent of the QS pool for each CR Program fishery was issued as C share QS. The Council's intent in creating C share QS was to provide both a QS holding opportunity for long-term fishery participants who intended to remain active in the fisheries and an entry level QS acquisition opportunity for new entrants.
The Council intended IFQ derived from C share QS to be harvested by individuals active in the CR Program fisheries. To achieve this goal, CR Program regulations required that individuals wishing to acquire C share QS to demonstrate that they had at least 150 days of sea time in a harvesting capacity in any U.S. commercial fishery and recent participation in one of the CR Program fisheries by making a landing of CR Program crab in the year preceding the application to acquire C share QS.
Implementation of the CR Program resulted in a significant reduction in harvesting vessel fleet size and a commensurate reduction in employment opportunities for vessel crew. Efficiencies gained under the CR Program provide harvesting vessels the option to not participate in each fishing season for each CR Program crab species. These changes in fishing practices have made it difficult for individuals who wish to acquire C share QS to satisfy the participation requirement of making a landing of CR
In addition, holders of C share QS may become members of harvesting cooperatives and, through contractual terms determined by the harvesting cooperative, may have IFQ derived from their C share QS harvested by other fishery participants. This ability to lease C share IFQ within a harvesting cooperative, coupled with the fleet contraction and changes in fishing practices occurring since implementation of the CR Program, rendered the initial regulations related to acquisition of C share QS ineffective in ensuring that those QS are held by active participants in the CR Program fisheries.
The crab fishing year begins on July 1 and ends on June 30. Annually, QS and PQS holders must apply for allocations of IFQ and IPQ, respectively, for the upcoming crab fishing year. QS holders apply for annual IFQ through an individual application. Currently, they must indicate on this application whether or not they are joining a cooperative. If they are joining a cooperative that year, the cooperative's annual IFQ application must include the QS holder's annual IFQ application (or a copy of that application). Because IPQ is not subject to cooperative management, a PQS holder applies for IPQ directly to NMFS, and NMFS issues IPQ directly to the PQS holder. Prior to this final rule, all applications for IFQ, IPQ, and cooperative IFQ had to be filed with the NMFS Restricted Access Management Program (RAM) by August 1. To aid QS and PQS holders in meeting the application deadline, NMFS provides application forms on its Web site (see
Although the crab fishing year begins on July 1, the individual crab fisheries open at different times later in the crab fishing year. The first crab fishery to open is the Aleutian Islands golden king crab fishery and, until recently, this fishery was scheduled to open on August 15. In March 2014, the State of Alaska changed the opening date for the Aleutian Islands golden king crab fishery to August 1, effective with the 2015/2016 crab fishing year, to allow for fishing to occur slightly earlier in the summer months when it is safer for the fishers. The remaining crab fisheries open on October 15 or later in the crab fishing year.
Below are brief descriptions of the actions implemented by this final rule. For more detailed descriptions of the actions and the rationale for these actions, please see section 2.4 of the RIR/IRFA (see
The final rule makes several changes to regulations governing the acquisition, use, and retention of C share QS under the CR Program. The final rule temporarily expands the eligibility requirements regarding acquisition of C share QS by permitting the transfer of C share QS to an individual who is a U.S. citizen with at least 150 days of sea time as part of a harvesting crew in any U.S. commercial fishery and who either received an initial allocation of CVC or CPC QS or participated in at least one delivery of crab from a fishery in the CR program in three of the five crab fishing years prior to the start of the CR Program, starting with the 2000/2001 crab fishing year through the 2004/2005 crab fishing year. The final rule does not remove the current eligibility criteria but adds to it the less restrictive eligibility criteria for a period of four years from the effective date of the final rule.
In order to receive an annual allocation of C share IFQ, the final rule requires a C share QS holder to have either participated in at least one delivery in a CR Program fishery in the three crab fishing years preceding the crab fishing year for which the holder is applying for IFQ, or received an initial allocation of C shares and participated in 30 days of State of Alaska or Alaska federal commercial fisheries in the three crab fishing years preceding the crab fishing year for which the holder is applying for IFQ. The final rule also requires holders of C share QS to meet similar participation requirements over a span of four years in order to retain their C share QS.
If a C share QS holder fails to satisfy the participation requirements and does not divest his or her C share QS, the final rule provides NMFS with the authority to revoke the C share QS. If a C share QS holder satisfies the participation requirements to receive C share IFQ, the holder also will satisfy the participation requirements for retention of C share QS.
The final rule removes the current prohibition on leasing C share IFQ and C share QS holders will continue to be able to join cooperatives. However, all C share QS holders must meet the participation requirements in order to receive C share IFQ and retain C share QS; those who lease C share IFQ or join a cooperative are not exempt from the participation requirements. Finally, the final rule revises regulations governing the annual calculation of IFQ to ensure that 3 percent of the annual TAC for each crab fishery included in the CR Program is allocated as IFQ to holders of C share QS.
These actions are necessary to fulfill the Council's intent that C share QS are held by individuals who are actively participating in the CR Program fisheries, to provide QS acquisition opportunities to captains and crew who may have been displaced from employment in the CR Program fisheries and were not initial recipients of QS, and to make C share QS available to captains and crew who are new entrants into the CR program fisheries.
Additionally, this final rule implements a regulatory amendment adopted by the Council. The regulatory amendment makes three changes in the annual application process for IFQ, IPQ, and cooperative IFQ in the CR Program. Specifically, this final rule: (1) establishes June 15 as the deadline for filing annual IFQ, IPQ, and cooperative IFQ applications, which also increases the amount of time during which NMFS will suspend the processing of IFQ and IPQ transfer applications; (2) shortens the amount of time in which to appeal an initial administrative determination to withhold issuance of IFQ or IPQ from 60 days to 30 days; and (3) provides in the regulations that an applicant's proof of timely filing an application for IFQ, IPQ, or cooperative IFQ creates a presumption of timely filing. These changes will provide NMFS with adequate time to resolve disputes prior to the issuance of IFQ and IPQ.
Finally, to accommodate the State of Alaska's change to the season opening date for the Aleutian Islands golden king crab fishery, the final rule revises the reporting period for RCR Ex-vessel Volume and Value Reports, from August 15 through April 30 to August 1 through May 31, and revises the date by which the RCR Ex-vessel Volume and Value Report must be received by the Regional Administrator, from May 15 to May 31. These changes align the reporting period with the new season opening date. The new reporting period will start with the 2015/2016 crab fishing year and the first reports using the new reporting period will be due by May 31, 2016.
NMFS received three letters of public comment during the public comment periods for Amendment 31 and the proposed rule. A summary of the
NMFS has made three changes from the proposed rule.
One adds the phrase “as crew” to § 680.41(c)(1)(vii)(B)(
The second change adds language to § 680.40(g)(2)(i) and (ii) and § 680.40(m)(2)(i) and (ii) that explains how NMFS will account for years in which a crab fishery is closed to fishing when determining whether an individual has satisfied the participation requirements for IFQ issuance and C share QS retention. NMFS received an inquiry, not formally submitted as a comment, regarding the participation requirements for individuals who hold C shares in a crab fishery that is closed, or in a crab fishery that closes in the future. NMFS recognizes that there are some individuals who hold C share QS in a single crab fishery and that some CR Program crab fisheries are closed to fishing periodically or for extended periods of time. It is neither the Council's nor NMFS' intent to penalize a C share QS holder for not participating when the only crab fishery for which the individual holds C share QS is closed to fishing. Therefore, the final rule clarifies that if an individual holds C share QS in a single CR Program crab fishery and that fishery is closed to fishing for an entire crab fishing year, NMFS will exclude that crab fishing year when determining whether the individual has satisfied the participation requirements for IFQ issuance and C share QS retention. NMFS emphasizes that the exclusion of years applies solely to those individuals who hold C share QS in just one CR Program crab fishery and that fishery is closed for an entire crab fishing year. NMFS will not exclude crab fishing years when an individual holds C share QS in more than one CR Program crab fishery, some of which may be closed for the entire crab fishing year and some of which may be open during that same year.
The following examples illustrate this clarification. Individual A holds C share QS in the Pribilof Islands blue crab fishery only, while Individual B holds C share QS in the Pribilof Islands blue king crab fishery and the Bering Sea snow crab fishery. Following implementation of this final rule, the Pribilof Islands blue king crab fishery is closed for three fishing years but the Bering Sea snow crab fishery is open during these years. Because Individual A holds C share QS in a single CR Program crab fishery and that fishery is closed to fishing for the entire year, NMFS would exclude those three crab fishing years in which the Pribilof Islands blue king crab fishery is closed when determining whether Individual A has satisfied the participation requirements. However, NMFS would not exclude the crab fishing years in which the Pribilof Islands blue king crab fishery is closed when determining whether Individual B has satisfied the participation requirements because Individual B can participate in the Bering Sea snow crab fishery and satisfy the participation requirements.
If the Pribilof Islands blue king crab fishery would open to fishing in the fourth crab fishing year but close again for the fifth and sixth fishing years, NMFS would include the fourth crab fishing year but exclude the fifth and sixth crab fishing years when determining whether Individual A has satisfied the participation requirements. Under this example, Individual A would only have one open fishing year that NMFS would use to determine participation. Because the participation requirements use three-year and four-year participation periods, NMFS would not have enough open fishing years to determine whether Individual A satisfied the participation requirements and NMFS would not withhold IFQ or initiate revocation proceedings until the required number of open fishing years have occurred and NMFS has determined that Individual A failed to satisfy the participation requirements. If the Pribilof Islands blue king crab fishery opens again in the seventh and eighth fishing years, NMFS would have enough open fishing years to determine whether Individual A has satisfied the participation requirements for issuance of C share IFQ for the ninth crab fishing year.
The third change adds a limited exemption at § 680.40(g)(2)(iii) and § 680.40(m)(5) to the participation requirements for IFQ issuance and C share QS retention for those individuals who acquire C share QS using the expanded eligibility criteria at § 680.41(c)(1)(vii)(B). NMFS determined that the participation requirements established by this final rule will be immediately applicable to individuals who acquire C share QS using the expanded eligibility criteria at § 680.41(c)(1)(vii)(B) but that those individuals may not be able to satisfy the participation requirements at the time of acquisition. By design, the expanded eligibility requirements do not require an eligible individual to have participated in a CR Program crab fishery in the 365 days prior to acquisition of the C share QS and create the possibility that an individual who is eligible to acquire C share QS under the expanded eligibility criteria would fail to satisfy the participation requirements for issuance of IFQ and retention of C
Section 3507(c)(B)(i) of the PRA requires that agencies inventory and display a current control number assigned by the Director, OMB, for each agency information collection. Section 902.1(b) identifies the location of NOAA regulations for which OMB approval numbers have been issued. Because this final rule revises and adds data elements within a collection-of-information for recordkeeping and reporting requirements, 15 CFR 902.1(b) is revised to reference correctly the sections resulting from this final rule.
The Administrator, Alaska Region, determined that Amendment 31 is necessary for the conservation and management of the Bering Sea/Aleutian Island CR Program fisheries and that it is consistent with the Magnuson-Stevens Fishery Conservation and Management Act and other applicable laws.
This final rule has been determined to be not significant for the purposes of Executive Order 12866.
Section 212 of the Small Business Regulatory Enforcement Fairness Act of 1996 states that, for each rule or group of related rules for which an agency is required to prepare a final regulatory flexibility analysis, the agency shall publish one or more guides to assist small entities in complying with the rule, and shall designate such publications as “small entity compliance guides.” The agency shall explain the actions a small entity is required to take to comply with a rule or group of rules. The preamble to the proposed rule (79 FR 77427; December 24, 2014) and the preamble to this final rule serve as the small entity compliance guide. This rule does not require any additional compliance from small entities that is not described in the preamble to the proposed rule (79 FR 77427; December 24, 2014) and this final rule. Copies of the proposed rule and this final rule are available from NMFS at the following Web site:
The following paragraphs constitute the final regulatory flexibility analysis for this action. Section 604 of the Regulatory Flexibility Act requires an agency to prepare a FRFA after being required by that section or any other law to publish a general notice of proposed rulemaking and when an agency promulgates a final rule under section 553 of Title 5 of the U.S. Code.
Section 604 describes the required contents of a FRFA: (1) A statement of the need for, and objectives of, the rule; (2) a statement of the significant issues raised by the public comments in response to the initial regulatory flexibility analysis, a statement of the assessment of the agency of such issues, and a statement of any changes made in the proposed rule as a result of such comments; (3) the response of the agency to any comments filed by the Chief Counsel for Advocacy of the Small Business Administration in response to the proposed rule, and a detailed statement of any change made to the proposed rule in the final rule as a result of the comments; (4) a description of and an estimate of the number of small entities to which the rule will apply or an explanation of why no such estimate is available; (5) a description of the projected reporting, recordkeeping and other compliance requirements of the rule, including an estimate of the classes of small entities which will be subject to the requirement and the type of professional skills necessary for preparation of the report or record; and (6) a description of the steps the agency has taken to minimize the significant economic impact on small entities consistent with the stated objectives of applicable statutes, including a statement of the factual, policy, and legal reasons for selecting the alternative adopted in the final rule and why each one of the other significant alternatives to the rule considered by the agency which affect the impact on small entities was rejected.
A description of the need for, and objectives of, the rule is contained in the preamble to this final rule and is not repeated here. This FRFA incorporates the Initial Regulatory Flexibility Analysis (IRFA) and the summary of the IRFA in the proposed rule (79 FR 77427, December 24, 2014).
NMFS published a proposed rule to implement Amendment 31 on December 24, 2014 (79 FR 77427). An IRFA was prepared and summarized in the Classification section of the preamble to the proposed rule. The description of this action, its purpose, and its legal basis are described in the preamble to the proposed rule and are not repeated here.
NMFS received three public comments on Amendment 31 and the proposed rule. No comments were received on the IRFA, or on the economic impacts of this action generally. The Chief Counsel for Advocacy of the Small Business Administration (SBA) did not file any comments on the proposed rule.
The entities directly regulated by this action are individuals who currently hold C share QS, and individuals who were at one time active in the crab fisheries as captain and crew prior to the implementation of the CR Program but who are no longer active as captain or crew. The SBA has established size standards for all major industry sectors in the U.S., including commercial shellfish harvesters. On June 12, 2014, the Small Business Administration (SBA) issued a final rule revising the small business size standards for several industries effective July 14, 2014 (79 FR 33647, June 12, 2014). The new size standards were used to prepare the FRFA for this final rule. A business primarily involved in finfish harvesting is classified as a small business if it is independently owned and operated, is not dominant in its field of operation (including its affiliates), and has combined annual gross receipts not in excess of $20.5 million, for all its affiliated operations worldwide. For commercial shellfish harvesters, the same qualifiers apply, except the combined annual gross receipts threshold is $5.5 million.
One hundred and seventy-nine individuals currently hold C shares. Of these individuals, 70 are estimated to have been part of the 239 individuals who received an initial allocation of C shares based on their historical participation record. About 750 individuals, who were active in the crab fisheries as captain and crew prior to the implementation of the CR Program, are no longer active as captain or crew; the final rule allows those 750 individuals to acquire C shares by transfer for a period of four years. Thus,
The final rule also makes several regulatory amendments that are not contained in Amendment 31 to the FMP. These amendments directly regulate holders of QS, PQS and cooperatives formed under the CR Program. Each of the cooperatives in the CR Program includes as few as several to as many as several hundred of QS holders as members and has revenues in excess of the small entity threshold; however, during the 2010-2011 fishing season, 64 QS holders elected not to join cooperatives. These 64 QS holders are all small entities for RFA purposes.
Entities holding PQS with fewer than 500 employees are “small entities” according to the RFA. As of 2011, 21 entities hold PQS. Of these 21 entities, 10 are large entities and 11 are small entities for RFA purposes.
The final rule makes several changes to recordkeeping and reporting requirements for C share QS holders, as well as those wishing to acquire C shares. Entities wishing to acquire C shares that are currently ineligible, because of they are not currently participating as captains or crew, but that will be eligible, because of past participation, will be required to submit evidence of past participation in the form of fish tickets or affidavits. Entities holding C share QS will also be required to submit verification of their compliance with participation standards necessary for the receiving C share IFQ and to maintain their C share QS holdings. Since C share QS holders must meet participation standards to receive annual IFQ allocations and retain C share QS, the reporting requirements are structured to determine compliance with those standards.
A FRFA must describe the steps the agency has taken to minimize the significant economic impact on small entities consistent with the stated objectives of applicable statues, including a statement of the factual, policy, and legal reasons for selecting the alternative adopted in the final rule and why each one of the other significant alternatives to the rule considered by the agency that affect the impact on small entities was rejected. “Significant alternatives” are those that achieve the stated objectives for the action, consistent with prevailing law with potentially lesser adverse economic impacts on small entities, as a whole.
Three alternatives, including the no action alternative, were considered to relax the eligibility requirements for the acquisition of C shares by transfer. The first alternative creates eligibility for entities that received an initial allocation of C shares. The second alternative creates eligibility for entities with historical participation in the CR Program fisheries. The Council decided to select both of the action alternatives to fully expand the eligibility to include all those entities who had historically participated in the crab fisheries prior to rationalization. The Council did not consider further expanding the eligibility to include entities that do not have any type of historical participation in the crab fisheries, because the original intent in establishing C shares was to provide an opportunity for entities with a connection to the crab fisheries, through participation, to own shares.
The final rule contains a provision that no C shares would be revoked until 5 years after implementation of the amendment to the FMP. The Council intended that this provision would mitigate negative effects on individuals whose shares may be revoked by this action. The Council and NMFS considered two other options to delay revocations. Under the first, no revocations would have taken place until 5 years after implementation of the CR Program, which would have been the year 2010. The second option extended the period to 10 years after implementation of the CR Program, which would have been the year 2015. The preferred alternative would begin revocations 5 years after this final rule is effective. This alternative was selected because it provides holders of C shares with certainty about the rules that will govern C shares and with time to consider business plans for their C shares. The preferred alternatives give holders of C shares time to plan whether to meet the new active participation requirements and retain their C shares or whether to divest their share holdings.
For the provision requiring active participation to receive annual IFQ from C shares, the final rule requires active participation over a 3-year period. For the provision requiring active participation requirement to retain C shares, the final rule requires active participation over a 4-year period. Three categories of alternatives were considered for these provisions: the status quo alternative, which essentially had no active participation requirement because holders of C shares can and do assign their shares to cooperatives; alternatives that would require less or no active participation in the fisheries to maintain C share holdings; and alternatives that would require greater levels of participation as crew.
The Council concluded, and NMFS agrees, that the status quo and the alternatives that require less participation to maintain C share holdings are inconsistent with the Council's intent to ensure that C shares are held by individuals who are active in the fisheries and to create a pool of C shares for use exclusively by individuals who are active in the fisheries. The Council examined alternatives that required higher levels of participation to maintain C share holdings or that required participation exclusively in CR Program fisheries. The Council concluded, and NMFS agrees that these alternatives unduly constrained holders of C shares, given the fleet consolidation and other changes in crab fishing under the CR Program. With fewer vessels active in the fisheries, greater competition for crew jobs is an obstacle to maintaining active participation in the CR Program fisheries. By allowing individuals to meet a minimal landing requirement to maintain their active participation status and by allowing individuals who are initial recipients of C shares to meet the active participation requirements through fishing in non-crab commercial fisheries in Alaska, the preferred alternative would allow individuals to miss some seasons, when crew jobs may be difficult to secure. The Council concluded and NMFS agrees that the preferred alternative reaches a reasonable balance between alternatives that would allow extended absences from active participation in the fisheries and alternatives that would require greater participation in the CR Program fisheries, an approach which fails to recognize the nature of the market for employment in the CR Program fisheries.
The Council did not consider an alternative to the regulatory mechanism to ensure three percent of the TAC for each CR Program fishery is allocated to holders of C share QS. Under the current regulations, approximately three
No duplication, overlap, or conflict between this action and existing Federal rules has been identified.
This final rule contains collection-of-information requirements subject to the Paperwork Reduction Act (PRA), which have been approved by the Office of Management and Budget (OMB). Collections are presented below by OMB control number.
Public reporting burden per response is estimated to average 2 hours for the Application for BSAI Crab Eligibility to Receive QS/PQS or IFQ/IPQ by Transfer; 2.5 hours for Application for Annual Crab Permit IFQ; 2.5 hours for Application for Annual Crab Permit IPQ; 30 minutes for Application for Converted CPO QS and CPO IFQ; 2.5 hours for Application for Crab Harvesting Cooperative IFQ Permit; 4 hours for Appeal for Denial of Application; 2.5 hours for Application for Transfer of Crab IFQ; 2.5 hours for Application for Transfer of Crab IPQ permit; and 2 hours for Application for Transfer of Crab QS or PQS.
Public reporting burden per response is estimated to average 2 hours for the CR Program Registered Crab Receiver Ex-vessel Volume and Value Report.
Burden estimates include the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection information.
Send comments regarding these burden estimates, or any other aspects of the information collections, to NMFS (see
Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to penalty for failure to comply with, a collection of information subject to the requirement of the PRA, unless that collection of information displays a currently valid OMB control number. All currently approved NOAA collections of information may be viewed at:
Reporting and recordkeeping requirements.
Alaska, Fisheries, Reporting and recordkeeping requirements.
For the reasons set out in the preamble, NMFS amends 15 CFR part 902 and 50 CFR part 680 as follows:
44 U.S.C. 3501
The additions and revisions read as follows:
(b) * * *
16 U.S.C. 1862; Pub. L. 109-241; Pub. L. 109-479.
(f) * * *
(1) A complete application must be received by NMFS no later than June 15 (or postmarked by this date, if sent via U.S. mail or a commercial carrier) for the upcoming crab fishing year for which a person is applying to receive IFQ or IPQ. If a complete application is not received by NMFS by this date, or postmarked by this date, the person will not receive IFQ or IPQ for the upcoming crab fishing year. In the event that NMFS has not received a complete and timely application by June 15, NMFS will presume that the application was timely filed if the applicant can provide NMFS with proof of timely filing.
(n) * * *
(1)(i) A complete application must be received by NMFS no later than June 15 (or postmarked by this date, if sent via U.S. mail or a commercial carrier) for the upcoming crab fishing year for which a person or crab harvesting cooperative is applying to receive converted CPO QS and the IFQ derived from that converted CPO QS. If a complete application is not received by NMFS by this date, or postmarked by this date, the person or crab harvesting cooperative will not receive converted CPO QS and the IFQ derived from that converted CPO QS for the upcoming crab fishing year. In the event that NMFS has not received a complete and timely application by June 15, NMFS will presume that the application was
(q)
(m) * * *
(2)
(3)
(b) * * *
(1)
(2)
(d) * * *
(1)
(g)
(2)
(i) The individual has participated as crew in at least one delivery of crab in any CR crab fishery during the three crab fishing years preceding the crab fishing year for which the individual is filing an annual crab IFQ permit application. If the individual holds C share QS in a single CR crab fishery and that CR crab fishery is closed to fishing for an entire crab fishing year, NMFS will exclude that crab fishing year when determining whether the individual has satisfied this participation requirement.
(ii) The individual was an initial recipient of CVC or CPC QS and participated as crew in at least 30 days of fishing in a commercial fishery managed by the State of Alaska or in a U.S. commercial fishery in the U.S. Exclusive Economic Zone off Alaska during the three crab fishing years preceding the crab fishing year for which the individual is filing an annual crab IFQ permit application. Individuals may combine participation as crew in State and Federal commercial fisheries to meet this requirement. If the individual holds C share QS in a single CR crab fishery and that CR crab fishery is closed to fishing for an entire crab fishing year, NMFS will exclude that crab fishing year when determining whether the individual has satisfied this participation requirement.
(iii) All of the CVC or CPC QS permits held by the individual were acquired using the eligibility criteria in 50 CFR 680.41(c)(1)(vii)(B) and the individual has held those CVC or CPC QS permits for less than three full crab fishing years.
(3)
(i)
(ii)
(h) * * *
(1)
(A) IFQ TAC
(B) IFQ
(ii)
(A) CVC/CPC IFQ
(B) CVO/CPO IFQ
(m)
(2)(i) The individual has participated as crew in at least one delivery of crab in any CR crab fishery during the previous four consecutive crab fishing years. If the individual holds C share QS in a single CR crab fishery and that CR crab fishery is closed to fishing for an entire crab fishing year, NMFS will exclude that crab fishing year when determining whether the individual has satisfied this participation requirement.
(ii) The individual was an initial recipient of CVC QS or CPC QS and participated as crew in at least 30 days of fishing in a commercial fishery managed by the State of Alaska or in a U.S. commercial fishery in the U.S. Exclusive Economic Zone off Alaska during the previous four consecutive crab fishing years. Individuals may combine participation as crew in State and Federal commercial fisheries to meet this requirement. If the individual holds C share QS in a single CR crab fishery and that CR crab fishery is closed to fishing for an entire crab fishing year, NMFS will exclude that crab fishing year when determining whether the individual has satisfied this participation requirement.
(3) An individual issued a CVC QS or CPC QS permit may include information demonstrating compliance with the participation requirements in paragraph (m)(2) of this section with the individual's annual Application for Crab IFQ.
(4) If an individual issued a CVC QS or CPC QS permit fails to meet the participation requirements in paragraph (m)(2) of this section or fails to qualify for the exemption in paragraph (m)(5) of this section, NMFS will revoke all of the individual's CVC QS or CPC QS in accordance with § 680.43.
(5) All of the CVC or CPC QS permits held by the individual were acquired using the eligibility criteria in § 680.41(c)(1)(vii)(B) and the individual has held those CVC or CPC QS permits for less than four full crab fishing years.
(b) * * *
(1)
(c) * * *
(1) * * *
(2) * * *
(ii) * * *
(C)
(e) * * *
(3)
(a) Beginning July 1, 2019, the Regional Administrator will revoke all CVC QS and CPC QS held by an individual who has not met the participation requirements set forth in § 680.40(m). The Regional Administrator will revoke an individual's CVC QS or CPC QS in accordance with the procedures set forth in this section.
(b)
(c)
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA) is taking final action to approve certain revisions to the Monterey Bay Unified Air Pollution Control District (MBUAPCD or District) portion of the applicable state implementation plan (SIP) for the State of California and to disapprove certain other revisions. This action was proposed in the
This rule is effective on April 27, 2015.
EPA has established docket number [EPA-R09-OAR-2014-0746] for this action. Generally, documents in the docket for this action are available electronically at
Laura Yannayon, EPA Region IX, by phone: (415) 972-3534 or by email at
Throughout this document, the terms “we,” “us,” and “our” refer to EPA.
On October 15, 2014 (79 FR 61797), EPA proposed several actions in connection with certain revisions to the MBUAPCD portion of the California SIP submitted by the California Air Resources Board under the CAA. Table 1 lists the rules submitted for EPA action.
EPA proposed a combination of actions consisting of disapproval of Rule 200 (Permits), limited approval and limited disapproval of Rule 207 (Review of New or Modified Sources), repeal of Rule 208 (Standards for Granting Permits to Operate) and approval of Rules 203 (Application), 204 (Cancellation of Applications), 206 (Standards for Granting Applications) and 212 (Public Availability of Emission Data). We noted one specific deficiency in Rule 200 and several deficiencies in Rule 207 that are the basis for the disapproval actions. Please see the proposed notice and the associated TSD for a list of these deficiencies.
EPA's proposed action provided a 30-day public comment period. During this time we received no comments.
No comments were submitted to change our assessment of the rules as described in our proposed action. Pursuant to section 110(k) of the CAA and for the reasons provided in our proposed action and associated TSD, EPA is finalizing a limited approval and limited disapproval of Rule 207, a full disapproval of Rule 200, full approval of Rules 203, 204, 206 and 212 and the request to repeal Rule 208.
Our full disapproval of Rule 200 means the current SIP approved version of Rule 200—Permits Required will remain in effect. (64 FR 35577 July 1, 1999).
The limited disapproval of Rule 207 triggers an obligation for EPA to promulgate a Federal Implementation Plan unless the State of California corrects the deficiencies, and EPA approves the related plan revisions within two years of the final action.
In this rule, the EPA is finalizing regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA is finalizing the incorporation by reference of the MBUAPCD rules described in the amendments to 40 CFR 52.220 set forth below. The EPA has made, and will continue to make, these documents available electronically through
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act 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 Clean Air Act. 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 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 Clean Air Act; 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 and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Reporting and
42 U.S.C. 7401
Part 52, Chapter I, Title 40 of the Code of Federal Regulations is amended as follows:
42 U.S.C. 7401
(c) * * *
(282) * * *
(i) * * *
(C) * * *
(
(
(284) * * *
(i) * * *
(A) * * *
(
(308) * * *
(i) * * *
(E) Monterey Bay Unified Air Pollution Control District.
(453) New and amended regulations for the following APCDs were submitted on May 12, 2011.
(i) Incorporation by reference.
(A) Monterey Bay Unified Air Pollution Control District.
Environmental Protection Agency (EPA).
Withdrawal of direct final rule.
On February 2, 2015, the Environmental Protection Agency (EPA) published a direct final rule approving revisions to the Albuquerque/Bernalillo County, New Mexico State Implementation Plan. These revisions add definitions and clarifying changes to the general provisions and add a new emissions inventory regulation that establishes reporting requirements for stationary sources in Albuquerque/Bernalillo County. The direct final rule was published without prior proposal because EPA anticipated no adverse comments. EPA stated in the direct final rule that if we received relevant, adverse comments by March 4, 2015, EPA would publish a timely withdrawal in the
The direct final rule published on February 2, 2015 (80 FR 5471), is withdrawn effective March 26, 2015.
Mr. John Walser (6PD-L), Air Planning Section, telephone (214) 665-7128, fax (214) 665-6762, email:
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxides, Ozone, Particulate matter, Reporting and recordkeeping requirements, Volatile organic compounds.
Accordingly, the amendments to 40 CFR 52.1620 published in the
Environmental Protection Agency (EPA).
Final rule.
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA” or “the Act”), as amended, requires that the National Oil and Hazardous Substances Pollution Contingency Plan (“NCP”) include a list of national priorities among the known releases or threatened releases of hazardous substances, pollutants or contaminants throughout the United States. The National Priorities List (“NPL”) constitutes this list. The NPL is intended primarily to guide the Environmental Protection Agency (“the EPA” or “the agency”) in determining which sites warrant further investigation. These further investigations will allow the EPA to assess the nature and extent of public health and environmental risks associated with the site and to determine what CERCLA-financed remedial action(s), if any, may be appropriate. This rule adds two sites to the General Superfund section of the NPL.
The document is effective on April 27, 2015.
Contact information for the EPA Headquarters and EPA Region 5 dockets:
• Docket Coordinator, Headquarters; U.S. Environmental Protection Agency; CERCLA Docket Office; 1301 Constitution Avenue NW.; William Jefferson Clinton Building West, Room
• Todd Quesada, Region 5 (IL, IN, MI, MN, OH, WI), U.S. EPA Superfund Division Librarian/SFD Records Manager SRC-7J, Metcalfe Federal Building, 77 West Jackson Boulevard, Chicago, IL 60604; 312/886-4465.
Terry Jeng, phone: (703) 603-8852, email:
In 1980, Congress enacted the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. 9601-9675 (“CERCLA” or “the Act”), in response to the dangers of uncontrolled releases or threatened releases of hazardous substances, and releases or substantial threats of releases into the environment of any pollutant or contaminant that may present an imminent or substantial danger to the public health or welfare. CERCLA was amended on October 17, 1986, by the Superfund Amendments and Reauthorization Act (“SARA”), Public Law 99-499, 100 Stat. 1613
To implement CERCLA, the EPA promulgated the revised National Oil and Hazardous Substances Pollution Contingency Plan (“NCP”), 40 CFR part 300, on July 16, 1982 (47 FR 31180), pursuant to CERCLA section 105 and Executive Order 12316 (46 FR 42237, August 20, 1981). The NCP sets guidelines and procedures for responding to releases and threatened releases of hazardous substances, or releases or substantial threats of releases into the environment of any pollutant or contaminant that may present an imminent or substantial danger to the public health or welfare. The EPA has revised the NCP on several occasions. The most recent comprehensive revision was on March 8, 1990 (55 FR 8666).
As required under section 105(a)(8)(A) of CERCLA, the NCP also includes “criteria for determining priorities among releases or threatened releases throughout the United States for the purpose of taking remedial action and, to the extent practicable, taking into account the potential urgency of such action, for the purpose of taking removal action.” “Removal” actions are defined broadly and include a wide range of actions taken to study, clean up, prevent or otherwise address releases and threatened releases of hazardous substances, pollutants or contaminants (42 U.S.C. 9601(23)).
The NPL is a list of national priorities among the known or threatened releases of hazardous substances, pollutants or contaminants throughout the United States. The list, which is appendix B of the NCP (40 CFR part 300), was required under section 105(a)(8)(B) of CERCLA, as amended. Section 105(a)(8)(B) defines the NPL as a list of “releases” and the highest priority “facilities” and requires that the NPL be revised at least annually. The NPL is intended primarily to guide the EPA in determining which sites warrant further investigation to assess the nature and extent of public health and environmental risks associated with a release of hazardous substances, pollutants or contaminants. The NPL is of only limited significance, however, as it does not assign liability to any party or to the owner of any specific property. Also, placing a site on the NPL does not mean that any remedial or removal action necessarily need be taken.
For purposes of listing, the NPL includes two sections, one of sites that are generally evaluated and cleaned up by the EPA (the “General Superfund section”) and one of sites that are owned or operated by other federal agencies (the “Federal Facilities section”). With respect to sites in the Federal Facilities section, these sites are generally being addressed by other federal agencies. Under Executive Order 12580 (52 FR 2923, January 29, 1987) and CERCLA section 120, each federal agency is responsible for carrying out most response actions at facilities under its own jurisdiction, custody or control, although the EPA is responsible for preparing a Hazard Ranking System (“HRS”) score and determining whether the facility is placed on the NPL.
There are three mechanisms for placing sites on the NPL for possible remedial action (see 40 CFR 300.425(c) of the NCP): (1) A site may be included on the NPL if it scores sufficiently high on the HRS, which the EPA promulgated as appendix A of the NCP (40 CFR part 300). The HRS serves as a screening tool to evaluate the relative potential of uncontrolled hazardous substances, pollutants or contaminants to pose a threat to human health or the environment. On December 14, 1990 (55 FR 51532), the EPA promulgated revisions to the HRS partly in response to CERCLA section 105(c), added by SARA. The revised HRS evaluates four pathways: Ground water, surface water, soil exposure and air. As a matter of
(1) The Agency for Toxic Substances and Disease Registry (ATSDR) of the U.S. Public Health Service has issued a health advisory that recommends dissociation of individuals from the release.
(2) The EPA determines that the release poses a significant threat to public health.
(3) The EPA anticipates that it will be more cost-effective to use its remedial authority than to use its removal authority to respond to the release.
The EPA promulgated an original NPL of 406 sites on September 8, 1983 (48 FR 40658) and generally has updated it at least annually.
A site may undergo remedial action financed by the Trust Fund established under CERCLA (commonly referred to as the “Superfund”) only after it is placed on the NPL, as provided in the NCP at 40 CFR 300.425(b)(1). (“Remedial actions” are those “consistent with a permanent remedy, taken instead of or in addition to removal actions” (40 CFR 300.5). However, under 40 CFR 300.425(b)(2), placing a site on the NPL “does not imply that monies will be expended.” The EPA may pursue other appropriate authorities to respond to the releases, including enforcement action under CERCLA and other laws.
The NPL does not describe releases in precise geographical terms; it would be neither feasible nor consistent with the limited purpose of the NPL (to identify releases that are priorities for further evaluation), for it to do so. Indeed, the precise nature and extent of the site are typically not known at the time of listing.
Although a CERCLA “facility” is broadly defined to include any area where a hazardous substance has “come to be located” (CERCLA section 101(9)), the listing process itself is not intended to define or reflect the boundaries of such facilities or releases. Of course, HRS data (if the HRS is used to list a site) upon which the NPL placement was based will, to some extent, describe the release(s) at issue. That is, the NPL site would include all releases evaluated as part of that HRS analysis.
When a site is listed, the approach generally used to describe the relevant release(s) is to delineate a geographical area (usually the area within an installation or plant boundaries) and identify the site by reference to that area. However, the NPL site is not necessarily coextensive with the boundaries of the installation or plant, and the boundaries of the installation or plant are not necessarily the “boundaries” of the site. Rather, the site consists of all contaminated areas within the area used to identify the site, as well as any other location where that contamination has come to be located, or from where that contamination came.
In other words, while geographic terms are often used to designate the site (
EPA regulations provide that the remedial investigation (“RI”) “is a process undertaken * * * to determine the nature and extent of the problem presented by the release” as more information is developed on site contamination, and which is generally performed in an interactive fashion with the feasibility study (“FS”) (40 CFR 300.5). During the RI/FS process, the release may be found to be larger or smaller than was originally thought, as more is learned about the source(s) and the migration of the contamination. However, the HRS inquiry focuses on an evaluation of the threat posed and therefore the boundaries of the release need not be exactly defined. Moreover, it generally is impossible to discover the full extent of where the contamination “has come to be located” before all necessary studies and remedial work are completed at a site. Indeed, the known boundaries of the contamination can be expected to change over time. Thus, in most cases, it may be impossible to describe the boundaries of a release with absolute certainty.
Further, as noted above, NPL listing does not assign liability to any party or to the owner of any specific property. Thus, if a party does not believe it is liable for releases on discrete parcels of property, it can submit supporting information to the agency at any time after it receives notice it is a potentially responsible party.
For these reasons, the NPL need not be amended as further research reveals more information about the location of the contamination or release.
The EPA may delete sites from the NPL where no further response is appropriate under Superfund, as explained in the NCP at 40 CFR 300.425(e). This section also provides that the EPA shall consult with states on proposed deletions and shall consider whether any of the following criteria have been met:
(i) Responsible parties or other persons have implemented all appropriate response actions required;
(ii) All appropriate Superfund-financed response has been implemented and no further response action is required; or
(iii) The remedial investigation has shown the release poses no significant threat to public health or the environment, and taking of remedial measures is not appropriate.
In November 1995, the EPA initiated a policy to delete portions of NPL sites where cleanup is complete (60 FR 55465, November 1, 1995). Total site cleanup may take many years, while portions of the site may have been cleaned up and made available for productive use.
The EPA also has developed an NPL construction completion list (“CCL”) to simplify its system of categorizing sites and to better communicate the
Sites qualify for the CCL when: (1) Any necessary physical construction is complete, whether or not final cleanup levels or other requirements have been achieved; (2) the EPA has determined that the response action should be limited to measures that do not involve construction (
The Sitewide Ready for Anticipated Use measure represents important Superfund accomplishments and the measure reflects the high priority the EPA places on considering anticipated future land use as part of the remedy selection process. See Guidance for Implementing the Sitewide Ready-for-Reuse Measure, May 24, 2006, OSWER 9365.0-36. This measure applies to final and deleted sites where construction is complete, all cleanup goals have been achieved, and all institutional or other controls are in place. The EPA has been successful on many occasions in carrying out remedial actions that ensure protectiveness of human health and the environment for current and future land uses, in a manner that allows contaminated properties to be restored to environmental and economic vitality. For further information, please go to
In order to maintain close coordination with states and tribes in the NPL listing decision process, the EPA's policy is to determine the position of the states and tribes regarding sites that the EPA is considering for listing. This consultation process is outlined in two memoranda that can be found at the following Web site:
A model letter and correspondence between the EPA and states and tribes where applicable, is available on the EPA's Web site at
Yes, documents relating to the evaluation and scoring of the sites in this final rule are contained in dockets located both at the EPA Headquarters and in the EPA Region 5 office.
An electronic version of the public docket is available through
The Headquarters docket for this rule contains the HRS score sheets, the documentation record describing the information used to compute the score and a list of documents referenced in the documentation record for each site.
The EPA Region 5 docket contains all the information in the Headquarters docket, plus the actual reference documents containing the data principally relied upon by the EPA in calculating or evaluating the HRS score. These reference documents are available only in the Region 5 docket.
You may view the documents, by appointment only, after the publication of this rule. The hours of operation for the Headquarters docket are from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding federal holidays. Please contact the Region 5 docket for hours. For addresses for the Headquarters and Region 5 dockets, see “Addresses” section in the beginning portion of this preamble.
You may obtain a current list of NPL sites via the Internet at
This final rule adds the following sites to the General Superfund section of the NPL. These sites are being added to the NPL based on HRS score.
General Superfund section:
The EPA is adding two sites to the NPL in this final rule, both of which were proposed for NPL addition on September 22, 2014 (79 FR 56538). The sites are the Kokomo Contaminated Ground Water Plume in Kokomo, Indiana, and the DSC McLouth Steel Gibraltar Plant in Gibraltar, Michigan. The EPA received no comments in connection with the Kokomo Contaminated Ground Water Plume. It received one comment in connection with the DSC McLouth Steel Gibraltar Plant.
On October 30, 2014, counsel for Detroit Steel Company and Gibraltar Land Company, the respective owners of the DSC McLouth Steel Gibraltar Plant and the Countywide Landfill, commented on the proposed listing. Counsel described the comments as “not technical in nature” and stated that the comments were “submitted in order to supplement the record. And provide needed background.” The comments did not challenge the HRS score but did provide a substantial site history, which includes litigation between Gibraltar Land Company (GLC) and the State of Michigan arising out of Michigan's denial of GLC's application for a construction permit to expand the Countywide Landfill. The commenter closed with the following statements, “The designation of the properties on the National Priorities List would make the financing of future landfill operations and/or the sale of the property to another landfill developer difficult. However, recognizing the continued areas of environmental concern, even if USEPA would elect to designate these sites on the NPL at this time, we would believe that USEPA could play a constructive role in attempting to mediate a resolution of this matter. Such a resolution would provide for the vertical expansion of the [Countywide Landfill], which would in turn provide a source of revenue that would minimize the use of federal monies.”
In response, the EPA notes that the commenter raised no issue with the HRS score. EPA is placing the DSC McLouth Steel Gibraltar Plant site on the NPL. EPA will coordinate with GLC, Michigan, and Wayne County to efficiently address the contamination. EPA, however, has no authority to require Michigan to approve a permit for landfill expansion at the Countywide Landfill facility.
Additional information about these statutes and Executive Orders can be found at
This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review.
This action does not impose an information collection burden under the PRA. This rule does not contain any information collection requirements that require approval of the OMB.
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities. This rule listing sites on the NPL does not impose any obligations on any group, including small entities. This rule also does not establish standards or requirements that any small entity must meet, and imposes no direct costs on any small entity. Whether an entity, small or otherwise, is liable for response costs for a release of hazardous substances depends on whether that entity is liable under CERCLA 107(a). Any such liability exists regardless of whether the site is listed on the NPL through this rulemaking.
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. This action imposes no enforceable duty on any state, local or tribal governments or the private sector. Listing a site on the NPL does not itself impose any costs. Listing does not mean that the EPA necessarily will undertake remedial action. Nor does listing require any action by a private party, state, local or tribal governments or determine liability for response costs. Costs that arise out of site responses result from future site-specific decisions regarding what actions to take, not directly from the act of placing a site on the NPL.
This final rule does not have federalism implications. It will not have substantial direct effects 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.
This action does not have tribal implications as specified in Executive Order 13175. Listing a site on the NPL does not impose any costs on a tribe or require a tribe to take remedial action. Thus, Executive Order 13175 does not apply to this action.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the 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 this action itself is procedural in nature (adds sites to a list) and does not, in and of itself, provide protection from environmental health and safety risks. Separate future regulatory actions are required for mitigation of environmental health and safety risks.
This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866.
This rulemaking does not involve technical standards.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it does not affect the level of protection provided to human health or the environment. As discussed in Section I.C. of the preamble to this action, the NPL is a list of national priorities. The NPL is intended primarily to guide the EPA in determining which sites warrant further
This action is subject to the CRA, and the EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2).
Provisions of the Congressional Review Act (CRA) or section 305 of CERCLA may alter the effective date of this regulation. Under 5 U.S.C. 801(b)(1), a rule shall not take effect, or continue in effect, if Congress enacts (and the President signs) a joint resolution of disapproval, described under section 802. Another statutory provision that may affect this rule is CERCLA section 305, which provides for a legislative veto of regulations promulgated under CERCLA. Although
If action by Congress under either the CRA or CERCLA section 305 calls the effective date of this regulation into question, the EPA will publish a document of clarification in the
Environmental protection, Air pollution control, Chemicals, Hazardous substances, Hazardous waste, Intergovernmental relations, Natural resources, Oil pollution, Penalties, Reporting and recordkeeping requirements, Superfund, Water pollution control, Water supply.
40 CFR part 300 is amended as follows:
33 U.S.C. 1321(c)(2); 42 U.S.C. 9601-9657; E.O. 13626, 77 FR 56749, 3 CFR, 2013 Comp., p.306; E.O. 12777, 56 FR 54757, 3 CFR, 1991 Comp., p.351; E.O. 12580, 52 FR 2923, 3 CFR, 1987 Comp., p.193.
Federal Communications Commission.
Final rule.
In this document, the Federal Communications Commission's Wireline Competition Bureau clarifies certain rules related to the implementation of the intercarrier compensation transition for rate-of-return local exchange carriers adopted in the
Effective April 27, 2015.
Pamela Arluk, Wireline Competition Bureau, Pricing Policy Division, (202) 418-1520 or (202) 418-0484 (TTY); or Robin Cohn, Wireline Competition Bureau, Pricing Policy Division, (202) 418-1520 or (202) 418-0484 (TTY).
This is a summary of the Commission's Order in WC Docket No. 10-90 and CC Docket No. 01-92, adopted and released on February 24, 2015. The full text of this document can be viewed at the following Internet address:
1. In the
2. In the
3. For rate-of-return LECs, the calculation each year of a carrier's Eligible Recovery begins with its Base Period Revenue (BPR). A rate-of-return carrier's BPR is the sum of certain ICC intrastate switched access revenues and net reciprocal compensation revenues received by March 31, 2012, for services provided during FY 2011, and the projected revenue requirement for interstate switched access services provided during the 2011-2012 tariff period. The BPR for rate-of-return carriers was reduced by 5% initially and is reduced by an additional 5% in each year of the transition. A rate-of-return LEC's Eligible Recovery is equal to the adjusted BPR for the year in question less, for each relevant year of the transition, the sum of (1) projected intrastate switched access revenue; (2) projected interstate switched access revenue; and (3) projected net reciprocal compensation revenue.
4. Beginning in 2014, the recovery mechanism also incorporates in the Eligible Recovery calculation a true-up of the revenue difference between projected and actual demand for interstate and intrastate switched access services, reciprocal compensation, and the ARC for the tariff period that began two years earlier. This adjustment measures the extent to which a carrier received more or less than the revenues it projected for the earlier period and thus whether it received too little, or too much, Eligible Recovery through ARCs and/or Connect America Fund ICC support for that period. The true-up is achieved by adjusting the later tariff period's Eligible Recovery to account for the carrier's revenue variance resulting from differences between projected and actual demand for the prior period. The true-up process ensures that rate-of-return carriers at a minimum have the opportunity to receive their adjusted BPR, notwithstanding changes in demand for their intercarrier compensation rates being capped or reduced. The true-up process does not require that a carrier that has negative Eligible Recovery, meaning the carrier received revenues in excess of its adjusted BPR from its interstate and intrastate switched access and reciprocal compensation alone and
5. To provide context for how the true-up process works, the following two examples demonstrate scenarios in which the carrier either under-projected or over-projected its revenues, and thus must engage in a true-up calculation pursuant to § 51.917(d)(1)(iii)-(iv) of the Commission's rules. In this first example, Carrier A under-projected its actual revenues and received too much Eligible Recovery for the 2012-2013 tariff period. Carrier A had a BPR of $100.00, a projected revenue amount of $80.00 and an actual revenue amount of $85.00:
6. Conversely, in the second example, Carrier B over-projected its revenue amounts in the 2012-2013 tariff period, and it would need to increase its 2014-2015 Eligible Recovery amounts to reflect the difference. Carrier B had a BPR of $100.00, a projected revenue amount of $85.00 and an actual revenue amount of $80.00:
7. As noted above, the 2014 annual tariff filing was the first time that Eligible Recovery was adjusted to
8. In conjunction with the 2014 annual tariff filing process, NECA informally sought clarification concerning a limited number of cases in which the true-up process did not work as outlined above and for which the rules do not provide an unambiguous resolution. In the Order, we clarify how rate-of-return carriers and USAC should address the 2014-15 fact scenarios described below, consistent with the policy goals of the
9. The first set of facts identified by NECA involves several carriers whose 2012-13 tariff period projected demand was underestimated compared to their ultimate actual demand. Each carrier therefore received too much Eligible Recovery in 2012-13, and, under the rules, their 2014-15 Eligible Recovery should be reduced by the amount of revenues associated with the demand difference. The carriers' Eligible Recovery for 2014-15 before reflecting the true-up adjustment, however, was not large enough to offset completely the true-up reduction from the 2012-13 tariff period. Thus, the excess Eligible Recovery carriers received during the 2012-13 tariff period has not been fully offset, and the carriers would be left with duplicative recovery in contravention of § 51.917(d)(1)(vii) of the rules absent clarification to specify the procedures to be followed under these circumstances. We accordingly clarify that carriers that are in this situation with respect to their 2014-15 Eligible Recovery calculation must refund to USAC the amount of the excess recovery that was not offset within thirty (30) days of the effective date of the Order. Consistent with the rules we adopt, as set forth in the Appendix, in the future a carrier in this situation must refund excess amounts to USAC by August 1 following the date of the annual access tariff filing.
10. The second set of facts that NECA sought clarification on involves several carriers who overestimated their 2012-13 tariff period projected demand compared to the resulting actual demand. Thus, to the extent carriers would have been entitled to Eligible Recovery for tariff period 2012-13 if they had accurately projected their demand, these carriers received too little Eligible Recovery in tariff period 2012-13. The affected carriers also have negative Eligible Recovery in the 2014-15 tariff period before adjusting for any true-ups. Absent a clarification of our rules, these carriers would not receive the same level of revenues they would have been entitled to if they had projected their demand accurately in the 2012-13 tariff period. This occurs because the positive amount of the 2012-13 under-recovery would be reduced by the negative 2014-15 Eligible Recovery amount before further Eligible Recovery would be possible in tariff period 2014-15. This would deprive such carriers of the cash flow certainty the Commission sought to provide carriers through the recovery mechanism. As explained above, carriers that have negative Eligible Recovery were allowed to retain any revenues received through intercarrier revenue payments, consistent with the transition from strict rate-of-return regulation to incentive regulation. We accordingly clarify that those carriers that were in this situation with respect to their tariff period 2014-15 Eligible Recovery calculation may seek recovery of 2012-13 true-up under-recovery from USAC and are not required to offset the 2012-13 amounts they could have received in Eligible Recovery in the 2012-13 tariff period if they had projected demand correctly against their 2014-15 negative Eligible Recovery. The carrier's Eligible Recovery from USAC shall be equal to the amount of the 2012-13 true-up that a carrier could have recovered through Eligible Recovery in the 2012-13 tariff period if it had accurately projected demand and which amount a carrier was unable to recover as Eligible Recovery in tariff period 2014-15. Consistent with the rules we adopt in the Appendix, in the future a carrier in this situation must treat the amount eligible for true-up as its Eligible Recovery for the true-up tariff period and flow that amount through the normal procedures associated with the recovery mechanism. This is consistent with the priorities established for recovery of Eligible Recovery in the
11. Finally, we clarify how ARC rates are to be handled in making Eligible Recovery calculations in light of mid-year revisions that some carriers have made to their ARC rates after discovering errors in the rates that were charged. The Commission's rules do not address applicable procedures for addressing such rate changes. If a carrier assessed an ARC rate that was too high for part of a tariff period, it must use this higher rate and the associated demand for that time period in calculating future true-ups for that tariff period. Failure to account for the higher ARC rates for the period in question would constitute impermissible duplicative recovery because, without this treatment, the carrier would have received the ARC revenues without having to offset Eligible Recovery to reflect their receipt. We also take this opportunity to remind carriers that if they charge ARCs that are below the maximum rate that could have been charged, whether for the whole year or for part of a year, they are required to impute the maximum rate that they could have assessed for purposes of determining the carrier's Eligible Recovery. These clarifications help to ensure that the recovery mechanism adopted for rate-of-return carriers in the
12. This document does not contain any new or modified information collection requirements subject to the Paperwork Reduction Act of 1995 (PRA). In addition, therefore, it does not contain any new or modified information collection burden for small business concerns with fewer than 25 employees, pursuant to the Small Business Paperwork Relief Act of 2002.
13. The Regulatory Flexibility Act of 1980, as amended (RFA), requires that a regulatory flexibility analysis be prepared for rulemaking proceedings, unless the agency certifies that “the rule will not have a significant economic
14. We hereby certify that the rule revisions adopted in the Order will not have a significant economic impact on a substantial number of small entities. The Order amends rules adopted in the
15. The Commission will send a copy of the Order to Congress and the Government Accountability Office pursuant to the Congressional Review Act.
16. Accordingly,
17.
18.
Communications common carriers, Telecommunications.
For the reasons discussed in the preamble, the Federal Communications Commission amends 47 CFR part 51 as follows:
Sections 1-5, 7, 201-05, 207-09, 218, 220, 225-27, 251-54, 256, 271, 303(r), 332, 706 of the Telecommunication Act of 1996, 48 Stat. 1070, as amended, 1077; 47 U.S.C. 151-55, 157, 201-05, 207-09, 218, 220, 225-27, 251-54, 256, 271, 303(r), 332, 1302, 47 U.S.C. 157 note, unless otherwise noted.
(d) * * *
(1) * * *
(viii) * * *
(A) If a Rate-of-Return Carrier in any tariff period underestimates its projected demand for services covered by § 51.917(b)(6) or 51.915(b)(13), and thus has too much Eligible Recovery in that tariff period, it shall refund the amount of any such True-up Revenues or True-up Revenues for Access Recovery Charge that are not offset by the Rate-of-Return Carrier's Eligible Recovery (calculated before including the true-up amounts in the Eligible Recovery calculation) in the true-up tariff period to the Administrator by August 1 following the date of the Rate-of-Return Carrier's annual access tariff filing.
(B) If a Rate-of-Return Carrier in any tariff period receives too little Eligible Recovery because it overestimates its projected demand for services covered by § 51.917(b)(6) or 51.915(b)(13), which True-up Revenues and True-up Revenues for Access Recovery Charge it cannot recover in the true-up tariff period because the Rate-of-Return Carrier has a negative Eligible Recovery in the true-up tariff period (before calculating the true-up amount in the Eligible Recovery calculation), the Rate-of-Return Carrier shall treat the unrecoverable true-up amount as its Eligible Recovery for the true-up tariff period.
Defense Acquisition Regulations System, Department of Defense (DoD).
Interim rule.
DoD is issuing an interim rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to implement sections of the Military Construction and Veterans Affairs and Related Agencies Appropriations Act, 2015, that require offerors bidding on DoD military construction contracts to provide opportunity for competition to American steel producers, fabricators, and manufacturers; and restrict use of military construction funds in certain foreign countries, including countries that border the Arabian Gulf.
Effective March 26, 2015.
Submit comments identified by DFARS Case 2015-D006, using any of the following methods:
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Comments received generally will be posted without change to
Ms. Amy G. Williams, telephone 571-372-6106.
This interim rule implements sections 108, 111, and 112 of the Military Construction and Veterans Affairs and Related Agencies Appropriations Act, 2015 (Division I of the Consolidated and Further Continuing Resolution Appropriations Act, 2015, Pub. L. 113-235), enacted December 16, 2014.
• Section 108 provides that none of the funds made available in Title I may be used for the procurement of steel for any construction activity for which the requirement for competition opportunity has been denied to American steel producers, fabricators, and manufacturers who bid on DoD construction contracts.
• Section 111 provides that none of the funds made available in Title I may be obligated for architect and engineer contracts estimated by the Government to exceed $500,000 for projects to be accomplished in certain foreign countries, including countries bordering the Arabian Gulf, unless such contracts are awarded to U.S. firms or U.S. firms in a joint venture with a host nation firm.
• Section 112 provides, with some exceptions, that none of the funds made available in Title I for military construction in certain foreign countries, including countries bordering the Arabian Gulf, may be used to award any military construction contract estimated by the Government to exceed $1,000,000 to a foreign contractor.
The restrictions in section 108 were first enacted in the annual military construction appropriations act in FY 2009 (Title I of the Military Construction and Veterans Affairs Appropriations Act, 2009, Pub. L. 110-329, Division E). This interim rule revises DFARS 236.274 and 236.570(d)(1) to implement the same provision in subsequent military appropriations acts, including section 108 of Title I of the Military Construction and Veterans Affairs Appropriations Act, 2015, Pub. L. 113-235, Division I.
This interim rule also implements section 111 by amending DFARS 225.7015, 236.602-70, and 236.609-70(b)(3) to reflect that the current law now applies to the award of architect and engineering contracts that are estimated to exceed the $500,000 threshold for projects to be performed in certain foreign countries, including countries bordering the Arabian Gulf. The term “Arabian Sea” has been replaced with “Arabian Gulf” in the clause prescription for DFARS 252.236-7011, Overseas Architect-Engineering Services—Restrictions to the United States.
This interim rule likewise implements section 112 by amending DFARS 225.7014, 236.273, and 236.570(c)(1) to reflect that the current law applies to military construction contracts estimated to exceed $1,000,000 that are performed in certain foreign countries, including countries bordering the Arabian Gulf. The term “Arabian Sea” has been replaced with “Arabian Gulf” in the clause prescription for DFARS 252.236-7010, Overseas Military Construction—Preference for United States Firms.
As further background on sections 111 and 112, these restrictions have also been in place since 1997, except that recently the military construction appropriations act restrictions have applied to countries bordering the Arabian Sea, rather than countries bordering the Arabian Gulf. The final rule under DFARS Case 2014-D016 was published in the
In order to avoid any possible ambiguity as to the applicability of the rule, because there is not uniform agreement as to the correct name for the body of water located between Iran and the Arabian Peninsula (often referred to as the “Persian Gulf”), the interim rule lists the countries bordering the Gulf in clockwise order (Iran, Oman, United Arab Emirates, Saudi Arabia, Qatar, Bahrain, Kuwait, and Iraq).
Executive Orders (E.O.s) 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). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This is not a significant regulatory action and, therefore, was not subject to review under section 6(b) of E.O. 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
DoD does not expect this rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
This rule is necessary to require offerors bidding on DoD military construction contracts to provide opportunity for competition to American steel producers, fabricators, and manufacturers; and implement the preference for award only to U.S. firms when awarding certain military construction and architect-engineer contracts to be performed in countries bordering the Arabian Gulf.
The objective of this rule is to implement sections 108, 111, and 112 of the Military Construction and Veterans Affairs, and Related Agencies Appropriations Act, 2015 (Division I of Pub. L. 113-235). This rule extends the applicability of the requirement to provide opportunity for competition to American steel producers, fabricators, and manufacturers, and revises the preference for award to U.S. firms of military construction contracts that have an estimated value greater than $1,000,000 and the restriction requiring award only to U.S. firms for architect-engineer contracts that have an estimated value greater than $500,000, to make it applicable to contracts to be performed in a country bordering the Arabian Gulf, rather than a country bordering the Arabian Sea (as required in earlier statutes).
Section 108 will benefit any small business entities involved in producing, fabricating, or manufacturing steel products to be used in military
This rule does not add any reporting or recordkeeping requirements. The rule does not duplicate, overlap, or conflict with any other Federal rules. This rule does not impose any significant economic burden on small firms. The rule primarily benefits U.S. firms (both small and large), by requiring offerors bidding on DoD military construction contracts to provide opportunity for competition to American steel producers, fabricators, and manufacturers; and providing a preference for U.S. firms competing for construction and architect-engineer contracts in certain foreign countries, including countries bordering the Arabian Gulf. DoD did not identify any alternatives that could reduce the burden and still meet the objectives of the rule.
DoD invites comments from small business concerns and other interested parties on the expected impact of this rule on small entities.
DoD will also consider comments from small entities concerning the existing regulations in subparts affected by this rule in accordance with 5 U.S.C. 610. Interested parties must submit such comments separately and should cite 5 U.S.C. 610 (DFARS Case 2015-D006), in correspondence.
The rule does not contain any information collection requirements that require the approval of the Office of Management and Budget under the Paperwork Reduction Act (44 U.S.C. chapter 35).
A determination has been made under the authority of the Secretary of Defense that urgent and compelling reasons exist to promulgate this interim rule without prior opportunity for public comment. This action is necessary because sections 108, 111, and 112 of Title I, Department of Defense, the Military Construction and Veterans Affairs, and Related Agencies Appropriations Act, 2015, Division I of Pub. L. 113-235, enacted December 16, 2014, became effective upon enactment. This interim rule is necessary so that contracting officers will not risk possible misuse of funds. The interim rule provides contracting officers with the appropriate clause and provision prescriptions for correct use of provisions and clauses that implement the statutory restrictions on use of military construction funds. However, pursuant to 41 U.S.C. 1707 and FAR 1.501-3(b), DoD will consider public comments received in response to this interim rule in the formation of the final rule.
Government procurement.
Therefore, 48 CFR parts 225 and 236 are amended as follows:
41 U.S.C. 1303 and 48 CFR chapter 1.
41 U.S.C. 1303 and 48 CFR chapter 1.
(a) In accordance with section 112 of the Military Construction and Veterans Affairs and Related Agencies Appropriations Act, 2015 (Division I of Pub. L. 113-235) and the same provision in subsequent military construction appropriations acts, military construction contracts funded with military construction appropriations, that are estimated to exceed $1,000,000 and are to be performed in the United States outlying areas in the Pacific and on Kwajalein Atoll, or in countries bordering the Arabian Gulf (
In accordance with section 111 of the Military Construction and Veterans Affairs and Related Agencies Appropriations Act, 2015 (Division I of Pub. L. 113-235) and the same provision in subsequent military construction appropriations acts, architect-engineer contracts funded by military construction appropriations that are estimated to exceed $500,000 and are to be performed in Japan, in any North Atlantic Treaty Organization member country, or in countries bordering the Arabian Gulf (
Defense Acquisition Regulations System, Department of Defense (DoD).
Final rule.
DoD is making technical amendments to the Defense Federal Acquisition Regulation Supplement (DFARS) to provide needed editorial changes.
Effective March 26, 2015.
Mr. Manuel Quinones, Defense Acquisition Regulations System, OUSD(AT&L)DPAP(DARS), Room 3B941, 3060 Defense Pentagon, Washington, DC 20301-3060. Telephone 571-372-6088; facsimile 571-372-6094.
This final rule amends the DFARS as follows:
1. Amends section 225.103(b)(iii) to remove an obsolete cross reference at paragraph (A) and redesignate paragraphs (B) and (C) as paragraphs (A) and (B), respectively. Amends section 225.202(a)(2) to remove an obsolete cross reference. DFARS case 2013-D020, which was published in the
2. Amends DFARS clause 252.245-7004, Reporting, Reutilization, and Disposal, to update a reference and a link to the reference contained in paragraph (b)(1)(iv).
Government procurement.
Therefore, 48 CFR parts 225 and 252 are amended as follows:
41 U.S.C. 1303 and 48 CFR chapter 1.
The revision reads as follows.
(b) * * *
(1) * * *
(iv)
Defense Acquisition Regulations System, Department of Defense (DoD).
Final rule.
DoD has adopted as final, without change, an interim rule amending the Defense Federal Acquisition Regulation Supplement (DFARS) to remove language based on a statute that provided the underlying authority for DoD's Small Disadvantaged Business (SDB) program. This action is necessary because the statute has expired.
Effective March 26, 2015.
Ms. Judith S. Rubinstein, telephone 571-372-6093.
DoD published an interim rule in the
There were no public comments submitted in response to the interim rule. The interim rule has been converted to a final rule, without change.
Executive Orders (E.O.s) 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). E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This is not a significant regulatory action and, therefore, was not subject to review under section 6(b) of E.O. 12866, Regulatory Planning and Review, dated September 30, 1993. This rule is not a major rule under 5 U.S.C. 804.
A final regulatory flexibility analysis has been prepared consistent with the Regulatory Flexibility Act, 5 U.S.C. 601,
The objective of this rule is to amend the DFARS to remove or revise clauses, provisions, and guidance conditioned on section 1207 of the National Defense Authorization Act of 1987, Public Law
No public comments were submitted in response to the initial regulatory flexibility analysis, or in response to the interim rule, which was published in the
DoD does not expect this rule to have a significant economic impact on a substantial number of small entities within the meaning of the Regulatory Flexibility Act, 5 U.S.C. 601,
The DoD Small Disadvantaged Business (SDB) program has not been in effect since fiscal year (FY) 2008. This rule does not change the fundamental procurement policies that DoD has used to achieve strong SDB participation or to encourage the involvement of historically Black colleges and universities and minority institutions in defense-related research, development, testing, and evaluation efforts. The following rationale is provided:
10 U.S.C. 2323 was the underlying statutory authority for DoD's small disadvantaged business (SDB) program. DoD's SDB program was intended to supplement and complement the Federal-wide SDB program authorized under the Small Business Act. It provided for the institution of a specific goal within the mandatory 5 percent SDB goal for the award of prime contracts and subcontracts to historically Black colleges and universities, minority institutions, and Hispanic-serving institutions. Section 2323 of Title 10 served as the basis for a number of unique acquisition techniques used by DoD to help it achieve these goals, such as the price evaluation adjustment for SDBs in competitive procurements and the set-aside for historically Black colleges and universities and minority institutions. It was also the basis for the special 95 percent customary progress payment rate for SDBs.
Now that the law has expired, these special techniques can no longer be used. However, the impact of this change is mitigated by a number of factors. Preeminent among those factors is DoD's obligation to meet or exceed the expectations of the Small Business Act regarding SDBs, and to provide assistance for defense-related research, development, testing, and evaluation activities to historically Black colleges and universities and minority institutions.
Section 15(g) of the Small Business Act, Public Law 85-536, as amended, (15 U.S.C. 644(g)), requires all Federal agencies to make every attempt to achieve the annual Government-wide goal for participation by SDBs. The statutory SDB goal is not less than 5 percent of the total value of all prime contract and subcontract awards for each fiscal year. DoD must comply with this law, and it has. The Department has met or exceeded the 5 percent SDB goal since FY 2001.
DoD contracting officers can employ monetary incentives in solicitations and contracts, when inclusion of such incentives is, in the judgment of the contracting officer, necessary to increase subcontracting opportunities for small businesses, service-disabled veteran-owned small businesses, HUBZone small businesses, women-owned small businesses, as well as small disadvantaged businesses. In addition, while the 95 percent progress payment rate is no longer allowable, SDBs, because they are small businesses, are still eligible to receive the 90 percent progress payment rate. Finally, the extent of participation of all small businesses, including small disadvantaged businesses, in performance of the contract is addressed during source selection for negotiated DoD acquisitions that are required to have subcontracting plans. The past performance of offerors in complying with subcontracting goals with all small businesses, including SDBs, is also evaluated in DoD acquisitions.
The capability and expertise that HBCUs and MIs bring to numerous DoD-funded research and development programs are valued commodities. DoD must explore new areas of science, mathematics, and engineering in order to develop the alternative technologies needed to fulfill its national security mission. HBCUs and MIs will continue to support DoD in these endeavors through their involvement in various research and development programs. This rule does not impose new reporting, recordkeeping or other compliance requirements.
The rule does not contain any information collection requirements that require the approval of the Office of Management and Budget under the Paperwork Reduction Act (44 U.S.C. chapter 35).
Government procurement.
Federal Motor Carrier Safety Administration, DOT.
Regulatory guidance.
FMCSA provides regulatory guidance concerning crashes involving motor vehicles striking the rear of attenuator trucks deployed at construction sites and whether such crashes meet the definition of “accident” under 49 CFR 390.5 for the motor carrier that controls the attenuator truck. Attenuator trucks are highway safety vehicles equipped with an impact attenuating crash cushion intended to reduce the risks of injuries and fatalities resulting from crashes in construction work zones. The guidance explains that such crashes in which motorists strike the attenuator trucks while they are deployed at construction work zones are not covered by the definition of accident and such occurrences will not be considered by FMCSA under its Compliance, Safety, Accountability Safety Measurement System (SMS) scores, or Safety Fitness Determination for the motor carrier that controls the attenuator truck. This guidance will provide the motor carrier industry and Federal, State, and local law enforcement officials with uniform information for use in determining whether certain crashes involving attenuator vehicles must be recorded on
This guidance is effective May 26, 2015.
Mr. Thomas L. Yager, Chief, Driver and Carrier Operations Division, Office of Bus and Truck Standards and Operations; 1200 New Jersey Ave. SE., Washington, DC 20590, Telephone 202-366-4325, Email:
The Secretary of Transportation has statutory authority to set minimum standards for commercial motor vehicle safety. These minimum standards must ensure that: (1) CMVs are maintained, equipped, loaded, and operated safely; (2) the responsibilities imposed on operators of CMVs do not impair their ability to operate the vehicles safely; (3) the physical condition of operators of CMVs is adequate to enable them to operate the vehicles safely; (4) the operation of CMVs does not have a deleterious effect on the physical condition of the operators; and (5) an operator of a commercial motor vehicle is not coerced by a motor carrier, shipper, receiver, or transportation intermediary to operate a commercial motor vehicle in violation of a regulation. (49 U.S.C. 31136(a)(1)-(5), as amended). The Secretary also has broad power in carrying out motor carrier safety statutes and regulations to “prescribe recordkeeping and reporting requirements” and to “perform other acts the Secretary considers appropriate.” (49 U.S.C. 31133(a)(8) and (10)).
The Administrator of FMCSA has been delegated authority under 49 CFR 1.87(f) to carry out the functions vested in the Secretary of Transportation by 49 U.S.C. chapter 311, subchapters I and III, relating to commercial motor vehicle programs and safety regulation.
This document provides regulatory guidance to the public with respect to the definition of “accident” in 49 CFR 390.5 of the Federal Motor Carrier Safety Regulations (FMCSRs), and the recording of accidents as required under 49 CFR 390.15. All interested parties may access the guidance in this document through the FMCSA's Internet site at
The regulatory guidance in this regulatory guidance responds to questions concerning the definition of “accident” in 49 CFR 390.5: Are crashes in which motorists strike the rear of attenuator trucks deployed at construction sites considered recordable accidents?
Section 390.5 defines “accident” as an occurrence involving a commercial motor vehicle operating on a highway in interstate or intrastate commerce which results in a fatality; bodily injury to a person who, as a result of the injury, immediately receives medical treatment away from the scene of the accident; or one or more motor vehicles incurring disabling damage as a result of the accident, requiring the motor vehicles to be transported away from the scene by a tow truck or other motor vehicle. It excludes occurrences involving only boarding and alighting from a stationary motor vehicle or involving only the loading or unloading of cargo.
FMCSA acknowledges the potential impact on motor carriers' Safety Measurement System (SMS) scores that could result from States uploading reports about crashes involving attenuator trucks deployed at construction sites into the Agency's Motor Carrier Management Information System (MCMIS). Because these vehicles are deployed to prevent certain crashes through the use of flashing lights and to reduce the severity of crashes through the use of truck-mounted impact attenuators or crash cushions when motorists do not take appropriate action to avoid the obstacles in the construction zone, it is expected that these vehicles will be struck from time to time while the attenuators are deployed. Such events that occur in a construction zone, either stationary or moving, should not count against the safety performance record of the motor carrier responsible for the operation of the attenuator truck.
In consideration of the above, FMCSA has determined that the current regulatory guidance should be revised to make clear that crashes involving motorists striking attenuator trucks are not considered accidents, as defined under 49 CFR 390.5. The Agency issues the following guidance to 49 CFR 390.5 to read as follows:
Starting on the effective date of this regulatory guidance, any crash meeting the above criteria may be removed from a carrier's record of crashes. To do so the carrier operating the attenuator vehicle should file a Request for Data Review (RDR) using the DataQ system at
Office of the Secretary, Labor.
Request for information; extension of comment period.
On February 3, 2015, the Department of Labor (DOL or the Department) published a Request for Information (RFI) in response to Executive Order 13563 on improving regulation and regulatory review, and Executive Order 13610 on identifying and reducing regulatory burden. The RFI invited public comment on how the Department can improve any of its significant regulations by modifying, streamlining, expanding, or repealing them. The comment period ended on February 25, 2015, and was subsequently extended to March 18, 2015. This extension further extends the date to comment on the RFI.
The comment period for the Request for Information published on February 3, 2015, at 80 FR 5715, and on March 3, 2015 at 80 FR 11334 is extended from March 18, 2015 to April 1, 2015. Comments must be received on or before April 1, 2015. The Department is accepting all comments received between February 25, 2015 and April 1, 2015.
You may submit comments through the Department's Regulations Portal at
All comments will be available for public inspection at
Pamela Peters, Program Analyst, Office of the Assistant Secretary for Policy, U.S. Department of Labor, 200 Constitution Avenue NW., Room S-2312, Washington, DC 20210,
On January 18, 2011, President Obama issued Executive Order 13563, “Improving Regulation and Regulatory Review.” The Order explains the Administration's goal of creating a regulatory system that protects “public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness, and job creation” while using “the best, most innovative, and least burdensome tools to achieve regulatory ends.” After receipt and consideration of comments, the Department issued its Plan for Retrospective Analysis of Existing Rules in August 2011. On May 12, 2012, President Obama issued Executive Order 13610, “Identifying and Reducing Regulatory Burdens.” This Order explained that “it is particularly important for agencies to conduct retrospective analyses of existing rules to examine whether they remain justified and whether they should be modified or streamlined in light of changed circumstances, including the rise of new technologies.”
The Department recognizes the importance of conducting retrospective review of regulations and is once again seeking public comment on how the Department can increase the effectiveness of its significant regulations while minimizing the burden on regulated entities. The Department recognizes that the regulated community, academia, and the public at large have an understanding of its programs and their implementing regulations, and therefore is requesting public comment on how the Department can prepare workers for better jobs, improve workplace safety and health, promote fair and high-quality work environments, and secure a wide range of benefits for employees and those who are seeking work, all in ways that are more effective and least burdensome.
This request for public input will inform development of the Department's future plans to review its existing significant regulations. To facilitate receipt of the information, the Department has created an Internet portal specifically designed to capture your input and suggestions,
Please note that these questions do not pertain to DOL rulemakings currently open for public comment. To comment on an open rulemaking, please visit regulations.gov and submit comments by the deadline indicated in that rulemaking. Comments that pertain to rulemakings currently open for public comment will not be addressed by the Department in this venue, which focuses on retrospective review.
The Department will consider public comments as we update our plan to review the Department's significant rules. The Department is issuing this request solely to seek useful information as we update our review plan. While responses to this request do not bind the Department to any further actions related to the response, all submissions will be made available to the public on
E.O. 13653, 76 FR 3821, Jan. 21, 2011; E.O. 12866, 58 FR 51735, Oct. 4, 1993.
Commodity Credit Corporation, USDA.
Proposed rule.
The Farm Service Agency (FSA) is proposing to revise regulations on behalf of the Commodity Credit Corporation (CCC) to specify the requirements for a person to be considered actively engaged in farming for the purpose of payment eligibility for certain FSA and CCC programs. Specifically, this rulemaking proposes to revise and clarify the requirements for a significant contribution of active personal management to a farming operation. These changes are required by the Agricultural Act of 2014 (the 2014 Farm Bill). The provisions of this rule would not apply to persons or entities comprised solely of family members. The rule would not change the existing regulations as they relate to contributions of land, capital, equipment, or labor, or the existing regulations related to landowners with a risk in the crop or to spouses.
We invite you to submit comments on this rule. In your comment, please include the Regulation Identifier Number (RIN) and the volume, date, and page number of this issue of the
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Comments will be available online at
James Baxa; Telephone: (202) 720-7641. Persons with disabilities who require alternative means for communication (Braille, large print, audio tape, etc.) should contact the USDA Target Center at (202) 720-2600 (voice and TDD).
Several CCC programs managed by FSA, specifically the Market Loan Gains (MLG) and Loan Deficiency Payments (LDP) associated with the Marketing Assistance Loan (MAL), Program the Agriculture Risk Coverage (ARC) Program, and the Price Loss Coverage (PLC) Program, require that a person be “actively engaged in farming” as a condition of eligibility for payments. As specified in 7 CFR part 1400, a person must contribute: (1) Land, capital, or equipment; and (2) personal labor, active personal management, or a combination of personal labor and active personal management to be considered “actively engaged in farming” for the purposes of payment eligibility. Section 1604 of the 2014 Farm Bill (Pub. L. 113-79) requires the Secretary of Agriculture to define in regulations what constitutes a “significant contribution of active personal management” for the purpose of payment eligibility. Therefore, this rule proposes to amend 7 CFR part 1400 to define that term and to revise the requirements for active personal management contributions. The 2014 Farm Bill also requires the Secretary to consider establishing limits on the number of persons per farming operation who may be considered actively engaged in farming based on a significant contribution of active personal management. This rule proposes to amend 7 CFR part 1400 to set a limit of one person per farming operation who may qualify based on a contribution of active personal management and not on a contribution of personal labor, with exceptions for up to three persons for large and complex farming operations if additional requirements are met. The new requirements and definitions would be specified in a new subpart G to 7 CFR part 1400.
As required by the 2014 Farm Bill, the provisions of this proposed rule would not apply to farming operations comprised of persons or entities comprised solely of family members. The definition of “family member” is not changing with this rule. As specified in 7 CFR 1400.3, a family member is “a person to whom another member in the farming operation is related as a lineal ancestor, lineal descendant, sibling, spouse, or otherwise by marriage.” FSA handbooks further clarify that eligible family members include: Great grandparent, grandparent, parent, child, including legally adopted children and stepchildren, grandchild, great grandchild, or a spouse or sibling of family members.
In 7 CFR 1400.208, there are existing provisions for family members to be considered actively engaged in farming by making a significant contribution of active personal labor, or active personal management, or a combination thereof, to a farming operation comprised of a majority of family members, without making a contribution of land, equipment, or capital. The new subpart G would not change these provisions.
As specified in the current regulations, there are exceptions to the requirement that a person be actively engaged in farming by contributing labor or management to be eligible for payments. These exceptions for certain landowners and for spouses would not be changed with this rule. Specifically, landowners who share a risk in the crop (profit or loss based on value of crop and not fixed rent amount) are considered to be actively engaged just by contributing land and being at risk; they do not have to contribute management or labor. If one spouse is considered to be actively engaged by contributing management or labor, the other spouse may be considered to be actively engaged without making a separate, additional contribution of management or labor.
The proposed rule would clarify how persons and legal entities comprised of nonfamily members may be eligible for payments, based on a contribution of active personal management made by persons with a direct or indirect interest in the farming operation. Payments made to persons or legal entities are attributed to persons as specified in 7 CFR 1400.105, and the methods for attribution would not change with this rule.
The proposed definition and standard for evaluating what constitutes a significant contribution of active personal management would apply to all nonfamily farming operations seeking to have more than one person qualify as actively engaged in farming by providing a significant contribution
For most farming operations that are entities, such as corporations and LLCs, adding an additional member to the entity does nothing to change the number of payment limits available and it simply increases the number of members that share a single $125,000 payment limit. But for general partnerships and joint ventures, adding another member to the operation can provide an additional $125,000 payment limit if the new member meets the other eligibility requirements, including being actively engaged in farming. This potential for a farming operation being able to qualify for multiple payment limits provides an opportunity to add members and to have those members claim actively engaged status, especially for farming operations close to or in excess of the payment limit.
For this reason, several additional requirements are being proposed for nonfamily farming operations seeking to qualify more than one farm manager. Specifically, in addition to providing information to FSA regarding the elements related to an actively engaged determination, there would be a restriction on the number of members of a farming operation that can be qualified as a farm manager and there would be an additional recordkeeping requirement for such farming operations.
This rule would restrict the number of farm managers to one person, with exceptions. Nonfamily member farming operations only seeking one farm manager would not be subject to the proposed rule. Such operations would continue to be subject to the existing regulations in subparts A and C of 7 CFR part 1400 governing actively engaged in farming.
Any farming operation seeking two or three farm managers would be required to meet the requirements of subpart G for all farm managers in the farming operation including the maintenance of the records or logs discussed below for all the managers in the farming operation. The farming operation may qualify for up to one additional farm manager as a large operation, and up to one additional farm manager as a complex operation. To qualify for three farm managers, the operation would have to meet the standards specified in this rule for both size and complexity. In other words, a very large farm operation that is not complex (for example, one growing a single crop) could only qualify for two managers, not three. Under no circumstances would a farming operation be allowed to qualify more than three farm managers.
The default standard for what constitutes a large farming operation would be an operation with crops on more than 2,500 acres (planted or prevented planted) or honey or wool with more than 10,000 hives or 3,500 ewes, respectively. The acreage standard is based on an analysis of responses to the Agricultural Resource Management Survey that indicate that on average farms producing eligible commodities that required more than one full time manager equivalent (2,040 hours of management) had 2,527 acres. The size standards for honey and wool did not have comparable survey information available. The honey standard of number of hives is based on the beekeepers participating in 2011 through 2012 Emergency Assistance for Livestock, Honey Bees, and Farm-Raised Fish that met or exceeded the payment limit. These large operations averaged 10,323 hives. The sheep standard was based on industry analysis that showed that operations with 1,500 through 2,000 ewes could be full time. The 3,500 standard is approximately double that threshold. Given the limited information available especially for the honey and wool size standards, we are specifically seeking comment on this issue in this proposed rule. State FSA committees (STCs) would have authority to modify these standards for their state based on the STC's determination of the relative size of farming operations in the state by up to 15 percent (that is plus or minus 375 acres, 1,500 hives or 525 ewes). In other words, the standard in a particular state may range from 2,125 acres to 2,875 acres; 8,500 to 11,500 hives; or 2,975 to 4,025 ewes. Relief from the State level standard would only be granted on a case by case basis by DAFP.
If a farming operation seeks a farm manager based on the complexity of the operation under the proposed rule, the farming operation would make a request that addresses the factors established in the proposed rule which would take into account the diversity of the operation including the number of agricultural commodities produced; the types of agricultural crops produced such as field, vegetable, or orchard crops; the geographical area in which an operation farms and produces agricultural commodities; alternative marketing channels (that is, fresh, wholesale, farmers market, or organic); and other aspects about the farming operation such as the production of livestock, types of livestock, and the various livestock products produced and marketed annually. All farming operations seeking to qualify one additional manager based on complexity which are approved by the STC would also have eligibility reviewed by the Deputy Administrator for Farm Programs (DAFP), to ensure consistency and fairness on a national level.
Under the proposed rule, if a farming operation is seeking to qualify more than one farm manager, then all persons that provide management of the operation would be required to maintain contemporaneous records or activity logs of their management activities, including management activities that would not qualify as active personal management under the proposed rule. Specifically, activity logs would include information about the hours of management provided. While the recordkeeping requirements under the proposed rule would be similar to the current provisions at 7 CFR 1400.203 and 1400.204 in which contributions must be identifiable and documentable, and separate and distinct from the contributions of other members, these additional records or logs would also include the location of where the management activity was performed and the time expended or duration of the management activity performed. These records and logs would be required to be available if requested by the appropriate FSA reviewing authority. If a person failed to meet this requirement, the represented contribution of active personal management would be disregarded and the person's eligibility for payments would be re-determined.
Section 1604 of the Farm Bill requires USDA to ensure that any additional paperwork that would be required by the proposed rule be limited only to persons in farming operations who
The existing definition of a “significant contribution” in 7 CFR 1400.3 specifies that for active personal management, a significant contribution includes “activities that are critical to the profitability of the farming operation,” but that definition does not specify what specific types of activities are included, whether these activities need to be direct actions and not passive activities, and to what level or degree such activities must be performed to achieve a level of significance.
This proposed rule would apply a new definition of “significant contribution of active personal management” only to non-family farming operations that are seeking to qualify more than one farm manager. Similar to the existing requirements in 7 CFR 1400.3 for a substantial amount of personal labor, the new definition for a significant contribution of active personal management would require an annual contribution of 500 hours of management, or at least 25 percent of the total management required for that operation. The proposed rule would also add a new, more specific definition for “active personal management” that includes a list of critical management activities that may be used to qualify as a significant contribution.
The 2014 Farm Bill requires us to specify a definition in regulations; the specific definition proposed reflects a discretionary analysis of various alternatives. Various proposals and concepts were considered in the development of this proposed rule, including a minimum level of interest a person must hold in a farming operation before the person could qualify as actively engaged with only an active personal management contribution, a weighted ranking of critical activities performed, or a higher hourly threshold. The hourly requirement standard proposed here is intended to address the 2014 Farm Bill requirement for clear and objective standards.
The new definition would change what constitutes “active personal management” only for farm managers in nonfamily farming operations seeking to qualify two or three farm managers. The proposed requirements for such farm managers would clarify that eligible management activities are critical actions performed under one or more of the following categories:
• Capital, land, and safety-net programs: Arrange financing, manage capital, acquire equipment, negotiate land acquisition and leases, and manage insurance or USDA program participation;
• Labor: Hire and manage labor; and
• Agronomics and Marketing: Decide which crop(s) to plant, purchase inputs, manage crops (that is, whatever it takes to keep the growing crops living and healthy—soil fertility and fertilization, weed control, insect control, irrigation if applicable), price crops, and market crops or futures.
The management activities described would emphasize actions taken by the person directly for the benefit and success of the farming operation. Under the proposed rule, passive management activities such as attendance of board meetings or conference calls, or watching commodity markets or input markets (without making trades) would not be considered as contributing to significant management. The proposed rule only would consider critical actions as specified in the new definition of “active personal management” as contributing to significant management.
The new definition and requirements in the proposed rule would take into account the size and complexity of farming operations across all parts of the country. The proposed rule takes into consideration all of the actions of the farming operation associated with the financing; crop selection and planting decisions; land acquisitions and retention of the land assets for an extended period of time; risk management and crop insurance decisions; purchases of inputs and services; utilization of the most efficient field practices; and prudent marketing decisions. Furthermore, in developing the proposed rule, FSA took into account advancements in farming, communication, and marketing technologies that producers must avail themselves of to remain competitive and economically viable operations in today's farming world.
Under the proposed rule, eligible management activities would include the activities required for the farming operation as a whole, not just activities for the programs to which the “actively engaged in farming” requirement applies. For example, if a farming operation is participating in ARC or PLC and using grain eligible for those programs to feed dairy cattle, activities to manage the dairy side of the operation would be considered as eligible management activities to qualify as a farm manager. Similarly, if a farming operation receives MLG or LDPs on some crops, but not on others, all the management activities for all the crops would be considered for eligibility purposes.
The proposed rule would clarify that the significant contribution of a person's active management may be used only to enable one person or entity in a farming operation to meet the requirements of being actively engaged in farming. For example, if members of a joint operation are entities, one person's contribution could only qualify one of the entities (and not any other entity to which the person belongs), as actively engaged in farming.
While this rule identifies an option that would allow a maximum of three managers to qualify the farming operation for farm payments for large or complex farming operations, we remain open to analysis and views of other options of merit that have been considered throughout the development of both this rule and the 2014 Farm Bill. We encourage comments to address whether the proposed change for the number of managers is appropriate and whether our definitions of large and complex farming operations are reasonable (as discussed above). Although the 2014 Farm Bill explicitly excludes the provisions of this proposed rule from applying to farming operations comprised solely of family members, we request comments on whether farming entities owned by family members should be subject to the same limits as other farming operations.
We also encourage comments to address whether there should be a strict limit of one manager, or if another option should be implemented to reduce the risk that individuals who have little involvement in a farming operation use the active personal management provision to qualify the farming operation for farm program payments. The proposed changes would not mandate how farms are structured; that is up to the farming operation.
FSA is requesting comments from the public on the methods that should be used to determine whether a person is actively engaged in farming for the purpose of payment eligibility and the number of managers per farming operation that may be eligible. Specifically, comments on the following topics may be helpful:
1. Should other methods be used to determine which activities constitute a significant contribution of active personal management? Should other
2. Should different standards be applied for the amount of management required for eligibility, such as a different number of hours, a percentage financial interest in the entity, or other criteria?
3. Should there be a different limit to the number of farm managers in a farming operation that qualify as actively engaged? If yes, how should that limit be determined?
4. Are there certain management activities or practices that are unique to particular farming methods, crops, or regions that should be taken into consideration?
The following suggestions may be helpful for preparing your comments:
• Explain your views as clearly as possible.
• Describe any assumptions that you used.
• Provide any technical information and data on which you based your views.
• Provide specific examples to illustrate your points.
• Offer specific alternatives to the current regulations or policies and indicate the source of necessary data, the estimated cost of obtaining the data, and how the data can be verified.
• Submit your comments to be received by FSA by the comment period deadline.
Executive Order 12866, “Regulatory Planning and Review,” and Executive Order 13563, “Improving Regulation and Regulatory Review,” 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 rules, and of promoting flexibility.
The Office of Management and Budget (OMB) designated this proposed rule as significant under Executive Order 12866, “Regulatory Planning and Review,” and therefore, OMB has reviewed this rule. The costs and benefits of this proposed rule are summarized below. The full cost benefit analysis is available on regulations.gov.
Executive Order 12866, as supplemented by Executive Order 13563, requires each agency to write all rules in plain language. In addition to your substantive comments on this proposed rule, we invite your comments on how to make the rule easier to understand. For example:
• Are the requirements in the rule clearly stated? Are the scope and intent of the rule clear?
• Does the rule contain technical language or jargon that is not clear?
• Is the material logically organized?
• Would changing the grouping or order of sections or adding headings make the rule easier to understand?
• Could we improve clarity by adding tables, lists, or diagrams?
• Would more, but shorter, sections be better? Are there specific sections that are too long or confusing?
• What else could we do to make the rule easier to understand?
About 1,400 joint operations could lose eligibility for around $50 million in total crop year 2016 to 2018 benefits from the Price Loss Coverage (PLC), Agriculture Risk Coverage (ARC), and Marketing Assistance Loan (MAL) programs (ranging from $38 million for the 2016 crop year down to approximately $4 million for the 2018 crop year). This is the expected cost to producers of this rule. This rule does not change the payment limit per person, which is a joint $125,000 for the applicable programs. As specified in the current regulations, the payment limits apply to general partnerships and joint operations based on the number of eligible partners in the operation; each partner may qualify for a separate payment limit of $125,000. In other words, each person in the partnership or joint operation who loses eligibility will lose eligibility for up to $125,000 in payments.
Other types of entities (such as corporations and limited liability companies) that share a single payment limit of $125,000, regardless of their number of owners, would not have their payments reduced by this rule. Each owner must contribute management or labor to the operation to qualify the operation to receive the member's share of the single payment limit.
No entities comprised solely of family members will be impacted by this rule.
If commodity prices are sufficiently high that few producers are eligible for any benefits, the costs of this rule to producers (and savings to USDA) will be less, even zero. In other words, if very few producers are earning farm program payments due to high commodity prices, limiting eligibility on the basis of management contributions will not have much impact. Government costs for implementing this rule are expected to be minimal.
The Regulatory Flexibility Act (5 U.S.C. 601-612), as amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), generally requires an agency to prepare a regulatory analysis of any rule whenever an agency is required by APA or any other law to publish a proposed rule, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. This proposed rule would not have a significant impact on a substantial number of small entities. The farming operations of small entities generally do not have to have multiple members that contribute only active personal management to meet the requirements of actively engaged in farming.
The environmental impacts of this proposed rule have been considered in a manner consistent with the provisions of the National Environmental Policy Act (NEPA, 42 U.S.C. 4321-4347), the regulations of the Council on Environmental Quality (40 CFR parts 1500-1508), and the FSA regulations for compliance with NEPA (7 CFR part 799). The Agricultural Act of 2014 (the 2014 Farm Bill) requires that USDA publish a regulation to specifically define a “significant contribution of active personal management” for the purposes of determining payment eligibility. This proposed regulation would clarify the activities that qualify as active personal management and the recordkeeping requirements to document eligible management activities. This is a mandatory administrative clarification. As such, FSA has determined that this proposed rule does not constitute a major Federal action that would significantly affect the quality of the human environment, individually or cumulatively. Therefore, FSA will not prepare an environmental assessment or environmental impact statement for this regulatory action.
Executive Order 12372, “Intergovernmental Review of Federal Programs,” requires consultation with State and local officials that would be directly affected by proposed Federal financial assistance. The objectives of the Executive Order are to foster an intergovernmental partnership and a strengthened Federalism, by relying on State and local processes for State and local government coordination and
This proposed rule has been reviewed under Executive Order 12988, “Civil Justice Reform.” This proposed rule would not preempt State or local laws, regulations, or policies unless they represent an irreconcilable conflict with this rule. This proposed rule would not have retroactive effect. Before any judicial actions may be brought regarding the provisions of this rule, the administrative appeal provisions of 7 CFR parts 11 and 780 are to be exhausted.
This proposed rule has been reviewed under Executive Order 13132, “Federalism.” The policies contained in this proposed rule would not have any substantial direct effect on States, on the relationship between the Federal government and the States, or on the distribution of power and responsibilities among the various levels of government, except as required by law. Nor would this rule impose substantial direct compliance costs on State and local governments. Therefore consultation with the States is not required.
This proposed rule has been reviewed in accordance with the requirements of Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Executive Order 13175 requires Federal agencies to consult and coordinate with tribes on a government-to-government basis on policies that have tribal implications, including regulations, legislative comments or proposed legislation, and other policy statements or actions that have substantial direct effects 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.
FSA has assessed the impact of this proposed rule on Indian tribes and determined that this rule would not, to our knowledge, have tribal implications that require tribal consultation under Executive Order 13175. If a Tribe requests consultation, FSA will work with the USDA Office of Tribal Relations to ensure meaningful consultation is provided where changes, additions, and modifications identified in this rule are not expressly mandated by the 2014 Farm Bill.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA, Pub. L. 104-4) requires Federal agencies to assess the effects of their regulatory actions on State, local, and Tribal governments or the private sector. Agencies generally must prepare a written statement, including cost benefits analysis, for proposed and final rules with Federal mandates that may result in expenditures of $100 million or more in any 1 year for State, local or Tribal governments, in the aggregate, or to the private sector. UMRA generally requires agencies to consider alternatives and adopt the more cost effective or least burdensome alternative that achieves the objectives of the rule. This proposed rule contains no Federal mandates, as defined in Title II of UMRA, for State, local and Tribal governments or the private sector. Therefore, this proposed rule is not subject to the requirements of sections 202 and 205 of UMRA.
The title and number of the Federal Domestic Assistance Programs in the Catalog of Federal Domestic Assistance to which this rules applies are: 10.051 Commodity Loans and Loan Deficiency Payments; 10.112 Price Loss Coverage; and 10.113 Agriculture Risk Coverage.
The regulations in this proposed rule are exempt from requirements of the Paperwork Reduction Act (44 U.S.C. Chapter 35), as specified in Section 1601(c)(2)(B) of the 2014 Farm Bill, which provides that these regulations be promulgated and administered without regard to the Paperwork Reduction Act. Section 1604 of the Farm Bill requires us to ensure that any additional paperwork required by this rule be limited only to persons who are subject to this rule. The additional recording and recordkeeping requirements of this proposed rule would only apply to persons who are claiming eligibility for payments based on a significant contribution of active personal management to the farming operation.
FSA is committed to complying 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.
Agriculture, Loan programs-agriculture, Conservation, Price support programs.
For the reasons discussed above, CCC proposes to amend 7 CFR part 1400 as follows:
7 U.S.C. 1308, 1308-1, 1308-2, 1308-3, 1308-3a, 1308-4, and 1308-5.
(a) This subpart is applicable to all of the programs as specified in § 1400.1 and any other programs as specified in individual program regulations.
(b) The requirements of this subpart will apply to farming operations for FSA program payment eligibility and limitation purposes as specified in subparts B and C of this part.
(c) The requirements of this subpart do not apply to farming operations specified in paragraph (b) of this section if either:
(1) All persons who are partners, stockholders, or persons with an ownership interest in the farming operation or of any entity that is a member of the farming operation are family members as defined in § 1400.3; or
(2) The farming operation is seeking to qualify only one person as making a significant contribution of active personal management for the purposes
(a) The terms defined in § 1400.3 are applicable to this subpart and all documents issued in accordance with this part, except as otherwise provided in this section.
(b) The following definitions are also applicable to this subpart:
(1) Capital, which includes:
(i) Arranging financing and managing capital;
(ii) Acquiring equipment;
(iii) Acquiring land and negotiating leases;
(iv) Managing insurance; and
(v) Managing participation in USDA programs;
(2) Labor, which includes hiring and managing of hired labor; and
(3) Agronomics and marketing, which includes:
(i) Selecting crops and making planting decisions;
(ii) Acquiring and purchasing crop inputs;
(iii) Managing crops (that is, whatever it takes to keep the growing crops living and healthy—soil fertility and fertilization, weed control, insect control, irrigation if applicable) and making harvest decisions; and
(iv) Pricing and marketing of crop production.
(1) Performs at least 25 percent of the total management hours required for the farming operation on an annual basis; or
(2) Performs at least 500 hours of management annually for the farming operation.
(a) If a farming operation includes any nonfamily members as specified under the provisions of § 1400.201(b)(2) and (3) and the farming operation is seeking to qualify more than one person as providing a significant contribution of active personal management then:
(1) Each such person must maintain contemporaneous records or logs as specified in § 1400.603; and
(2) Subject to paragraph (b) of this section, if the farming operation seeks not more than one additional person to qualify as providing a significant contribution of active personal management because the operation is large, then the operation may qualify for one such additional person if the farming operation:
(i) Produces and markets crops on 2,500 acres or more of cropland; or
(ii) For farming operations that produce honey with more than 10,000 hives; or
(iii) For farming operations that produce wool with more than 3,500 ewes; and
(3) If the farming operation seeks not more than one additional person to qualify as providing a significant contribution of active personal management because the operation is complex, then the operation may qualify for one such additional person if the farming operation is determined by the FSA state committee as complex after considering the factors described in paragraphs (a)(3)(i) and (ii) of this section. Any determination that a farming operation is complex by an FSA state committee must be reviewed and the determination must be concurred by DAFP to be applied. To demonstrate complexity, the farming operation will be required to provide information to the FSA state committee on the following:
(i) Number and type of livestock, crops, or other agricultural products produced and marketing channels used; and
(ii) Geographical area covered.
(b) FSA state committees may adjust the limitations described in paragraph (a)(2) of this section up or down by not more than 15 percent if the FSA state committee determines that the relative size of farming operations in the state requires a modification of either or both of these limitations. If the FSA state committee seeks to make a larger adjustment, then DAFP will review and may approve such request.
(c) If a farming operation seeks to qualify a total of three persons as providing a significant contribution of active personal management, then the farming operation must demonstrate both size and complexity as specified in paragraph (a) of this section.
(d) In no case may more than three persons in the same farming operation qualify as providing a significant contribution of active personal management, as defined by this subpart.
(e) A person's contribution of active personal management to a farming operation specified in § 1400.601(b) will only qualify one member of that farming operation as actively engaged in farming as defined in this part. Other individual persons in the same farming operation are not precluded from making management contributions, except that such contributions will not be recognized to meet the requirements of being a significant contribution of active personal management.
(a) Any farming operation requesting that more than one person qualify as making a significant contribution of active personal management must maintain contemporaneous records or activity logs for all persons that make any contribution of any management to a farming operation under this subpart that must include, but are not limited to, the following:
(1) Location where the management activity was performed; and
(2) Time expended and duration of the management activity performed.
(b) To qualify as providing a significant contribution of active personal management each person covered by this subpart must:
(1) Maintain these records and supporting business documentation; and
(2) If requested, timely make these records available for review by the appropriate FSA reviewing authority.
(c) If a person fails to meet the requirement of paragraphs (a) and (b) of this section, then both of the following will apply:
(1) The person's contribution of active personal management as represented to the farming operation for payment eligibility purposes will be disregarded; and
(2) The person's payment eligibility will be re-determined for the applicable program year.
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Request for information (RFI).
The U.S. Department of Energy (DOE) is initiating a rulemaking to consider amended energy conservation standards for direct heating equipment and pool heaters. Once completed, this rulemaking will fulfill DOE's statutory obligation to either propose amended energy conservation standards for these products or to determine that the existing standards do not need to be amended. This RFI seeks to solicit information to help DOE determine whether national standards more stringent than those that are currently in place would result in a significant amount of additional energy savings and whether such amended national standards would be technologically feasible and economically justified. In overview, this document presents a brief description of the analysis DOE plans to perform for this rulemaking and requests comment on various issues relating to each of the analyses (
Written comments and information are requested on or before April 27, 2015.
Interested parties are encouraged to submit comments electronically. However, interested persons may submit comments, identified by docket number EERE-2015-BT-STD-0003 and/or regulatory identification number (RIN) 1904-AD49 by any of the following methods:
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•
•
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For detailed instructions on submitting comments and additional information on the rulemaking process, see section III of this document (Public Participation).
Requests for additional information may be sent to Ms. Ashley Armstrong, 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) 586-6590. Email:
Mr. Sarah Butler, U.S. Department of Energy, Office of the General Counsel, GC-33, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-1777. Email:
For information on how to submit or review public comments, contact Ms. Brenda Edwards, U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-2945. Email:
Title III, Part B
EPCA prescribes specific energy conservation standards for the pool heaters and gas-fired direct heating equipment. (42 U.S.C. 6295(e)(2), (3)) EPCA also directed DOE to conduct two cycles of rulemakings to determine whether to amend its standards for direct heating equipment and pool heaters. (42 U.S.C. 6295(e)(4)) The statute further requires DOE to publish a notice of proposed rulemaking including new proposed standards or a notice of determination that the standards for a product need not be amended no later than 6 years after issuance of any final rule establishing or amending standards for that product. (42 U.S.C. 6295(m)(1)) DOE last promulgated a final rule on April 16, 2010, amending its energy conservation standards for direct heating equipment and pool heaters, constituting the first of these two required rulemakings. 75 FR 20112. The current rulemaking satisfies the statutory requirements under EPCA to conduct a second round of review of the DHE and pool heater standards. (42 U.S.C. 6295(e)(4)(B)) Additionally, this
EPCA also provides criteria for prescribing amended standards for covered products generally, including direct heating equipment and pool heaters. As indicated above, any such amended standard must be designed to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. (42 U.S.C. 6295(o)(2)(A)) Additionally, EPCA provides specific prohibitions on prescribing such standards. DOE may not prescribe an amended standard for any of its covered products for which it has not established a test procedure. (42 U.S.C. 6295(o)(3)(A)) Further, DOE may not prescribe a standard if DOE determines by rule that such standard would not result in “significant conservation of energy,” or “is not technologically feasible or economically justified.” (42 U.S.C. 6295(o)(3)(B)) EPCA also provides that in deciding whether a standard is economically justified for covered products, DOE must, after receiving comments on the proposed standard, determine whether the benefits of the standard exceed its burdens by considering, to the greatest extent practicable, the following seven factors:
1. The economic impact of the standard on manufacturers and consumers of the products subject to the standard;
2. The savings in operating costs throughout the estimated average life of the covered products in the type (or class) compared to any increase in the price, initial charges, or maintenance expenses for the covered products that are likely to result from the imposition of the standard;
3. The total projected amount of energy (or, as applicable, water) savings likely to result directly from the imposition of the standard;
4. Any lessening of the utility or the performance of the covered products likely to result from the imposition of the standard;
5. The impact of any lessening of competition, as determined in writing by the Attorney General, that is likely to result from the imposition of the standard;
6. The need for national energy and water conservation; and
7. Other factors the Secretary of Energy (Secretary) considers relevant. (42 U.S.C. 6295(o)(2)(B)(i)(I) through (VII))
In addition, EPCA, as amended, establishes a rebuttable presumption that any standard for covered products is economically justified if the Secretary finds that “the additional cost to the consumer of purchasing a product complying with an energy conservation standard level will be less than three times the value of the energy (and as applicable, water) savings during the first year that the consumer will receive as a result of the standard,” as calculated under the test procedure in place for that standard. (42 U.S.C. 6295(o)(2)(B)(iii))
EPCA also contains what is commonly known as an “anti-backsliding” provision. (42 U.S.C. 6295(o)(1)) This provision mandates that the Secretary not prescribe any amended standard that either increases the maximum allowable energy use or decreases the minimum required energy efficiency of a covered product. EPCA further provides that the Secretary may not prescribe an amended standard if interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States of any product type (or class) with performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as those generally available in the United States at the time of the Secretary's finding. (42 U.S.C. 6295(o)(4)) Under 42 U.S.C. 6295(q)(1), EPCA specifies requirements applicable to promulgating standards for any type or class of covered product that has two or more subcategories. Under this provision, DOE must specify a different standard level than that which applies generally to such type or class of product that has the same function or intended use, if DOE determines that the products within such group: (A) Consume a different kind of energy from that consumed by other covered products within such type (or class); or (B) have a capacity or other performance-related feature which other products within such type (or class) do not have and such feature justifies a higher or lower standard” than applies or will apply to the other products. (42 U.S.C. 6295(q)(1)) In determining whether a performance-related feature justifies such a different standard for a group of products, DOE must consider “such factors as the utility to the consumer of such a feature” and other factors the Secretary deems appropriate.
Section 310(3) of the Energy Independence and Security Act of 2007 (EISA 2007; Pub. L. 110-140) amended EPCA to prospectively require that energy conservation standards address standby mode and off mode energy use. Specifically, when DOE adopts new or amended standards for a covered product after July 1, 2010, the final rule must, if justified by the criteria for adoption of standards in section 325(o) of EPCA, incorporate standby mode and off mode energy use into a single standard if feasible, or otherwise adopt a separate standard for such energy use for that product. (42 U.S.C. 6295(gg)(3)) On December 17, 2012 DOE promulgated a final rule amending its test procedures for vented direct heating equipment and pool heaters to incorporate standby and off-mode energy consumption (see section II.A below for further detail). 77 FR 74559. The amendments related to standby and off-mode energy consumption were not required for purposes of compliance until the compliance date of the next standards final rule for those products. Id. This rulemaking, if amended standards are ultimately adopted, would serve as the next energy conservation standards rulemaking subsequent to these test procedure amendments, and therefore this rulemaking will take into account standby and off-mode energy consumption.
Finally, Federal energy conservation requirements for covered products generally supersede State laws or regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6297(a) through (c)) DOE can, however, grant waivers of Federal preemption for particular State laws or regulations, in accordance with the procedures and other provisions of section 327(d) of the Act. (42 U.S.C. 6297(d))
In addition to the specific statutory criteria discussed in section I.A that DOE must follow for prescribing amended standards for covered products, DOE uses a specific process to assess the appropriateness of amending the standards that are currently in place for a given type of product. For direct heating equipment and pool heaters, DOE plans to conduct in-depth technical analyses of the costs and benefits of the potential amended standards to determine whether more stringent standards are technologically feasible and would lead to significant energy savings, and whether such
Subsequently, DOE may conduct a preliminary analysis for some or all products, particularly heat pump pool heaters since no prior rulemaking record for these products exists. Alternatively, DOE may elect to proceed directly to a NOPR (or determination that standards need not be amended) for some or all products.
In this section, DOE summarizes the rulemaking analyses and identifies a number of issues on which it seeks input and data in order to aid in the development of the technical and economic analyses to determine whether amended energy conservation standards may be warranted for direct heating equipment and/or pool heaters. In addition, DOE welcomes comments on other issues relevant to the conduct of this rulemaking that may not specifically be identified in this RFI.
The test procedure for vented home heating equipment is located at 10 CFR 430.23(o) and 10 CFR part 430, subpart B, appendix O (Appendix O) for vented home heating equipment (“vented heater”). The vented heater test procedure includes provisions for determining energy efficiency (annual fuel utilization efficiency (AFUE)), as well as annual energy consumption. DOE's test procedure for pool heaters is found at 10 CFR 430.23(p) and 10 CFR part 430, subpart B, appendix P (Appendix P). The test procedure includes provisions for determining two energy efficiency descriptors (
EISA 2007 amended EPCA to require DOE to amend its test procedures for all covered products to include measurement of standby mode and off mode energy consumption. (42 U.S.C. 6295(gg)(2)(A)) DOE published a final rule adopting standby mode and off mode provisions for direct heating equipment and pool heaters in the
For DHE, the December 2012 test procedure final rule included additional measurements and calculations in the test procedure to determine the annual electrical consumption in standby and off-mode separate from the AFUE metric. 77 FR 74559, 74571-74572. The standby and off-mode fossil fuel consumption for DHE was previously incorporated in the AFUE in the form of the pilot light usage and off-cycle flue and stack losses. For gas-fired pool heaters, the December 2012 test procedure final rule included measurements and calculations that incorporate electrical and fossil fuel consumption in standby and off-mode into an integrated thermal efficiency metric.
For both DHE and pool heaters, the December 2012 test procedure amendments were not required for testing in determining compliance with the current energy conservation standards until the next energy conservation standard final rule. 77 FR 74559. This rulemaking is the subsequent standards rulemaking to the December 2012 test procedure amendments; therefore, DOE plans to consider energy conservation standards as part of this rulemaking that incorporate standby and off-mode energy use as measured by the amended test procedures.
In the case of vented home heating equipment, while the pilot light and off-cycle flue and stack losses are integrated into the AFUE, the measurements and calculations for standby and off-mode electrical consumption are not. Should DOE consider standby and off-mode electrical consumption of vented home heating equipment separate analyses would be conducted in order to propose energy conservation standards for standby and off-mode electrical consumption. In order to make such a determination, DOE is seeking data, information, and comment on the electrical consumption of vented home heating equipment in standby and off-mode.
Issue 1: DOE seeks data, information, and comment on the electrical consumption of all product classes of DHE in standby and off-mode.
In the case of pool heaters, the amendments contained in the December 2012 test procedure final rule integrated the standby and off-mode electrical consumption for gas-fired pool heaters into an integrated thermal efficiency metric. Likewise, the January 2015 test procedure final rule added provisions for determining the integrated thermal efficiency of electric resistance and electric heat pump pool heaters. Since the current pool heater rating metric (thermal efficiency) and energy conservation standards do not incorporate standby and off-mode energy consumption, DOE would need to develop a method to convert from the existing thermal efficiency ratings (which does not include standby and off mode energy consumption) to ratings under the new integrated thermal efficiency metric (which includes standby and off mode energy consumption). DOE plans to develop a method of converting ratings from those under the current metrics to those under the new metrics that include standby and off-mode energy consumption. To that end, DOE is requesting information regarding typical standby and off-mode fossil fuel and electricity consumption for DHE and pool heaters.
Issue 2: DOE requests data and information regarding typical energy use (fossil fuel and electricity) in standby and off-modes for all pool heater types (
The market and technology assessment provides information about the direct heating equipment and pool heater industries that will be used throughout the rulemaking process. For example, this information will be used to determine whether the existing product class structure requires modification based on the statutory criteria for setting such classes and to explore the potential for technological improvements in the design of such products. The Department uses qualitative and quantitative information to assess the past and present industry structure and market characteristics. DOE will use existing market materials and literature from a variety of sources, including industry publications, trade journals, government agencies, and trade organizations. DOE will also consider conducting interviews with manufacturers to assess the overall market for both direct heating equipment and for pool heaters.
The current product classes as established in the Code of Federal Regulations for direct heating equipment are characterized by product type (
DOE's energy conservation standards for pool heaters currently regulate only one type of pool heater—gas-fired pool heaters. In analyzing standards for electric (including both resistance and heat pump), DOE will consider creating separate product classes for pool heaters based on fuel type, capacity, or other performance related features that may affect efficiency and justify the establishment of different energy conservation standards.
Issue 3: DOE requests feedback on the current product classes for direct heating equipment and seeks information regarding other product classes it should consider for inclusion in its analysis.
Issue 4: DOE seeks comment on whether product classes should be established for pool heaters and seeks information regarding product classes it should consider for inclusion in its analysis.
Issue 5: DOE seeks data, information, and comment on electric resistance pool heaters, specifically on their capacities and applications. DOE also requests data, information, and comment on whether heat pump technology is a viable design for those applications in which electric resistance pool heaters are typically found.
As discussed in section II.A, DOE published a final rule on January 6, 2015 regarding its test procedures for DHE and pool heaters in which it was clarified that the test procedure applies to oil-fired pool heaters. 80 FR 792 However, in reviewing the pool heater market, DOE found only one model of oil-fired pool heater available. DOE therefore has tentatively determined that the energy savings potential for oil-fired pool heaters is
Issue 6: DOE seeks comment on its tentative conclusion that energy conservation standards for oil-fired pool heaters would result in
DOE uses information about existing and past technology options and prototype designs to help identify technologies that manufacturers could use to meet and/or exceed energy conservation standards. In consultation with interested parties, DOE intends to develop a list of technologies to consider in its analysis. Initially, this list will include all those technologies considered to be technologically feasible and will serve to establish the maximum technologically feasible design. For DHE, DOE will initially consider the specific technologies and design options listed below, along with any other technologies identified during the rulemaking analysis.
For gas-fired pool heaters, DOE will consider the specific technologies and design options listed below.
For electric pool heaters, if included in the scope of this rulemaking, DOE would initially consider the specific technologies and design options listed below.
Issue 7: DOE seeks information related to these or other efficiency-improving technologies for DHE or pool heaters. Specifically, DOE is interested in comments regarding their costs, applicability to the current market, and how these technologies improve efficiency of DHE and pool heaters.
The engineering analysis estimates the cost-efficiency relationship of products at different levels of increased energy efficiency. This relationship serves as the basis for the cost-benefit calculations for consumers, manufacturers, and the nation. In determining the cost-efficiency relationship, DOE will estimate the increase in manufacturer cost associated
Issue 8: DOE requests comment on approaches that it should consider when determining a baseline for product classes of DHE and pool heaters, including information regarding the merits and/or deficiencies of such approaches.
Issue 9: DOE requests information on max-tech efficiency levels achievable in the current market and associated technologies for both DHE and pool heaters.
In order to create the cost-efficiency relationship, DOE anticipates that it will structure its engineering analysis using both a reverse-engineering (or cost-assessment) approach and a catalog teardown approach. A cost-assessment approach relies on a teardown analysis of representative units at the baseline efficiency level and higher efficiency levels up to the maximum technologically feasible designs. A teardown analysis (or physical teardown) determines the production cost of a product by disassembling the product “piece-by-piece” and estimating the material and labor cost of each component. A catalog teardown approach uses published manufacturer catalogs and supplementary component data to estimate the major physical differences between a piece of equipment that has been physically disassembled and another similar product. These two methods would be used together to help DOE estimate the manufacturer production cost of products at various efficiency levels.
Issue 10: DOE requests feedback on the planned approach for the engineering analysis and on the appropriate representative capacities and characteristics for each DHE product class and for pool heaters of all types.
To carry out the life-cycle cost (LCC) and payback period (PBP) calculations, DOE needs to determine the cost to the consumer of baseline products that satisfy the currently applicable standards, and the cost of the more efficient unit the customer would purchase under potential amended standards. This is done by applying a markup multiplier to the manufacturer's selling price to estimate the consumer's price.
Markups depend on the distribution channels for a product (
In the replacement market for direct heating equipment, most sales go through wholesalers to mechanical contractors, and then to consumers. In new construction market, most sales go through wholesaler to mechanical contractors hired by the general contractors. Thus, DOE defined two distribution channels for the purposes of estimating markups for direct heating equipment, and the distribution channel for replacement market is characterized as follows:
In the case of new construction, DOE plans to characterize the distribution channel as follows:
To determine distribution channels for pool heaters, DOE used information from a consultant report.
For replacement pool heaters, DOE plans to characterize the distribution channel as follows:
For the new construction market, DOE plans to characterize the distribution channel for pool heaters as follows:
Issue 11: DOE seeks input from stakeholders on whether the distribution channels described above are appropriate for direct heating equipment and pool heaters and are sufficient to describe the distribution markets.
Issue 12: DOE seeks input on the percentage of products being distributed through the different distribution channels, and whether the share of products through each channel varies based on product class, capacity, or other feature.
To develop markups for the parties involved in the distribution of direct heating equipment and pool heaters, DOE would utilize several sources including: (1) the Heating, Air-Conditioning & Refrigeration Distributors International (HARDI) 2013 Profit Report
In addition to the markups, DOE would derive State and local taxes from data provided by the Sales Tax Clearinghouse.
Issue 13: DOE seeks updated data, if available, and recommendations regarding data sources to establish the markups for the parties involved with the distribution of covered equipment.
The purpose of the energy use analysis is to assess the energy requirements of direct heating equipment and pool heaters described in the engineering analysis for a representative sample of households that utilize the product, and to assess the energy-savings potential of increased product efficiencies. DOE uses the annual energy consumption and energy-savings potential in the LCC and PBP analysis to establish the operating costs savings at various product efficiency levels. DOE will estimate the annual energy consumption of direct heating equipment at specified energy efficiency levels across a range of applications, household types, and climate zones. The annual energy consumption includes use of natural gas, liquefied petroleum gas (LPG), and electricity.
DOE intends to base the energy use analysis on household characteristics from the Energy Information Administration's (EIA) 2009 Residential Energy Consumption Survey (RECS)
The RECS survey data include information on the physical characteristics of homes, space heating equipment used, fuels used, energy consumption and expenditures, and other building characteristics. RECS data also reports energy consumption for pool heating in households that use them. Based on these data, DOE will develop a representative population of households for each direct heating equipment and pool heater class.
Issue 14: DOE requests comment on the overall method to determine energy use of direct heating equipment and pool heaters and if other factors should be considered in developing the energy use or energy use methodology.
Issue 15: DOE seeks input on the current distribution of product efficiencies in the market for different product types and classes.
The purpose of the LCC and PBP analysis is to analyze the effects of potential amended energy conservation standards on consumers of direct heating equipment and pool heaters by determining how a potential amended standard affects their operating expenses (usually decreased) and their total installed costs (usually increased).
DOE intends to analyze the potential for variability by performing the LCC and PBP calculations on a representative sample of individual households. DOE plans to utilize the sample of households developed for the energy use analysis and the corresponding simulations results. Within a given household, one or more direct heating equipment units may serve the building's space heating needs, depending on the space heating requirements of the building. As a result, the Department intends to express the LCC and PBP results for each of the individual direct heating equipment units installed in the building. DOE plans to model variability in many of the inputs to the LCC and PBP analysis using Monte Carlo simulation and probability distributions. As a result, the LCC and PBP results will be displayed as distributions of impacts compared to the base case (without amended standards) conditions. DOE also intends to utilize the sample of households developed for energy use analysis of pool heaters. DOE plans to model variability in many of the inputs to the pool heater LCC and PBP analysis using Monte Carlo simulation and probability distributions.
Issue 16: DOE requests comment on the overall method that it intends on using to conduct the LCC and PBP analysis for direct heating equipment and pool heaters.
Inputs to the LCC and PBP analysis are categorized as: (1) inputs for establishing the purchase expense, otherwise known as the total installed cost, and (2) inputs for calculating the operating expense.
The primary inputs for establishing the total installed cost are the baseline consumer price, standard-level consumer price increases, and installation costs. Baseline consumer prices and standard-level consumer price increases will be determined by applying markups to manufacturer selling price estimates. The installation cost is added to the consumer price to arrive at a total installed cost. DOE intends to develop installation costs using the most recent RS Means data available.
Issue 17: DOE seeks input on the approach and data sources it intends to use to develop installation costs, specifically, its intention to use the most recent RS Means Mechanical Cost Data.
The primary inputs for calculating the operating costs are product energy consumption, product efficiency, energy prices and forecasts, maintenance and repair costs, product lifetime, and discount rates. Both product lifetime and discount rates are used to calculate the present value of future operating expenses.
The product energy consumption is the site energy use associated with providing space heating to the room of a building (DHE) or water heating to a pool or spa (pool heaters). DOE intends to utilize the energy use calculation methodology described in Section II.F to establish product energy use.
DOE will identify an approach to account for the gas, liquefied petroleum gas (LPG) and electricity prices paid by consumers for the purposes of calculating operating costs, savings, net present value, and payback period. DOE intends to consider determining gas, LPG, and electricity prices based on geographically available fuel cost data such as state level data, with consideration for the variation in energy costs paid by different building types. This approach calculates energy expenses based on actual energy prices that customers are paying in different geographical areas of the country. As a potential additional source, DOE may consider data to compare provided in EIA's Form 826 data
Issue 18: DOE seeks comment and sources on its approach for developing gas, LPG, and electricity prices.
Maintenance costs are expenses associated with ensuring continued operation of the covered products over time. DOE intends to develop maintenance costs for its analysis using the most recent RS Means data available.
Issue 19: DOE seeks input on the approach and data sources it intends to use to develop maintenance costs for DHE and pool heaters, specifically, its intention to use the most recent RS Means Facilities Maintenance & Repair Cost Data, as well as to consider the cost of service and/or maintenance agreements.
Repair costs are expenses associated with repairing or replacing components of the covered products that have failed. DOE intends to assess whether repair costs vary with product efficiency as part of its analysis. Likewise, DOE intends to assess whether maintenance costs vary with product efficiency as part of its analysis.
Issue 20: DOE seeks comment as to whether repair costs vary as a function of product efficiency for either DHE or pool heaters. DOE also requests any data or information on developing repair costs for these products.
Product lifetime is the age at which a unit of covered equipment is retired from service. The average equipment lifetimes for DHE and gas-fired pool heaters are estimated by various sources to be between 3 and 20 years based on application and equipment type.
Issue 21: DOE seeks comment on its approach of using a Weibull probability distribution to characterize product lifetimes. DOE also requests DHE and pool heater product lifetime data and information on whether product lifetime varies based on product characteristics, fuel type, product application, or efficiency level considerations.
Issue 22: DOE seeks data, information, and comment on the product lifetimes of electric resistance and electric heat pump pool heaters.
The discount rate is the rate at which future expenditures are discounted to establish their present value. DOE intends to derive the discount rates by estimating the finance cost to consumers direct heating equipment and pool heaters. For replacement purchasers, the estimated cost of financing of this equipment is estimated from a portfolio of consumer debts. For new construction purchases, financing costs are related to mortgage interest rates.
DOE's analysis includes measures of LCC and PBP impacts of potential standard levels relative to a base case, which reflects the likely market in the absence of amended standards. DOE plans to develop market-share efficiency data (
DOE also plans to assess the applicability of the “rebound effect” in the energy consumption for DHE and for pool heaters. A rebound effect occurs when a product that is made more efficient is used more intensively, so that the expected energy savings from the efficiency improvement may not fully materialize. However, at this time, DOE is not aware of any information about the rebound effect for these product types.
Issue 23: DOE requests data on current efficiency market shares (of shipments) by product class for DHE and pool heaters, and also input on similar historic data. DOE also requests comment on market segmentation based on capacity, application and fuel type, as well as trends in fuel switching.
Issue 24: DOE also requests information on expected future trends in efficiency for DHE product classes and for all pool heater types, including the relative market share of condensing versus non-condensing products in the market in the absence of new efficiency standards.
Issue 25: DOE seeks comments and data on any rebound effect that may be associated with more efficient DHE and pool heaters.
DOE uses shipment projections by product class to calculate the national impacts of standards on energy consumption, net present value (NPV) of customer benefits, and future manufacturer cash flows.
DOE intends to develop a shipments models for DHE and gas-fired pool heaters based on historical shipments data obtained during the rulemaking process. DOE currently does not have any historical shipments information for electric resistance or electric heat pump pool heaters. DOE will also examine unit shipments and value of shipments for direct heating equipment, and pool heaters using publicly available data from the U.S. Census Bureau's Annual Survey of Manufacturers (ASM) and Current Industrial Reports (CIR), and the American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) and Air-Conditioning, Heating, and Refrigeration Institute (AHRI).
Issue 26: DOE seeks historical shipments data for DHE and pool heaters, particularly for electric resistance and electric heat pump pool heaters.
Issue 27: DOE seeks data, information, and comment on expected future trends for shipments of all product classes of DHE and all types of pool heaters, including the relative share of sales to new construction vs. existing households.
DOE intends to utilize the U.S. Census Bureau data
Issue 28: DOE seeks input on the approach and data sources it intends to use in developing the shipments model and shipments forecasts for this analysis, including main drivers and trends toward consumer switching between fuel types.
The purpose of the national impact analysis (NIA) is to estimate aggregate impacts of potential energy conservation standards at the national level. Impacts that DOE reports include the national energy savings (NES) from potential standards and the net present value (NPV) of the total customer benefits.
To develop the NES, DOE calculates annual energy consumption for the base case and the standards cases. DOE calculates the annual energy consumption using per-unit annual energy use data multiplied by projected shipments.
To develop the NPV of customer benefits from potential energy conservation standards, DOE calculates annual energy expenditures and annual product expenditures for the base case and the standards cases. DOE calculates annual energy expenditures from annual energy consumption by incorporating projected energy prices. DOE calculates annual product expenditures by multiplying the price per unit times the projected shipments. The difference each year between energy bill savings, increased maintenance and repair costs, and increased product expenditures is the net savings or net costs.
A key component of DOE's estimates of NES and NPV are the product energy efficiencies forecasted over time for the base case and for each of the standards cases. For the base case trend, DOE will consider whether historical data show any trend and whether any trend can be reasonably extrapolated beyond current efficiency levels. In particular, DOE is interested in historical and future shipments of products with step changes in efficiency, such as condensing gas-fired DHE or heat pump pool heaters.
Issue 29: DOE requests comment and any available data on historical, current, and future market share of equipment with step changes in efficiency, such as gas-fired vented home heaters that use condensing technology and electric heat pump pool heaters, as compared to less efficient products, such as non-condensing gas-fired DHE and electric resistance pool heaters, respectively, for each product class.
For the various standards cases, to estimate the impact that amended energy conservation standards may have in the year compliance becomes required, DOE would likely use a “roll-up” scenario. Under the “roll-up” scenario, DOE assumes: (1) Product efficiencies in the base case that do not meet the new or amended standard level under consideration would “roll up” to meet that standard level; and (2) product shipments at efficiencies above the standard level under consideration would not be affected. After DOE establishes the efficiency distribution for the assumed compliance date of a standard, it may consider future projected efficiency growth using available trend data.
As described in section II.F, DOE intends to determine whether there is a rebound effect associated with more efficient DHE or pool heaters. If data indicate that there is a rebound effect, DOE will account for the rebound effect in its calculation of NES.
DOE has historically presented NES in terms of primary energy savings. On August 18, 2011, DOE announced its intention to use full-fuel-cycle (FFC) measures of energy use and greenhouse gas and other emissions in the national impact analyses and emissions analyses included in future energy conservation standards rulemakings. 76 FR 51282. While DOE stated in that notice that it intended to use the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) model to conduct the analysis, it also said it would review alternative methods, including the use of NEMS. After evaluating both models and the approaches discussed in the August 18, 2011 notice, DOE determined NEMS is a more appropriate tool for this purpose. 77 FR 49701 (Aug. 17, 2012). Therefore, DOE is using NEMS to conduct FFC analyses. The method used to derive the FFC multipliers will be described in the TSD.
The purpose of the manufacturer impact analysis (MIA) is to estimate the financial impacts of potential energy conservation standards on manufacturers of direct heating equipment and pool heaters, and to evaluate the potential impact of such standards on direct employment and manufacturing capacity. The MIA includes both quantitative and qualitative aspects. The quantitative part of the MIA primarily relies on the Government Regulatory Impact Model (GRIM), an industry cash-flow model used to estimate a range of potential impacts on manufacturer profitability. The qualitative part of the MIA addresses a proposed standard's potential impacts on manufacturing capacity and industry competition, as well as factors such as product characteristics, impacts on particular subgroups of firms, and important market and product trends.
As part of the MIA, DOE also analyzes impacts of potential energy conservation standards on small business manufacturers of covered products. DOE uses the Small Business Administration's (SBA) small business size standards to determine whether manufacturers qualify as small businesses. The size standards are listed by North American Industry Classification System (NAICS) code and industry description.
DOE has initially identified four manufacturers of direct heating equipment and 16 manufacturers of pool heaters. The table below lists all identified manufacturers. Domestic small businesses are designated with an asterisk.
Issue 30: DOE requests comment on the completeness of the manufacturer list presented, including names of any additional manufacturers that may belong on this list.
DOE will accept comments, data, and information regarding this RFI and other matters relevant to DOE's consideration of amended energy conservations standard for DHE and pool heaters no later than the date provided in the
A link to the docket Web page can be found at:
For information on how to submit a comment, review other public comments and the docket, or participate in the public meeting, contact Ms. Brenda Edwards at (202) 586-2945 or by email:
DOE considers public participation to be a very important part of the process for developing test procedures. DOE actively encourages the participation and interaction of the public during the comment period in each stage of the rulemaking process. Interactions with and between members of the public provide a balanced discussion of the issues and assist DOE in the rulemaking process. Anyone who wishes to be added to the DOE mailing list to receive future notices and information about this rulemaking should contact Ms. Brenda Edwards at (202) 586-2945, or via email at
Nuclear Regulatory Commission.
Draft NUREG; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) is issuing for public comment a draft NUREG, NUREG-2175, “Guidance for Conducting Technical Analyses for 10 CFR part 61.” The NRC is proposing to amend its regulations that govern low-level radioactive waste (LLRW) disposal facilities to require new and revised site-specific technical analyses, to permit the development of site-specific criteria for LLRW acceptance based on the results of these analyses, and to facilitate implementation and better align the requirements with current health and safety standards. The NRC has prepared draft guidance to address the implementation of the proposed regulations. This notice is announcing the availability of the draft guidance for public comment.
Submit comments by July 24, 2015. Comments received after this date will be considered if it is practical to do so, but the Commission is able to ensure consideration only for comments received before this date.
You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):
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For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Priya Yadav, Office of Nuclear Material Safety and Safeguards, telephone: 301-415-6667, email:
Please refer to Docket ID NRC-2015-0003 when contacting the NRC about the availability of information for this action. You may obtain publicly-available information related to this action by any of the following methods:
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Please include Docket ID NRC-2015-0003 in the subject line of your comment submission.
The NRC cautions you not to include identifying or contact information that you do not want to be publicly disclosed in your comment submission. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
The guidance for conducting technical analyses for part 61 of Title 10 of the
NUREG-2175 provides detailed guidance in new areas, such as the inadvertent intruder analysis, defense-in-depth analyses, and analyses for the three phases of the analysis timeframe (compliance period, protective assurance period, and performance period). This guidance discusses the use of a graded level of effort needed to risk-inform the analyses for the compliance period (1,000 years), the protective assurance period (from 1,000 years to 10,000 years after disposal site closure), and also covers the performance period analyses that should be performed for analysis of long-lived waste beyond 10,000 years. Additional topics covered in this document include: (1) Demonstration that radiation doses are minimized to the extent reasonably achievable; (2) identification and screening of the features, events, and processes to develop scenarios for technical analyses; (3) use of the waste classification tables or the results of the technical analyses to develop site-specific waste acceptance criteria; and (4) use of performance confirmation to evaluate and verify the accuracy of information used to demonstrate compliance prior to site closure.
On May 3, 2011, the NRC published preliminary proposed rule language (76 FR 24831), “Part 61: Site Specific Analyses for Demonstrating Compliance with Subpart C Performance Objectives” (ADAMS Accession No. ML111150205). As a result of additional direction from the Commission in staff requirement memoranda (SRM)-COMWDM-11-0002/COMGEA-11-0002, “Revisions to Part 61,” dated January 19, 2012 (ADAMS Accession No. ML120190360), the NRC staff published a second version of the preliminary proposed rule language (77 FR 72997; December 7, 2012), “November 2012 Preliminary Rule Language for Proposed Revisions to Low-Level Waste Disposal Requirements (10 CFR part 61)”
(ADAMS Accession No. ML12311A444). Based on comments received, the NRC published in the Proposed Rules section of this issue of the
For the Nuclear Regulatory Commission.
Farm Credit Administration.
Proposed rule.
The Farm Credit Administration (FCA, we, or our) is proposing new regulations, and clarifying and enhancing existing regulations, related to the Federal Agricultural Mortgage Corporation (Farmer Mac or Corporation) Board governance and standards of conduct, including director election procedures, conflict-of-interest, and risk governance. We also propose enhancements to existing disclosure and reporting requirements to remove repetitive reporting and allow for electronic filing of reports. In keeping with today's financial and economic environment, we believe it prudent and timely to undertake a review of our regulatory guidance on the identified areas. We also propose rules on the examination and enforcement authorities held by the
You may send comments on or before June 24, 2015.
We offer a variety of methods for you to submit your comments. For accuracy and efficiency reasons, commenters are encouraged to submit comments by email or through the FCA's Web site. As facsimiles (fax) are difficult for us to process and achieve compliance with section 508 of the Rehabilitation Act, we are no longer accepting comments submitted by fax. Regardless of the method you use, please do not submit your comments multiple times via different methods. You may submit comments by any of the following methods:
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You may review copies of all comments we receive at our office in McLean, Virginia, or on our Web site at
Joe Connor, Associate Director for Policy and Analysis, Office of Secondary Market Oversight, Farm Credit Administration, McLean, VA 22102-5090, (703) 883-4364, TTY (703) 883-4056, or Laura McFarland, Senior Counsel, Office of General Counsel, Farm Credit Administration, McLean, VA 22102-5090, (703) 883-4020, TTY (703) 883-4056.
The purpose of this proposed rule is to:
• Enhance risk governance at Farmer Mac to further its long-term safety and soundness and mission achievement;
• Clarify the roles of the board and voting stockholders in the Farmer Mac director nomination and election process;
• Enhance the usefulness, transparency, and consistency of conflict-of-interest reporting;
• Clarify conflict-of-interest prohibitions;
• Clarify the appropriate balance between a director's representational requirements and duties as director of Farmer Mac; and
• Remove repetitious disclosure and reporting requirements, given the dual reporting responsibilities of Farmer Mac to the FCA and the Securities and Exchange Commission (SEC).
Farmer Mac is a stockholder-owned, federally chartered instrumentality that is an institution of the Farm Credit System (System) and a Government-sponsored enterprise (GSE). Farmer Mac was established and chartered by the Agricultural Credit Act of 1987 (1987 Act)
As a GSE, Farmer Mac has a public policy purpose embedded in its corporate mission. One aspect of this public policy mission includes financial services to customer-stakeholders (institutions that lend to farmers, ranchers, rural homeowners, and rural utility cooperatives) and the resulting flow-through benefits to rural borrowers. Another key aspect is the protection of taxpayer-stakeholders because the risk that Farmer Mac accepts in the course of business exposes both investors (debt and equity holders) and taxpayers to potential loss. The taxpayer's exposure arises in part from Farmer Mac's authority to issue debt to the Department of the Treasury to cover guarantee losses under certain adverse circumstances.
Farmer Mac has two classes of voting common stock: Class A and Class B. Class A voting common stock is owned by banks, insurance companies, and other financial institutions. Class B voting common stock is owned by System institutions. In addition, Farmer Mac has nonvoting common stock (Class C), the ownership of which is not restricted and is a means for Farmer Mac to raise capital. Farmer Mac may also issue nonvoting preferred stock.
The Farmer Mac Board of Directors is, by statute, composed of 15 directors from three defined representative groups: Class A stockholders, Class B stockholders, and the general public.
Although the Farmer Mac Board is representative in nature, Congress chose a corporate structure to govern the operations of Farmer Mac. Common law corporate principles affirm the fiduciary duty of directors to act in the best interests of Farmer Mac and all of its stockholders. However, this fiduciary duty to stockholders must be understood in the context of the duty of the directors to further the statutory purpose and public mission of Farmer Mac.
The essence of corporate governance is to facilitate an entity's proper accountability to all stakeholders and mitigate conflicts-of-interest. As part of this, it is essential that corporations practice sound risk management. Risk management includes the identification, assessment measurement, and controlling of risks that may arise from all aspects of business activities, pursuit of opportunities and the operating environment. In financial institutions, risk can be attributed to three broad
The Sarbanes-Oxley Act of 2002 (Sarbanes-Oxley)
Farmer Mac, as a publicly traded company, is subject to many of the governance requirements of Sarbanes-Oxley, Dodd-Frank, and SEC disclosure regulations for publicly traded companies. However, with the recent events in the financial industry, increased sophistication in financial markets, and on-going scrutiny of GSE financial activities and related reporting practices, we believe it is prudent to update our current regulatory standards related to Farmer Mac's Board governance and reporting and disclosures in the interest of continuing the safety and soundness and public mission achievement of Farmer Mac. Portions of this proposed rule are related to some of the key governance provisions of Sarbanes-Oxley and Dodd-Frank, such as director independence and conflict-of-interest reporting, but we are not addressing executive compensation disclosures at this time as we believe those are being adequately addressed by SEC regulations implementing Dodd-Frank, to which Farmer Mac is subject under section 8.12 of the Act.
Farmer Mac is regulated by FCA through the FCA Office of Secondary Market Oversight (OSMO). Congress charged us to issue regulations to ensure mission compliance and the safety and soundness of Farmer Mac. When issuing regulations for Farmer Mac, the Act requires FCA to consider:
• The purpose for which Farmer Mac was created;
• The practices are appropriate to the conduct of secondary markets in agricultural loans; and
• The reduced levels of risks associated with appropriately structured secondary market transactions.
We issued an Advance Notice of Proposed Rulemaking (ANPRM) on February 25, 2014, to solicit opinions and suggestions from investors, stockholders, and other interested parties on ways to enhance our regulation of Farmer Mac's governance activities.
Those opposing a rulemaking argued that FCA does not possess general rulemaking authority over Farmer Mac, with Farmer Mac specifically remarking that corporate governance is not a component of FCA's safety and soundness oversight. Zions commented that the current practices at Farmer Mac, combined with current regulations, already result in best practices being in place at Farmer Mac. Those favoring a rulemaking commented that it is appropriate and necessary for FCA to establish regulations making clear that Class A and Class B directors are duty bound to represent the interest of their respective Class and clarify that this duty is not a conflict-of-interest. Commenters affiliated with the System asked that any rulemaking safeguard against reducing the rights of Class A and Class B shareholders. The Weinberg Center comment letter emphasized the importance of crisis management plans to guide a corporation's response to adverse events, but discouraged overly prescriptive regulations. The Weinberg Center also noted that any required risk committee should be viewed as a supplemental oversight body and not a reassignment of risk management duties and authorities from other board committees.
We last issued regulations on Farmer Mac Board governance and standards of conduct on March 1, 1994 (59 FR 9622). In that rulemaking, we implemented the requirements of section 514 of the Farm Credit Banks and Associations Safety and Soundness Act of 1992 (1992 Act)
We believe this proposed rulemaking clarifies existing board responsibilities and authorities while providing the Corporation Board with more tools to carry out its fiduciary and oversight responsibilities. This rule would set forth a minimum level of good governance practices that would assure stakeholders of the continuing safe and sound operation of the Corporation. Regulations necessarily place limits on
In addition to substantive changes, we propose reorganizing our rules addressing Farmer Mac's operations by adding a new part 653 which is currently reserved, revising existing parts 650, 651, and 655, adding subparts to parts 650 and 651, and revising existing subparts in part 655. We also propose adding definition sections to all these parts. We propose no changes to part 652 or reserved part 654.
Existing part 650 contains general provisions, without subparts, on the supervision of Farmer Mac. We propose adding a new subpart A, entitled “Regulation, examination and enforcement,” to address the authorities of OSMO. We also propose moving existing §§ 650.1 through 650.80 into a new subpart B, entitled “Conservators, receivers, and liquidations.” We then propose redesignating existing §§ 650.1 and 650.5 on appointing and removing receivers or conservators as new §§ 650.13 and 650.14 to make room for the provisions of new subpart A. We are proposing no other changes to these existing provisions.
We propose adding a new § 650.1 in subpart A for definitions of certain terms used in part 650. We propose adding definitions for the following terms:
• The Act;
• Business day;
• Corporation or Farmer Mac;
• FCA, OSMO, our, and we;
• NYSE and SEC;
• Securities Act; and
• Signed.
We also propose a new § 650.2 to provide clarity on the situation of Farmer Mac having FCA as its primary regulator, while also being subject to certain SEC regulatory requirements. The proposed § 650.2 would identify FCA the “primary regulator” of Farmer Mac, possessing examination, enforcement, conservatorship, liquidation, and receivership authority over Farmer Mac. Section 8.11 of the Act specifies that FCA holds oversight, regulation, examination, and enforcement authority over Farmer Mac to ensure it operates in a safe and sound manner. Further, FCA has the authority to regulate how Farmer Mac performs its powers, functions, and duties in furtherance of its public policy purposes. The new § 650.2 would also recognize that Farmer Mac, as a publicly traded company, follows the SEC disclosure regulations for publicly traded companies. We selected the term “primary regulator” to explain FCA's role as the safety and soundness regulator of Farmer Mac based on the recent adoption of the term in the financial industry after passage of the Dodd-Frank Act, where it is used to distinguish the different roles of federal regulators in the financial industry.
We next propose a new § 650.3 to incorporate into our regulations the supervision and enforcement authorities given us under the Act to provide reasonable assurance that, among other things, Farmer Mac is adequately capitalized and operating safely. Financial safety and soundness supervision involves monitoring, inspecting, and examining Farmer Mac to assess its condition and compliance with law and regulation. We believe identifying in our regulations the minimum authorities of OSMO to require corrective or remedial actions by Farmer Mac, as well as to take such enforcement action as deemed to be appropriate, will add clarity and facilitate the general supervision of Farmer Mac.
We are proposing new § 650.4 to address our authority to access Farmer Mac records and personnel in the exercise of our examination and oversight authority. The FCA, acting through OSMO, examines and provides general supervision over the activities of Farmer Mac pursuant to section 8.11 of the Act. Section 5.17(a)(11) of the Act provides that FCA may “Exercise such incidental powers as may be necessary or appropriate to fulfill its duties and carry out the purposes of this Act.” Access to Farmer Mac's documents and personnel is incidental to the supervision and examination of Farmer Mac. We believe new § 650.4 will clarify our expectations of the Corporation in providing us this access.
Finally, we are proposing new §§ 650.5 and 650.6, containing cross-citations to existing regulatory provisions regarding access to FCA Reports of Examination and Farmer Mac's obligation to make criminal referrals in certain circumstances. We believe these cross-cites will clarify the applicability of these provisions to Farmer Mac, and thereby facilitate compliance with them.
Existing part 651 contains the corporate governance provisions for Farmer Mac, without subparts. We propose adding the following subparts:
• Subpart A, entitled “General,” to address general corporate governance matters;
• Subpart B, entitled “Standards of Conduct,” to contain the existing provisions of part 651; and
• Subpart C, entitled “Board Governance,” to address Board-level activities, including director elections, fiduciary duties, and Board committees.
We then propose placing existing § 651.1 into new subpart A and placing existing §§ 651.2 through 651.4 into new subpart B, while also revising them.
We propose placing the existing definitions of § 651.1 in new subpart A, modifying certain existing terms and adding new terms to the section. We propose modifying the existing meaning of “material” and “resolved” to cover all conflicts, not just potential ones, and modifying the existing meaning of a “potential conflict-of-interest” to remove the list of imputed interests. We also propose adding to this part the definitions proposed for part 650 (listed in section III.A. of this preamble), except the terms in proposed § 650.1(e), (h), and (i).
We propose the following additional terms for part 651:
• Appointed director;
• Class A stockholders;
• Class B stockholders;
• Director elections;
• Elected director; and
• Reasonable person.
The above terms and their meanings, except “reasonable person”, are based on sections 8.2 and 8.4 of the Act and the manner in which FCA has consistently applied them over the years. The proposed definition for the term “reasonable person” is based on use of the term in conflict-of-interest proceedings and substantially resembles the legal meaning of term.
We propose new § 651.2 on indemnifications of directors, officers, and employees to address indemnifications that Farmer Mac may offer. The provision would recognize that the decision of whether to offer indemnification is a business decision of Farmer Mac and not required by law or regulation. However, new § 651.2 would require Farmer Mac, in the interest of safety and soundness, to establish policies and procedures for offering indemnification insurance before any such indemnification occurs. As proposed, the required procedures would have to address: When and how indemnification is offered, safeguards to avoid over-indemnification, and reviews of any indemnification made. The policies and procedures may also address when indemnification payments will be made and how those payments will be calculated. For example, the policy might provide that Farmer Mac will give consideration to any other source of indemnification when calculating indemnification or prohibit indemnification when a director, officer, or employee is already covered by an indemnification policy separate from that offered by Farmer Mac. We proposed these provisions to set adequate controls over indemnification practices in order to prevent unintended consequences such as over-indemnification. Finally, the proposed § 651.2 would require notice to OSMO before an indemnification payment is made. The notice would provide the opportunity for OSMO to evaluate, prior to payment, the impact of an indemnification payment to the safety and soundness of Farmer Mac.
We propose adding a new § 651.21 in new subpart B to require a written code of conduct that establishes ethical benchmarks for the professional behavior of Farmer Mac directors, officers, employees, and agents. The proposed code of conduct would resemble existing § 651.4(a)(1) and the “Code of Business Conduct and Ethics” currently maintained by Farmer Mac pursuant to section 406 of Sarbanes-Oxley, with the key difference being that the Code would set benchmarks for professional integrity, competence, and respect. The proposed provision would require a review of the Code every 3 years.
We propose moving existing § 651.2, which requires Farmer Mac to have a conflict-of-interest policy, to new subpart B and redesignating it as new § 651.22. In addition, we propose changes and additions to the existing provision. Some of the proposed changes are organizational and grammatical changes, as well as intended to incorporate the proposed new terms from revised § 651.1. Organizational changes mainly consist of consolidating like provisions with each other, such as moving existing § 651.3(b), requiring release of the conflict-of-interest policy, to new § 651.22(d).
We propose the following substantive changes and additions for new § 651.22:
• Requiring that the conflict-of-interest policy consider the required representational affiliations of elected directors.
• Moving to new paragraph (b)(1) the list of imputed interests that are currently part of the existing definition of a “potential conflict-of-interest” (proposed to be removed from the definition).
• Revising the list of imputed interest in new paragraph (b)(1) by removing highly specific relationships such as “spouse” and “child” and replacing them with language to address all persons residing in the household or who are otherwise legal dependents. This change is premised on the ever-evolving understanding of what is considered a family as well as intended to address non-residential dependents whose activities and interests may create a conflict-of-interest for a director, officer, or employee.
• Adding as new paragraph (b)(1)(iv) an exception to the imputed interest list for relationships maintained solely because of the representational nature of elected directorships. Since this relationship is required by the Act, it should not be treated as a conflict-of-interest.
• Adding as new paragraph (b)(4) a requirement that conflict-of-interest procedures address recusals when conflicts are identified. We believe this requirement is necessary to ensure a standard approach to recusals is used by the Corporation and to ensure directors, officers, and employees have notice of the expectation to recuse themselves when a conflict-of-interest exists.
• Adding as new paragraph (b)(5) a requirement that conflict-of-interest procedures define documentation and reporting requirements to ensure compliance with conflict-of-interest decisions.
• Removing the requirement for negative conflict-of-interest reports from directors, officers, and employees. This negative reporting is unnecessary as other proposed changes would require an annual filing from all directors, officers and employees, in which it may be reported that no conflicts exist.
As a GSE, the Corporation has strategic objectives that are both commercially and public policy oriented. Conflicts-of-interest must be understood and interpreted not only in the context of the fiduciary responsibilities to the Corporation and its shareholders, but also in the context of the statutory duty to further the Congressional purposes the Corporation was chartered to achieve. We believe conflict-of-interest to be among the most potentially complex and nuanced areas of corporate governance. We intend the minimum specifications set forth in the proposed rule to facilitate the uniform disclosure, identification, and treatment of directors, officers, employees and agent holding employment, contractual business relationships, or other relationships and interests that may interfere with that person's ability to serve the interests of the Corporation before serving personal interests.
We propose moving existing § 651.2, regarding conflict-of-interest reports, to new subpart B and redesignating it as new § 651.23. In addition, we propose
We propose the following substantive changes and additions for new § 651.23:
• Specifying that the sufficiency of a conflict-of-interest report is based on a “reasonable person” standard.
• Requiring in new paragraph (a) that conflict-of-interest reports be signed. While the signature element may have been implied in the past, we believe it is best to specify it as a requirement.
• Specifying in new paragraph (a)(1) that the transactions, relationships, and activities identified as creating real or potential conflicts are based on (1) the opinion of the person filing the report, (2) conflicts specifically identified in Farmer Mac's policies, and (3) conflicts identified in FCA regulation. We are proposing this specificity to ensure a common understanding of the basis used by persons completing conflict-of-interest reports. By specifying the sources used when determining if a transaction, relationship, or activity creates a conflict, it should be easier to identify omissions and remove doubts as to what needs to be reported. However, if doubt remains, we encourage every person completing a conflict-of-interest report to err on the side of inclusion, rather than omission.
• Requiring in new paragraph (b) that Farmer Mac review conflict-of-interest reports within 10 business days of receipt, and if a conflict is identified as material, to document its findings. We believe time is of the essence in identifying material conflicts in order to take necessary actions to minimize the impact of the conflict on the operations of Farmer Mac. We believe it is important that conflicts identified as “material” be clearly documented, as well as the rationale used to make the determination. It is essential that the basis for any “materiality” determination be supported by appropriate documentation to avoid misunderstandings and to minimize the potential for abuse of the process.
• Requiring in new paragraph (b)(2) that Farmer Mac notify a filer within 3 business days when a reported conflict has been identified as material and provide filers with an opportunity to respond to the materiality determination. We believe that material conflict determinations should be explained to those impacted by such determinations. We also believe it is necessary for the Corporation and the person with the conflict to hold discussions about the conflict. These discussions could add clarity to the process, help avoid mistaken “materiality” determination, and provide the opportunity for the person with the conflict to resolve it quickly.
• Requiring in new paragraph (c) that Farmer Mac document material conflicts-of-interest and the efforts made to address the conflicts. The requirement for documentation of conflicts is a good business practice, which we recognize Farmer Mac has already been employing. However, we believe a regulatory requirement is necessary to ensure the practice continues.
• Clarifying that the existing disclosure to shareholders and investors of unresolved material conflicts applies to those conflicts that remain unresolved as of the date of the annual report or proxy statement. The requirement does not include conflicts resolved during the reporting period beyond updating those previously reported as “unresolved.”
• Requiring in new paragraph (d)(3) that Farmer Mac notify OSMO of unresolved material conflicts-of-interest. As the safety and soundness regulatory, we need to remain informed of any conflicts that could potentially affect the on-going operations of Farmer Mac. For example, if a conflict remains unresolved for months and that person has been recused from performing their full duties, we would want to know what Farmer Mac has done to address the impact of that recusal. This is especially true if a director or senior officer holds the unresolved conflict.
• Limiting the existing requirement that reports of conflicts must be maintained for 6 years to only material conflicts. We believe this change will balance the recordkeeping burden with the value obtained from the longevity of the records. Material conflicts are the ones that will result in recusal actions and most likely to last or reappear. As such, they are more valuable to retain for historical reference. However, this provision would not prevent Farmer Mac from retaining all records for the 6-year period, if it so desires.
• Requiring in new paragraph (g) that Farmer Mac establish procedures for obtaining conflict-of-interest disclosures from agents of the Corporation. Agents of any corporation have a standing that differs from directors, officers, and employees. As such, we believe Farmer Mac should have procedures in place to provide reasonable assurance that their agents hold no material conflicts that could adversely affect the work those agents perform on behalf of Farmer Mac. As Farmer Mac's operations grow and its products and lines of business diversify, identification and prevention of potential conflicts become more challenging and make our enhanced regulatory focus on this topic timely and appropriate.
We propose moving existing § 651.4 to new subpart B and redesignating the section as new § 651.24. This section addresses director, officer, employee, and agent responsibilities. We also propose replacing the contents of existing § 651.4(a)(1) requiring directors, officers, employees, and agents to maintain a high standard of behavior with the earlier discussed code of conduct at new § 651.21. We next propose removing existing § 651.4(a)(2) and (b), which requires directors, officers, employees, and agents to comply with the Corporation's conflict-of-interest policy and provide the Corporation with any information the Corporation deems necessary or face penalties. We propose removing these provisions as they are unnecessary in light of other proposed changes contained in this rulemaking. For example, we have already proposed addressing our enforcement authorities in new § 650.3 and conflicts-of-interest in new § 651.22.
Instead, we propose this section address the actions of directors, officers, employees, and agents in regards to the Corporation, its property, and its reputation. We propose under new § 651.24 listing prohibitions on the conduct of directors, officers, employees, and agents. The proposed prohibitions are on making misleading or untrue statements of material facts regarding Farmer Mac, improper use of the official property and information of Farmer Mac, and disclosing confidential information related to Farmer Mac when not in the performance of official duties. We believe these prohibitions are necessary because, as a GSE and a publicly traded corporation, misinformation deliberately provided to outside parties could have a materially adverse impact on the safety and soundness of the Corporation.
It is common corporate practice to use a board committee, often the corporate governance committee, to name director-nominees and Farmer Mac follows this practice.
New § 651.30 would also allow the board committee responsible for nominations to engage the services of third parties to evaluate the professional qualifications of candidates prior to nomination. We believe allowing the board committee used for nominations to engage third parties to vet candidates can aid in achieving timely and objective evaluation of director-candidates.
Next, new § 651.30(b)(3) would require the nomination of a director-candidate to include affirmative votes for nomination from a majority of those involved in the Corporation's nomination process who also represent the same class of stockholders as the candidate. Since the voting stockholders are only presented with one director-candidate per board vacancy—and Farmer Mac no longer allows floor nominations
We are not proposing to require the use of nominating committees or floor nominations in this rulemaking. However, we believe requiring director-candidates to have majority support from those involved in the nomination process who share the candidate's affiliation with either Class A or Class B stockholders facilitates fulfillment of the statutory provision that both Class A and Class B stockholders determine who will represent them on the Corporation's Board. In situations where a “majority” would mathematically result in a fraction, we would expect the next whole number to be used (
The proposed rule at new § 651.30(c) would require Farmer Mac to document the representational affiliation of all elected directors at the time of nomination and election to the board and maintain this documentation until 3 years after the director's service on the board ends. Such recordkeeping would help ensure only those eligible to serve as directors representing Class A or Class B are nominated. We also believe a 3-year record of director affiliations could be of assistance when reviewing director-candidates up for re-election. We believe the statutory term “representative” means that elected directors must have an official affiliation with a Class A or Class B entity at the time of nomination and election in order to serve as director. We view this affiliation as one that is a substantial and visible connection to the class of stockholders.
The proposed new § 651.35 would require Farmer Mac to identify its director removal procedures in the Corporation's bylaws, which are available to shareholders. We believe shareholders are entitled to know how Farmer Mac determines when to require a director to resign (director removal) and how that removal action is achieved. It is important that shareholders understand Farmer Mac's actions in this area since nothing in the proposed provision would affect the ability of voting shareholders to exercise their rights in the election and governance of Farmer Mac's Board of Directors. To further emphasize this, the rule would prohibit Farmer Mac from initiating a director's removal in a manner that would adversely affect the rights of voting shareholders. The rule would also recognize that appointed directors serve at the pleasure of the President of the United States.
We are also proposing language to explain what is considered a “director removal” action initiated by the Corporation. Publicly traded companies use contractual agreements with their directors to ensure certain behavior (
We propose that all director resignations required or otherwise initiated by Farmer Mac be called “director removals.” We believe when a director must resign (or is deemed to have resigned) in response to a Farmer Mac bylaw, policy, or other governing document, that the resignation was initiated by the Corporation since Farmer Mac drafted the document at issue. Further, we believe that when Farmer Mac requires directors, director-nominees, and/or director-candidates to accede to a resignation provision in order to serve on the board of directors that, even if characterized as “voluntary,” it is more appropriately called a removal provision.
The proposed rule would further require Farmer Mac to notify OSMO at least 14 days before seeking the removal of one of its directors. This advance notice is considered necessary to protect the safety and soundness of Farmer Mac. We view this level of advance reporting to be appropriate given the
We are proposing a new § 651.40 that requires Farmer Mac to have policies in place to provide reasonable assurance that its Board of directors maintains responsibility for and provides appropriate oversight of the risk management activities of Farmer Mac, the reports and disclosures issued by Farmer Mac, and shareholder communications. Also, new § 651.40 would clarify the duty of directors to conduct the business of the Corporation in a manner that promotes the best interest of the Corporation and furthers its statutory mission. As a GSE, Farmer Mac should strive to ensure that its Board activities fulfill its public missions. Unlike corporations incorporated under State statutes of incorporation, statutorily chartered GSEs are not free to alter their purposes or powers, even when such alteration may be in the best interest of the investing stockholders. For GSEs, such changes can only be made by law. Thus, it is the responsibility of Farmer Mac directors to lead the Corporation in the manner that best effectuates the public policy it was designed to serve.
Paragraphs (b) and (c) of the proposed provision would set forth key duties of the Farmer Mac Board, among which are the duty to act in good faith and for the best interest of Farmer Mac, as well as acting fairly and impartially without discriminating in favor of or against any investor, stockholder, or group of stockholders. The proposed provisions are intended to ensure that all directors, regardless of how they acquired their seats on the board of directors, understand that they are bound by their fiduciary duty to Farmer Mac and, as a result, act for the betterment of Farmer Mac overall and not any particular group of shareholders or investors. We believe these provisions are necessary to clarify that the required elected director affiliations should not be interpreted to mean an elected director serves solely to further the viewpoints of the electing class without regard to the impact on Farmer Mac and all its shareholders. Such an interpretation would be inconsistent with the established corporate common law principles of a director's fiduciary duties, as well as with Congressional intent. The fiduciary duties of directors are essential to good governance and necessary to the safe and sound operation of the Corporation. Thus, directors failing to fulfill this fiduciary duty could have a negative impact on the safety and soundness of Farmer Mac.
The proposed provisions are another step in ensuring directors maintain their duty of loyalty to the Corporation, notwithstanding any required affiliation with a group of stockholders. However, they are not to be read as requiring elected directors to disregard the perspectives of those electing them to office. Instead, we believe elected directors should share these perspectives with the entire Board so that every director is informed of stockholder concerns and views, thus facilitating Board decisions and ensuring those decisions are being made in the best interests of the Corporation and all of its shareholders.
In balance with the other requirements of new § 651.40, and to help ensure the rule is not misapplied, proposed paragraph (d) would protect the ability of directors to be accountable to the shareholders that elected them. We recognize that fiduciary duties to shareholders must be understood in the context of the duty of the elected directors to possess a representational relationship with certain groups of shareholders. As such, the provision, as proposed, would specifically allow directors to comment on non-private and non-privileged corporate business, provided doing so will not violate any laws or regulations, particularly securities laws. The intent is to allow directors to converse with stockholders as a means of gathering information, gaining insights into stockholder wishes, and demonstrating accountability. The provision clarifies that this authority does not prevent Farmer Mac from protecting proprietary information. It is an established corporate governance principle that once elected to the board a director owes his or her fiduciary duties, including a duty of confidentiality, to the company and shareholders as a whole. As such, the proposed rule would clarify that Farmer Mac may take measures to ensure each director abides by policies defining and specifying the treatment of the Corporation's confidential information, including restricting directors from disclosing the Corporation's confidential information to the shareholders electing them to serve on the Corporation's board. We believe the proposed § 651.40 strikes the appropriate balance between a director's representational duties required by the Act and his or her corporate fiduciary duties.
We propose a new § 651.50 on board committees in subpart C. The new § 651.50 would address the relationship between the entire board and its committees, require certain committees, place membership requirements on the committees, and establish minimum operational requirements for board committees (
In paragraph (a) of new § 651.50, we propose limiting the authority of the board to delegate its collective authority to develop and amend Farmer Mac bylaws to a committee of the board. This provision would not prevent board committees from making recommendations on the bylaws to the entire board. We also propose regulatory language holding the entire board accountable for committee actions. In directing the Corporation, the board of directors may rely on reports from board committees, but doing so does not relieve the board of final responsibility.
In paragraph (b) of new § 651.50, we propose that Farmer Mac have, at the minimum, committees to address risk management, audit, compensation, and corporate governance matters. We propose that there be separate committees dedicated to audit and risk management and that these committees not be tasked with other matters. Our reasoning in support of this proposal is that the oversight responsibilities of each of these two committees represent an aggregation of a very broad array of issues and detailed operational policies and procedures that cover essentially the entire breadth of the Corporation's operations—in addition to the associated ongoing monitoring of all of these. We believe a portfolio of responsibility any larger for either committee would be excessive and risk a severe dilution in a committee's effectiveness.
In paragraph (c) of new § 651.50, we propose that each board committee be established through a written charter. We further propose that committee charters specify the powers, responsibilities, and structure of each committee. We further propose that each committee have both elected and appointed directors and that among the elected directors there be ones with affiliations to both Class A and Class B stockholders. Similarly, we propose that no director may serve as a committee chair of more than one committee. Our
In paragraph (d) of new § 651.50, we propose requiring each board committee to have meeting minutes and to keep the minutes for 3 years. We propose that the minutes include the agenda for the meeting, attendance, a summary of pertinent discussions held during the meeting, and any resulting committee recommendations. In proposing this requirement, we are not seeking transcripts of meetings, but a record of matters addressed by the committee and who participated in the meeting in sufficient detail to allow the reader a reasonable understanding of the substance of the discussion. We propose no set meeting schedule for committees, but do propose a requirement that each committee meet with sufficient frequency to fulfill its duties. We believe these provisions would facilitate both the historical context of policies and procedures for future management teams and directors as well as facilitate the regulatory oversight of board activity.
In proposing new § 651.50, we intend no conflict with SEC regulations on the structure of board committees and welcome comments identifying any potential conflict that might exist between the proposed provision and SEC requirements. Where our proposal contains provisions on board committees that would be requirements, but which are optional under existing SEC rules, it was intentional as we believe the requirements facilitate the safe and sound operations of Farmer Mac.
We propose opening existing reserved part 653 to add risk management provisions for Farmer Mac, renaming the part, “Federal Agricultural Mortgage Corporation Risk Management.” We propose no subparts to part 653, but propose adding the following provisions:
• A new § 653.1 to contain the definitions of certain terms used in part 653;
• A new § 653.2 to address general board-level risk management matters;
• A new § 653.3 to contain required risk management programs and activities; and
• A new § 653.4 to contain requirements for internal controls.
We discuss the proposed §§ 653.1 through 653.4 below.
We propose as new § 653.1 definitions for the terms “Corporation”, “FCA”, and “OSMO.” We are proposing the same meaning as are proposed elsewhere in this rulemaking. We propose these definitions to ensure a common understanding of the terms as used in part 653.
We propose in new § 653.2 to require the Farmer Mac Board approve the overall risk-appetite and tolerance of the Corporation. We believe that while management may design and implement the Corporation's internal controls, the Board remains ultimately responsible for how those controls affect the risk management of the Corporation. The Board's oversight of internal controls is a critical component of its responsibility for monitoring corporate activities and providing reasonable assurance that the controls will prevent excessive risk-taking or unsafe and unsound activities.
A comprehensive and integrated risk management program significantly enhances the coordination of risk decision-making as well as capital allocation among individual business units and allows the units to act within the context of the broader risk-taking activities and risk tolerance limits of the Corporation. Although the Corporation has recently expanded its risk management program to include a risk committee, we propose in new § 653.3(a) to require Farmer Mac to have a risk management program addressing the Corporation's exposure to credit, market, liquidity, operations, and reputation risks. As proposed, the rule would require the risk management program to include:
• Periodic assessments of the Corporation's risk profile, with related adjustments to the Corporation's operations;
• Coordination with board-approved risk tolerance levels;
• Delineation of management's authority and independence in implementing the program; and
• Integration with Corporation goals, business objectives, and compensation.
As referenced in the discussion of proposed § 651.50 (preamble section III.C.3.d.), we are proposing in new § 653.3(b) to require Farmer Mac to have a risk management committee. As proposed, the membership of the risk committee would include a risk management expert. Also, we are proposing that the risk committee be responsible for reviewing the design of the risk management program and receiving management reports on risk management issues, as well as monitoring the Corporation's risk management policies and procedures. We believe it is essential that the tone of Corporation's risk culture and its procedures for risk decision-making be set by the Board even when they are based on management's recommendations. Further, the Board plays a critical role in the ongoing oversight of, and cohesive implementation of, operational strategies and plans that conform to its established risk appetite and tolerance.
We also propose in new § 653.3(c) to require Farmer Mac to have a “Risk Officer” to implement the risk management program. We are proposing that the risk officer report directly to the chief executive officer and risk committee. We also propose that the risk officer be separated from other management functions to ensure s/he devotes full attention to Farmer Mac's risk management activities. Under new § 653.3(c), the risk officer would have to have experience in risk management commensurate with Farmer Mac's operations. The risk officer also would be responsible for monitoring compliance with risk management policies; developing systems to identify and report risks; and making recommendations to adjust risk management behaviors. We believe a staff position that serves as coordinator of the consistent and collaborative implementation of corporate risk policies and objectives across business units is necessary. A risk officer could help coordinate, organize, prioritize and monitor risks on behalf of the CEO and Board risk committee.
As financial institutions become larger and more complex, which Farmer Mac has since it was chartered by Congress in 1987, the need arises for a continuous, coordinated, and comprehensive oversight of the broad spectrum of current and prospective risks the entity faces. A key role of a risk officer is to prevent the emergence of isolated risk “silos” among the entity's business units and ensure a consistent and integrated monitoring of key sources of risks, such as strategic risks (including reputation and political risk), compliance risks, and reporting risks. We believe requiring a risk officer position at Farmer Mac plays a key role in ensuring that the Board and CEO are adequately informed regarding the Corporation's aggregate risk position—thus providing reasonable assurance of the achievement of corporate and
A sound system of comprehensive and integrated internal controls is vital to the operations of any organization and especially those whose business is taking financial risk. In the 26 years since Farmer Mac was chartered, business and operational environments have become significantly more complex and technology-driven. Systems of internal controls should dynamically respond to such changes in complexity—not just in business unit operations but also in compliance with increasingly complex laws, regulations, and industry standards. Thus, while FCA regulations on various aspects of Farmer Mac's operations (
The proposed provision would require an internal controls system that addresses: The effectiveness of corporate activities; security of corporate assets; accuracy and completeness of financial reports; separation of duties to avoid conflicts in responsibilities; transparent reports to the Farmer Mac board; and compliance with applicable laws, regulations, and corporate policies. The new § 653.4 would also require Farmer Mac to have a system to correct weaknesses identified by the internal controls program. Finally, we are proposing an annual reporting requirement, where Farmer Mac would report to OSMO on the effectiveness of the internal controls program.
Existing part 655 contains financial disclosure and reporting provisions for Farmer Mac in two subparts: Subpart A on annual reports and subpart B on securities reports. We propose organizational changes to this part as follows:
• Adding a new subpart A, entitled “General” to address the matters common to disclosures and reports;
• Renaming and redesignating the existing subpart A as new subpart B, to be called “Reports of Condition of the Federal Agricultural Mortgage Corporation;”
• Redesignating existing subpart B as new subpart C;
• Adding a new § 655.1 to identify the definitions of certain terms used in part 655;
• Adding a new § 655.2 to prohibit misleading, inaccurate, or incomplete disclosures;
• Moving existing § 655.1 on annual reports, currently under existing subpart A, to new subpart B and redesignating it as § 655.10;
• Adding a new § 655.15 on the distribution of interim notices and proxies to new subpart B;
• Moving, renaming, and redesignating existing § 655.50 on securities not registered under the Securities Act, currently under existing subpart B, as new § 655.20 in new subpart C; and
• Adding a new § 655.21 on communications with the U.S. Treasury, SEC, and NYSE.
We also propose enhancements to existing disclosure and reporting requirements of part 655 to remove repetitious reporting and incorporate technology by allowing for electronic filing of reports with OSMO. These proposed enhancements are designed to reduce Farmer Mac's reporting responsibilities, while also improving the quality and timeliness of information provided to FCA. We are also proposing changes to remove repetitious disclosure and reporting requirements resulting from the dual reporting responsibilities of Farmer Mac to the FCA and the SEC.
We propose adding a new § 655.1 for definitions of certain terms used in part 655. We are proposing the same definitions to this part as are proposed for part 650 (listed in section III.A. of this preamble). We are also proposing to add the same definition for “person” as is proposed for part 651. In addition, we propose definitions for the term “material” and “report.” While there is a definition for “material” in part 651, the one proposed for this part is different in that it focuses on the meaning of the term when considering financial reports, not conflicts-of-interest. We propose these definitions to ensure a common understanding of the terms as used in part 655. In addition, we propose changes to the existing provisions of part 655 to incorporate the proposed new terms.
We propose adding a new § 655.2 to prohibit misleading, inaccurate, or incomplete disclosures. This prohibition is substantially similar to the one that currently exists in our regulations for the reports of System banks and associations. The provision would establish that no director, officer, employee or agent of Farmer Mac may mislead the FCA, Farmer Mac stockholders, or the general public by making misleading, inaccurate, or incomplete disclosures within the reports required under part 655. The provision would also clarify the authority of FCA to require a corrected report if we determine it contained any misleading, inaccurate, or incomplete disclosures.
The Act requires Farmer Mac to register its equities with the SEC and be subject to SEC disclosure regulations issued under section 14 of the Securities and Exchange Act of 1934.
We propose revising existing § 655.1 (proposed to be redesignated as § 655.10) to cover all reports of conditions, not just annual reports. We are also proposing to require reports be signed and certified. The proposed certification components would be attesting that the signatory reviewed the report, the report was prepared in accordance with applicable laws and regulations, and the reported information is true, accurate, and complete to the best of the signatory's knowledge. Further, we are proposing that quarterly and annual reports be filed by Farmer Mac with OSMO and that those reports either be equivalent to those required by the SEC or according to our instructions. We are proposing the provision that reports be filed
For the reasons already discussed, we are proposing changes to the existing report distribution requirements to reduce timeframes, require Web site posting of reports, and ensure reports distributed to shareholders and investors are the same as those filed with both the FCA and SEC. We are proposing to reduce the existing 120-day timeframe to distribute reports to a 90-day timeframe for distribution of reports to shareholder and a 5-day filing timeframe with OSMO. We believe the reduced timeframes are more reasonable given available technology and other advances in reporting systems. We further propose that if the report is the same as that filed with the SEC, it be filed with OSMO simultaneous with the SEC filing. We next propose changing the existing requirement to send us three paper copies of each report by reducing it to only one paper copy. We also propose allowing the use of electronic filing of reports with OSMO.
We propose requiring Farmer Mac to post reports on its Web site within 3 business days of filing the report with OSMO. We propose that a report remain available on the Web site until the next report is posted. We further propose that if the report is the same as that filed with the SEC, an electronic link to the SEC reports database (EDGAR) would satisfy our regulatory requirement in this area. In making this proposal, we relied on technological advances, the existing availability of the information, and Farmer Mac's existing practice of posting reports on its Web site.
Further, we are proposing a new § 655.15 to require that Farmer Mac send OSMO one paper and one electronic copy of every notice, interim report, and proxy statement it files with the SEC. We believe it is essential that communications between Farmer Mac and OSMO, its primary regulator, include the communications Farmer Mac has with the SEC. The proposed provision would require Farmer Mac to make these disclosures within 1 business day of filing the notice, interim report, or proxy statement with the SEC. We believe this requirement is necessary to ensure we have timely notice of events outside our scheduled examination of these documents.
Similar to the proposal to post reports on its Web site, we are proposing in § 655.15(b) that Farmer Mac post on its Web site notices, interim reports, and proxy statements within 5 business days of filing them with the SEC. As proposed, this requirement could be satisfied with a link to EDGAR. We also propose that these documents remain on the Web site for 6 months, or until the next annual report, whichever is later.
We propose revising existing § 655.50 by first breaking it into two sections: § 655.20 on unregistered securities (currently § 655.50(a)) and § 655.21 on all other filings and communications with the U.S. Treasury, SEC, and NYSE (currently § 655.50(b) and (c)). In new § 655.20, we propose changing the manner of making special filings with OSMO by replacing the existing requirement to send us three paper copies to require one paper and one electronic copy. In new § 655.21, we propose expanding the existing requirement to send us copies of “substantive” correspondence between Farmer Mac and the SEC or U.S. Treasury to include the NYSE. The proposal would also remove the limitation on the type of communication. Currently, the requirement covers correspondence relating to securities activities or regulatory compliance. We believe the Corporation should provide us all substantive communications it has with the U.S. Treasury, the SEC, and the NYSE as that communication may have a bearing on the safety and soundness of Farmer Mac. We also propose setting a 3-day timeframe for providing the information to us. Finally, new § 655.21(c) would require Farmer Mac to notify us of exemptions from SEC filing requirements within 1 business day. The current rule requires this information to be sent to us “promptly.” In light of the proposed changes to reporting requirements, we believe it is necessary to have definitive and fast notice of any changes Farmer Mac seeks in SEC filing requirements.
Pursuant to section 605(b) of the Regulatory Flexibility Act (5 U.S.C. 601
Agriculture, Banks, banking, Credit, Reporting and recordkeeping requirements, Rural areas.
Agriculture, Banks, banking, Conduct standards, Conflict of interests, Elections, Ethical conduct, Rural areas.
Agriculture, Banks, banking, Capital, Conduct standards, Credit, Finance, Rural areas.
Accounting, Agriculture, Banks, banking, Accounting and reporting requirements, Disclosure and reporting requirements, Financial disclosure, Rural areas.
For the reasons stated in the preamble, parts 650, 651, 653, and 655 of chapter VI, title 12 of the Code of Federal Regulations are proposed to be amended as follows:
Secs. 4.12, 5.9, 5.17, 5.25, 8.11, 8.12, 8.31, 8.32, 8.33, 8.34, 8.35, 8.36, 8.37, 8.41 of the Farm Credit Act (12 U.S.C. 2183, 2243, 2252, 2261, 2279aa-11, 2279aa-12, 2279bb, 2279bb-1, 2279bb-2, 2279bb-3, 2279bb-4, 2279bb-5, 2279bb-6, 2279cc); sec. 514 of Pub. L. 102-552, 106 Stat. 4102; sec. 118 of Pub. L. 104-105, 110 Stat. 168.
The following definitions apply for the purpose of this part:
(a)
(b)
(c)
The Act provides FCA, acting through OSMO, with enforcement authority to protect the financial safety and soundness of the Corporation and to ensure that the Corporation's powers, functions, and duties are exercised in a safe and sound manner.
(a)
(1) Issue an order to cease and desist;
(2) Issue a temporary order to cease and desist;
(3) Assess civil monetary penalties against the Corporation and its directors, officers, employees, and agents; and
(4) Issue an order to suspend, remove, or prohibit directors and officers.
(b)
When we determine the Corporation is taking excessive risks that adversely impact capital, we have authority to address that risk. This includes, but is not limited to, requiring capital restoration plans, restricting dividend distributions, requiring changes in the Corporation's obligations and assets, requiring the acquisition of new capital and restricting those Corporation activities determined to create excessive risk to the Corporation.
(a) The Corporation must make its records available promptly upon request by OSMO, at a location and in a form and manner acceptable to OSMO.
(b) The Corporation must make directors, officers, employees and agents available to OSMO during the course of an examination or supervisory action when OSMO determines it necessary to facilitate an examination or supervisory action.
The Corporation is subject to the provisions in 12 CFR part 602 regarding FCA Reports of Examination.
The rules at 12 CFR part 612, subpart B, regarding “Referral of Known or Suspected Criminal Violations” are applicable to the Corporation.
Secs. 4.12, 5.9, 5.17, 8.3, 8.11, 8.14, 8.31, 8.32, 8.33, 8.34, 8.35, 8.36, 8.37, 8.41 of the Farm Credit Act (12 U.S.C. 2183, 2243, 2252, 2279aa-3, 2279aa-11, 2279aa-14, 2279bb, 2279bb-1, 2279bb-2, 2279bb-3, 2279bb-4, 2279bb-5, 2279bb-6, 2279cc); sec. 514 of Pub. L. 102-552, 106 Stat. 4102; sec. 118 of Pub. L. 104-105, 110 Stat. 168.
The following definitions apply to this part:
(a)
(1) Indemnification policies and procedures must address how the board of directors approves or denies requests for indemnification from current and former directors, officers, and employees. The policies and procedures must include standards relating to indemnification, investigations by the board of directors, and reviews by independent counsel.
(2) Indemnification policies and procedures must consider all sources of potential indemnification to protect the Corporation against over-indemnification of an individual director or officer.
(b)
(a)
(b)
(a) The Corporation must establish and administer a conflict-of-interest policy that will provide reasonable assurance that the directors, officers, employees, and agents of the Corporation discharge their official responsibilities in an objective, impartial, and business-like manner that furthers the lawful interests and statutory purpose of the Corporation. The conflict-of-interest policy must acknowledge and respect the representational affiliations required by the Act for elected directors.
(b) The conflict-of-interest policy must:
(1) Define the types of transactions, relationships, or activities that could reasonably be expected to give rise to potential conflicts of interest. For the purpose of determining whether a potential conflict-of-interest exists, the following interests shall be imputed to a person subject to this regulation as if they were that person's own interests:
(i) Interests of any individual residing in that person's household;
(ii) Interests of any individual identified as a legal dependent of that person;
(iii) Interests of that person's general partner;
(iv) Interests of an organization or entity that the person serves as officer, director, trustee, general partner or employee, unless the organization or entity is directly connected to the representational affiliations required by the Act for elected directors; and
(v) Interests of a person, organization, or entity with which that person is negotiating for or has an arrangement concerning prospective employment.
(2) Include guidelines for determining when a potential conflict is material (as that term is defined in this part);
(3) Contain procedures for resolving or disclosing material conflicts of interest.
(4) Address recusal from official actions on any matter in which a director, officer, employee, or agent is prohibited from participating based on a conflict-of-interest identified under this part; and
(5) Define documentation and reporting requirements, consistent with this part, for demonstrating compliance with conflict-of-interest decisions.
(c) The Corporation must notify directors, officers, employees, and agents of the conflict-of-interest policy
(d) When requested, the Corporation must provide to any shareholder, investor, or potential investor, with a copy of its conflict-of-interest policy. The Corporation may charge a nominal fee to cover the costs of reproduction and handling.
(a) Annually, each director, officer, and employee must provide to the Corporation a written and signed conflict-of-interest report. The report must disclose information about financial interests, transactions, relationships, and activities sufficient enough for a reasonable person to make a conflict-of-interest determination.
(1) The annual conflict-of-interest report must identify any transaction, relationship, or activity that, in the director, officer or employee's opinion, creates a real or potential material conflict-of-interest or that is:
(i) Specifically named in the Corporation's policies on conflict-of-interest; or
(ii) Addressed in regulation.
(2) If potential or real conflicts arise between annual reporting periods, each director, officer, and employee must update his or her annual disclosure at the time(s) such conflict arises.
(b) The Corporation must review the annual conflict-of-interest reports, and any subsequent reports, within 10 business days of receipt.
(1) The Corporation must determine for each director, officer, and employee whether any real or potential material conflict-of-interest exists and document its findings.
(2) If a real or potential conflict-of-interest is identified as material by the Corporation, the Corporation must, within 3 business days of identification, notify the director, officer, or employee of the material conflict-of-interest determination and must provide the director, officer, or employee a reasonable opportunity to respond.
(c) The Corporation must document all resolved and unresolved material conflicts-of-interest. Until resolved, the Corporation must maintain on-going documentation that explains how unresolved conflicts are being handled.
(d) The Corporation must disclose any unresolved material conflict-of-interest involving its directors, officers, and employees existing at the time to:
(1) Shareholders through annual reports and proxy statements;
(2) Investors and potential investors through disclosure documents supplied to them; and
(3) The FCA, through procedures established by OSMO.
(e) The Corporation must establish and maintain internal controls to ensure that conflict-of-interest reports are filed and reviewed as required and that conflicts are resolved or disclosed in accordance with this subpart.
(f) The Corporation must maintain all reports of real or potential material conflicts-of-interest, including documentation of materiality determinations and resolutions, for a period of 6 years.
(g) The Corporation must establish procedures for obtaining conflict-of-interest disclosures from agents of the Corporation. These disclosures must provide enough information for the Corporation to identify if the agent has material conflicts-of-interest with the Corporation. The procedures on agent conflicts-of-interest must satisfy the documentation and record retention requirements in paragraphs (c) and (f) of this section.
(a) No director, officer, employee, or agent of the Corporation may make any untrue or misleading statement of a material fact intended or having the effect of reducing public confidence in the Corporation.
(b) No director, officer, employee, or agent of the Corporation may make improper use of official Corporation property or information. Improper use includes, but is not limited to, the purchase or retirement of any stock in advance of the public release of material non-public information concerning the Corporation.
(c) Except in the performance of official duties, no director of the Corporation shall divulge or use any fact, information, or document that is acquired by virtue of serving on the board of the Corporation and not generally available to the public.
(a) The Corporation must have in effect at all times director election procedures and must administer those procedures in a fair and impartial manner.
(b) The director election procedures must:
(1) Provide that any holder of an equity interest in the Corporation may submit candidates for consideration as director-nominees to the Corporation's board of directors.
(2) Allow the board committee used for director nominations to engage the services of third parties to evaluate the professional qualifications of potential nominees.
(3) Require that during the director nomination process, a director-candidate must receive affirmative votes for nomination from a majority of those representing the same class of stockholders as the candidate.
(c) The Corporation must ensure director elections acknowledge and respect the voting rights of Class A and Class B stockholders, as well as the elected director representational affiliations required by the Act. Elected director candidates must have a recognized affiliation or relationship with their respective class of voting stockholders at the time of nomination and election to the Corporation board of directors. The Corporation must maintain documentation supporting the affiliation or relationship of each elected director until 3 years after the director's service on the board ends.
(a) The procedures that the Corporation relies upon to initiate director removals must be contained in the Corporation's bylaws. Director removals initiated by the Corporation include, but are not limited to, resignations requested by the Corporation, mandatory resignations based on contractual agreements with the Corporation, and resignations required in response to predetermined events or actions identified in the Corporation's governing documents.
(b) Director removals initiated by the Corporation may not adversely affect the rights of voting shareholders. Appointed directors may only be removed as authorized by the President of the United States.
(c) The Corporation must notify OSMO at least 14 days before any director removal is initiated by the Corporation.
(a)
(1) The risk management and compensation programs of the Corporation,
(2) The processes for providing accurate financial reporting and other disclosures, and
(3) Communications with stockholders.
(b)
(c)
(1) Carry out his or her duties as director in good faith, in a manner such director believes to be in the best interests of the Corporation, and with such care, including reasonable inquiry, as a reasonable person in a similar position would use under similar circumstances;
(2) Administer the affairs of the Corporation fairly and impartially and without discrimination in favor of or against any investor, stockholder, or class of stockholders; and
(3) Direct the operations of the Corporation in conformity with safety and soundness standards and the requirements set forth in the authorizing statute and in compliance with all applicable laws and regulations.
(d)
(a)
(b)
(c)
(1) Each board committee must have at least one elected director from each class of voting stock and one appointed director as members of the committee.
(2) No director may serve as chairman of more than one board committee.
(d)
Secs. 8.3, 8.4, 8.6, 8.8, and 8.10 of the Farm Credit Act (12 U.S.C. 2279aa-3, 2279aa-4, 2279aa-6, 2279aa-8, and 2279aa-10).
The following definitions apply for the purpose of this part:
The Corporation's board of directors must approve the overall risk-appetite and risk tolerance of the Corporation and monitor internal controls to ensure risk-taking activities are conducted in a safe and sound manner.
(a)
(1) Periodically assess and document the Corporation's risk profile.
(2) Align the Corporation's risk profile with the board-approved risk appetite and risk tolerance and the Corporation's operational planning strategies and objectives.
(3) Address the Corporation's exposure to credit, market, liquidity, business and operational risks.
(4) Specify management's authority and independence to carry out risk management responsibilities.
(5) Integrate risk management and control objectives into management goals and compensation structures.
(6) Comply with all applicable FCA regulations and policies.
(b)
(1) The risk committee must have at least one member with risk management expertise commensurate with the Corporation's capital structure, risk profile, complexity, activities, size, and other appropriate risk-related factors.
(2) The responsibilities of the risk committee include, but are not limited to:
(i) Overseeing and documenting the enterprise-wide risk management policies and practices of the Corporation;
(ii) Reviewing and recommending an appropriate risk management program commensurate with the Corporation's capital structure, risk profile, complexity, activities, size, and other appropriate risk-related factors; and
(iii) Receiving and reviewing regular reports from the Corporation's Risk Officer.
(c)
(1) Identifying and monitoring compliance with risk limits, exposures, and controls;
(2) Implementing risk management policies, procedures, and risk controls;
(3) Developing appropriate processes and systems for identifying and reporting risks, including emerging risks;
(4) Reporting risk management issues, emerging risks, and compliance concerns to the chief executive officer and the risk committee; and
(5) Making recommendations to the chief executive officer and board risk committee on adjustments to risk management policies, procedures, and risk controls of the Corporation.
(a) The Corporation's board of directors must adopt an internal controls policy that provides adequate directions for, and identifies expectations in, establishing effective control over, and accountability for, operations, programs, and resources to ensure that the Corporation's powers, functions, and duties are exercised in a safe and sound manner and in compliance with all applicable laws and regulations.
(b) The internal control system must address:
(1) The efficiency and effectiveness of the Corporation activities;
(2) Safeguarding the assets of the Corporation;
(3) Evaluating the reliability, completeness, and timely reporting of financial and management information;
(4) Compliance with applicable laws, regulations, regulatory directives, and the policies of the Corporation's board of directors and senior management;
(5) The appropriate segregation of duties among the Corporation personnel so that personnel are not assigned conflicting responsibilities; and
(6) The transparency of information provided to the Corporation's board of directors.
(c) The Corporation is responsible for establishing and implementing an effective system to track internal control weaknesses and take action to correct detected weaknesses. As part of that program, the Corporation must establish and maintain a compliance program that is reasonably designed to assure that the Corporation complies with applicable laws, regulations, and internal controls.
(d) The Corporation must annually report to OSMO on the effectiveness of the internal control system.
Secs. 5.9, 8.3, 8.11, and 8.12 of the Farm Credit Act (12 U.S.C. 2243, 2279aa-3, 2279aa-11, 2279aa-12).
The following definitions apply for the purpose of this part:
The Corporation and any agent, employee, officer, or director of the Corporation may not make any report or disclosure to FCA, stockholders or the general public concerning any matter required to be disclosed by this part that is incomplete, inaccurate, or misleading. When any such person makes a report or disclosure that, in the judgment of FCA, is incomplete, inaccurate, or misleading, whether or not such report or disclosure is made in reports or disclosure statements required by this part, the FCA may require the Corporation to make such additional or corrective disclosure as is necessary to provide a full and fair disclosure.
(a)
(b)
(1) The signatories have reviewed the report,
(2) The report has been prepared in accordance with all applicable statutory or regulatory requirements, and
(3) The information is true, accurate, and complete to the best of signatories' knowledge and belief.
(c)
(1) The Corporation must publish a copy of each report of condition on its Web site within 3 business days of filing the report with us. The report must remain on the Web site until the next report is posted. When the reports are the same as those filed with the SEC, electronic links to the SEC filings Web site, EDGAR, may be used in satisfaction of this requirement.
(2) Upon receiving a request for an annual report of condition from a stockholder, investor, or the public, the Corporation must promptly provide the requester the most recent signed annual report issued in compliance with this section.
(a) The Corporation must provide to us one paper and one electronic copy of every interim report, notice, and proxy statement filed with the SEC within 1 business day of filing the item with the SEC, including all papers and documents that are a part of the report, notice, or statement.
(b) The Corporation must publish a copy of each interim report, notice, and proxy statement on its Web site within 5 business days of filing the document(s) with the SEC. The interim report, notice, or proxy statement must remain on the Web site for 6 months or until the next annual report of condition is posted, whichever is later. Electronic links to the SEC filings Web site, EDGAR, may be used in satisfaction of this requirement.
The Corporation must make special filings with OSMO for securities either issued or guaranteed by the Corporation that are not registered under the Securities Act. These filings include, but are not limited to:
(a) One paper and one electronic copy of any offering circular, private placement memorandum, or information statement prepared in connection with the securities offering at or before the time of the securities offering.
(b) For securities backed by qualified loans as defined in section 8.0(9)(A) of the Act, one paper and one electronic copy of the following within 1 business day of the finalization of the transaction:
(1) The private placement memoranda for securities sold to investors; and
(2) The pooling and servicing agreement when the security is purchased by the Corporation as authorized by section 8.6(g) of the Act.
(c) For securities backed by qualified loans as defined in section 8.0(9)(B) of the Act, the Corporation must provide summary information on such securities issued during each calendar quarter in the form prescribed by us. Such summary information must be provided with each report of condition and performance filed pursuant to § 621.12, and at such other times as OSMO may require.
(a) The Corporation must send us one paper and one electronic copy of every filing made with U.S. Treasury, the SEC, or NYSE, including financial statements and related schedules, exhibits, and other documents that are a part of the filing. Such copies must be filed with us no later than 1 business day after any U.S. Treasury, SEC, or NYSE filing. If the filing is one addressed in subpart B of this part, no action under this paragraph is required.
(b) The Corporation must send us, within 3 business days and according to instructions provided by us, copies of all substantive correspondence between the Corporation and the U.S. Treasury, the SEC, or NYSE.
(c) The Corporation must notify us within 1 business day if it becomes exempt or claims exemption from any filing requirements of the Securities Act.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to supersede Airworthiness Directive (AD) 2012-18-05, which applies to The Boeing Company Model DC-9-10, DC-9-20, DC-9-30, DC-9-40, and DC-9-50 series airplanes; and Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), DC-9-87 (MD-87), MD-88, and MD-90-30 airplanes; equipped with a center wing fuel tank and Boeing original equipment manufacturer-installed auxiliary fuel tanks. AD 2012-18-05 currently requires adding design features to detect electrical faults and to detect a pump running in an empty fuel tank. Since we issued AD 2012-18-05, we have determined that it is necessary to clarify the actions for airplanes on which the auxiliary fuel tanks are removed. This proposed AD would allow certain actions as optional methods of compliance. We are proposing this AD to reduce the potential of ignition sources inside fuel tanks, which, in combination with flammable fuel vapors, could result in fuel tank explosions and consequent loss of the airplane.
We must receive comments on this proposed AD by May 11, 2015.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
For service information identified in this proposed AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, 3855
You may examine the AD docket on the Internet at
Sérj Harutunian, Aerospace Engineer, Propulsion Branch, ANM-140L, FAA, Los Angeles Aircraft Certification Office (ACO), 3960 Paramount Boulevard, Lakewood, CA 90712-4137; phone: 562-627-5254; fax: 562-627-5210; email:
We invite you to send any written relevant data, views, or arguments about this proposed AD. Send your comments to an address listed under the
We will post all comments we receive, without change, to
On August 6, 2012, we issued AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012), for The Boeing Company Model DC-9-10, DC-9-20, DC-9-30, DC-9-40, and DC-9-50 series airplanes; and Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), DC-9-87 (MD-87), MD-88, and MD-90-30 airplanes; equipped with a center wing fuel tank and Boeing original equipment manufacturer-installed auxiliary fuel tanks. AD 2012-18-05 requires adding design features to detect electrical faults and to detect a pump running in an empty fuel tank. AD 2012-18-05 resulted from fuel system reviews conducted by the manufacturer. We issued AD 2012-18-05 to reduce the potential of ignition sources inside fuel tanks, which, in combination with flammable fuel vapors, could result in fuel tank explosions and consequent loss of the airplane.
Since we issued AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012), we have determined that it is necessary to clarify the actions for airplanes on which the auxiliary fuel tanks are removed. In addition, The Boeing Company has issued new service information for Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), DC-9-87 (MD-87), and Model MD-88 airplanes; and Model MD-90-30 airplanes, which provides a method of compliance for the actions required by AD 2012-18-05. Boeing has not yet issued corresponding service information for Boeing Model DC-9-10, DC-9-20, DC-9-30, DC-9-40, and DC-9-50 series airplanes. The applicability of AD 2012-18-05 has not changed in this proposed AD.
We reviewed Boeing Service Bulletin MD80-28-228, dated September 27, 2013; and Boeing Service Bulletin MD90-28-013, dated September 27, 2013. The service information describes procedures for installing GFI relays that change fuel pump system wiring, installing a low fuel pressure indication system, and revising the inspection or maintenance program to include new limitations.
We have also reviewed Appendixes B, C, and D of Boeing Special Compliance Item Report MDC-92K9145, Revision M, dated February 5, 2013, which includes Critical Design Configuration Control Limitations (CDCCLs), Airworthiness Limitations Instructions (ALIs), and short-term extensions.
Boeing Service Bulletin MD80-28-228, dated September 27, 2013, specifies prior or concurrent accomplishment of the following concurrent service information.
• Boeing MD-80 Service Bulletin 28-53, Revision 1, dated April 16, 1992, which describes procedures for installing a low fuel pressure indication system.
• Boeing MD-80 Service Bulletin 28-63, Revision 2, dated April 8, 1992, which describes procedures for installing a low fuel pressure indication inhibit system.
This service information is reasonably available; see
In paragraph (c) of this proposed AD, we have added the text “for airplanes on which auxiliary fuel tanks are removed, the AD action specified for the auxiliary fuel tanks are not required” to clarify that the actions specified in this AD for the auxiliary fuel tanks are not required when the auxiliary fuel tanks are removed, but the AD actions for the center fuel tanks still apply.
We have determined that it is appropriate to allow additional time to accomplish the design features and requirements specified in this proposed AD. Therefore, we have added a compliance time of “within 42 months after the effective date of this AD” to paragraph (g) of this proposed AD. We have determined that this extension of the compliance time will provide an acceptable level of safety.
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of these same type designs.
This proposed AD would retain all requirements of AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012). This proposed AD would clarify the actions for airplanes on which the auxiliary fuel tanks are removed, that the actions specified for the auxiliary fuel tanks are not required. This proposed AD would also provide certain methods of compliance for the actions restated from AD 2012-18-05 (one option is accomplishing the actions
This proposed AD specifies to revise certain operator maintenance documents to include new actions (
We estimate that this proposed AD affects 809 airplanes of U.S. registry.
We estimate the following costs to comply with this proposed AD:
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701, “General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We have determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have 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.
For the reasons discussed above, I certify that the proposed regulation:
(1) Is not a “significant regulatory action” under Executive Order 12866,
(2) Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979),
(3) Will not affect intrastate aviation in Alaska, and
(4) Will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.
Air transportation, Aircraft, Aviation safety,
Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:
49 U.S.C. 106(g), 40113, 44701.
The FAA must receive comments on this AD action by May 11, 2015.
This AD replaces AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012).
This AD applies to The Boeing Company airplanes identified in paragraphs (c)(1) through (c)(8) of this AD, certificated in any category, and equipped with center wing fuel tanks and Boeing original equipment manufacturer-installed auxiliary fuel tanks. For airplanes on which the auxiliary fuel tanks have been removed, the actions specified for the auxiliary fuel tanks are not required.
(1) Model DC-9-11, DC-9-12, DC-9-13, DC-9-14, DC-9-15, and DC-9-15F airplanes.
(2) Model DC-9-21 airplanes.
(3) Model DC-9-31, DC-9-32, DC-9-32 (VC-9C), DC-9-32F, DC-9-33F, DC-9-34, DC-9-34F, and DC-9-32F (C-9A, C 9B) airplanes.
(4) Model DC-9-41 airplanes.
(5) Model DC-9-51 airplanes.
(6) Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), and DC-9-87 (MD-87) airplanes.
(7) Model MD-88 airplanes.
(8) Model MD-90-30 airplanes.
Air Transport Association (ATA) of America Code 28, Fuel.
This AD was prompted by fuel system reviews conducted by the manufacturer. We are issuing this AD to reduce the potential of ignition sources inside fuel tanks, which, in combination with flammable fuel vapors, could result in fuel tank explosions and consequent loss of the airplane.
Comply with this AD within the compliance times specified, unless already done.
This paragraph restates the actions required by paragraph (g) of AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012), with a new compliance time. Except as provided by paragraphs (h) and (i) of this AD: As of 42 months after the effective date of this AD, no person may operate any airplane affected by this AD unless an amended type certificate or supplemental type certificate that incorporates the design features and requirements described in paragraphs (g)(1) and (g)(2) of this AD has been approved by the Manager, Los Angeles Aircraft Certification Office (ACO), FAA, and those design features are installed on the airplane.
(1) Each electrically powered fuel pump installed in the center wing tank or auxiliary fuel tank must have a protective device installed to detect electrical faults that can cause arcing and burn through the fuel pump housing. The same device must shut off the pump by automatically removing electrical power from the pump when such faults are detected. When a fuel pump is shut off as the result of detection of an electrical fault, the device must stay latched off until the fault is cleared through maintenance action and verified that the pump and the electrical power feed are safe for operation.
(2) Additional design features must be installed to detect when any center wing tank or auxiliary fuel tank pump is running in an empty fuel tank. The prospective pump shutoff system must shut off each pump no later than 60 seconds after the fuel tank is emptied. The pump shutoff system design must preclude undetected running of a fuel pump in an empty tank, after the pump was commanded off manually or automatically.
For Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), DC-9-87 (MD-87), and Model MD-88 airplanes; and Model MD-90-30 airplanes: In lieu of doing the requirements of paragraph (g) of this AD, do the applicable actions specified in paragraphs (h)(1), (h)(2), and (h)(3) of this AD.
(1) For Model DC-9-81 (MD-81), DC-9-82 (MD-82), DC-9-83 (MD-83), DC-9-87 (MD-87), and Model MD-88 airplanes: Do the applicable actions specified in paragraphs (h)(1)(i), (h)(1)(ii), and (h)(1)(iii) of this AD.
(i) For all airplanes identified in paragraph (h)(1) of this AD: Within the compliance time specified in paragraph (g) of this AD, install ground fault interrupter (GFI) relays, in accordance with the Accomplishment Instructions of Boeing Service Bulletin MD80-28-228, dated September 27, 2013.
(ii) For airplanes identified in Boeing MD-80 Service Bulletin 28-53, Revision 1, dated April 16, 1992: Prior to or concurrently with accomplishing the action specified in paragraph (h)(1)(i) of this AD, install a low fuel pressure indication system, in accordance with the Accomplishment Instructions of Boeing MD-80 Service Bulletin 28-53, Revision 1, dated April 16, 1992.
(iii) For airplanes identified in Boeing MD-80 Service Bulletin 28-63, Revision 2, dated April 8, 1992: Prior to or concurrently with accomplishing the action specified in paragraph (h)(1)(i) of this AD, install a low fuel pressure indication inhibition system, in accordance with the Accomplishment Instructions of Boeing MD-80 Service Bulletin 28-63, Revision 2, dated April 8, 1992.
(2) For Model MD-90-30 airplanes: Within the compliance time specified in paragraph (g) of this AD, install brackets and mod block rails, and install GFI relays, in accordance with the Accomplishment Instructions of Boeing Service Bulletin MD90-28-013, dated September 27, 2013.
(3) For all airplanes: Within 30 days after accomplishing the actions required by paragraph (h)(1) or (h)(2) of this AD or within 30 days after the effective date of this AD, whichever occurs later, revise the maintenance or inspection program, as applicable, to incorporate the Critical Design Configuration Control Limitations (CDCCLs), Airworthiness Limitations Instructions (ALIs), and short-term extensions specified in Appendixes B, C, and D of Boeing Special Compliance Item Report MDC-92K9145, Revision M, dated February 5, 2013. The initial compliance time for accomplishing the actions specified in the ALIs is at the later of the times in paragraphs (h)(3)(i) and (h)(3)(ii) of this AD. Doing the revision of the maintenance or inspection program, as applicable, required by this paragraph terminates the requirements in paragraphs (g) and (h) of AD 2008-11-15, Amendment 39-15538 (73 FR 30746, May 29, 2008).
(i) At the applicable time specified in in Appendix C of Boeing Special Compliance Item Report MDC-92K9145, Revision M, dated February 5, 2013, except as provided by Appendix D, of Boeing Special Compliance Item Report MDC-92K9145, Revision M, dated February 5, 2013.
(ii) Within 30 days after accomplishing the actions required by paragraph (h)(1) or (h)(2) of this AD, or within 30 days after the effective date of this AD, whichever occurs later.
In lieu of doing the requirements of paragraph (g) of this AD, within the compliance time specified in paragraph (g) of this AD install a TDG Aerospace Inc. UFI using a method approved in accordance with the procedures specified in paragraph (l) of this AD.
TDG Aerospace STC ST02502LA ([
After the maintenance or inspection program, as applicable, has been revised as required by paragraph (h)(3) of this AD, no alternative actions (
This paragraph provides credit for the actions specified in paragraphs (h)(1)(ii) and (h)(1)(iii) of this AD, if those actions were performed before the effective date of this AD using any of the service information specified in paragraph (k)(1), (k)(2), or (k)(3) of this AD.
(1) Boeing MD-80 Service Bulletin 28-53, dated April 8, 1991.
(2) Boeing MD-80 Service Bulletin 28-63, dated, June 14, 1991.
(3) Boeing MD-80 Service Bulletin 28-63, Revision 1, dated July 19, 1991.
(1) The Manager, Los Angeles Aircraft Certification Office (ACO), FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the manager of the ACO, send it to the
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.
(3) An AMOC that provides an acceptable level of safety may be used for any repair required by this AD if it is approved by the Boeing Commercial Airplanes Organization Designation Authorization (ODA) that has been authorized by the Manager, Los Angeles ACO, to make those findings. For a repair method to be approved, the repair must meet the certification basis of the airplane, and the approval must specifically refer to this AD.
(4) AMOCs approved for AD 2012-18-05, Amendment 39-17181 (77 FR 54793, September 6, 2012), are approved as AMOCs for the corresponding provisions of this AD.
(1) For more information about this AD, contact Sérj Harutunian, Aerospace Engineer, Propulsion Branch, ANM-140L, FAA, Los Angeles Aircraft Certification Office (ACO), 3960 Paramount Boulevard, Lakewood, CA 90712-4137; phone: 562-627-5254; fax: 562-627-5210; email:
(2) For service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Data & Services Management, 3855 Lakewood Boulevard, MC D800-0019, Long Beach, CA 90846-0001; telephone 206-544-5000, extension 2; fax 206-766-5683; Internet
Department of Justice.
Notice of proposed rulemaking.
As described in the notice section of this issue of the
Comments must be received by April 27, 2015.
Address all comments to the Privacy Analyst, Office of Privacy and Civil Liberties, National Place Building, 1331 Pennsylvania Avenue NW., Suite 1000, Washington, DC 20530, or by facsimile to (202) 307-0693. To ensure proper handling, please reference the CPCLO Order Number on your correspondence. You may review an electronic version of the proposed rule at
Please note that the Department is requesting that electronic comments be submitted before midnight Eastern Time on the day the comment period closes because this is when
If you want to submit personally identifying information (such as your name, address, etc.) as part of your comment, but do not want it to be posted online or made available in the public docket, you must include the phrase “PERSONALLY IDENTIFYING INFORMATION” in the first paragraph of your comment. You must also place all the personally identifying information you do not want posted online or made available in the public docket in the first paragraph of your comment and identify what information you want redacted.
If you want to submit confidential business information as part of your comment, but do not want it to be posted online or made available in the public docket, you must include the phrase “CONFIDENTIAL BUSINESS INFORMATION” in the first paragraph of your comment. You must also prominently identify confidential business information to be redacted within the comment. If a comment has so much confidential business information that it cannot be effectively redacted, all or part of that comment may not be posted online or made available in the public docket.
Personally identifying information and confidential business information identified and located as set forth above will be redacted and the comment, in redacted form, will be posted online and placed in the Department's public docket file. Please note that the Freedom of Information Act applies to all comments received. If you wish to inspect the agency's public docket file in person by appointment, please see the
Tricia Francis, Executive Office for United States Attorneys, FOIA/Privacy Act Staff, 600 E Street NW., Suite 7300, Washington, DC 20530, or by facsimile at (202) 252-6047.
In the notices section of this issue of the
This proposed rule relates to individuals as opposed to small business entities. Pursuant to the requirements of the Regulatory Flexibility Act, 5 U.S.C. 601-612, the proposed rule will not have a significant economic impact on a substantial number of small entities.
The Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 801
The Paperwork Reduction Act of 1995, 44 U.S.C. 3507(d), requires that the Department consider the impact of paperwork and other information-collection burdens imposed on the public. There are no current or new information-collection requirements associated with this proposed rule. The records that are contributed to this system would be created in any event by law enforcement entities, and their sharing of this information electronically will not increase the paperwork burden on these entities.
This proposed rule is not a “significant regulatory action” within the meaning of Executive Order 12866 and therefore further regulatory evaluation is not necessary. This proposed rule will not have a significant economic impact on a substantial number of small entities because it applies only to information about individuals.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, 109 Stat. 48, requires Federal agencies to assess the effects of certain regulatory actions on State, local, and tribal governments and the private sector. UMRA requires a written statement of economic and regulatory alternatives for proposed and final rules that contain Federal mandates. A “Federal mandate” is a new or additional enforceable duty imposed on any State, local, or tribal government or the private sector. If any Federal mandate causes those entities to spend, in aggregate, $100 million or more in any one year, the UMRA analysis is required. This proposed rule would not impose Federal mandates on any State, local, or tribal government or the private sector.
Administrative Practices and Procedures, Courts, Freedom of Information Act, Government in the Sunshine Act, Privacy Act.
Pursuant to the authority vested in the Attorney General by 5 U.S.C. 552a and delegated to me by Attorney General Order No. 2940-2008 the DOJ proposes to amend 28 CFR part 16 as follows:
5 U.S.C. 301, 552, 552a, 552b(g), 553; 18 U.S.C. 4203(a)(1); 28 U.S.C. 509, 510, 534; 31 U.S.C. 3717, 9701.
(a) The Department of Justice, Giglio Information Files (JUSTICE/DOJ-017) system of records is exempted from subsections (c)(3) and (4); (d)(1) through (4); (e)(1), (2), (3), (4)(G), (H), and (I), (5), and (8); (f); and (g) of the Privacy Act. These exemptions apply only to the extent that information in this system is subject to exemption pursuant to 5 U.S.C. 552a(j) and/or (k).
(b) Exemptions from the particular subsections are justified for the following reasons:
(1) From subsection (c)(3) of the Privacy Act because this subsection is inapplicable to the extent that an exemption is being claimed for subsection (d) of the Privacy Act.
(2) From subsection (c)(4) of the Privacy Act because this subsection is inapplicable to the extent that an exemption is being claimed for subsection (d) of the Privacy Act.
(3) From subsection (d) of the Privacy Act because access to the records contained in this system may interfere with or impede an ongoing investigation as it may be related to allegations against an agent or witness who is currently being investigated. Further, other records that are derivative of the subject's employing agency files may be accessed through the employing agency's files.
(4) From subsection (e)(1) of the Privacy Act because it may not be possible to determine in advance if potential impeachment records collected and maintained in order to sufficiently meet the Department's
(5) From subsection (e)(2) of the Privacy Act because collecting information directly from the subject individual could serve notice that the individual is the subject of investigation and because of the nature of the records in this system, which are used to impeach or demonstrate bias of a witness, requires that the information be collected from others.
(6) From subsection (e)(3) of the Privacy Act because federal law enforcement officers receive notice from their supervisors and prosecuting attorneys that impeachment information may be used at trial. Law enforcement officers are also given notice by the
(7) From subsections (e)(4)(G), (H), and (I) of the Privacy Act because this system of records is exempt from the access and amendment provisions of subsection (d) of the Privacy Act.
(8) From subsection (e)(5) of the Privacy Act because it may not be possible to determine in advance if all potential impeachment records collected and maintained in order to sufficiently meet the Department's
(9) From subsection (e)(8) of the Privacy Act because the nature of the
(10) From subsections (f) and (g) of the Privacy Act because these subsections are inapplicable to the extent that the system is exempt from other specific subsections of the Privacy Act.
Office of Surface Mining Reclamation and Enforcement, Interior.
Proposed rule; reopening of the public comment period and opportunity for public hearing.
We, the Office of Surface Mining Reclamation and Enforcement (OSMRE), are reopening the public comment period on the proposed amendment to the Kentucky regulatory program (the Kentucky program) under the Surface Mining Control and Reclamation Act of 1977 (SMCRA or the Act) that was originally published on February 20, 2013. The public comment period and opportunity for public hearing is being reopened to incorporate subsequent information (emergency regulations, permanent regulations, legislation, and revised statutes) that we received from Kentucky to address a deficiency in the Kentucky program regarding reclamation bonds and to revise its program to be administered in a manner consistent with SMCRA and the Federal regulations.
This document gives the times and locations that this proposed amendment to the Kentucky program is 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 the proposed rules until 4:00 p.m., Eastern Standard Time (EST) April 27, 2015. If requested, we will hold a public hearing on April 20, 2015. We will accept requests to speak until 4:00 p.m., EST on April 10, 2015.
You may submit comments, identified by SATS No. KY-256-FOR and OSM Docket No. OSM-2012-0004, by any of the following methods:
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In addition, you may review a copy of the amendment during regular business hours at the following location: Mr. Steve Hohmann, Commissioner, Kentucky Department for Natural Resources, 2 Hudson Hollow, Frankfort, Kentucky 40601. Telephone: (502) 564-6940. Email:
Mr. Robert Evans, Office of Surface Mining Reclamation and Enforcement, Telephone: (859) 260-3900. Email:
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, “* * * 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 criteria, the Secretary of the Interior conditionally approved the Kentucky program on May 18, 1982. You can find background information on the Kentucky program, including the Secretary's findings, the disposition of comments, and conditions of approval, in the May 18, 1982,
Kentucky submitted information on three occasions in response to a Notice under 30 CFR part 733 that we sent to Kentucky on May 1, 2012 (Docket ID OSM-2012-0014) regarding deficiencies in its bonding program. These submissions are intended to address the noted deficiencies and were submitted as follows: September 28, 2012 (emergency and permanent administrative regulations), July 5, 2013 (House Bill (HB) 66 and emergency and permanent regulations), and December 3, 2013 (revised statutes and permanent regulations). Below is a summary of those submissions.
The first amendment submission included program changes intended to take immediate action involving the financial inadequacies of the bond program. These program changes are identified as either emergency Kentucky Administrative Regulations (KARs) or corresponding permanent (ordinary) KARs. Both the emergency and permanent regulations were signed by the Secretary, Energy and Environment Cabinet on May 4, 2012 and submitted to the Kentucky Legislative Research Commission (LRC) on that date. Kentucky recognizes emergency regulations as being valid for 180 days unless permanent regulations are approved and replace the emergency regulations.
Since Kentucky permanent regulations were approved on September 6, 2012, the emergency regulations expired and we will not be rendering a decision on the emergency regulations in this, or any future, rulemaking. Instead, we will issue a decision only on the permanent regulations. We are including only a brief summary of the emergency administrative regulations, along with a more detailed description in the corresponding permanent administrative regulations. Significant program changes that have been submitted for approval are highlighted below. Minor changes such as typographical corrections, cross-reference changes, and paragraph renumbering are not mentioned.
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We are not seeking comments on the emergency regulations at 10:011E and 10:015E as they have been replaced by 10:015. If you submitted comments on the emergency and permanent regulations noted above during the public comment period when we published the first submission (79 FR 11796) you do not need to resubmit them, we will be considering these comments in our analysis of the total submission.
On March 11, 2013, the General Assembly of the Commonwealth of Kentucky enacted HB No. 66 (HB 66), which addressed the deficiencies of the bonding program. This bill had an emergency clause (section 14) and therefore became effective upon signature of the Governor on March 22, 2013. On July 5, 2013, Kentucky submitted HB 66 and emergency and permanent regulations to OSMRE for approval.
Kentucky Revised Statutes (KRS), sections were submitted to OSMRE for approval in December 2013, along with final permanent regulations. We are including a summary of the KRS sections along with the corresponding HB sections even though the revised statutes were submitted with the third submission. This is being done since the HB and statutes are interrelated. The following summarizes the HB, revised statutes, and emergency and permanent regulations:
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In addition, this section also provides for the initial capitalization of the KRGF fund that consists of: (1) Transfer of the assets and liabilities of the voluntary bond pool fund; (2) a one-time start-up assessment for all current permittees as of July 1, 2013 in the amount of $1,500; and (3) a one-time $10 per active permitted acre assessment. Entities entering the fund after July 1, 2013 shall pay a one-time assessment of $10,000 to the fund. No individual permit shall be issued until the one-time assessments are paid. Members of the former voluntary bond pool are exempt from the one-time start-up assessment and active permitted acre assessment. If an applicant opts out and elects to provide a full-cost bond, the applicant shall not be subject to these assessments.
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The KRGF will continue to provide coverage for the existing bonds previously issued for them by the voluntary bond pool. It also provides the criteria that members of the voluntary bond pool as of July 1, 2013 must meet in order to be included in the Fund. This section also specifies a maximum increase for which the total amount of bonds issued to any one member of the voluntary bond pool will apply.
In addition, if an entity was not a participant in the Fund as of March 22, 2013, a permit may be considered for inclusion in the fund if the entity and entity's owners can meet eligibility standards established in permanent regulations promulgated by the RGFC. Any permits accepted into the fund shall require payment of a permit-specific performance bond based on acreage and shall pay the actuarially determined tonnage rates prescribed. The RGFC shall make changes to the rates in an amount sufficient to maintain actuarial soundness of the fund in accordance with the annual actuarial study.
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We note that it is our understanding that HB 66 was intended to also repeal 350.715, Pool administrator, and is consistent with the removal of all other sections involving the voluntary bond pool references. However, this section remains in effect and cannot be removed until the repeal is submitted for approval.
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The full text of the program amendment is available for you to read at the locations listed above under
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. As mentioned earlier, if you submitted comments on the first submission during the public comment period (79 FR 11796) you do not need to resubmit them, we will be considering these comments in our analysis of the total submission.
If you submit written or electronic comments on the proposed rule during the 30-day comment period, 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 a 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 there is only limited interest in having 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 rule is exempt 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.
Copyright Royalty Board, Library of Congress.
Proposed rule.
The Copyright Royalty Judges are publishing for comment proposed regulations governing the rates and terms for the digital performances of sound recordings by certain public radio stations and for the making of ephemeral recordings necessary to facilitate those transmissions for the period commencing January 1, 2016, and ending on December 31, 2020.
Comments and objections, if any, are due no later than April 16, 2015.
The proposed rule is posted on the agency's Web site (
Kimberly Whittle, Attorney Advisor, by telephone at (202) 707-7658, or by email at
On February 24, 2015, the Copyright Royalty Judges (Judges) received a joint
Section 114 of the Copyright Act, title 17 of the United States Code, provides a statutory license that allows for the public performance of sound recordings by means of a digital audio transmission by, among others, eligible nonsubscription transmission services. 17 U.S.C. 114(f). For purposes of the section 114 license, an “eligible nonsubscription transmission” is a noninteractive digital audio transmission that does not require a subscription for receiving the transmission. The transmission must also be made as part of a service that provides audio programming consisting in whole or in part of performances of sound recordings the purpose of which is to provide audio or other entertainment programming, but not to sell, advertise, or promote particular goods or services.
Services using the section 114 license may need to make one or more temporary or “ephemeral” copies of a sound recording in order to facilitate the transmission of that recording. The section 112 statutory license allows for the making of the necessary ephemeral reproductions. 17 U.S.C. 112(e).
Chapter 8 of the Copyright Act requires the Judges to conduct proceedings every five years to determine the rates and terms for the sections 114 and 112 statutory licenses. 17 U.S.C. 801(b)(1), 804(b)(3)(A). The current proceeding commenced in January 2014 for rates and terms that will become effective on January 1, 2016, and end on December 31, 2020. Pursuant to section 804(b)(3)(A), the Judges published in the
The Judges set the timetable for the three-month negotiation period for February 21, 2014, through May 22, 2014.
Section 801(b)(7)(A) allows for the adoption of rates and terms negotiated by “some or all of the participants in a proceeding at any time during the proceeding” provided the parties submit the negotiated rates and terms to the Judges for approval. That provision directs the Judges to provide those who would be bound by the negotiated rates and terms an opportunity to comment on the agreement. Unless a participant in a proceeding objects and the Judges conclude that the agreement does not provide a reasonable basis for setting statutory rates or terms, the Judges adopt the negotiated rates and terms. 17 U.S.C. 801(b)(7)(A).
If the Judges adopt the proposed rates and terms pursuant to this provision for the 2016-2020 rate period, the adopted rates and terms shall be binding on all copyright owners of sound recordings, NPR, American Public Media, Public Radio International, and Public Radio Exchange, and up to 530 public radio stations to be named by CPB that perform sound recordings during the license period 2016-2020.
In the proposed settlement, SoundExchange and the Settling Parties request that the Judges adopt the rates and terms for public radio as a new “Subpart D” to part 380, 37 CFR. Under the proposal, the parties would continue the rate structure in place for public radio, while increasing the fee amount. Joint Motion to Adopt Partial Settlement at 3. The proposal also contemplates retention of largely unchanged recordkeeping and reporting terms, by which affected entities take advantage of a consolidated report of usage prepared by and submitted through the Corporation for Public Broadcasting.
The public may comment and object to any or all of the proposed regulations contained in this notice. Such comments and objections must be submitted no later than April 16, 2015.
Interested members of the public must submit comments to only one of the following addresses. If not commenting by email or online, commenters must submit an original of their comments, five paper copies, and an electronic version on a CD.
Copyright, Sound recordings, Webcasters.
For the reasons set forth in the preamble, the Copyright Royalty Judges propose to amend 37 CFR part 380 as follows:
17 U.S.C. 112(e), 114(f), 804(b)(3).
(a)
(b)
(c)
For purposes of this subpart, the following definitions shall apply:
(1) Such Phonorecords are limited solely to those necessary to encode Sound Recordings in different formats and at different bit rates as necessary to facilitate Web site Performances covered by this subpart;
(2) Such Phonorecords are made in strict conformity with the provisions set forth in 17 U.S.C. 112(e)(1)(A) through (D), and
(3) The Covered Entities comply with 17 U.S.C. 112(a) and (e) and all of the terms and conditions of this Agreement.
(1) Is licensed as such by the Federal Communications Commission;
(2) Originates programming and is not solely a repeater station;
(3) Is a member or affiliate of NPR, American Public Media, Public Radio International, or Public Radio Exchange, a member of the National Federation of Community Broadcasters, or another public radio station that is qualified to receive funding from CPB pursuant to its criteria;
(4) Qualifies as a “noncommercial webcaster” under 17 U.S.C. 114(f)(5)(E)(i); and
(5) Either:
(i) Offers Web site Performances only as part of the mission that entitles it to be exempt from taxation under section 501 of the Internal Revenue Code of 1986 (26 U.S.C. 501); or
(ii) In the case of a governmental entity (including a Native American Tribal governmental entity), is operated exclusively for public purposes.
(i) The retransmission of a Covered Entity's over-the-air terrestrial radio programming; or
(ii) The digital transmission of nonsubscription Side Channels that are programmed and controlled by the Covered Entity.
(2) This term does not include digital audio transmissions made by any other means.
(a)
(b)
(1) An annual minimum fee of $500 for each Covered Entity for each year during the Term;
(2) Additional usage fees for certain Covered Entities; and
(3) A discount that reflects the administrative convenience to the Collective of receiving annual lump sum payments that cover a large number of separate entities, as well as the protection from bad debt that arises from being paid in advance.
(c)
(d)
(e)
(f)
(1) Obligate such third person to provide all such services in accordance with all applicable provisions of the statutory licenses and this subpart,
(2) Specify that such third person shall have no right to make Web site Performances or any other performances or Phonorecords on its own behalf or on behalf of any person or entity other than a Covered Entity through the Covered Entity's Authorized Web site by virtue of its services for the Covered Entity, including in the case of Phonorecords, pre-encoding or otherwise establishing a library of Sound Recordings that it offers to a Covered Entity or others for purposes of making performances, but instead must obtain all necessary licenses from the Collective, the copyright owner or another duly authorized person, as the case may be;
(3) Specify that such third person shall have no right to grant any sublicenses under the statutory licenses; and
(4) Provide that the Collective is an intended third-party beneficiary of all such obligations with the right to enforce a breach thereof against such third person.
(a)
(b)
(2) If SoundExchange, Inc. should dissolve or cease to be governed by a board consisting of equal numbers of representatives of Copyright Owners and Performers, then it shall be replaced by a successor Collective upon the fulfillment of the requirements set forth in paragraph (b)(2)(i) of this section.
(i) By a majority vote of the nine Copyright Owner representatives and the nine Performer representatives on the SoundExchange board as of the last day preceding the condition precedent in this paragraph (b)(2) of this section, such representatives shall file a petition with the Copyright Royalty Judges designating a successor to collect and distribute royalty payments to Copyright Owners and Performers entitled to receive royalties under 17 U.S.C. 112(e) or 114(g) that have themselves authorized the Collective.
(ii) The Copyright Royalty Judges shall publish in the
(c)
(d)
(e)
(2) If the Collective is unable to locate a Copyright Owner or Performer entitled to a distribution of royalties under paragraph (e)(1) of the section within 3 years from the date of payment by a Licensee, such royalties shall be handled in accordance with § 380.37.
(f)
(a)
(b)
(c)
(d)
(1) Those employees, agents, attorneys, consultants and independent contractors of the Collective, subject to an appropriate confidentiality agreement, who are engaged in the collection and distribution of royalty payments hereunder and activities related thereto, for the purpose of performing such duties during the ordinary course of their work and who require access to the Confidential Information;
(2) An independent and Qualified Auditor, subject to an appropriate confidentiality agreement, who is authorized to act on behalf of the Collective with respect to verification of a Licensee's statement of account pursuant to § 380.35 or on behalf of a Copyright Owner or Performer with respect to the verification of royalty distributions pursuant to § 380.36,
(3) Copyright Owners and Performers, including their designated agents, whose works have been used under the statutory licenses set forth in 17 U.S.C. 112(e) and 114 by the Licensee whose Confidential Information is being supplied, subject to an appropriate confidentiality agreement, and including those employees, agents, attorneys, consultants and independent contractors of such Copyright Owners and Performers and their designated agents, subject to an appropriate confidentiality agreement, for the purpose of performing their duties during the ordinary course of their work and who require access to the Confidential Information; and
(4) In connection with future proceedings under 17 U.S.C. 112(e) and 114 before the Copyright Royalty Judges, and under an appropriate protective order, attorneys, consultants and other authorized agents of the parties to the proceedings or the courts, subject to the provisions of any relevant agreements restricting the activities of CPB, Covered Entities or the Collective in such proceedings.
(e)
(a)
(b)
(c)
(d)
(e)
(f)
(a)
(b)
(c)
(d)
(e)
(f)
If the Collective is unable to identify or locate a Copyright Owner or Performer who is entitled to receive a royalty distribution under this subpart, the Collective shall retain the required payment in a segregated trust account for a period of 3 years from the date of distribution. No claim to such distribution shall be valid after the expiration of the 3-year period. After expiration of this period, the Collective may apply the unclaimed funds to offset any costs deductible under 17 U.S.C. 114(g)(3). The foregoing shall apply notwithstanding the common law or statutes of any State.
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing to approve elements of a State Implementation Plan (SIP) submission from the State of New Mexico addressing the applicable requirements of Clean Air Act (CAA) section 110 for the 2008 National Ambient Air Quality Standards (NAAQS) for Ozone (O
Written comments must be received on or before April 27, 2015.
Submit your comments, identified by Docket ID Number EPA-R06-OAR-2014-0270, by one of the following methods:
•
•
•
Ms. Sherry Fuerst, (214) 665-6454,
Throughout this document, whenever “we”, “us”, or “our” is used, we mean EPA.
EPA is proposing action on two SIP submissions from New Mexico that address the infrastructure requirements of CAA sections 110(a)(1) and (a)(2). The first action was submitted on August 27, 2013 for the 2008 O
One of the SIP requirements for new or revised NAAQS is to provide adequate provisions prohibiting emissions which interfere with required measures in any other State to protect visibility (CAA 110(a)(2)(D)(i)(II)). In a June 12, 2009 SIP submittal, New Mexico stated that they had satisfied the SIP requirements of CAA 110(a) for the PM
Additional information about EPA's review of the information New Mexico presented in these SIP submittals, how EPA reviews infrastructure SIPs and effects of recent Supreme Court decisions on these infrastructure SIPs can be found in the Technical Support Document, including Appendices A and B.
On March 27, 2008, EPA revised the primary and secondary O
On February 9, 2010, based on its review of the air quality criteria for oxides of nitrogen and the primary national ambient air quality standard (hereafter the 2010 NO
For both the 2008 O
On August 27, 2013 and March 12, 2014, the state of New Mexico sent a letter signed by the Cabinet Secretary of the New Mexico Environmental Department to EPA demonstrating how the existing New Mexico SIP met all the requirements for the 2008 O
EPA has an established procedure for reviewing infrastructure SIPs. A discussion of the CAA requirements and EPA's approach for reviewing infrastructure SIPs is outlined in Appendix A of the O
New Mexico's Environmental Improvement Act and Air Quality Control Act authorize the New Mexico Environment Department (NMED) to regulate air quality and implement air quality control regulations. Specifically, the New Mexico Air Quality Control Act delegates authority to the Environmental Improvement Board (EIB) to adopt, promulgate, publish, amend and repeal regulations consistent with the State's Air Quality Control Act to attain and maintain NAAQS and prevent or abate air pollution (NMSA 1978, Section 74-2-5(B)). The Air Quality Control Act also designates the NMED as the State's air pollution control agency, and the Environmental Improvement Act provides the NMED with enforcement authority. These statutes have been approved into the SIP (see 44 FR 21019, April 9, 1979; revised 49 FR 44101, November 2, 1984; re-codified and approved in 62 FR 50518, September 26, 1997).
NMED's air quality rules and standards are codified at Title 20 Environmental Protection, Chapter 2 Air Quality (Statewide) of NMAC. Numerous parts of the regulations codified into Chapter 2 necessary for implementing and enforcing the NAAQS have been adopted into the SIP. The approved SIP for New Mexico is documented at 40 CFR 52.1620, Subpart GG. The TSD for the action provides additional information on specific rules that have been adopted into the SIP.
Based upon review of the state's infrastructure SIP submissions for the 2008 O
To address this element, the Air Quality Act at NMSA 1978, section 74-2-5 provides the enabling authority necessary for the New Mexico EIB and NMED to fulfill the requirements of section 110(a)(2)(B). Along with their other duties, the NMED collects air monitoring data, quality-assures the results, and reports the data.
Historically, EPA has promulgated regulations in 40 CFR part 58 (Ambient Air Quality Surveillance), indicating the necessary data states need to collect and submit as part of their SIPs. Monitoring networks are designed to meet three basic criteria: (a) Provide timely results (b) provide results that verify compliance with the NAAQS and (c) to support research. For the 2008 O
The New Mexico statewide air quality surveillance network was approved into the New Mexico SIP by EPA on August 6, 1981 (46 FR 40005). Furthermore, New Mexico's air quality surveillance network undergoes recurrent annual review by EPA, as required by 40 CFR 58.10. On July 15, 2013, NMED submitted its 2013 Annual Air Monitoring Network Plan (AAMNP) that included ambient monitoring for the 2008 O
NMED makes ambient monitoring data available for public review on its Web site, as well as on national Web sites.
Based upon review of the state's infrastructure SIP submissions for the 2008 O
The Environmental Improvement Act, which has been approved into the SIP (49 FR 44101, 64 FR 29255), authorizes the creation of the Environmental Improvement Board (NMSA 1978, section 74-1-4); authorizes the EIB, the NMED, and its Secretary to file lawsuits, conduct investigations and enter into remediation agreements, enforce rules, regulations and orders promulgated by the EIB, and collect civil penalties (NMSA 1978, section 74-1-6); develop and enforce rules and standards related to protection of air quality (NMSA 1978, sections 74-1-7 and 74-1-8); and issue compliance orders and commence civil actions in response to violations (NMSA 1978, section 74-1-10).
Likewise, the Air Quality Control Act empowers the EIB and NMED to institute legal proceedings to compel compliance with the Air Quality Control Act and any regulations of the EIB or local air quality control agencies (NMSA 1978, section 74-2-5.1); issue compliance orders, commence civil actions, and issue field citations (NMSA 1978, section 74-2-12); assess civil penalties for violations of the Act or regulations promulgated under it or permits issued (NMSA 1978, section 74-2-12.1); conduct inspections of regulated entities (NMSA 1978, section 74-2-13); and pursue criminal prosecutions (NMSA 1978, section74-2-14). Additional enforcement authorities and funding mechanisms are provided by the Act at NMSA 1978, section 74-2-15. These sections of the Air Quality Control Act were adopted into the SIP on November 2, 1984 (49 FR 44101).
NMED air quality standards and regulations containing specific enforcement provisions and adopted into the SIP include: 20.2.7 NMAC
In this action, EPA is proposing to approve New Mexico's infrastructure SIPs for the 2008 O
PSD programs apply in areas that are meeting the NAAQS, referred to as areas in attainment, and in areas for which there is insufficient information to designate as either attainment or nonattainment, referred to as unclassifiable areas. New Mexico's PSD program was conditionally approved into the SIP on February 27, 1987 (52 FR 5964) and fully approved on August 15, 2011 (76 FR 41698). Revisions to New Mexico's PSD program were approved into the SIP on August 21, 1990 (55 FR 34013), May 2, 1991 (56 FR 20137), October 15, 1996 (61 FR 53639), March 10, 2003 (68 FR 11316), December 24, 2003 (68 FR 74483), September 5, 2007 (72 FR 50879), November 26, 2010 (75 FR 72688), July 20, 2011 (76 FR 43149), June 13, 2012 (75 FR 72688), January 22, 2013 (78 FR 4339), and March 11, 2013 (78 FR 15296). Additionally, on June 11, 2009 and May 23, 2011, New Mexico submitted modifications to revise the state's PSD and non-attainment new source review (NNSR) permitting regulations to address the permitting requirements associated with the NAAQS for 8-hour ozone and PM
Based upon review of the state's infrastructure SIP submissions for the 2008 O
With respect to prongs 1 and 2, New Mexico elected to not make a submittal, consistent with a court decision that was relevant at the time (
With respect to prong 3, as noted above, the New Mexico PSD program contains the necessary provisions to meet the prevention of significant deterioration element as required for both the standards and has been approved by EPA into the SIP.
With respect to prong 4, as noted previously, on November 27, 2012, we approved the New Mexico Regional Haze SIP except for the BART determination for SJGS. On October 9, 2014, we approved the BART determination for SJGS and found that the New Mexico SIP satisfies the requirements of CAA 110(a)(2)(D)(i)(II) with respect to interstate transport of air pollution and visibility protection.
Finally, § 110(a)(2)(D)(ii) regards the interstate pollution abatement requirements of section 126 and the international pollution requirements of section 115. As stated above in Section 110(a)(2)(C) of the Infrastructure SIP, New Mexico has a SIP-approved PSD program which includes provisions that satisfy the interstate pollution abatement requirements of section 126 of the CAA. Section 115 of the CAA authorizes EPA to require a state to revise its SIP under certain conditions to alleviate international transport into another country. There are no final findings under section 115 of the CAA with respect to any air pollutant generated in New Mexico. Therefore, New Mexico has no obligations under section 115. If there are future final findings under section 115 of the CAA, NMED will consult with EPA.
Based upon review of the state's infrastructure SIP submissions for the 2008 O
With respect to adequacy of authority, we have previously discussed New Mexico's statutory and regulatory authority to implement the 2008 O
With respect to adequacy of resources, NMED asserts that it has adequate personnel to implement the SIP. The infrastructure SIP submissions for the 2008 O
With respect to funding, the Air Quality Control Act NMSA 1978, section 74-2-7 requires NMED to establish an emissions fee schedule for sources in order to fund the reasonable costs of administering various air pollution control programs and also authorizes NMED to collect additional fees necessary to cover reasonable costs associated with processing of air permit applications. The Act provides for the deposit of the fees into various subaccounts (
With regard to the conflict of interest provisions of Section 128 of the Act, section 110(a)(2)(E)(ii) requires that each state SIP meet the requirements of section 128, relating to representation on state boards and conflicts of interest by members of such boards. Section 128(a)(1) requires that any board or body which approves permits or enforcement orders under the CAA must have at least a majority of members who represent the public interest and do not derive any “significant portion” of their income from persons subject to permits and enforcement orders under the CAA. Section 128(a)(2) requires that members of such a board or body, or the head of an agency with similar powers, adequately disclose any potential conflicts of interest.
The Environmental Improvement Act at NMSA 1978, section 74-1-4 provides that the Environmental Improvement Board contain at least a majority of members who represent the public interest and do not derive any significant portion of their income from persons subject to or who appear before the board on issues related to the Clean Air Act or Air Quality Control Act. Furthermore, pursuant to state regulations adopted by the Board, Board members are required to recuse themselves from rule-makings in which their impartiality may reasonably be questioned. (see 20.1.1.111 NMAC).
With respect to assurances that the State has responsibility to implement the SIP adequately when it authorizes local or other agencies to carry out portions of the plan, the Environmental Improvement Act and the Air Quality Control Act designate the NMED as the primary air pollution control agency “for all purposes” of implementing the requirements of the federal Clean Air Act and the New Mexico Air Quality Control Act.
There is one local air quality control agency that assumes jurisdiction for local administration and enforcement of Air Quality Control Act in New Mexico, the Albuquerque/Bernalillo County Air Quality Control Board, as authorized by the NMSA 1978, section 74-2-4. Pursuant to the New Mexico Air Quality Control Act, the local air quality control agency, within the boundaries of the Albuquerque/Bernalillo County area, is delegated all those functions delegated to the Environmental Improvement Board, with the exception of any functions reserved exclusively for the Environmental Improvement Board, NMSA 1978, section 74-2-4(A)(1). Further, The Air Quality Control Act, grants the local air quality control agency, within the boundaries of the Albuquerque/Bernalillo County are, the authority to perform all the duties required of NMED and exert all of the powers granted to NMED, except for those powers and duties reserved exclusively for the department, NMSA 1978, section 74-2-4(A)(2). However, the NMED and the state Environmental Improvement Board retain oversight authority in the event the local authority fails to act. EPA conducts reviews of the local program activities in conjunction with its oversight of the state program.
Based upon review of the state's infrastructure SIP submissions for the 2008 O
To address this element, the Air Quality Control Act at NMSA 1978, 74-2-5 authorizes the NMED to require persons engaged in operations which result in air pollution to monitor or test emissions and to file reports containing information relating to the nature and amount of emissions. State regulations pertaining to sampling and testing are codified at 20.2.72 NMAC
The NMED uses this information, in addition to information obtained from other sources, to track progress towards maintaining the NAAQS, developing control and maintenance strategies, identifying sources and general emission levels, and determining compliance with emission regulations and additional EPA requirements. NMED makes this information available to the public (20.2.5 NMAC
Based upon review of the state's infrastructure SIP submissions for the 2008 O
The Air Quality Control Act provides NMED with authority to address environmental emergencies, and NMED has contingency plans to implement emergency episode provisions in the SIP.
Upon a finding that any owner/operator is unreasonably affecting the public health, safety or welfare, or the health of animal or plant life, or property, the New Mexico Air Quality Control Act authorizes NMED to, after a reasonable attempt to give notice, declare a state of emergency and issue without hearing an emergency special order directing the owner/operator to cease such pollution immediately (NMSA 1978, § 74-7-10).
States also need to comply with the Prevention of Air Pollution Emergency Episode requirements of 40 CFR 51, Subpart H. New Mexico promulgated the “Air Pollution Episode Contingency Plan for New Mexico,” which includes contingency measures, and these provisions were approved into the SIP on August 21, 1990 (55 FR 34013). Under Subpart H, Priority III Regions are not required to have contingency plans. For ozone, Priority III Regions are those monitoring less than 195 μg/m
For NO
Based upon review of the state's infrastructure SIP submissions for the 2008 O
New Mexico's Environmental Improvement Act and Air Quality Control Act authorize the NMED as the primary agency in the state concerned with environmental protection and enforcement of regulations, including but not limited to air quality (see NMSA 1978, section 74-1 and NMSA 1978, section 74-2). The Air Quality Control Act gives the NMED the authority to “develop and present to the Environmental Improvement Board a plan for the control, regulation, prevention or abatement of air pollution . . .,” and authorizes the EIB to adopt such a plan (see NMSA 1978, section 74-2-5.1(H) and NMSA 1978, section 74-2-5(B)(2)). The Act also authorizes the New Mexico EIB to “adopt, promulgate, publish, amend and repeal regulations consistent with the Air Quality Control Act to attain and maintain the national ambient air quality standards and prevent and abate air pollution . . .” and the Environmental Improvement Act authorizes the NMED to enforce such rules, regulations and orders promulgated by the EIB (see NMSA 1978, section 74-2-5(B)(1) and NMSA 1978, section 74-1-6(F)). Furthermore, the Air Quality Control Act requires the NMED to, “. . . advise, consult, contract with and cooperate with local authorities, other states, the federal government and other interested persons or groups in regard to matters of common interest in the field of air quality control . . .” (see NMSA 1978, section 74-2-5.2(B)).
Thus, New Mexico has the authority to revise its SIP, as necessary, to account for revisions of the NAAQS, to adopt more effective methods of attaining the NAAQS, and to respond to EPA SIP calls. Based upon review of the state's infrastructure SIP submissions for the 2008 O
As noted earlier, EPA does not expect infrastructure SIP submissions to address subsection (I). The specific SIP submissions for designated nonattainment areas, as required under CAA title I, part D, are subject to different submission schedules than those for section 110 infrastructure elements. Instead, EPA will take action on part D attainment plan SIP submissions through a separate rulemaking process governed by the requirements for nonattainment areas, as described in part D. Additionally, New Mexico presently does not contain any non-attainment areas for O
(1) With respect to interagency consultation, the SIP should provide a process for consultation with general-purpose local governments, designated organizations of elected officials of local governments, and any Federal Land Manager having authority over Federal land to which the SIP applies. New Mexico's Air Quality Control Act provides that “no regulations or emission control requirement shall be adopted until after a public hearing by the environmental improvement board or the local board” and that, “at the hearing, the environmental improvement board or the local board shall allow all interested persons reasonable opportunity to submit data, views, or arguments orally or in writing and to examine witnesses testifying at the hearing” (see NMSA 1978, 74-2-6(B) and (D)). In addition, the Air Quality Control Act provides that the NMED shall have the power and duty to “advise, consult, contract with and cooperate with local authorities, other states, the federal government and other interested persons or groups in regard to matters of common interest in the field of air quality control . . .” (see 1978 74-2-5.2(B)). Furthermore, New Mexico's PSD rules at 20.2.74.400 NMAC mandate that the NMED shall provide for public participation and notification regarding permitting applications to any other state or local air pollution control agencies, local government officials of the city or county where the source will be located, tribal authorities, and FLMs whose lands may be affected by emissions from the source or modification. Additionally, the State's PSD rules at 20.2.74.403 NMAC require the NMED to consult with Federal Land Managers (FLMs) regarding permit applications for sources with the potential to impact Class I Federal Areas (75 FR 72688 and 72 FR 50879). Finally, the State of New Mexico has committed in the SIP to consult continually with the FLMs on the review and implementation of the visibility program, and the State recognizes the expertise of the FLMs in monitoring and new source review applicability analyses for visibility and has agreed to notify the FMLs of any advance notification or early consultation with a major new or modifying source prior to the submission of the permit application (71 FR 4490). The State's Transportation Conformity rules at 20.2.99.116 through 20.2.99.124 NMAC provide procedures for interagency consultation, resolution of conflicts, and public notification (65 FR 14873 and 75 FR 21169).
(2) With respect to the requirements for public notification in section 127 of the CAA, the infrastructure SIP should provide citations to regulations in the SIP requiring the air agency to regularly notify the public of instances or areas in which any NAAQS are exceeded; advise the public of the health hazard associated with such exceedances; and enhance public awareness of measures that can prevent such exceedances and of ways in which the public can participate in the regulatory and other efforts to improve air quality. Provisions regarding public notification of instances or areas in which any primary NAAQS was exceeded were approved into the New Mexico SIP on August 24, 1983 (48 FR 38466). In addition, as discussed for infrastructure element B above, the NMED air monitoring Web site provides live air quality data for each of the monitoring stations in New Mexico.
(3) Regarding the applicable requirements of part C of the CAA, relating to prevention of significant deterioration of air quality and visibility protection, as noted above under infrastructure element C, the New Mexico SIP meets the PSD requirements. With respect to the visibility component of section 110(a)(2)(J), EPA recognizes that states are subject to visibility and regional haze program requirements under part C of the CAA, which includes sections 169A and 169B. However, when EPA establishes or revises a NAAQS, these visibility and regional haze requirements under part C do not change. Therefore, EPA believes that there are no new visibility protection requirements under part C as a result of a revised NAAQS, and consequently there are no newly applicable visibility protection obligations pursuant to infrastructure element J after the promulgation of a new or revised NAAQS.
Based upon review of the state's infrastructure SIP submission for the 2008 O
(K) Air quality and modeling/data: The CAA Section 110(a)(2)(K) requires that SIPs provide for performing air quality modeling, as prescribed by EPA, to predict the effects on ambient air quality of any emissions of any NAAQS pollutant, and for submission of such data to EPA upon request.
The NMED has the power and duty, under the Air Quality Control Act to “develop facts and make investigations and studies,” thereby providing for the functions of environmental air quality assessment (see NMSA 1978, 74-2-5). Past modeling and emissions reductions measures have been submitted by the State and approved into the SIP. For example, the air modeling and control measures submitted within the attainment demonstration for the San Juan County Early Action Compact Area, approved by EPA and adopted into the SIP on August 17, 2005 (70 FR 48285). Additionally, New Mexico has the ability to perform modeling for the primary and secondary PM
This section of the CAA also requires that a SIP provide for the submission of data related to such air quality modeling to the EPA upon request. The New Mexico Air Quality Control Act authorizes and requires NMED to cooperate with the federal government and local authorities in regard to matters of common interest in the field of air quality control, thereby allowing the
Based upon review of the state's infrastructure SIP submissions for the 2008 O
The Air Quality Control Act provides the EIB with the legal authority for establishing an emission fee schedule and a construction permit fee schedule to recover the reasonable costs of acting on permit applications, implementing, and enforcing permits.
In addition to preconstruction fees, New Mexico also requires major sources subject to the federal Title V operating permit program to pay annual operating permit fees. This operating permit fee schedule is codified at 20.2.71 NMAC,
Based upon review of the state's infrastructure SIP submissions for the 2008 O
New Mexico's Air Quality Control Act provides that, “no regulations or emission control requirement shall be adopted until after a public hearing by the environmental improvement board or the local board” and provides that, “at the hearing, the environmental improvement board or the local board shall allow all interested persons reasonable opportunity to submit data, views, or arguments orally or in writing and to examine witnesses testifying at the hearing” (see NMSA 1978, 74-2-6(B) and (D)). In addition, the Air Quality Control Act provides that the NMED shall have the power and duty to “advise, consult, contract with and cooperate with local authorities, other states, the federal government and other interested persons or groups in regard to matters of common interest in the field of air quality control . . .” (see NMSA 1978, 74-2-5.2(B)). The Act also requires initiation of cooperative action between local authorities and the NMED, between one local authority and another, or among any combination of local authorities and the NMED for control of air pollution in areas having related air pollution problems that overlap the boundaries of political subdivisions; and entering into agreements and compacts with adjoining states and Indian tribes, where appropriate. NMED has a long history of successful cooperation with the local air quality authority in Albuquerque/Bernalillo County and tribal governments.
With regard to permitting actions, New Mexico's PSD regulations at 20.2.74.400 NMAC, approved into the SIP on March 30, 1987 (52 FR 5964) and December 16, 1996 (61 FR 53642), mandate that the NMED shall provide for public participation and notification regarding permitting applications to any other state or local air pollution control agencies, local government officials of the city or county where the source will be located, and Federal Land Managers whose lands may be affected by emissions from the source or modification. New Mexico's Transportation Conformity regulations at 20.2.99.116 and 20.2.99.124 NMAC, both approved into the SIP on April 23, 2010 (75 FR 21169), require that interagency consultation and opportunity for public involvement be provided before making transportation conformity determinations and before adopting applicable SIP revisions on transportation-related SIPs.
Based upon review of the state's infrastructure SIP submissions for the 2008 O
One of the SIP requirements for new or revised NAAQS is to provide adequate provisions prohibiting emissions which interfere with required measures in any other State to protect visibility (CAA 110(a)(2)(D)(i)(II)). In a June 12, 2009 SIP submittal, New Mexico stated that they had satisfied the SIP requirements of CAA 110(a) for the PM
EPA is proposing to approve the August 27, 2013 and March 12, 2014, infrastructure SIP submissions from New Mexico, which address the requirements of CAA sections 110(a)(1) and (2) as applicable to the 2008 O
We are also proposing to approve the visibility protection portion of the June 12, 2009 SIP submittal and find that the New Mexico Visibility SIP meets the CAA 110(a)(2)(D)(i)(II) requirement for the 2006 PM
In this action, we are proposing to include in a final rule regulatory text that includes incorporation by reference. In accordance with the requirements of 1 CFR 51.4, we are proposing to incorporate by reference revisions to the New Mexico SIP regulations as described in the Proposed Action section above. We have made, and will continue to make, these documents generally available electronically through
Under the Clean Air Act, the Administrator is required to approve a SIP submission that complies with the provisions of the Act 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 Clean Air Act. Accordingly, this action merely proposes to approve 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 FR3821, 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 proposed rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Interstate transport of pollution, Nitrogen dioxide, Ozone, Reporting and recordkeeping requirements, Visibility.
42 U.S.C. 7401
Environmental Protection Agency (EPA).
Proposed rule.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “the Act”), as amended, requires that the National Oil and Hazardous Substances Pollution Contingency Plan (“NCP”) include a list of national priorities among the known releases or threatened releases of hazardous substances, pollutants or contaminants throughout the United States. The National Priorities List (“NPL”) constitutes this list. The NPL is intended primarily to guide the Environmental Protection Agency (“EPA” or “the agency”) in determining which sites warrant further investigation. These further investigations will allow the EPA to assess the nature and extent of public health and environmental risks associated with the site and to determine what CERCLA-financed remedial action(s), if any, may be appropriate. This rule proposes to add six sites to the General Superfund section of the NPL.
Comments regarding any of these proposed listings must be submitted (postmarked) on or before May 26, 2015.
Identify the appropriate docket number from the table below.
Submit your comments, identified by the appropriate docket number, by one of the following methods:
•
•
•
•
Terry Jeng, phone: (703) 603-8852, email:
In 1980, Congress enacted the Comprehensive Environmental Response, Compensation, and Liability Act, 42 U.S.C. 9601-9675 (“CERCLA” or “the Act”), in response to the dangers of uncontrolled releases or threatened releases of hazardous substances, and releases or substantial threats of releases into the environment of any pollutant or contaminant that may present an imminent or substantial danger to the public health or welfare. CERCLA was amended on October 17, 1986, by the Superfund Amendments and Reauthorization Act (“SARA”), Public Law 99-499, 100 Stat. 1613
To implement CERCLA, the EPA promulgated the revised National Oil and Hazardous Substances Pollution
As required under section 105(a)(8)(A) of CERCLA, the NCP also includes “criteria for determining priorities among releases or threatened releases throughout the United States for the purpose of taking remedial action and, to the extent practicable taking into account the potential urgency of such action, for the purpose of taking removal action.” “Removal” actions are defined broadly and include a wide range of actions taken to study, clean up, prevent or otherwise address releases and threatened releases of hazardous substances, pollutants or contaminants (42 U.S.C. 9601(23)).
The NPL is a list of national priorities among the known or threatened releases of hazardous substances, pollutants or contaminants throughout the United States. The list, which is appendix B of the NCP (40 CFR part 300), was required under section 105(a)(8)(B) of CERCLA, as amended. Section 105(a)(8)(B) defines the NPL as a list of “releases” and the highest priority “facilities” and requires that the NPL be revised at least annually. The NPL is intended primarily to guide the EPA in determining which sites warrant further investigation to assess the nature and extent of public health and environmental risks associated with a release of hazardous substances, pollutants or contaminants. The NPL is only of limited significance, however, as it does not assign liability to any party or to the owner of any specific property. Also, placing a site on the NPL does not mean that any remedial or removal action necessarily need be taken.
For purposes of listing, the NPL includes two sections, one of sites that are generally evaluated and cleaned up by the EPA (the “General Superfund section”), and one of sites that are owned or operated by other federal agencies (the “Federal Facilities section”). With respect to sites in the Federal Facilities section, these sites are generally being addressed by other federal agencies. Under Executive Order 12580 (52 FR 2923, January 29, 1987) and CERCLA section 120, each federal agency is responsible for carrying out most response actions at facilities under its own jurisdiction, custody or control, although the EPA is responsible for preparing a Hazard Ranking System (“HRS”) score and determining whether the facility is placed on the NPL.
There are three mechanisms for placing sites on the NPL for possible remedial action (see 40 CFR 300.425(c) of the NCP): (1) A site may be included on the NPL if it scores sufficiently high on the HRS, which the EPA promulgated as appendix A of the NCP (40 CFR part 300). The HRS serves as a screening tool to evaluate the relative potential of uncontrolled hazardous substances, pollutants or contaminants to pose a threat to human health or the environment. On December 14, 1990 (55 FR 51532), the EPA promulgated revisions to the HRS partly in response to CERCLA section 105(c), added by SARA. The revised HRS evaluates four pathways: Ground water, surface water, soil exposure and air. As a matter of agency policy, those sites that score 28.50 or greater on the HRS are eligible for the NPL. (2) Each state may designate a single site as its top priority to be listed on the NPL, without any HRS score. This provision of CERCLA requires that, to the extent practicable, the NPL include one facility designated by each state as the greatest danger to public health, welfare or the environment among known facilities in the state. This mechanism for listing is set out in the NCP at 40 CFR 300.425(c)(2). (3) The third mechanism for listing, included in the NCP at 40 CFR 300.425(c)(3), allows certain sites to be listed without any HRS score, if all of the following conditions are met:
• The Agency for Toxic Substances and Disease Registry (ATSDR) of the U.S. Public Health Service has issued a health advisory that recommends dissociation of individuals from the release.
• The EPA determines that the release poses a significant threat to public health.
• The EPA anticipates that it will be more cost-effective to use its remedial authority than to use its removal authority to respond to the release.
The EPA promulgated an original NPL of 406 sites on September 8, 1983 (48 FR 40658) and generally has updated it at least annually.
A site may undergo remedial action financed by the Trust Fund established under CERCLA (commonly referred to as the “Superfund”) only after it is placed on the NPL, as provided in the NCP at 40 CFR 300.425(b)(1). (“Remedial actions” are those “consistent with permanent remedy, taken instead of or in addition to removal actions” (40 CFR 300.5). However, under 40 CFR 300.425(b)(2) placing a site on the NPL “does not imply that monies will be expended.” The EPA may pursue other appropriate authorities to respond to the releases, including enforcement action under CERCLA and other laws.
The NPL does not describe releases in precise geographical terms; it would be neither feasible nor consistent with the limited purpose of the NPL (to identify releases that are priorities for further evaluation), for it to do so. Indeed, the precise nature and extent of the site are typically not known at the time of listing.
Although a CERCLA “facility” is broadly defined to include any area where a hazardous substance has “come to be located” (CERCLA section 101(9)), the listing process itself is not intended to define or reflect the boundaries of such facilities or releases. Of course, HRS data (if the HRS is used to list a site) upon which the NPL placement was based will, to some extent, describe the release(s) at issue. That is, the NPL site would include all releases evaluated as part of that HRS analysis.
When a site is listed, the approach generally used to describe the relevant release(s) is to delineate a geographical area (usually the area within an installation or plant boundaries) and identify the site by reference to that area. However, the NPL site is not necessarily coextensive with the boundaries of the installation or plant, and the boundaries of the installation or plant are not necessarily the “boundaries” of the site. Rather, the site consists of all contaminated areas within the area used to identify the site, as well as any other location where that contamination has come to be located, or from where that contamination came.
In other words, while geographic terms are often used to designate the site (
The EPA regulations provide that the remedial investigation (“RI”) “is a process undertaken * * * to determine the nature and extent of the problem presented by the release” as more information is developed on site contamination, and which is generally performed in an interactive fashion with the feasibility Study (“FS”) (40 CFR 300.5). During the RI/FS process, the release may be found to be larger or smaller than was originally thought, as more is learned about the source(s) and the migration of the contamination. However, the HRS inquiry focuses on an evaluation of the threat posed and therefore the boundaries of the release need not be exactly defined. Moreover, it generally is impossible to discover the full extent of where the contamination “has come to be located” before all necessary studies and remedial work are completed at a site. Indeed, the known boundaries of the contamination can be expected to change over time. Thus, in most cases, it may be impossible to describe the boundaries of a release with absolute certainty.
Further, as noted above, NPL listing does not assign liability to any party or to the owner of any specific property. Thus, if a party does not believe it is liable for releases on discrete parcels of property, it can submit supporting information to the agency at any time after it receives notice it is a potentially responsible party.
For these reasons, the NPL need not be amended as further research reveals more information about the location of the contamination or release.
The EPA may delete sites from the NPL where no further response is appropriate under Superfund, as explained in the NCP at 40 CFR 300.425(e). This section also provides that the EPA shall consult with states on proposed deletions and shall consider whether any of the following criteria have been met:
(i) Responsible parties or other persons have implemented all appropriate response actions required;
(ii) All appropriate Superfund-financed response has been implemented and no further response action is required; or
(iii) The remedial investigation has shown the release poses no significant threat to public health or the environment, and taking of remedial measures is not appropriate.
In November 1995, the EPA initiated a policy to delete portions of NPL sites where cleanup is complete (60 FR 55465, November 1, 1995). Total site cleanup may take many years, while portions of the site may have been cleaned up and made available for productive use.
The EPA also has developed an NPL construction completion list (“CCL”) to simplify its system of categorizing sites and to better communicate the successful completion of cleanup activities (58 FR 12142, March 2, 1993). Inclusion of a site on the CCL has no legal significance.
Sites qualify for the CCL when: (1) Any necessary physical construction is complete, whether or not final cleanup levels or other requirements have been achieved; (2) the EPA has determined that the response action should be limited to measures that do not involve construction (
The Sitewide Ready for Anticipated Use measure (formerly called Sitewide Ready-for-Reuse) represents important Superfund accomplishments and the measure reflects the high priority the EPA places on considering anticipated future land use as part of the remedy selection process. See Guidance for Implementing the Sitewide Ready-for-Reuse Measure, May 24, 2006, OSWER 9365.0-36. This measure applies to final and deleted sites where construction is complete, all cleanup goals have been achieved, and all institutional or other controls are in place. The EPA has been successful on many occasions in carrying out remedial actions that ensure protectiveness of human health and the environment for current and future land uses, in a manner that allows contaminated properties to be restored to environmental and economic vitality. For further information, please go to
In order to maintain close coordination with states and tribes in the NPL listing decision process, the EPA's policy is to determine the position of the states and tribes regarding sites that the EPA is considering for listing. This consultation process is outlined in two memoranda that can be found at the following Web site:
A model letter and correspondence from this point forward between the EPA and states and tribes where applicable, is available on the EPA's Web site at
Yes, documents that form the basis for the EPA's evaluation and scoring of the sites in this proposed rule are contained in public dockets located both at the EPA Headquarters in Washington, DC, and in the regional offices. These documents are also available by electronic access at
You may view the documents, by appointment only, in the Headquarters or the regional dockets after the publication of this proposed rule. The hours of operation for the Headquarters
The following is the contact information for the EPA Headquarters Docket: Docket Coordinator, Headquarters, U.S. Environmental Protection Agency, CERCLA Docket Office, 1301 Constitution Avenue NW., William Jefferson Clinton Building West, Room 3334, Washington, DC 20004; 202/566-0276. (Please note this is a visiting address only. Mail comments to the EPA Headquarters as detailed at the beginning of this preamble.)
The contact information for the regional dockets is as follows:
• Holly Inglis, Region 1 (CT, ME, MA, NH, RI, VT), U.S. EPA, Superfund Records and Information Center, 5 Post Office Square, Suite 100, Boston, MA 02109-3912; 617/918-1413.
• Ildefonso Acosta, Region 2 (NJ, NY, PR, VI), U.S. EPA, 290 Broadway, New York, NY 10007-1866; 212/637-4344.
• Lorie Baker (ASRC), Region 3 (DE, DC, MD, PA, VA, WV), U.S. EPA, Library, 1650 Arch Street, Mailcode 3HS12, Philadelphia, PA 19103; 215/814-3355.
• Jennifer Wendel, Region 4 (AL, FL, GA, KY, MS, NC, SC, TN), U.S. EPA, 61 Forsyth Street SW., Mailcode 9T25, Atlanta, GA 30303; 404/562-8799.
• Todd Quesada, Region 5 (IL, IN, MI, MN, OH, WI), U.S. EPA Superfund Division Librarian/SFD Records Manager SRC-7J, Metcalfe Federal Building, 77 West Jackson Boulevard, Chicago, IL 60604; 312/886-4465.
• Brenda Cook, Region 6 (AR, LA, NM, OK, TX), U.S. EPA, 1445 Ross Avenue, Suite 1200, Mailcode 6SFTS, Dallas, TX 75202-2733; 214/665-7436.
• Preston Law, Region 7 (IA, KS, MO, NE), U.S. EPA, 11201 Renner Blvd., Mailcode SUPRERNB, Lenexa, KS 66219; 913/551-7097.
• Sabrina Forrest, Region 8 (CO, MT, ND, SD, UT, WY), U.S. EPA, 1595 Wynkoop Street, Mailcode 8EPR-B, Denver, CO 80202-1129; 303/312-6484.
• Sharon Murray, Region 9 (AZ, CA, HI, NV, AS, GU, MP), U.S. EPA, 75 Hawthorne Street, Mailcode SFD 6-1, San Francisco, CA 94105; 415/947-4250.
• Ken Marcy, Region 10 (AK, ID, OR, WA), U.S. EPA, 1200 6th Avenue, Mailcode ECL-112, Seattle, WA 98101; 206/463-1349.
You may also request copies from the EPA Headquarters or the regional dockets. An informal request, rather than a formal written request under the Freedom of Information Act, should be the ordinary procedure for obtaining copies of any of these documents. Please note that due to the difficulty of reproducing oversized maps, oversized maps may be viewed only in-person; since the EPA dockets are not equipped to either copy and mail out such maps or scan them and send them out electronically.
You may use the docket at
The Headquarters docket for this proposed rule contains the following for the sites proposed in this rule: HRS score sheets; documentation records describing the information used to compute the score; information for any sites affected by particular statutory requirements or the EPA listing policies; and a list of documents referenced in the documentation record.
The regional dockets for this proposed rule contain all of the information in the Headquarters docket plus the actual reference documents containing the data principally relied upon and cited by the EPA in calculating or evaluating the HRS score for the sites. These reference documents are available only in the regional dockets.
Comments must be submitted to the EPA Headquarters as detailed at the beginning of this preamble in the
The EPA considers all comments received during the comment period. Significant comments are typically addressed in a support document that the EPA will publish concurrently with the
Comments that include complex or voluminous reports, or materials prepared for purposes other than HRS scoring, should point out the specific information that the EPA should consider and how it affects individual HRS factor values or other listing criteria (
Generally, the EPA will not respond to late comments. The EPA can guarantee only that it will consider those comments postmarked by the close of the formal comment period. The EPA has a policy of generally not delaying a final listing decision solely to accommodate consideration of late comments.
During the comment period, comments are placed in the Headquarters docket and are available to the public on an “as received” basis. A complete set of comments will be available for viewing in the regional dockets approximately one week after the formal comment period closes.
All public comments, whether submitted electronically or in paper form, will be made available for public viewing in the electronic public docket at
In certain instances, interested parties have written to the EPA concerning sites that were not at that time proposed to the NPL. If those sites are later proposed to the NPL, parties should review their earlier concerns and, if still appropriate, resubmit those concerns for consideration during the formal comment period. Site-specific correspondence received prior to the period of formal proposal and comment will not generally be included in the docket.
In this proposed rule, the EPA is proposing to add six sites to the NPL, all to the General Superfund section. All of the sites in this proposed rulemaking are being proposed based on HRS scores of 28.50 or above.
The sites are presented in the table below.
Additional information about these statutes and Executive Orders can be found at
This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review.
This action does not impose an information collection burden under the PRA. This rule does not contain any information collection requirements that require approval of the OMB.
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities. This rule listing sites on the NPL does not impose any obligations on any group, including small entities. This rule also does not establish standards or requirements that any small entity must meet, and imposes no direct costs on any small entity. Whether an entity, small or otherwise, is liable for response costs for a release of hazardous substances depends on whether that entity is liable under CERCLA 107(a). Any such liability exists regardless of whether the site is listed on the NPL through this rulemaking.
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. This action imposes no enforceable duty on any state, local or tribal governments or the private sector. Listing a site on the NPL does not itself impose any costs. Listing does not mean that the EPA necessarily will undertake remedial action. Nor does listing require any action by a private party, state, local or tribal governments or determine liability for response costs. Costs that arise out of site responses result from future site-specific decisions regarding what actions to take, not directly from the act of placing a site on the NPL.
This rule does not have federalism implications. It will not have substantial direct effects 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.
This action does not have tribal implications as specified in Executive Order 13175. Listing a site on the NPL does not impose any costs on a tribe or require a tribe to take remedial action. Thus, Executive Order 13175 does not apply to this action.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the 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 this action itself is procedural in nature (adds sites to a list) and does not, in and of itself, provide protection from environmental health and safety risks. Separate future regulatory actions are required for mitigation of environmental health and safety risks.
This action is not subject to Executive Order 13211, because it is not a significant regulatory action under Executive Order 12866.
This rulemaking does not involve technical standards.
The EPA believes the human health or environmental risk addressed by this action will not have potential disproportionately high and adverse human health or environmental effects on minority, low-income or indigenous populations because it does not affect the level of protection provided to human health or the environment. As discussed in Section I.C. of the preamble to this action, the NPL is a list of national priorities. The NPL is intended primarily to guide the EPA in determining which sites warrant further investigation to assess the nature and extent of public health and environmental risks associated with a release of hazardous substances, pollutants or contaminants. The NPL is of only limited significance as it does not assign liability to any party. Also, placing a site on the NPL does not mean that any remedial or removal action necessarily need be taken.
Environmental protection, Air pollution control, Chemicals, Hazardous substances, Hazardous waste, Intergovernmental relations, Natural resources, Oil pollution, Penalties,
42 U.S.C. 9601-9657; 33 U.S.C. 1321(d); E.O. 11735, 38 FR 21243; E.O. 12580, 52 FR 2923; E.O. 12777, 56 FR 54757.
and
and
Pursuant to Section 766.24 of the Export Administration Regulations (the “Regulations” or “EAR”),
Pursuant to Section 766.24, BIS may issue an order temporarily denying a respondent's export privileges upon a showing that the order is necessary in the public interest to prevent an “imminent violation” of the Regulations. 15 CFR 766.24(b)(1) and 776.24(d). “A violation may be `imminent' either in time or degree of likelihood.” 15 CFR 766.24(b)(3). BIS may show “either that a violation is about to occur, or that the general circumstances of the matter under investigation or case under criminal or administrative charges demonstrate a likelihood of future violations.”
In its request, OEE has presented evidence that it has reason to believe that Trident engaged in conduct prohibited by the Regulations by exporting items subject to the EAR to Russia via transshipment through third countries. In Automated Export System (“AES”) filings it made, Trident identified as “ultimate consignees” companies in Estonia and Finland that BIS has reason to believe were operating as freight forwarders and not end users of the U.S.-origin items. OEE's presentation also indicates that at least two of these transactions are known to have involved items that are listed on the Commerce Control List and that a search of BIS's licensing database reveals no licensing history of controlled U.S.-origin electronics to Russia for the company and individuals captioned in this case. Based on,
On or about April 6, 2013, the U.S. Customs and Border Protection (“CBP”) detained two outbound shipments at San Francisco International Airport. CBP ultimately allowed one of these exports to proceed, but the other attempted export was not and the items were ultimately seized. The manifest and the AES filing for the seized shipment described the items as “power supplies,” but the shipment actually contained, among other items, 15 Xilinx field programmable gate array (FPGA) circuits that were controlled under Export Control Classification Number (ECCN) 3A001.a.2.c for national security reasons and generally required a license for Russia. The shipping documentation also listed Logilane Oy Ltd. in Finland (“Logilane”) as the ultimate consignee. Open source information confirmed that Logilane was a freight forwarder and thus unlikely to be the end user for the items contained in the shipment. When questioned about the shipment, Pavel Flider requested that the ultimate consignee be changed to Adimir OU (“Adimir”) in Estonia, which itself also proved to be a freight forwarder as discussed further below.
On or about April 19, 2013, OEE interviewed Trident office manager Gennadiy Flider, who identified his responsibilities as handling the procurement and shipment of items, including for export. He stated Trident had been doing business with Adimir for many years and that it was the only customer that his company had. He also indicated that Trident at times shipped
Similarly, in an August 5, 2013 interview, Trident's president and owner Pavel Flider stated that Adimir was Trident's one and only customer and that at times Adimir requested that items be shipped to a freight forwarder in Finland. Both Gennadiy Flider and Pavel Flider denied shipping to Russia.
On or about July 20, 2013, the U.S. Government detained a Trident shipment bound for Adimir in Estonia. In addition to Adimir being identified as the ultimate consignee on the AES filing, the items were identified as “Electronic Equipment.” A review of the invoice showed six Xilinx FPGAs, items which were controlled under ECCN 3A001.a.2.c for national security reasons and generally required a license for Russia. Moreover, an inspection of the shipment uncovered 51 controlled Xilinx chips, rather than just the six that had been declared. CBP ultimately seized the shipment on or about October 18, 2013.
Based on information obtained in 2014 via a late 2013 MLAT request sent to Estonia relating to Adimir, BIS has reason to believe that Adimir was not an end user. During an interview, an Adimir corporate officer admitted to transshipping Trident shipments to Russia at the request of Pavel Flider. Adimir subsequently ceased operating.
Following the detention and seizures, the MLAT request, and the Adimir interview, Trident began exporting directly to Russia, claiming that the controlled circuits were for use in railroads. This assertion sought to track a note to ECCN 3A001.a.2, which indicates that the ECCN does not apply to integrated circuits for civil automotive or railway train applications. Pavel Flider reported to the U.S. distributor that Trident had been “referred” Russian customers by Adimir, which was going out of business. After being made aware that the items actually were intended for export to Russia, the U.S. distributor requested that Trident sign a Form BIS-711 “Statement by Ultimate Consignee and Purchaser,” which includes an end use statement and must be signed by the purchaser and the ultimate consignee.
From on or about January 23, 2014, to on or about April 16, 2014, Trident began listing in its AES filings OOO Elkomtex (“Elkomtex”) in St. Petersburg, Russia, as the ultimate consignee. On or about July 17, 2014, the Elkomtex employees admitted that the company was not an end user but a distributor of electronics, acting as a broker between an exporter and an end use company.
Beginning with an export on or about May 6, 2014, Trident again changed its export route and began exporting to a purported ultimate consignee named Logimix Ltd., in Vantaa, Finland (“Logimix”). Between on or about May 6, 2014, to on or about March 12, 2015, AES filings indicate that Trident has made 33 exports with Logimix listed as the ultimate consignee. Based on Logimix's Web site and other open source Internet information, however, OEE's presentation indicates that it has reason to believe that Logimix is a freight forwarder and not an end user. Moreover, given the violations, deceptive actions, and other evidence involving Trident, including those admitted by the Fliders, OEE also indicates that it has reason to believe that Trident has been making transshipments to Russia.
OEE has further indicated that in February 2014, Trident ordered an additional 195 integrated circuits controlled under ECCN 3A001.a.2.c from a U.S. distributor and that those items would be available by in or around April 2015. In addition, Trident and Pavel and Gennadiy Flider have been indicted for smuggling and money laundering, including in connection with some of the transactions discussed above.
I find that the evidence presented by BIS demonstrates that a violation of the Regulations is imminent in both time and degree of likelihood. Trident has engaged in some known violations of the Regulations and its actions, including changes in how it structures its export transactions and routes its shipments, appear designed to camouflage the actual destinations, end uses, and/or end users of the U.S.-origin items it has been and continues to export, including items on the Commerce Control List that are subject to national security-based license requirements. Moreover, when interviewed in 2013, the Fliders could not provide a reasonable explanation for the purported exports to Estonia and Finland. When for a time Trident began direct exports to Russia, the entity listed as the ultimate consignee admitted that it was not an end user and instead acting as a broker.
In sum, the fact and circumstances taken as a whole provide strong indicators that future violations are likely absent the issuance of a TDO. As such, a TDO is needed to give notice to persons and companies in the United States and abroad that they should cease dealing with Trident in export transactions involving items subject to the EAR. Such a TDO is consistent with the public interest to preclude future violations of the EAR.
Additionally, Section 766.23 of the Regulations provides that “[i]n order to prevent evasion, certain types of orders under this part may be made applicable not only to the respondent, but also to other persons then or thereafter related to the respondent by ownership, control, position of responsibility, affiliation, or other connection in the conduct of trade or business. Orders that may be made applicable to related persons include those that deny or affect export privileges, including temporary denial orders . . .” 15 CFR § 766.23(a). As stated above, Pavel Flider is the president and owner of Trident. Gennadiy Flider also is a Trident office manager, with responsibilities relating directly to the procurement and export activities at issue. As such, I find that Pavel Semenovich Flider and Gennadiy Semenovich Flider are related persons to Trident based on their positions of responsibility and that their additions to the order is necessary to prevent evasion.
Accordingly, I find that an order denying the export privileges of Trident, Pavel Flider, and Gennadiy Flider is necessary, in the public interest, to prevent an imminent violation of the EAR.
This Order is being issued on an
A. Applying for, obtaining, or using any license, License Exception, or export control document;
B. Carrying on negotiations concerning, or ordering, buying, receiving, using, selling, delivering, storing, disposing of, forwarding, transporting, financing, or otherwise servicing in any way, any transaction involving any item exported or to be exported from the United States that is subject to the EAR, or in any other activity subject to the EAR; or
C. Benefitting in any way from any transaction involving any item exported or to be exported from the United States that is subject to the EAR, or in any other activity subject to the EAR.
A. Export or reexport to or on behalf of a Denied Person any item subject to the EAR;
B. Take any action that facilitates the acquisition or attempted acquisition by a Denied Person of the ownership, possession, or control of any item subject to the EAR that has been or will be exported from the United States, including financing or other support activities related to a transaction whereby a Denied Person acquires or attempts to acquire such ownership, possession or control;
C. Take any action to acquire from or to facilitate the acquisition or attempted acquisition from a Denied Person of any item subject to the EAR that has been exported from the United States;
D. Obtain from a Denied Person in the United States any item subject to the EAR with knowledge or reason to know that the item will be, or is intended to be, exported from the United States; or
E. Engage in any transaction to service any item subject to the EAR that has been or will be exported from the United States and which is owned, possessed or controlled by a Denied Person, or service any item, of whatever origin, that is owned, possessed or controlled by a Denied Person if such service involves the use of any item subject to the EAR that has been or will be exported from the United States. For purposes of this paragraph, servicing means installation, maintenance, repair, modification or testing.
In accordance with the provisions of Section 766.24(e) of the EAR, Flider Electronics, LLC d/b/a Trident International Corporation, may, at any time, appeal this Order by filing a full written statement in support of the appeal with the Office of the Administrative Law Judge, U.S. Coast Guard ALJ Docketing Center, 40 South Gay Street, Baltimore, Maryland 21202-4022. In accordance with the provisions of Sections 766.23(c)(2) and 766.24(e)(3) of the EAR, Pavel Semenovich Flider and Gennadiy Semenovich Flider may, at any time, appeal their inclusion as a related person by filing a full written statement in support of the appeal with the Office of the Administrative Law Judge, U.S. Coast Guard ALJ Docketing Center, 40 South Gay Street, Baltimore, Maryland 21202-4022.
In accordance with the provisions of Section 766.24(d) of the EAR, BIS may seek renewal of this Order by filing a written request not later than 20 days before the expiration date. Flider Electronics, LLC d/b/a Trident International Corporation may oppose a request to renew this Order by filing a written submission with the Assistant Secretary for Export Enforcement, which must be received not later than seven days before the expiration date of the Order.
A copy of this Order shall be sent to Flider Electronics LLC d/b/a Trident International Corporation and each related person, and shall be published in the
This Order is effective upon issuance and shall remain in effect for 180 days.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Joshua Morris or Shane Subler, AD/CVD Operations, Office I, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-1779 or (202) 482-0189, respectively.
On February 26, 2015, the Department of Commerce (the Department) received a countervailing duty (CVD) petition
On March 3 and 13, 2015, we requested information and clarification for certain areas of the Petition.
In accordance with section 702(b)(1) of the Tariff Act of 1930, as amended (the Act), the petitioner alleges that the Government of Canada (the GOC) and certain Canadian provinces are providing countervailable subsidies, within the meaning of sections 701 and 771(5) of the Act, to imports of SC paper from Canada, and that such imports are materially injuring, or are threatening material injury to, the domestic industry in the United States pursuant to section 701 of the Act. Consistent with section 702(b)(1) of the Act, the Petition is accompanied by information reasonably available to petitioner supporting its allegations.
The Department finds that the petitioner filed the Petition on behalf of the domestic industry because the petitioner is an interested party as defined in section 771(9)(F) of the Act, and that the petitioner has demonstrated
The period for which we are measuring subsidies,
The product covered by this investigation is SC paper from Canada. For a full description of the scope of this investigation,
During our review of the Petition, we issued questions to, and received responses from, the petitioner pertaining to the proposed scope to ensure that the scope language in the Petition would be an accurate reflection of the products for which the domestic industry is seeking relief.
As discussed in the preamble to our regulations,
We request that any factual information the parties consider relevant to the scope of the investigation be submitted during this time period. However, if a party subsequently finds that additional factual information pertaining to the scope of the investigation may be relevant, the party may contact the Department and request permission to submit the additional information.
All submissions to the Department must be filed electronically using the Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS).
Pursuant to section 702(b)(4)(A)(i) of the Act, we notified the GOC of the receipt of the Petition. Also, in accordance with section 702(b)(4)(A)(ii) of the Act, we invited representatives of the GOC for consultations with respect to the Petition.
Section 702(b)(1) of the Act requires that a petition be filed on behalf of the domestic industry. Section 702(c)(4)(A) of the Act provides that a petition meets this requirement if the domestic producers or workers who support the petition account for: (i) At least 25 percent of the total production of the domestic like product; and (ii) more than 50 percent of the production of the domestic like product produced by that portion of the industry expressing support for, or opposition to, the petition. Moreover, section 702(c)(4)(D) of the Act provides that, if the petition does not establish support of domestic producers or workers accounting for more than 50 percent of the total production of the domestic like product, the Department shall: (i) Poll the industry or rely on other information in order to determine if there is support for the petition, as required by subparagraph (A); or (ii) determine industry support using a statistically valid sampling method to poll the industry.
Section 771(4)(A) of the Act defines the “industry” as the producers as a whole of a domestic like product, or those producers whose collective output of a domestic like product constitutes a major proportion of the total domestic production of the product. Thus, to determine whether a petition has the requisite industry support, the statute directs the Department to look to producers and workers who produce the domestic like product. The International Trade Commission (ITC), which is responsible for determining whether “the domestic industry” has been injured, must also determine what constitutes a domestic like product in order to define the industry. While both the Department and the ITC must apply the same statutory definition regarding the domestic like product,
Section 771(10) of the Act defines the domestic like product as “a product which is like, or in the absence of like, most similar in characteristics and uses with, the article subject to an investigation under this title.” Thus, the reference point from which the domestic like product analysis begins is “the article subject to an investigation” (
With regard to the domestic like product, the petitioner does not offer a definition of the domestic like product distinct from the scope of the investigation. Based on our analysis of the information submitted on the record, we have determined that SC paper constitutes a single domestic like product and we have analyzed industry support in terms of that domestic like product.
In determining whether the petitioner has standing under section 702(c)(4)(A) of the Act, we considered the industry support data contained in the Petition with reference to the domestic like product as defined in the “Scope of the Investigation,” in Appendix I of this notice. To establish industry support, the petitioner provided its own production of the domestic like product in 2014.
Based on the data provided in the Petition, Petition Supplement, and other information readily available to the Department, we determine that the petitioner has established industry support.
The Department finds that the petitioner filed the Petition on behalf of the domestic industry because it is an interested party as defined in section 771(9)(F) of the Act and it has demonstrated sufficient industry support with respect to the CVD investigation that it is requesting the Department initiate.
Because Canada is a “Subsidies Agreement Country” within the meaning of section 701(b) of the Act, section 701(a)(2) of the Act applies to this investigation. Accordingly, the ITC must determine whether imports of the subject merchandise from Canada materially injure, or threaten material injury to, a U.S. industry.
The petitioner alleges that imports of the subject merchandise are benefitting from countervailable subsidies and that such imports are causing, or threaten to cause, material injury to the U.S. industry producing the domestic like product. The petitioner alleges that subject imports exceed the negligibility threshold provided for under section 771(24)(A) of the Act.
The petitioner contends that the industry's injured condition is illustrated by reduced market share, underselling and price suppression or depression, lost sales and revenues, and other adverse impacts on the domestic industry, including declining capacity utilization rates and shipments, declining employment variables, and decline in domestic industry performance.
Section 702(b)(1) of the Act requires the Department to initiate a CVD investigation whenever an interested party files a CVD petition on behalf of an industry that: (1) Alleges the elements necessary for an imposition of a duty under section 701(a) of the Act; and (2) is accompanied by information reasonably available to the petitioner supporting the allegations. In the Petition, the petitioner alleges that producers of SC paper in Canada benefited from countervailable subsidies bestowed by the GOC and certain Canadian provincial governments. We have examined the Petition and find that it complies with the requirements of section 702(b)(1) of the Act. Therefore, in accordance with section 702(b)(1) of the Act, we are initiating a CVD investigation to determine whether manufacturers, producers, or exporters of SC Paper from Canada receive countervailable subsidies from the GOC and the certain Canadian provincial governments.
Based on our review of the Petition, we find that there is sufficient information to initiate a CVD investigation of 28 of the 29 alleged programs. For a full discussion of the basis for our decision to initiate or not to initiate on each program,
The petitioner named four companies as producers/exporters of SC paper from Canada.
In accordance with section 702(b)(4)(A)(i) of the Act and 19 CFR 351.202(f), a copy of the public version of the Petition has been provided to representatives of the GOC
We have notified the ITC of our initiation, as required by section 702(d) of the Act.
The ITC will preliminarily determine, within 45 days after the date on which the Petition was filed, whether there is a reasonable indication that imports of SC paper from Canada are materially injuring, or threatening material injury to, a U.S. industry.
Factual information is defined in 19 CFR 351.102(b)(21) as: (i) Evidence submitted in response to questionnaires;
Parties may request an extension of time limits before the expiration of a time limit established under Part 351, or as otherwise specified by the Secretary. In general, an extension request will be considered untimely if it is filed after the expiration of the time limit established under Part. For submissions that are due from multiple parties simultaneously, an extension request will be considered untimely if it is filed after 10:00 a.m. on the due date. Under certain circumstances, we may elect to specify a different time limit by which extension requests will be considered untimely for submissions which are due from multiple parties simultaneously. In such a case, we will inform parties in the letter or memorandum setting forth the deadline (including a specified time) by which extension requests must be filed to be considered timely. An extension request must be made in a separate, stand-alone submission; under limited circumstances we will grant untimely-filed requests for the extension of time limits. Review
Any party submitting factual information in an AD or CVD proceeding must certify to the accuracy and completeness of that information.
Interested parties must submit applications for disclosure under APO in accordance with 19 CFR 351.305. On January 22, 2008, we published
This notice is issued and published pursuant to sections 702 and 777(i) of the Act.
The merchandise covered by this investigation is supercalendered paper (SC paper). SC paper is uncoated paper that has undergone a calendering process in which the base sheet, made of pulp and filler (typically, but not limited to, clay, talc, or other mineral additive), is processed through a set of supercalenders, a supercalender, or a soft nip calender operation.
The scope of this investigation covers all SC paper regardless of basis weight, brightness, opacity, smoothness, or grade, and whether in rolls or in sheets. Further, the scope covers all SC paper that meets the scope definition regardless of the type of pulp fiber or filler material used to produce the paper.
Specifically excluded from the scope are imports of paper printed with final content of printed text or graphics.
Subject merchandise primarily enters under Harmonized Tariff Schedule of the United States (HTSUS) subheading 4802.61.3035, but may also enter under subheadings 4802.61.3010, 4802.62.3000, 4802.62.6020, and 4802.69.3000. Although the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of the investigation is dispositive.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; availability of NMFS evaluation of joint state/tribal hatchery plans and request for comment.
Notice is hereby given that the Washington Department of Fish and Wildlife (WDFW), with the Jamestown S'Klallam Tribe, the Lummi Nation, the Nooksack Tribe, the Stillaguamish Tribes, and the Tulalip Tribes as the
This notice further advises the public of the availability for review of a draft Environmental Assessment of the effects of the NMFS determination on the subject joint plans.
Comments must be received at the appropriate address or email mailbox (see
Written comments on the proposed evaluation and pending determination should be addressed to the NMFS Sustainable Fisheries
Tim Tynan at (360) 753-9579 or email:
Steelhead (
Chinook salmon (
Chum salmon (
Bull trout (
The WDFW, with the Jamestown S'Klallam Tribe, the Lummi Nation, the Nooksack Tribe, the Stillaguamish Tribes, and the Tulalip Tribes as the
As required by the ESA 4(d) rule (65 FR 42422, July 10, 2000, as updated in 70 FR 37160, June 28, 2005), the Secretary is seeking public comment on her pending determination as to whether the joint plans for early winter steelhead hatchery programs in the Dungeness River, Nooksack River, and Stillaguamish River would appreciably reduce the likelihood of survival and recovery of ESA-listed Puget Sound steelhead and Puget Sound salmon.
Under section 4(d) of the ESA, the Secretary is required to adopt such regulations as she deems necessary and advisable for the conservation of species listed as threatened. NMFS has issued a final ESA 4(d) Rule for salmon and steelhead, adopting in Limit 6 regulations necessary and advisable to harmonize statutory conservation requirements with tribal rights and the Federal trust responsibility to tribes (50 CFR 223.209).
This 4(d) Rule applies the prohibitions enumerated in section 9(a)(1) of the ESA. NMFS did not find it necessary and advisable to apply the take prohibitions described in section 9(a)(1)(B) and 9(a)(1)(C) to artificial propagation activities if those activities are managed in accordance with a joint plan whose implementation has been determined by the Secretary to not appreciably reduce the likelihood of survival and recovery of the listed salmonids. As specified in limit 6 of the 4(d) Rule, before the Secretary makes a decision on the joint plan, the public must have an opportunity to review and comment on the pending determination.
Under section 4 of the ESA, the Secretary of Commerce is required to adopt such regulations as she deems necessary and advisable for the conservation of species listed as threatened. The ESA salmon and steelhead 4(d) rule (65 FR 42422, July 10, 2000, as updated in 70 FR 37160, June 28, 2005) specifies categories of activities that contribute to the conservation of listed salmonids and sets out the criteria for such activities. Limit 6 of the updated 4(d) rule (50 CFR 223.203(b)(6)) further provides that the prohibitions of paragraph (a) of the updated 4(d) rule (50 CFR 223.203(a)) do not apply to activities associated with a joint state/tribal artificial propagation plan provided that the joint plan has been determined by NMFS to be in accordance with the salmon and steelhead 4(d) rule (65 FR 42422, July 10, 2000, as updated in 70 FR 37160, June 28, 2005).
We also apply this notice in accordance with the requirements of NEPA as amended (42 U.S.C. 4371
Bureau of Economic Analysis, Commerce.
Notice of reporting requirements.
By this Notice, the Bureau of Economic Analysis (BEA), Department of Commerce, is informing the public that it is conducting the mandatory survey titled Quarterly Survey of Insurance Transactions by U.S. Insurance Companies with Foreign Persons (BE-45). This survey is authorized by the International Investment and Trade in Services Survey Act.
This Notice constitutes legal notification to all United States persons (defined below) who meet the reporting requirements set forth in this Notice that they must respond to, and comply with, the survey. Reports are due 60 days after the end of the U.S. person's fiscal quarter, except for the final quarter of the U.S. person's fiscal year when reports must be filed within 90 days. This notice is being issued in conformance with the rule BEA issued in 2012 (77 FR 24373) establishing guidelines for collecting data on international trade in services and direct investment through notices, rather than through rulemaking. Additional information about BEA's collection of data on international trade in services and direct investment can be found in the 2012 rule, the International Investment and Trade in Services Survey Act (22 U.S.C. 3101
(a)
(b)
(c)
(d)
(b) Entities required to report will be contacted individually by BEA. Entities not contacted by BEA have no reporting responsibilities.
This data collection has been approved by the Office of Management and Budget (OMB) in accordance with the Paperwork Reduction Act and assigned control number 0608-0066. 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 OMB. Public reporting burden for this collection of information is estimated to average 8 hours per response. Send comments regarding this burden estimate to Director, Bureau of Economic Analysis (BE-1), U.S. Department of Commerce, Washington, DC 20230; and to the Office of Management and Budget, Paperwork Reduction Project 0608-0066, Washington, DC 20503.
22 U.S.C. 3101-3108.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of withdrawal.
NMFS is announcing the withdrawal of a draft Environmental Impact Statement (EIS) that was being prepared on two resource management plans (RMPs) and 114 supporting hatchery and genetic management plans (HGMPs) for Puget Sound hatchery programs. The plans were submitted to NMFS by the Washington Department of Fish and Wildlife and the Puget Sound treaty tribes (referred to as the co-managers) for evaluation under the Endangered Species Act (ESA) for threatened Puget Sound Chinook salmon and Puget Sound steelhead. Subsequent to the notice of intent to prepare an EIS in 2004, the co-managers have made important changes in hatchery programs for salmon and steelhead. Changes in the programs and updated information important for analysis are being reflected in revised joint RMPs that are generally organized on a watershed-specific basis. In light of this and the ongoing submissions of revised watershed-specific joint hatchery RMPs and considering public comments received on the draft EIS, NMFS has determined that it is appropriate to withdraw the draft EIS. NMFS will conduct NEPA reviews for the revised RMPs that are jointly submitted to NMFS by the co-managers.
Steve Leider, telephone (360) 753-4650; fax (360) 753-9517; electronic mail:
On May 12, 2004, NMFS published the original notice of intent in the
Subsequent to NMFS' publication of the notice of intent to prepare an EIS in 2004, and subsequent to the 2004 RMPs, the co-managers have updated their hatchery programs to reflect important changes in hatchery management in different areas of Puget Sound. Such changes include new management practices to respond to new scientific information, revised purposes and sizes of some programs, and management responses to other issues unique to particular watersheds. Several hatchery programs have been terminated since 2004. Finally, the RMPs have been updated to reflect the 2007 listing of Puget Sound steelhead under the ESA.
In light of these changes, the co-managers have begun to submit to NMFS for review and approval revised joint RMPs for hatchery programs, generally organized by watershed, but located within the same action area as the 2004 RMPs. Because the co-managers are in control of how to design their RMPs and whether to revise the underlying HGMPs, these new RMPs replace the RMPs submitted in 2004.
While the draft EIS for Puget Sound hatchery programs was being developed, and in response to co-manager requests, NMFS conducted
Public comments on the draft EIS for Puget Sound hatchery programs noted that the 2004 RMPs for hatchery programs do not accurately reflect current hatchery program purposes or practices, and that some of the information used was outdated. It was also noted that the scale of the review, incorporating more than a hundred hatchery programs, tended to mask effects for some species.
Therefore, considering ongoing submissions of revised watershed-specific joint RMPs within the action area of the 2004 RMPs and public comments received on the draft EIS, NMFS has determined it is appropriate to terminate the EIS and transition this effort into new NEPA reviews on revised hatchery RMPs that are jointly submitted to NMFS by the co-managers. NMFS does not plan to formally respond to public comments on the draft EIS; however, information in the terminated draft EIS, along with public comments received on the draft EIS, will be considered by NMFS in subsequent NEPA reviews of watershed-specific RMPs.
We provide this notice in accordance with the requirements of NEPA as amended (42 U.S.C. 4371
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (Department) is amending the preliminarily determination of the antidumping duty (AD) investigation of certain passenger vehicle and light truck tires (passenger tires) from the People's Republic of China (PRC) to correct significant ministerial errors.
Toni Page, Jun Jack Zhao, or Lingjun Wang, 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) 482-1398, (202) 482-1396, or (202) 482-2316, respectively.
On January 27, 2015, the Department published its affirmative preliminary determination that passenger tires from the PRC are being, or are likely to be, sold in the United States at less than fair value, as provided by section 733 of the Tariff Act of 1930, as amended (the Act).
The Sailun Group
For a full description of the scope of this investigation,
The Department will analyze any comments received and, if appropriate, correct any significant ministerial error by amending the preliminary determination according to 19 CFR 351.224(e). A ministerial error is defined in 19 CFR 351.224(f) as “an error in addition, subtraction, or other arithmetic function, clerical error resulting from inaccurate copying, duplication, or the like, and any other similar type of unintentional error which the Secretary considers ministerial.” Further, a significant ministerial error is defined in 19 CFR
In accordance with 19 CFR 351.224(e) and (g)(1), the Department is amending the
For a complete analysis of the ministerial error allegations,
In the
We corrected the preliminary dumping margin for the Sailun Group. Consequently, we amended the preliminary separate rate for the exporter-producer combinations listed below. Further, we corrected companies' names as requested.
The collection of cash deposits and suspension of liquidation will be revised according to the rates calculated in this amended preliminary determination. Because the amended rates for the Sailun Group and separate rate companies results in reduced cash deposits, the rate for Sailun Group will be effective retroactively to January 27, 2015, the date of publication of the
In accordance with section 733(f) of the Act, we notified the International Trade Commission of our amended preliminary determination.
The Department intends to disclose calculations performed in connection with this amended preliminary determination within five days of the date of publication of this notice in accordance with 19 CFR 351.224(b).
This amended preliminary determination is issued and published in accordance with sections 733(f) and 777(i)(1) of the Act and 19 CFR 351.224(e).
U.S. Census Bureau, Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)).
To ensure consideration, written comments must be submitted on or before May 26, 2015.
Direct all written comments to Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Requests for additional information or copies of the information collection instrument(s) and instructions should be directed to Aaron Cantu, U.S. Census Bureau, DSD/CPS HQ-7H108D, Washington, DC 20233-8400, (301) 763-3806 (or via the Internet at
The Census Bureau plans to request clearance for the collection of data concerning the Annual Social and Economic Supplement (ASEC) to be conducted in conjunction with the February, March, and April Current Population Survey (CPS). The Census Bureau has conducted this supplement annually for more than 50 years. The Census Bureau and the Bureau of Labor Statistics sponsor this supplement.
The ASEC data collection underwent a transition period from 2013 to 2015, in which it was redesigned to include a new series of questions relating to (1) income; and (2) health insurance. For 2016, the data collection questions and design will remain unchanged from the previous year.
For this data collection, information on work experience, personal income, noncash benefits, current and previous year health insurance coverage, employer-sponsored insurance take-up, and migration is collected. The work experience items in the ASEC provide a unique measure of the dynamic nature of the labor force as viewed over a one-year period. These items produce statistics that show movements in and out of the labor force by measuring the number of periods of unemployment experienced by people, the number of different employers worked for during the year, the principal reasons for unemployment, and part-/full-time attachment to the labor force. We can make indirect measurements of discouraged workers and others with a casual attachment to the labor market.
The income data from the ASEC are used by social planners, economists, government officials, and market researchers to gauge the economic well-being of the country as a whole, and selected population groups of interest. Government planners and researchers use these data to monitor and evaluate the effectiveness of various assistance programs. Market researchers use these data to identify and isolate potential customers. Social planners use these data to forecast economic conditions and to identify special groups that seem to be especially sensitive to economic fluctuations. Economists use ASEC data to determine the effects of various economic forces, such as inflation, recession, recovery, and so on, and their differential effects on various population groups.
A prime statistic of interest is the classification of people in poverty and how this measurement has changed over time for various groups. Researchers evaluate ASEC income data not only to determine poverty levels but also to determine whether government programs are reaching eligible households.
The ASEC also contains questions related to: (1) Medical expenditures; (2) presence and cost of a mortgage on property; (3) child support payments; and (4) amount of child care assistance received. These questions enable analysts and policymakers to obtain better estimates of family and household income, and more precisely gauge poverty status.
The ASEC information will be collected by both personal visit and telephone interviews in conjunction with the regular February, March and April CPS interviewing. All interviews are conducted using computer-assisted interviewing.
This information collection request may be viewed at
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 shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed collection 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 on respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of intent to prepare an environmental impact statement (EIS); notice of initiation of scoping process; notice of public scoping meetings; request for comments.
The Mid-Atlantic Fishery Management Council announces its intent to prepare, in cooperation with NMFS, an amendment to the Fishery Management Plan for Atlantic Mackerel, Squid, and Butterfish, and to potentially prepare an EIS in accordance with the National Environmental Policy Act to analyze the impacts of any proposed management measures. The current focus of the amendment is to consider alternatives to reduce the capacities of the longfin squid and
The meetings will be held over several weeks between April 6, 2015 and April 21, 2015. Written comments must be received on or before 11:59 p.m., EST, on May 11, 2015.
There will be six scoping meetings listed under the heading Dates, Times, and Locations.
• Email to the following
• Mail or hand deliver to Dr. Christopher M. Moore, Executive Director, Mid-Atlantic Fishery Management Council, 800 North State Street, Suite 201, Dover, Delaware 19901. Mark the outside of the envelope “Squid Amendment Scoping Comments”; or
• Fax to (302) 674-5399.
• Comments may also be provided verbally at any of the public scoping meetings.
Christopher M. Moore, Ph.D. Executive Director, Mid-Atlantic Fishery Management Council; telephone: (302) 526-5255. The Council's Web site,
A scoping document will be posted to the Mid-Atlantic Fishery Management Council Web site.
1. Monday April 6, 2015, 4 p.m. Superior Trawl, 55 State Street, Narragansett, RI 02882. Telephone: (401) 782-1171.
2. Tuesday April 7, 2015, 5 p.m. Montauk Library, 871 Montauk Highway, Montauk, NY 11954. Telephone: (631) 668-3377.
3. Wednesday April 8, 2015, 5 p.m. Fairfield Inn, 185 MacArthur Dr, New Bedford, MA 02740. Telephone: (774) 634-2000.
4. Monday April 13, 2015, 6 p.m. Congress Hall Hotel, 251 Beach Ave, Cape May, NJ 08204. Telephone: (888) 944-1816.
5. Wednesday April 15, 2015, 5 p.m. Ocean Place Resort. 1 Ocean Blvd., Long Branch, NJ, 07740. Telephone: 732-571-4000.
6. Tuesday April 21, 2015, 6 p.m. This April 21, 2015 meeting will be conducted via webinar accessible via the internet from the Council's Web site,
In the Mid-Atlantic Fishery Management Council's (Council) 2015 Implementation Plan (available at
The Council may (or may not) use the current or previous control dates as reference points as it considers whether, and/or how, to further limit the number of participants in the squid fisheries (see preceding links for additional details on the control dates). The Council will first gather information during the scoping period. This is the first and best opportunity for members of the public to raise concerns related to the scope of issues that will be considered in the Amendment. The Council needs your input both to identify management issues and develop effective alternatives. Your comments early in the amendment development process will help us address issues of public concern in a thorough and appropriate manner. Comment topics could include the scope of issues in the amendment, concerns and potential alternatives related to capacity in the squid fisheries, and the appropriate level of environmental analysis. Comments can be made during the scoping hearings as detailed above or in writing. If the Council decides to move forward with the Amendment, the Council will develop a range of management alternatives to be considered and prepare a draft EIS and/or other appropriate environmental analyses. These analyses will consider the impacts of the management alternatives being considered, as required by the National Environmental Policy Act. Following a review of any comments on the draft analyses, the Council will then choose preferred management measures for submission with a Final EIS or Environmental Assessment to the Secretary of Commerce for publishing of a proposed and then final rule, both of which have additional comment periods.
While the Council is conducting these scoping hearings, the Council will also accept general comments on the MSB fisheries. These general comments could inform Council decision making for upcoming annual specifications or other actions.
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aid should be directed to M. Jan Saunders, (302) 526-5251, at least 5 days prior to the meeting date.
16 U.S.C. 1801
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; receipt of application.
Notice is hereby given that the Alaska Department of Fish and Game (ADFG) [Responsible Party: Robert Small, Ph.D., 1255 West 8th Street, Juneau, Alaska 99811-5526] has applied in due form for a permit to conduct research on bowhead (
Written, telefaxed, or email comments must be received on or before April 27, 2015.
The application and related documents are available for review by selecting “Records Open for Public Comment” from the “Features” box on the Applications and Permits for Protected Species (APPS) home page,
These documents are also available upon written request or by appointment in the Permits and Conservation Division, Office of Protected Resources, NMFS, 1315 East-West Highway, Room 13705, Silver Spring, MD 20910; phone (301) 427-8401; fax (301) 713-0376.
Written comments on this application should be submitted to the Chief, Permits and Conservation Division, at the address listed above. Comments may also be submitted by facsimile to (301) 713-0376, or by email to
Those individuals requesting a public hearing should submit a written request to the Chief, Permits and Conservation Division at the address listed above. The request should set forth the specific reasons why a hearing on this application would be appropriate.
Courtney Smith or Brendan Hurley, (301) 427-8401.
The subject permit is requested under the authority of the Marine Mammal Protection Act of 1972, as amended (MMPA; 16 U.S.C. 1361
The applicant proposes to take the above listed species by research activities within the coastal areas and open waters of the Bering, Chukchi, and Beaufort seas adjacent to Alaska and the eastern Beaufort Sea in Canada over a five year period. Research topics include population abundance (beluga), stock structure (bowhead, gray, humpback, and beluga), feeding areas and other important habitats (all species), migration routes (all species), behavior relative to human disturbance (all species), and to genetically identify individuals in order to determine survival and calving intervals (belugas). Takes per year, including incidental harassment, are as follows. For bowhead whales, take includes tagging with biopsy (up to 320), and biopsy only (up to 150). For gray whales take includes tagging with biopsy and photo-id (up to 90 per year) and biopsy with photo-id (up to 160), and photo-id only (up to 350). For humpback whales, take includes tagging with biopsy and photo-id (up to 35), biopsy with photo-id (up to 40), and photo-id (up to 50). For beluga whales the type of take includes aerial survey (up to 4,000), capture for tagging and sample collection (up to 200 takes per stock per year), boat approach for remote biopsy (up to 450 per stock per year). For all species, import and export activities will include biological samples for genetic, health, and dietary studies. Non-target species listed under the Endangered Species Act (ESA) that may be taken incidentally include up to 10 ringed seals. Other non-target species include annual incidental takes of up to 10 bearded, harbor and spotted seals and up to 10 beluga whales potentially taken during large whale (bowhead, gray and humpback) research.
In compliance with the National Environmental Policy Act of 1969 (42
Concurrent with the publication of this notice in the
Bureau of Economic Analysis, Commerce.
Notice of reporting requirements.
By this Notice, the Bureau of Economic Analysis (BEA), Department of Commerce is informing the public that it is conducting the mandatory survey titled Quarterly Survey of Foreign Airline Operators' Revenues and Expenses in the United States (BE-9). This survey is authorized by the International Investment and Trade in Services Survey Act.
This Notice constitutes legal notification to all United States persons (defined below) who meet the reporting requirements set forth in this Notice that they must respond to, and comply with, the survey. Reports are due 45 days after the end of each calendar quarter. This notice is being issued in conformance with the rule BEA issued in 2012 (77 FR 24373) establishing guidelines for collecting data on international trade in services and direct investment through notices, rather than through rulemaking. Additional information about BEA's collection of data on international trade in services and direct investment can be found in the 2012 rule, the International Investment and Trade in Services Survey Act (22 U.S.C. 3101
(a)
(b)
(c)
(d)
(b) Entities required to report will be contacted individually by BEA. Entities not contacted by BEA have no reporting responsibilities.
This data collection has been approved by the Office of Management and Budget (OMB) in accordance with the Paperwork Reduction Act and assigned control number 0608-0068. 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 OMB. Public reporting burden for this collection of information is estimated to average 6 hours per response. Send comments regarding this burden estimate to Director, Bureau of Economic Analysis (BE-1), U.S. Department of Commerce, Washington, DC 20230; and to the Office of Management and Budget, Paperwork Reduction Project 0608-0068, Washington, DC 20503.
22 U.S.C. 3101-3108.
National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice.
The Department of Commerce, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995.
Written comments must be submitted on or before May 26, 2015.
Direct all written comments to Jennifer Jessup, Departmental Paperwork Clearance Officer, Department of Commerce, Room 6616, 14th and Constitution Avenue NW., Washington, DC 20230 (or via the Internet at
Stephen Manley, (301) 427-8476 or
This request is for revision of a current information collection.
The marine mammal stranding report provides information on strandings so that the National Marine Fisheries Service (NMFS) can compile and analyze, by region, the species, numbers, conditions, and causes of illnesses and deaths (including health problems related to human interaction) in stranded marine mammals. NMFS requires this information to fulfill its management responsibilities under the Marine Mammal Protection Act (16 U.S.C. 1421a). NMFS is also responsible for the welfare of marine mammals while in rehabilitation status. The data from the marine mammal rehabilitation disposition report are required for monitoring and tracking of marine mammals held at various NMFS-authorized facilities.
Revision: The data from a new human interaction exam form are required for monitoring and tracking of illnesses, injury, and death related to human interaction. This information will be submitted primarily by members of the marine mammal stranding networks which are authorized by NMFS.
Paper applications, electronic reports, and telephone calls are required from participants, and methods of submittal include Internet through the NMFS National Marine Mammal Stranding Database; facsimile transmission of paper forms; or mailed copies of forms.
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 shall have practical utility; (b) the accuracy of the agency's estimate of the burden (including hours and cost) of the proposed repository of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; and (d) ways to minimize the burden and submission of the collection of information on respondents, including through the use of automated collection techniques or other forms of information technology.
Comments submitted in response to this notice will be summarized and/or included in the request for OMB approval of this information collection; they also will become a matter of public record.
Department of the Air Force, DoD.
Notice to delete a System of Records.
The Department of the Air Force is deleting a system of records notice in its existing inventory of record systems subject to the Privacy Act of 1974, as amended. The system notice is entitled “F044 AF SG J, Air Force Blood Program.”
Comments will be accepted on or before April 27, 2015. This proposed action will be effective the date following the end of the comment period unless comments are received which result in a contrary determination.
You may submit comments, identified by docket number and title, by any of the following methods:
*
*
Mr. Charles J. Shedrick, Department of the Air Force, Air Force Privacy Act Office, Office of Warfighting Integration and Chief Information officer, ATTN: SAF/CIO A6, 1800 Air Force Pentagon, Washington, DC 20330-1800, or by phone at (571) 256-2515.
The Department of the Air Force systems of records notices subject to the Privacy Act of 1974, as amended, have been published in the
The Department of the Air Force proposes to delete a system of records notice from its inventory of record systems subject to the Privacy Act of 1974, as amended. The proposed deletion is not within the purview of subsection (r) of the Privacy Act of 1974, as amended, which requires the submission of a new or altered system report.
Air Force Blood Program (June 16, 2003, 68 FR 35646)
Reason: Defense Health Agency has published a new System of Record Notice entitled “EDHA 25 DoD, Enterprise Blood Management System (EBMS)” to cover all DoD medical facilities Blood Programs.
DoD.
Establishment of federal advisory committee.
The Department of Defense (DoD) is publishing this notice to announce that it is establishing the National Commission on the Future of the Army (“the Commission”).
Jim Freeman, Advisory Committee Management Officer for the Department of Defense, 703-692-5952.
This committee is being established pursuant to Section 1702 of the Carl Levin and Howard P. “Buck” McKeon National Defense Authorization Act for Fiscal Year 2015 (“the FY 2015 NDAA”) (Pub. L. 113-291) and in accordance with the Federal Advisory Committee Act (FACA) of 1972 (5 U.S.C., Appendix, as amended) and 41 CFR 102-3.50(a).
The Commission is a non-discretionary Federal advisory committee that shall undertake a comprehensive study of the structure of the Army, and policy assumptions related to the size and force mixture of the Army, in order (a) to make an assessment of the size and force structure of the active component of the Army and the reserve components of the Army; and (b) to make recommendations on the modifications, if any, of the structure of the Army related to current and anticipated mission requirements for the Army at acceptable levels of national risk and in a manner consistent with available resources and anticipated future resources. The Commission shall also conduct a study of a transfer of Army National Guard AH-64 Apache aircraft from the Army National Guard to the regular Army.
Pursuant to section 1703(c) of the FY 2015 NDAA, the Commission, not later than February 1, 2016, shall submit to the President and the Congressional defense committees a report setting forth a detailed statement of the findings and conclusions of the Commission as a result of the studies required by Sections 1703(a) and (b) of the FY 2015 NDAA, together with its recommendations for such legislative and administrative actions it considers appropriate in light of the results of the studies.
In undertaking both studies as described above, the Commission shall give particular consideration to:
A. An evaluation and identification of a structure for the Army that:
(1) Has the depth and scalability to meet current and anticipated requirements of the combatant commands;
(2) achieves cost-efficiency between the regular and reserve components of the Army, manages military risk, takes advantage of the strengths and capabilities of each, and considers fully burdened lifecycle costs;
(3) ensures that the regular and reserve components of the Army have the capacity needed to support current and anticipated homeland defense and disaster assistance missions in the United States;
(4) provides for sufficient numbers of regular members of the Army to provide a base of trained personnel from which the personnel of the reserve components of the Army could be recruited;
(5) maintains a peacetime rotation force to avoid exceeding operational tempo goals of 1:2 for active members of the Army and 1:5 for members of the reserve components of the Army; and
(6) manages strategic and operational risk by making tradeoffs among readiness, efficiency, effectiveness, capability, and affordability.
B. An evaluation and identification of force generation policies for the Army with respect to size and force mixture in order to fulfill current and anticipated mission requirements for the Army in a manner consistent with available resources and anticipated future resources including policies in connection with:
(1) Readiness;
(2) training;
(3) equipment;
(4) personnel; and
(5) maintenance of the reserve components as an operational reserve in order to maintain as much as possible the level of expertise and experience developed since September 11, 2001.
C. An identification and evaluation of the distribution of responsibility and authority for the allocation of Army National Guard personnel and force structure to the States and territories.
D. An identification and evaluation of the strategic basis or rationale, analytical methods, and decision-making processes for the allocation of Army National Guard personnel and force structure to the States and territories.
The Commission may hold such hearings, sit and act at such times and places, take such testimony and receive such evidence as the Commission considers advisable to carry out its mission.
The Commission may secure directly from any Federal department or agency such information as the Commission considers necessary to carry out its duties. Upon request of the Chair of the Commission, the head of such department or agency shall furnish such information to the Commission.
The Commission, pursuant to Section 1702(b)(1) of the FY 2015 NDAA, shall be composed of eight members. In making appointments, consideration should be given to individuals with expertise in national and international security policy and strategy, military forces capability, force structure design, organization, and employment, and reserve forces policy. The Commission's membership shall include:
a. Four individuals appointed by the President;
b. One individual appointed by the Chairman of the Committee on Armed Services of the Senate;
c. One individual appointed by the Ranking Member of the Committee on Armed Services of the Senate;
d. One individual appointed by the Chairman of the Committee on Armed Services of the House of Representatives; and
e. One individual appointed by the Ranking Member of the Committee on Armed Services of the House of Representatives.
Pursuant to Section 1702(b)(2) of FY 2015 NDAA, the appointments of the members of the Commission shall be made not later than 90 days after the enactment of the FY 2015 NDAA.
If one or more appointments under Section 12, subparagraph (a) above is not made by the appointment date specified in Section 1702(b)(2) of the FY 2015 NDAA, the authority to make such appointment or appointments shall expire, and the number of members of the Commission shall be reduced by the number equal to the number of appointments so not made. If an appointment under Section 12, subparagraphs (b)-(e) above is not made by the appointment date specified in Section 1702(b)(2) of the FY 2015 NDAA, the authority to make an appointment shall expire, and the number of members of the Commission shall be reduced by the number equal to the number otherwise appointable.
Members shall be appointed for the life of the Commission. Any vacancy in the Commission shall not affect its powers, but shall be filled in the same manner as the original appointment. The Commission members shall select a Chair and Vice Chair from the total membership. Commission members who are full-time or permanent part-time Federal officers or employees shall be appointed as regular government employee (RGE) members. Commission members who are not full-time or permanent part-time Federal officers or employees shall be appointed as experts or consultants pursuant to 5 U.S.C. 3109 to serve as special government employee (SGE) members.
Consistent with Section 1705(a) of the FY 2015 NDAA, each member of the
The members of the Commission shall be allowed travel expenses, including per diem in lieu of subsistence, at rates authorized for employees of agencies under subchapter I of chapter 57 of title 5 United States Code, while away from their homes or regular places of business in the performance of services for the Commission.
The DoD, when necessary and consistent with the Commission's mission and DoD policies and procedures, may establish subcommittees, task forces, or working groups to support the Commission. Establishment of subcommittees will be based upon a written determination, to include terms of reference, by the Secretary of Defense, the Deputy Secretary of Defense, or the DCMO, as the DoD sponsor.
Such subcommittees shall not work independently of the Commission and shall report all of their recommendations and advice solely to the Commission for full and open deliberation and discussion. Subcommittees, task forces, or working groups have no authority to make decisions and recommendations, verbally or in writing, on behalf of the Commission. No subcommittee or its members can update or report, verbally or in writing, on behalf of the Commission, directly to the DoD or to any Federal officer or employee.
All subcommittee members shall be appointed by the Secretary of Defense or the Deputy Secretary of Defense according to governing DoD policies and procedures, even if the member in question is already a member of the Commission. Subcommittee members, with the approval of the Secretary of Defense, may serve a term of service for the life of the subcommittee.
Subcommittee members, if not full-time or part-time Federal officers or employees, shall be appointed as experts or consultants pursuant to 5 U.S.C. § 3109 to serve as SGE members. Subcommittee members who are full-time or permanent part-time Federal officers or employees will be appointed pursuant to 41 CFR § 102-3.130(a) to serve as RGE members.
Each subcommittee member is appointed to provide advice to the government on the basis of his or her best judgment without representing any particular point of view and in a manner that is free from conflict of interest. Subcommittee members may be compensated, and shall be allowed travel expenses, in the same manner as Commission members.
All subcommittees operate under the provisions of the FACA, the Sunshine Act, governing Federal statutes and regulations, and established DoD policies and procedures.
The Commission's Designated Federal Officer (DFO), pursuant to DoD policy, shall be a full-time or permanent part-time DoD employee appointed in accordance with governing DoD policies and procedures.
The Commission's DFO is required to be in attendance at all meetings of the Commission and any of its subcommittees for the entire duration of each and every meeting. However, in the absence of the Commission's DFO, a properly approved Alternate DFO, duly appointed to the Commission according to established DoD policies and procedures, shall attend the entire duration of the Commission or any subcommittee meeting.
The DFO, or the Alternate DFO, shall call all meetings of the Commission and its subcommittees; prepare and approve all meeting agendas; and adjourn any meeting when the DFO, or the Alternate DFO, determines adjournment to be in the public interest or required by governing regulations or DoD policies and procedures.
Pursuant to 41 CFR 102-3.105(j) and 102-3.140, the public or interested organizations may submit written statements to National Commission on the Future of the Army membership about the Commission's mission and functions. Written statements may be submitted at any time or in response to the stated agenda of planned meeting of the National Commission on the Future of the Army.
All written statements shall be submitted to the DFO for the National Commission on the Future of the Army, and this individual will ensure that the written statements are provided to the membership for their consideration. Contact information for the National Commission on the Future of the Army DFO can be obtained from the GSA's FACA Database—
The DFO, pursuant to 41 CFR 102-3.150, will announce planned meetings of the National Commission on the Future of the Army. The DFO, at that time, may provide additional guidance on the submission of written statements that are in response to the stated agenda for the planned meeting in question.
Department of Defense.
Notice of meeting.
The Department of Defense is publishing this notice to announce the following Federal Advisory Committee meeting of the Judicial Proceedings since Fiscal Year 2012 Amendments Panel (“the Judicial Proceedings Panel” or “the Panel”). The meeting is open to the public.
A meeting of the Judicial Proceedings Panel will be held on Friday, April 10, 2015. The Public Session will begin at 8:30 a.m. and end at 5:00 p.m.
U.S. District Court for the District of Columbia, 333 Constitution Avenue NW., Courtroom #20, 6th floor, Washington, DC 20001.
Ms. Julie Carson, Judicial Proceedings Panel, One Liberty Center, 875 N. Randolph Street, Suite 150, Arlington, VA 22203. Email:
This public 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.
White House Initiative on Educational Excellence for Hispanics, U.S. Department of Education.
Announcement of an open meeting.
This notice sets forth the schedule and agenda of the tenth meeting of the President's Advisory Commission on Educational Excellence for Hispanics. The notice also describes the functions of the Commission. Notice of the meeting is required by section 10(a)(2) of the Federal Advisory Committee Act and intended to notify the public of its opportunity to attend.
The President's Advisory Commission on Educational Excellence for Hispanics meeting will be held on Tuesday, April 14, 2015 from 9 a.m.-4 p.m. Eastern Daylight Time.
New Building, John Jay College, 860 11th Avenue, New York, NY 10019.
Emmanuel Caudillo, Special Advisor, White House Initiative on Educational Excellence for Hispanics, 400 Maryland Ave. SW., Room 4W108, Washington, DC 20202; telephone: 202-401-1411.
The President's Advisory Commission on Educational Excellence for Hispanics Statutory Authority and Function: The President's Advisory Commission on Educational Excellence for Hispanics (the Commission) is established by Executive Order 13555 (Oct. 19, 2010; reestablished December 12, 2012 by Executive Order 13634). The Commission is governed by the provisions of the Federal Advisory Committee Act (FACA), (Pub. L. 92-463; as amended, 5 U.S.C.A., Appendix 2) which sets forth standards for the formation and use of advisory committees. The purpose of the Commission is to advise the President and the Secretary of Education on all matters pertaining to the education attainment of the Hispanic community.
The Commission shall advise the President and the Secretary in the following areas: (i) Developing, implementing, and coordinating
Individuals who wish to attend the Commission meeting must RSVP by 12 noon EDT, Friday, April 10th, 2015, to
An opportunity for public comment will be available on Tuesday, April 14, 2014, from 9 a.m. to 4 p.m., EDT. Individuals who wish to provide comments will be allowed three minutes to speak. Those members of the public interested in submitting written comments may do so by submitting them to the attention of Emmanuel Caudillo, White House Initiative on Educational Excellence for Hispanics, U.S. Department of Education, 400 Maryland Ave. SW., Room 4W108, Washington, DC 20202, by Friday, April 10, 2015 or via email at
The open meeting will facilitate a discussion on the Commission's 25th Anniversary year of action strategy, including updates on the Administration's education priorities and proposed anniversary outreach and engagement efforts, provide an opportunity for breakout sessions led by each subcommittee—Early Learning, K-12, and Postsecondary Education, and allow for a public comment session.
Reasonable Accommodations: Individuals who will need accommodations in order to attend the meeting (
Electronic Access To This Document: The official version of this document is the document published in the
You may also access documents of the Department published in the
Executive Order 13555; reestablished by Executive Order 13634.
Election Assistance Commission.
Tuesday, March 31, 2015 AT 10:00 a.m.
1335 East-West Highway (First Floor Conference Room), Silver Spring, MD 20910.
This Meeting Will Be Open To The Public
The Commission will receive presentations on the DRAFT Voluntary Voting System Guidelines (VVSG 1.1) and consider the proposed VVSG 1.1 for adoption. The Commission will receive presentations on the DRAFT Certification Program Procedural Manual, Version 2.0, and consider the proposed final document for approval. The Commission will receive presentations on the DRAFT Laboratory Accreditation Program Manual, Version 2.0, and consider the proposed final document for approval. The Commission will consider approval of advisory opinion requests related to expenditure of HAVA funds from the state and local election offices in the States of Pennsylvania, Puerto Rico, Montana, Washington State and California. The Commission will consider other administrative matters.
Bryan Whitener, Telephone: (301) 563-3961.
Department of Energy (DOE).
Notice of Open Meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Paducah. The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Thursday, April 16, 2015 6:00 p.m.
Barkley Centre, 111 Memorial Drive, Paducah, Kentucky 42001.
Jennifer Woodard, Deputy Designated Federal Officer, Department of Energy Paducah Site Office, 1017 Majestic Drive, Suite 200, Lexington, Kentucky 40513, (270) 441-6820.
Breaks Taken As Appropriate
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 electric securities 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:
Office of Fossil Energy, DOE.
Notice of application.
The Office of Fossil Energy (FE) of the Department of Energy (DOE) gives notice of receipt of an application (Application), filed on December 31, 2014, by American LNG Marketing LLC (American LNG), requesting long-term, multi-contract authorization to export domestically produced liquefied natural gas (LNG) in a volume equivalent to approximately 3.02 billion cubic feet per year (Bcf/yr) of natural gas (0.008 Bcf/day). American LNG seeks to export the LNG from a proposed natural gas liquefaction project under construction in Medley, Florida, on the northern portion of the Hialeah Railyard (Hialeah Facility).
Protests, motions to intervene or notices of intervention, as applicable, requests for additional procedures, and written comments are to be filed using procedures detailed in the Public Comment Procedures section no later than 4:30 p.m., Eastern time, May 26, 2015.
U.S. Department of Energy (FE-34), Office of Oil and Gas Global Security and Supply, Office of Fossil Energy, P.O. Box 44375, Washington, DC 20026-4375.
U.S. Department of Energy (FE-34), Office of Oil and Gas Global Security and Supply, Office of Fossil Energy, Forrestal Building, Room 3E-042, 1000 Independence Avenue SW., Washington, DC 20585.
Larine Moore or Benjamin Nussdorf, U.S. Department of Energy (FE-34), Office of Oil and Gas Global Security and Supply, Office of Fossil Energy, Forrestal Building, Room 3E-042, 1000 Independence Avenue SW., Washington, DC 20585, (202) 586-9478; (202) 586-7991.
Cassandra Bernstein, U.S. Department of Energy (GC-76), Office of the Assistant General Counsel for Electricity and Fossil Energy, Forrestal Building, 1000 Independence Avenue SW., Washington, DC 20585, (202) 586-9793.
The Application will be reviewed pursuant to section 3(a) of the NGA, 15 U.S.C. 717b(a), and DOE will consider any issues required by law or policy. To the extent determined to be relevant, these issues will include the domestic need for the natural gas proposed to be exported, the adequacy of domestic natural gas supply, U.S. energy security, and the cumulative impact of the requested authorization and any other LNG export application(s) previously approved on domestic natural gas supply and demand fundamentals. DOE may also consider other factors bearing on the public interest, including the impact of the proposed exports on the U.S. economy (including GDP, consumers, and industry), job creation, the U.S. balance of trade, and international considerations; and whether the authorization is consistent with DOE's policy of promoting competition in the marketplace by allowing commercial parties to freely negotiate their own trade arrangements. Additionally, DOE will consider the following environmental document:
The National Environmental Policy Act (NEPA), 42 U.S.C. 4321
In response to this Notice, any person may file a protest, comments, or a motion to intervene or notice of intervention, as applicable. Due to the complexity of the issues raised by the Applicant, interested parties will be provided 60 days from the date of publication of this Notice in which to submit their comments, protests, motions to intervene, or notices of intervention.
Any person wishing to become a party to the proceeding must file a motion to intervene or notice of intervention. The filing of comments or a protest with respect to the Application will not serve to make the commenter or protestant a party to the proceeding, although protests and comments received from persons who are not parties will be considered in determining the appropriate action to be taken on the Application. All protests, comments, motions to intervene, or notices of intervention must meet the requirements specified by the regulations in 10 CFR part 590.
Filings may be submitted using one of the following methods: (1) Emailing the filing to
A decisional record on the Application will be developed through responses to this notice by parties, including the parties' written comments and replies thereto. Additional procedures will be used as necessary to achieve a complete understanding of the facts and issues. If an additional procedure is scheduled, notice will be provided to all parties. If no party requests additional procedures, a final Opinion and Order may be issued based on the official record, including the Application and responses filed by parties pursuant to this notice, in accordance with 10 CFR 590.316.
The Application is available for inspection and copying in the Division of Natural Gas Regulatory Activities docket room, Room 3E-042, 1000 Independence Avenue SW., Washington, DC 20585. The docket room is open between the hours of 8:00 a.m. and 4:30 p.m., Monday through Friday, except Federal holidays. The Application and any filed protests, motions to intervene or notice of interventions, and comments will also be available electronically by going to the following DOE/FE Web address:
Office of Energy Efficiency and Renewable Energy, Department of Energy.
Decision and Order.
The U.S. Department of Energy (DOE) gives notice of its Decision and Order in Case No. VHE-002, which grants Empire Comfort Systems, Inc. (Empire) a waiver from the existing DOE test procedure for determining the energy consumption of residential vented home heating equipment. DOE previously published the Empire Petition for Waiver and solicited comments, data, and information regarding the petition, which requested permission to use the DOE test procedure proposed in the
This Decision and Order is effective March 26, 2015. The waiver granted in this Decision and Order shall terminate on July 6, 2015.
Mr. Bryan Berringer, U.S. Department of Energy, Building Technologies Office, Mailstop EE-5B, 1000 Independence Avenue SW., Washington, DC 20585-0121. Telephone: (202) 586-0371. Email:
Mr. Eric Stas, U.S. Department of Energy, Office of the General Counsel, Mail Stop GC-33, 1000 Independence Avenue SW., Washington, DC 20585-0103. Telephone: (202) 586-9507. Email:
In accordance with 10 CFR 430.27(l), DOE gives notice of the issuance of its Decision and Order as set forth below. The Decision and Order grants Empire's request for waiver from the existing residential vented home heating equipment test procedure in 10 CFR part 430, subpart B, appendix O for its PVS (18,35)(K)(N)(P) basic model of condensing-type direct heating equipment, provided that Empire tests and rates such products using the alternate test procedure described in this notice. This Decision and Order prohibits Empire from making representations concerning the energy efficiency of these products unless the product has been tested consistent with the provisions of the alternate test procedure set forth below, and the representations fairly disclose the test results. Distributors, retailers, and private labelers are held to the same standard when making representations regarding the energy efficiency of these products. (42 U.S.C. 6293(c)) This waiver shall terminate on July 6, 2015, the mandatory compliance date for the amended DOE DHE test procedure (the source of the alternate test procedure).
Title III, Part B
The regulations set forth in 10 CFR 430.27, which were recently amended, contain provisions that enable a person to petition DOE to obtain a waiver from the test procedure requirements for covered products.
DOE may grant a waiver subject to conditions, including adherence to alternate test procedures. 10 CFR 430.27(f)(2). Waivers remain in effect pursuant to the provisions of 10 CFR 430.27(h).
Any interested person who has submitted a Petition for Waiver may also file an Application for Interim Waiver from the applicable test procedure requirements. 10 CFR 430.27(b)(2). DOE will grant an interim waiver request if it is determined that the applicant will experience economic hardship if the interim waiver is denied, if it appears likely that the petition for waiver will be granted, and/or DOE determines that it would be desirable for public policy reasons to grant immediate relief pending a determination on the petition for waiver. 10 CFR 430.27(e)(2).
On January 20, 2014, Empire filed a Petition for Waiver and Application for Interim Waiver for a condensing-type direct heating equipment model from the test procedure applicable to vented home heating equipment set forth in 10 CFR part 430, subpart B, appendix O.
DOE notes that of the eight basic model numbers set forth in Empire's petition, only one (PVS (18, 35) (K)(N)(P)) qualifies as a covered DHE product. The remaining seven basic models (which are fireplaces, fireplace inserts, or stoves) are hearth products and are, therefore, subject to neither the test procedure requirements of 10 CFR part 430, subpart B, appendix O nor the proposed requirements of the October 2013 NOPR.
Empire also requested an interim waiver from the existing DOE test procedure, which DOE granted.
DOE did not receive any comments on the Empire petition published in the
Under this Decision and Order, Empire shall be required to test and rate its condensing-type direct heating equipment (DHE) models using the DOE Final Rule test procedure for DHE published in the
DOE consulted with the Federal Trade Commission (FTC) staff concerning the Empire petition for waiver. The FTC staff did not have any objections to granting a waiver to Empire.
After careful consideration of all the material that was submitted by Empire and consultation with the FTC staff, it is ordered that:
(1) The Petition for Waiver submitted by the Empire Comfort Systems, Inc. (Case No. VHE-002) is hereby granted as set forth in the paragraphs below.
(2) Empire shall be required to test and rate the following basic model (condensing vented heater):
PVS (18,35) (K)(N)(P) according to the alternate test procedure set forth in paragraph (3) below.
(3) Empire shall not be required to test the products listed in paragraph (2) above according to the test procedure for residential vented home heating equipment set forth in 10 CFR part 430, subpart B, appendix O, but instead shall use as the amended test procedure as set forth in the final rule published in the
(4) Representations. Empire may make representations about the energy use of its condensing-type DHE models for compliance, marketing, or other purposes only to the extent that such products have been tested in accordance with the provisions outlined above and such representations fairly disclose the results of such testing.
(5) This waiver shall terminate on July 6, 2015, consistent with the provisions of 10 CFR 430.27(h)(2).
(6) This waiver is issued on the condition that the statements, representations, and documentary materials provided by the petitioner are valid. DOE may revoke or modify this waiver at any time if it determines the factual basis underlying the Petition for Waiver is incorrect, or the results from the alternate test procedure are unrepresentative of the basic model's true energy consumption characteristics.
(7) This waiver is granted for only those models specifically set out in Empire's January 20, 2014 Petition for Waiver, not future models that may be manufactured by Empire. Empire may submit a new or amended Petition for Waiver and Application for Grant of Interim Waiver, as appropriate, for additional residential vented home heating equipment models for which it seeks a waiver from the DOE test
U.S. Department of Energy.
Notice and request for comments.
The Department of Energy (DOE), pursuant to the Paperwork Reduction Act of 1995, intends to extend for three years, an information collection request with the Office of Management and Budget (OMB). Comments are invited on: (a) Whether the extended 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 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 respondents, including through the use of automated collection techniques or other forms of information technology.
Comments regarding this proposed information collection must be received on or before May 26, 2015. If you anticipate difficulty in submitting comments within that period, contact the person listed below as soon as possible.
Written comments may be sent to: Eva Auman, GC-63, Department of Energy, 1000 Independence Ave. SW., Washington, DC 20585; Fax: 202-586-0971; or email at:
Requests for additional information or copies of the information collection instrument and instructions should be directed to Eva Auman, GC-63, Department of Energy, 1000 Independence Ave. SW., Washington, DC 20585; Fax: 202-586-0971; or email at:
This information collection request contains: (1) OMB No. 1910-5143; (2)
42 U.S.C. 7254, 7256.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency (EPA) has submitted an information collection request (ICR), “NESHAP for the Secondary Lead Smelter Industry (Renewal)” (EPA ICR No. 1686.10, OMB Control No. 2060-0296) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before April 27, 2015.
Submit your comments, referencing Docket ID Number EPA-HQ-OECA-2014-0055, to (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Patrick Yellin, Monitoring, Assistance, and Media Programs Division, Office of Compliance, Mail Code 2227A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-2970; fax number: (202) 564-0050; email address:
Supporting documents, which explain in detail the information that the EPA will be collecting, are available in the public docket for this ICR. The docket can be viewed online at
Environmental Protection Agency (EPA).
Notice.
EPA's Office of Pesticide Programs, the U.S. Fish and Wildlife Service (FWS), and the National Marine Fisheries Service (NMFS) (collectively, the Services), and the U.S. Department of Agriculture (USDA) are holding a 1-day workshop to provide an update on the status of interagency efforts to further develop interim scientific methods that were issued in November 2013 by EPA, the Services, and USDA in response to the National Academy of Sciences (NAS) report entitled, “Assessing Risks to Endangered and Threatened Species from Pesticides”. This workshop builds upon public meetings held in November and December 2013, and April and October 2014, and provides a forum for stakeholders to offer scientific and technical feedback on the ongoing efforts to develop draft Biological Evaluations (BEs) for three pilot chemicals (chlorpyrifos, diazinon, and malathion). This workshop provides an opportunity to continue the dialogue on the implementation of the enhanced stakeholder engagement process that was finalized in March 2013. The workshop is not designed, or intended, to be a decision-making forum; consensus will not be sought, or developed at the meeting. This meeting furthers the agencies' goal of developing a consultation process for assessing pesticide's impacts on listed species that is efficient, inclusive, and transparent.
The meeting will be held on April 15, 2015 from 8:30 a.m. to 5:30 p.m. The workshop will be available via webinar for those interested in attending the workshop remotely. A teleconference line will also be available. Requests to attend the workshop in person, or via webinar and teleconference must be received on or before April 7, 2015. Individuals wishing to make a presentation at the workshop should submit presentation materials by March 30, 2015.
To request accommodation of a disability, please contact the person listed under
The meeting will be held at FWS Skyline Bldg. 7, 5275 Leesburg Pike, Bailey's Crossroads, VA 22041-3803, in the Rachel Carson Room. See Unit III for additional information.
Requests to attend the meeting, identified by docket identification (ID) number EPA-HQ-OPP-2014-0233, must be submitted to the person listed under
You may be potentially affected by this action if you develop, manufacture, formulate, sell, and/or apply pesticide products, and if you are interested in the potential impacts of pesticide use on listed species. 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 code 311)
• Pesticide manufacturing (NAICS code 32532)
The docket for this action, identified by docket identification (ID) number EPA-HQ-OPP-2014-0233, is available at
This workshop is an opportunity for stakeholders and agencies to continue their dialogue on the technical aspects of implementing the NAS recommendations in the context of ongoing interagency efforts to develop draft Biological Evaluations for the three pilot chemicals; this workshop builds upon public meetings held in November and December 2013, and April and October 2014, and implementation of the enhanced stakeholder engagement process that was finalized in March 2013. The workshop is not designed, or intended to be a decision-making forum; consensus will not be sought, or developed at the meeting.
Stakeholders are invited to hear presentations by the agencies on the
The agencies' interim approach document entitled, “Interagency Approach for Implementation of the National Academy of Sciences Report”, dated November 13, 2013, and the presentation materials from the November 2013 stakeholder workshop are available at the following Web site:
Presentations by the agencies supporting this stakeholder workshop will be made available on the EPA Web site on April 1st (
Representatives from Federal agencies will join the dialogue to answer clarifying questions regarding the pesticide registration process and Endangered Species Act consultation process. The agencies see this workshop as an integral component of the stakeholder engagement process developed for pesticide consultations that contributes to the agencies' commitment to adapt and refine the interim approaches as we progress through initial consultations.
You may submit a request to participate in this meeting to the person listed under
Public parking is available for attendees; follow blue signs to the lot. There is a fee for all day parking.
Attendees will need to present identification at the Security check-in.
Webinar and teleconference information will be provided to participants requesting access via webinar and telephone.
7 U.S.C. 136
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency (EPA) has submitted an information collection request (ICR), “EPA's Light-Duty In-Use Vehicle Testing Program (Renewal)” (EPA ICR No. 0222.10, OMB Control No. 2060-0086) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Additional comments may be submitted on or before April 27, 2015.
Submit your comments, referencing Docket ID No. EPA-HQ-OAR-2010-0690, to (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Lynn Sohacki, Compliance Division, Office of Transportation and Air Quality, U.S. Environmental Protection Agency, 2000 Traverwood, Ann Arbor, Michigan 48105; telephone number: 734-214-4851; fax number: 734-214-4869; email address:
Supporting documents, which explain in detail the information that the EPA will be collecting, are available in the public docket for this ICR. The docket can be viewed online at
This ICR involves light-duty surveys and vehicle testing, which is strictly voluntary. A group of 25 to 50 potential participants is identified from state vehicle registration records. Three of the respondent pool are asked survey questions concerning vehicle condition, operation and maintenance. Additional groups of potential participants may be contacted until a sufficient number of vehicles have been obtained. Owners verify the survey information when they deliver their vehicles to EPA, release the vehicle to EPA, voluntarily provide maintenance records for copying, receive a cash incentive and, if requested, a loaner car, then receive the vehicle from EPA at the conclusion of the testing.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency (EPA) has submitted an information collection request (ICR), “Effluent Guidelines and Standards for the Airport Deicing Category (Renewal)” (EPA ICR No. 2326.03, OMB Control No. 2040-0285) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before April 27, 2015.
Submit your comments, referencing Docket ID No. EPA-HQ-OW-2008-0719, to (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Sarita Hoyt, State and Regional Branch, Water Permits Division, OWM Mail Code: 4203M, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-1471; email address:
Supporting documents, which explain in detail the information that the EPA will be collecting, are available in the public docket for this ICR. The docket can be viewed online at
Federal Communications Commission (FCC or Commission or Agency)
Notice; one new Privacy Act system of records.
Pursuant to subsection (e)(4) of the
In accordance with 5 U.S.C. 552a(e)(4) and (e)(11) of the Privacy Act, as amended, any interested person may submit written comments concerning
Address comments to Leslie F. Smith, Privacy Analyst, Information Technology (IT), Office of Managing Director (OMD), Room 1-C216, Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554, or via the Internet at
Contact Leslie F. Smith, Information Technology (IT), Office of Managing Director (OMD), Room 1-C216, Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554, (202) 418-0217, or via the Internet at
As required by the Privacy Act of 1974, as amended, 5 U.S.C. 552a(e)(4) and (e)(11), this document sets forth notice of the proposed new system of records maintained by the FCC. This notice is a summary of the more detailed information about the proposed new system of records, which may be obtained or viewed pursuant to the contact and location information given above in the
FCC Telework Program.
The FCC's CIO team will provide a security classification to this system based on NIST FIPS-199 standards.
Human Resources Management (HRM), Office of Managing Director (OMD), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554; and Individual FCC Bureaus and Offices (B/O), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554.
The categories of individuals in this system include FCC employees who voluntarily apply for permission to telework from their home, a satellite office, or other FCC approved alternate worksite(s), and their supervisors who review, approve, deny, and/or renew the telework applications.
The categories of records in the system include but are not limited to, the information that FCC employees are (voluntarily) required to provide on FCC Telework Request Form and Agreement, Home Safety Self-Certification for Home-Based Telecommuters, Certificate of Completion of telework training, and/or Reasonable Accommodation Requests
1. FCC employee's name; title, series, grade; bureau/division/branch; date of request and date telework training completed; and supervisor's name and telephone number;
2. Employee telework request: Routine (regular/recurring) and/or situational (ad hoc), start date and end date; regular/recurring days during pay period week 1 and/or week 2—Monday(s) to Friday(s);
3. Description of work to be performed during telework, including supervisor's conditions specific to telework agreement (
4. Employee's Official Duty Station: Address and telephone number(s);
5. Employee's alternate worksite: Address and telephone number(s); employee's email address (if different from work email); fax number; and tour of duty (hours);
6. Approvals (including terms of the telework agreement): Employee's signature and date; supervisor's signature and date; cancellation/denial, including reason; renewal; and supervisor and employee's initials and date;
7. Self-certification for home safety;
8. Telework Training certificate (
9. Reasonable Accommodation Requests; and
10. Rosters of teleworking employees maintained by the Bureaus and Offices (B/O) for (routine and emergency) contact purposes.
The FCC provides a telework program for Commission employees. The telework program is voluntary, but employees must qualify to participate in this program by: (1) Filling out FCC Telework Request Form and Agreement and Home Safety Self-Certification Checklist for Home-Based Telecommuters, and (2) completing telework training. This system covers the personally identifiable information (PII) that FCC employees must provide when they apply for permission to telework from home or at other FCC approved alternate worksite(s); and the terms and conditions that relate to this telework agreement. The FCC will use the information in the FCC Telework
The B/O may also maintain employee teleworking rosters for contact purposes.
Information about individuals in this system of records may routinely be disclosed under the following conditions. The FCC will determine whether disclosure of the records is compatible with the purpose for which the records were collected in each of these cases.
1. FCC Program Management—A record from this system may be accessed and used by the FCC's HRM and B/O supervisory staff in their duties associated with the management and operation of the FCC Telework Program participants for FCC employees. This information may be used to conduct audits, evaluations, and/or investigations of the telework program (for the purposes, which include, but are not limited to, eliminating waste, fraud, and abuse in the telework program). This information may be shared with an employee's supervisors or co-workers, staff in OMD, and/or the Office of Inspector General (OIG), as necessary;
2. FCC Contractors—Records from this system (including paper documents and electronic records and data) may be disclosed to and used by contractors working at the FCC as required in the performance of their assigned duties as directed by the HRM and IT supervisors and staff;
3. Congressional Investigations and Inquiries—A record from this system may be disclosed to either House of Congress, or, to the extent of matter within its jurisdiction, any committee or subcommittee thereof, for the purposes of an official Congressional investigation, which includes but is not limited to information concerning the FCC Telework Program, and/or in response to an inquiry made by an individual to the Congressional office for the individual's own records;
4. Government-wide Program Management and Oversight—When requested by the National Archives and Records Administration (NARA), the Office of Personnel Management (OPM), the General Services Administration (GSA), and/or the Government Accountability Office (GAO) for the purpose of records management studies conducted under authority of 44 U.S.C. 2904 and 2906 (such disclosure(s) shall not be used to make a determination about individuals); when the U.S. Department of Justice (DOJ) is contacted in order to obtain that department's advice regarding disclosure obligations under the Freedom of Information Act; or when the Office of Management and Budget (OMB) is contacted in order to obtain that office's advice regarding obligations under the Privacy Act;
5. General Services Administration (GSA)—A record from this system may be disclosed to GSA when FCC employees and contractors use a GSA approved alternate worksite for the purposes that include, but are not limited to security regulations, facilities management (that include, but are not limited to facility space allocation and management requirements, staffing requirements, and related work-space arrangements), and/or other GSA function(s); or when an emergency at the FCC headquarters and/or FCC facilities requires FCC employees to relocate to a GSA approved alternate worksite(s) until they can return to their normal FCC work location;
6. Department of Labor—A record from this system may be disclosed to the Department of Labor (DOL) for telework labor management issues, which include but are not limited to when an employee sustains injuries while working at home, emergency office relocation requirements, and other issues that impact an employee teleworking at home or at approved alternate worksites.
7. Law Enforcement and Investigation—Where there is an indication of a violation or potential violation of a statute, regulation, rule, or order, records from this system may be shared with appropriate federal, state, or local authorities either for purposes of obtaining additional information relevant to a FCC decision or for referring the record for investigation, enforcement, or prosecution by another agency;
8. Adjudication and Litigation—Where by careful review, the Agency determines that the records are both relevant and necessary to litigation and the use of such records is deemed by the Agency to be for a purpose that is compatible with the purpose for which the Agency collected the records, these records may be used by a court or adjudicative body in a proceeding when: (a) The Agency or any component thereof; or (b) any employee of the Agency in his or her official capacity; or (c) any employee of the Agency in his or her individual capacity where the Agency has agreed to represent the employee; or (d) the United States Government is a party to litigation or has an interest in such litigation;
9. Department of Justice—A record from this system of records may be disclosed to the Department of Justice (DOJ) or in a proceeding before a court or adjudicative body when:
(a) The United States, the Commission, a component of the Commission, or, when represented by the government, an employee of the Commission is a party to litigation or anticipated litigation or has an interest in such litigation, and
(b) The Commission determines that the disclosure is relevant or necessary to the litigation;
10. Breach of Federal Data—A record from this system may be disclosed to appropriate agencies, entities, and persons when: (1) The Commission suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised; (2) the Commission has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by the Commission or another agency or entity) that rely upon the compromised information; and (3) the disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with the Commission's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm;
11. Labor Relations—A record from this system may be disclosed to officials of labor organizations recognized under 5 U.S.C. Chapter 71 upon receipt of a formal request and in accord with the conditions of 5 U.S.C. 7114 when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting working conditions;
12. Employment, Clearances, Licensing, Contract, Grant, or other Benefits Decisions by the agency—A record from this system may be disclosed to a Federal, State, local, foreign, tribal, or other public agency or authority maintaining civil, criminal, or other relevant enforcement records, or other pertinent records, or to another public authority or professional organization, if necessary to obtain information relevant to an investigation concerning the retention of an employee or other personnel action (other than hiring), the retention of a security clearance, the letting of a contract, or
13. Employment, Clearances, Licensing, Contract, Grant, or other Benefits Decisions by other than the agency—A record from this system may be disclosed to a Federal, State, local, foreign, tribal, or other public agency or authority of the fact that this system of records contains information relevant to the retention of an employee, the retention of a security clearance, the letting of a contract, or the issuance or retention of a license, grant, or other benefit. The other agency or licensing organization may then make a request supported by the written consent of the individual for the entire records if it so chooses. No disclosure will be made unless the information has been determined to be sufficiently reliable to support a referral to another office within the agency or to another Federal agency for criminal, civil, administrative, personnel, or regulatory action.
None.
The information pertaining to the FCC Telework Program includes electronic records, files, and data and paper documents, records, and files. HRM and the B/O will jointly manage these electronic data and paper document files:
1. The electronic data will be stored in the computer files housed in the FCC's computer network databases.
2. The paper documents, files and records will be stored in filing cabinets in the HRM office suite and, in the appropriate B/O files, as applicable for teleworking employees.
Information in the FCC Telework Program may be retrieved by various identifiers, including, but not limited to the individual's name, B/O, address, home phone number, and residential address, and supervisor's name.
Access to the electronic files is restricted to authorized HRM and B/O supervisors and staff, and the contractor's supervisors and staff, who manage the FCC computer network databases. The FCC requires that these computer network databases be protected by various security protocols and safeguards, which include, but are not limited to, controlled access, passwords, and other security features. In addition, data in the network servers are routinely backed-up. The servers are stored in a secured environment to protect the data.
The paper documents, including all forms and related documentation, are maintained in file cabinets that are located in HRM and B/Os. The file cabinets are locked when not in use and at the end of the business day. Access to these files is restricted to authorized HRM, B/O supervisors, staff, and contractors. Only authorized staff may be granted access to contact rosters. Paper copies of such rosters must be under the control of the employee or locked in a secure container when not in use. Safeguards in place adhere to Federal standards, including the National Institute of Standard and Technology (NIST) and FCC standards.
The National Archives and Records Administration (NARA) has not established a records schedule for the information in the FCC Telework Program. Consequently, the FCC will maintain the information in the telework program files until NARA approves the appropriate records schedule.
Human Resources Management (HRM), Office of Managing Director (OMD), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554; and Individual FCC Bureaus and Offices, Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554.
Privacy Analyst, Information Technology (IT), Office of Managing Director (OMD), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554.
Privacy Analyst, Information Technology (IT), Office of Managing Director (OMD), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554.
Privacy Analyst, Information Technology (IT), Office of Managing Director (OMD), Federal Communications Commission (FCC), 445 12th Street SW., Washington, DC 20554.
The sources for the information in the FCC Telework Program include, but are not limited to:
1. The information that the FCC employees are required to provide on the FCC Telework Request Form and Agreement, Telework Training Certificate, and Home Safety Self-Certification when they voluntarily seek to participate in the telework program; Reasonable Accommodations Requests; and
2. Information related to an employee's application, which the supervisor may include as part of the terms and conditions for an employee's telework review and approval, disapproval, and/or renewal.
None.
The companies listed in this notice have applied to the Board for approval, pursuant to the Bank Holding Company Act of 1956 (12 U.S.C. 1841
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 applications will also 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 BHC Act (12 U.S.C. 1842(c)). 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 4 of the BHC Act (12 U.S.C. 1843). Unless otherwise noted, nonbanking activities will be conducted throughout the United States.
Unless otherwise noted, comments regarding each of these applications
A. Federal Reserve Bank of New York (Ivan Hurwitz, Vice President) 33 Liberty Street, New York, New York 10045-0001:
1.
The bank holding company listed in this notice has applied to the Board for approval to conduct a minority stock issuance in accordance with the Board's regulations governing mutual holding companies.
The application listed below, as well as other related filings required by the Board, is available for immediate inspection at the Federal Reserve Bank indicated. The application will also be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing.
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 April 23, 2015.
A. Federal Reserve Bank of Boston (Prabal Chakrabarti, Senior Vice President) 600 Atlantic Avenue, Boston, Massachusetts 02210-2204:
1.
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 13, 2015.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President), 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
Federal Trade Commission.
Proposed consent agreement.
The consent agreement in this matter settles alleged violations of federal law prohibiting unfair or deceptive acts or practices. The attached Analysis to Aid Public Comment describes both the allegations in the draft complaint and the terms of the consent order—embodied in the consent agreement—that would settle these allegations.
Comments must be received on or before April 20, 2015.
Interested parties may file a comment at
Svetlana Gans, Bureau of Consumer Protection, (202) 326-3708, 600 Pennsylvania Avenue NW., Washington, DC 20580.
Pursuant to Section 6(f) of the Federal Trade Commission Act, 15 U.S.C. 46(f), and FTC Rule 2.34, 16 CFR 2.34, notice is hereby given that the above-captioned consent agreement containing consent order to cease and desist, having been filed with and accepted, subject to final approval, by the Commission, has been placed on the public record for a period of thirty (30) days. The following Analysis to Aid Public Comment describes the terms of the consent agreement, and the allegations in the complaint. An electronic copy of the full text of the consent agreement package can be obtained from the FTC Home Page (for March 19, 2015), on the World Wide Web at:
You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before April 20, 2015. Write “BMW of North America, LLC—Consent Agreement; File No. 1323150” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, like anyone's Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, like medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which . . . is privileged or confidential,” as discussed in Section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you have to follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c).
Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, we encourage you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at
If you file your comment on paper, write “BMW of North America, LLC—Consent Agreement; File No. 1323150” on your comment and on the envelope, and mail your comment to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610 (Annex D), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor, Suite 5610 (Annex D), Washington, DC 20024. If possible, submit your paper comment to the Commission by courier or overnight service.
Visit the Commission Web site at
The Federal Trade Commission (“FTC” or “Commission”) has accepted, subject to final approval, a consent agreement applicable to BMW of North America, LLC (“respondent”).
The proposed consent order has been placed on the public record for thirty (30) days for receipt of comments by interested persons. Comments received during this period will become part of the public record. After thirty (30) days, the Commission will again review the agreement and comments received, and will decide whether it should withdraw from the agreement and take appropriate action or make final the agreement's proposed order.
The Respondent's MINI Division provides purchasers of new MINI passenger cars a Service and Warranty Information Statement (“Warranty Statement”). According to the FTC complaint, language in the Warranty Statement violates the Magnuson-Moss Warranty Act (“Warranty Act”), 15 U.S.C. 2302(c), by conditioning warranty coverage on the consumer's use of genuine MINI parts and MINI dealers to perform maintenance and repair work.
The FTC enforces the Warranty Act, which regulates consumer warranties and the procedures used to resolve warranty disputes. The broad purposes of the Warranty Act are (1) to improve the adequacy of warranty information available to consumers, and thereby facilitate consumer choice; (2) to prevent deception; and (3) to improve competition in the marketing of consumer products. Among other things, the Warranty Act prohibits a warrantor from conditioning a consumer product's warranty on the consumer's use of an article or a service (other than an article or a service provided without charge) which is identified by brand, trade, or corporate name. 15 U.S.C. 2302(c) (“the anti-tying provision”).
According to the FTC complaint, in connection with the warranty for certain MINI models, respondent has required owners to have routine maintenance, such as oil changes, performed by MINI dealers and to use genuine MINI parts. The complaint alleges that this requirement appears in two places in the Warranty Statement.
First, in order to have a warranty claim approved, owners must demonstrate that they obtained regular maintenance of their vehicles by having a MINI dealer place a stamp in the warranty booklet. See Complaint at ¶ 12. Second, the Warranty Statement states that it “is not obligated to pay for repairs that include non-genuine MINI parts. . . .” (emphasis added). Although respondent provides, with the purchase of its vehicles, a free scheduled maintenance program, many of the models have a three-year maintenance program, but a four-year new vehicle warranty. Thus, according to the complaint, there is one year during the warranty period in which consumers must pay for their maintenance and repair work while being required to use MINI dealers and MINI parts to retain warranty coverage.
The proposed consent order contains provisions designed to prevent respondent from engaging in similar acts or practices in the future. Specifically, Part I prohibits respondent, in connection with the sale of any MINI Division good or service, from violating any provision of the Warranty Act, including, but not limited to, the anti-tying provision. Part II prohibits respondent, in connection with the sale of any MINI good or service, from misrepresenting that vehicles, in order to operate safely or maintain value, must have maintenance work performed by a MINI dealer. Part II also prohibits respondent from misrepresenting any material fact concerning any warranty or maintenance requirements of any MINI good or service.
Part III requires respondent to send notices to all affected consumers informing them that their warranties are not conditioned on repair work being performed by MINI dealers or on the use of genuine MINI parts.
Parts IV through VIII of the proposed order are reporting and compliance provisions. Part IV requires respondent to maintain, and make available to the Commission upon written request, copies of Owner's Manuals and Warranty Statements for each motor
The purpose of this analysis is to facilitate public comment on the proposed order. It is not intended to constitute an official interpretation of the proposed order or to modify its terms in any way.
By direction of the Commission.
Periodically, the Substance Abuse and Mental Health Services Administration (SAMHSA) will publish a summary of information collection requests under OMB review, in compliance with the Paperwork Reduction Act (44 U.S.C. Chapter 35). To request a copy of these documents, call the SAMHSA Reports Clearance Officer on (240) 276-1243.
The Substance Abuse and Mental Health Services Administration (SAMHSA), is requesting approval from the Office of Management and Budget (OMB) for a revision of the 2016 and 2017 Community Mental Health Services Block Grant (MHBG) and Substance Abuse Prevention and Treatment Block Grant (SABG) Plan and Report Guidance and Instructions.
Currently, the SABG and the MHBG differ on a number of their practices (
Increasingly, under the Affordable Care Act, more individuals are eligible for Medicaid and private insurance. This expansion of health insurance coverage will continue to have a significant impact on how State Mental Health Authorities (SMHAs) and Single State Agencies (SSAs) use their limited resources. In 2009, more than 39 percent of individuals with serious mental illnesses (SMI) or serious emotional disturbances (SED) were uninsured. Sixty percent of individuals with substance use disorders whose treatment and recovery support services were supported wholly or in part by SAMHSA block grant funds were also uninsured. A substantial proportion of this population, as many as six million people, will gain health insurance coverage in 2014 and will have various outpatient and other services covered through Medicaid, Medicare, or private insurance. However, these plans will not provide access to the full range of support services necessary to achieve and maintain recovery for most of these individuals and their families.
Given these changes, SAMHSA has conveyed that block grant funds be directed toward four purposes: (1) To fund priority treatment and support services for individuals without insurance or who cycle in and out of health insurance coverage; (2) to fund those priority treatment and support services not covered by Medicaid, Medicare or private insurance offered through the exchanges and that demonstrate success in improving outcomes and/or supporting recovery; (3) to fund universal, selective and targeted prevention activities and services; and (4) to collect performance and outcome data to determine the ongoing effectiveness of behavioral health prevention, treatment and recovery support services and to plan the implementation of new services on a nationwide basis.
To help states meet the challenges of 2016 and beyond, and to foster the implementation of an integrated physical health and mental health and addiction service system, SAMHSA must establish standards and expectations that will lead to an improved system of care for individuals with or at risk of mental and substance use disorders. Therefore, this application package includes fully exercising SAMHSA's existing authority regarding states', territories' and the Red Lake Band of the Chippewa Tribe's (subsequently referred to as “states”) use of block grant funds, and a shift in SAMHSA staff functions to support and provide technical assistance for states receiving block grant funds as they fully integrate behavioral health services into health care.
Consistent with previous applications, the FY 2016-2017 application has sections that are required and other sections where additional information is requested. The FY 2016-2017 application requires states to submit a face sheet, a table of contents, a behavioral health assessment and plan, reports of expenditures and persons served, an executive summary, and funding agreements and certifications. In addition, SAMHSA is requesting information on key areas that are critical to the states success in addressing health care integration. Therefore, as part of this block grant planning process, SAMHSA is asking states to identify their technical assistance needs to implement the strategies they identify in their plans for FY 2016 and 2017.
To facilitate an efficient application process for states in FY 2016-2017, SAMHSA convened an internal workgroup to develop the application for the block grant planning section. In addition, SAMHSA consulted with representatives from SMHAs and SSAs to receive input regarding proposed changes to the block grant. Based on these discussions with states, SAMHSA is proposing several changes to the block grant programs, discussed in greater detail below.
The revisions reflect changes within the planning section of the application. The most significant of these changes relate to evidenced based practice for early intervention for the MHBG, participant directed care, medication assisted treatment for the SABG, crisis services, pregnant women and women with dependent children, community living and the implementation of Olmstead, and quality and data readiness collection.
The FY 2014-2015 application sections on the Affordable Care Act, health insurance marketplace,
The proposed revisions are described below:
•
Implementation by SMHAs, SSAs and their partners of the Affordable Care Act is an important part of efforts to ensure access to care and better integrate care. In a recent report, the Congressional Budget Office estimates that by 2018, 25 million persons will have enrolled in the Affordable Care Act Marketplace and 12 million in Medicaid and the State Children's Health Insurance Program (SCHIP). The Department of Health and Human Services Assistant Secretary for Planning and Evaluation (ASPE) estimates that 32 million Americans will acquire coverage for mental and substance use disorder treatment as a result of the Affordable Care Act, including both previously uninsured persons and those enrolled in plans that lacked adequate coverage. In 2014, non-grandfathered health plans sold in the individual or the small group health insurance markets offered coverage for mental and substance use disorders as an essential health benefit.
•
States can implement models across a continuum, which have demonstrated efficacy, including the range of services and principles identified by NIMH. Utilizing these principles, regardless of the amount of investment, and with leveraging funds through inclusion of services reimbursed by Medicaid or private insurance, every state will be able to begin to move their system toward earlier intervention, or enhance the services already being implemented.
•
States interested in utilizing a voucher system should create or maintain a voucher management system to support vouchering and the reporting of data to enhance accountability by measuring outcomes. Meeting these voucher program challenges by creating and coordinating a wide array of service providers, leading them though the innovations and inherent system change processes results in the building of an integrated system that provides holistic care to individuals recovering from mental and substance use disorders.
•
•
• A crisis response system will have the capacity to recognize and respond to crises across a continuum, from crisis planning, to early stages of support and respite, to crisis stabilization and intervention, to post-crisis follow-up and support for the individual and their family. SAMHSA expects that states will build on the emerging and growing body of evidence for effective community-based crisis response systems. Given the multi-system involvement of many individuals with behavioral health issues, the crisis response system approach provides the infrastructure to improve care coordination and outcomes, manage costs and better invest resources.
•
•
Community living has been a priority across the federal government with recent changes to Section 811 and other housing programs operated by the Department of Housing and Urban Development (HUD). HUD and HHS collaborate to support housing opportunities for persons with disabilities, including persons with mental/substance use disorders. The Department of Justice (DOJ) and HHS Office of Civil Rights (OCR) cooperate on enforcement and compliance measures. DOJ and HHS OCR have expressed concern about some aspects of state mental health systems including use of traditional institutions and other settings that have institutional characteristics to serve persons whose needs could be better met in community settings. More recently, there has been litigation regarding certain employment services such as sheltered workshops. States should ensure Block Grant funds are allocated to support treatment and recovery services in community settings whenever feasible and remain committed, as SAMHSA is, to ensuring services are implemented in accordance with Olmstead and Title II of the ADA.
•
The foundation of this effort is National Quality Behavioral Health Framework, which derives from the National Quality Strategy and seeks to improve the delivery of health care services, individual patient health outcomes, and the overall health of the population. The overarching goals are to ensure that services are evidence-based and effective; that they are person/family-centered; that care is coordinated across systems; that services promote healthy living; and that they are safe, accessible and affordable.
For the FY 2016-2017 MHBG and SABG reports, achieving these goals will result in a more coordinated behavioral health data collection program that complements other existing systems (
SAMHSA anticipates this movement is consistent with the current state authority's movement toward system integration and will minimize challenges associated with changing operational logistics of data collection and reporting. SAMHSA understands some modifications to data collection systems may be necessary, but will work with the states to minimize the impact of these changes.
The overall format has been streamlined to integrate the environmental factors throughout the behavioral health assessment and plan narrative. This has reduced the length of the application by 10 pages.
While the statutory deadlines and block grant award periods remain unchanged, SAMHSA encourages states to turn in their application as early as possible to allow for a full discussion and review by SAMHSA. Applications for the MHBG-only is due no later than September 1, 2015.
The application for SABG-only is due no later than October 1, 2015. A single application for MHBG
The estimated annualized burden for a uniform application is 37,429 hours. Burden estimates are broken out in the following tables showing burden separately for Year 1 and Year 2. Year 1 includes the estimates of burden for the uniform application and annual reporting. Year 2 includes the estimates of burden for the application update and annual reporting. The reporting burden remains constant for both years.
Link for the application:
Written comments and recommendations concerning the proposed information collection should be sent by April 27, 2015 to the SAMHSA Desk Officer at the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB). To ensure timely receipt of comments, and to avoid potential delays in OMB's receipt and processing of mail sent through the U.S. Postal Service, commenters are encouraged to submit their comments to OMB via email to:
The Centers for Disease Control and Prevention (CDC) has submitted 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 notice for
Written comments and suggestions from the public and affected agencies concerning the proposed collection of information are encouraged. Your comments should address any of the following: (a) Evaluate 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) Evaluate the accuracy of the agencies estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (c) Enhance the quality, utility, and clarity of the information to be collected; (d) 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,
To request additional information on the proposed project or to obtain a copy of the information collection plan and instruments, call (404) 639-7570 or send an email to
Colorectal Cancer Control Program Indirect/Non-Medical Cost Study (OMB No. 0920-0963, exp. 4/30/2014)—Reinstatement—National Center for Chronic Disease Prevention and Health Promotion (NCCDPHP), Centers for Disease Control and Prevention (CDC).
Colorectal Cancer (CRC) is the second leading cause of cancer-related deaths in the United States, following lung cancer. Regular CRC screening is now recommended for average-risk persons. While screening rates have increased over the past decade, screening prevalence is still lower than desirable, particularly among individuals with low socioeconomic status. In 2009, the Centers for Disease Control and Prevention (CDC) designed and initiated the population-based Colorectal Cancer Control Program (CRCCP) at 29 sites. The goals of the program are to reduce health disparities in CRC screening, incidence and mortality by promoting CRC screening for the eligible population and providing CRC screening to low-income adults over 50 years of age who have no health insurance or inadequate health insurance for CRC screening.
In 2013 CDC received Office of Management and Budget (OMB) approval to conduct a study to measure the time and costs incurred by patients screened for CRC (OMB No. 0920-0963, exp. 4/30/2014). Understanding the indirect and non-medical costs associated with CRC screening may provide insights on the barriers to screening participation. Information has been collected, however, the target number of respondents was not achieved during the initial approval period. CDC requests OMB approval to reinstate the information collection for one year in order to meet recruitment goals and complete the data analysis as outlined in the original approval.
Information will be collected from a subset of patients enrolled in the CRCCP. Those who undergo screening by FIT or colonoscopy will be asked to complete a specialized questionnaire about the time and personal expense associated with their screening. The FIT questionnaire is estimated to take about 10 minutes. The Colonoscopy questionnaire, which includes additional questions about the preparation and recovery associated with this procedure, has an estimated burden per response of 25 minutes. Demographic information will be collected from all patients who participate in the study.
CDC plans to conduct the information collection in partnership with providers in four states (Alabama, Arizona, Georgia, and Pennsylvania). Providers will be reimbursed for patient navigator time and administrative expense associated with data collection.
The target number of responses for the overall study will result in 300 completed Colonoscopy Questionnaires and 290 completed FIT Questionnaires. To complete the study CDC plans to collect an additional 150 Colonoscopy Questionnaires and an additional 177 FIT Questionnaires.
This information collection will be used to produce estimates of the personal costs incurred by patients who undergo CRC screening by FIT or colonoscopy, and to improve understanding of these costs as potential barriers to participation. Study findings will be disseminated through reports, presentations, and publications. Results will also be used by participating sites, CDC, and other federal agencies to improve delivery of CRC screening services and to increase screening rates among low-income adults over 50 years of age who have no health insurance or inadequate health insurance for CRC screening.
OMB approval is requested for one year. Each respondent will have the option of completing a hardcopy questionnaire or an on-line questionnaire. No identifiable information will be collected by CDC or CDC's data collection contractor. Participation is voluntary and there are no costs to respondents other than their time. The total estimated annualized burden hours are 93.
Federal Emergency Management Agency, DHS.
Notice.
This notice extends the comment period for the proposed “Revised Guidelines for Implementing Executive Order 11988, Floodplain Management” published in the
The comment period is extended until May 6, 2015.
Comments must be identified by docket ID FEMA-2015-0006 and may be submitted by one of the following methods:
Bradley Garner, 202-646-3901 or
On January 30, 2015, the President signed Executive Order 13690, directing FEMA, on behalf of the Mitigation Framework Leadership Group, to publish for public comment draft revised Floodplain Management Guidelines to provide guidance to agencies on the implementation of Executive Order 11988, as amended, consistent with a new Federal Flood Risk Management Standard. These draft revised Guidelines were developed by the Mitigation Framework Leadership Group in consultation with the Federal Interagency Floodplain Management Task Force. On February 5, 2015, FEMA published the proposed “Revised Guidelines for Implementing Executive Order 11988, Floodplain Management” on behalf of the Mitigation Framework Leadership Group to solicit and consider public input.
The Mitigation Framework Leadership Group has received several comments regarding the 60-day time period to submit comments. The commenters stated that they needed additional time to review and adequately respond to the proposed revised guidelines because of the complex nature of the topic. Because of the scope of the proposed revised guidelines, and because the Mitigation Framework Leadership Group has specifically requested the public's comments on the proposed revised guidelines in an attempt to benefit from the experience of all interested parties, the comment period will be extended for an additional 30 days. This notice announces the extension of the public comment period to May 6, 2015.
Executive Order 11988, as amended; Executive Order 13690.
Bureau of Land Management, Interior.
Notice of public meetings.
In accordance with the Federal Land Policy and Management Act (FLPMA), the Federal Advisory Committee Act of 1972 (FACA), the U.S. Department of the Interior, Bureau of Land Management (BLM) Twin Falls District Resource Advisory Council (RAC) will meet as indicated below.
The Twin Falls District RAC will meet April 22, 2015, at the Sawtooth Best Western Inn, 2653 S. Lincoln Avenue, Jerome, Idaho 83338. The meeting will begin at 9:00 a.m. and end no later than 3:00 p.m. The public comment period will take place from 9:10 a.m. to 9:40 a.m.
Heather Tiel-Nelson, Twin Falls District, Idaho, 2536 Kimberly Road, Twin Falls, Idaho 83301, (208) 736-2352.
The 15-member RAC advises the Secretary of the Interior, through the Bureau of Land Management, on a variety of planning and management issues associated with public land management in Idaho. During the April 22nd meeting, there will be an overview of the roles and responsibilities of a BLM manager, an update on the Idaho and Southwest Montana Sub-regional Sage-Grouse Draft Environmental Impact Statement, and field office updates. Additional topics may be added and will be included in local media announcements.
More information is available at
43 CFR 1784.4-1.
Fish and Wildlife Service, Interior.
Call for nominations.
The Secretary of the Interior and the Secretary of Agriculture seek nominations for individuals to be considered as members of the Wildlife and Hunting Heritage Conservation Council (Council). The Council provides advice about wildlife and habitat conservation endeavors that (a) benefit wildlife resources; (b) encourage partnership among the public, sporting conservation organizations, States, Native American tribes, and the Federal Government; and (c) benefit recreational hunting. Nominations should describe and document the proposed nominee's qualifications for membership to the Council, and include a resume listing his or her full name, address, telephone, and fax number.
Written nominations must be received by April 27, 2015.
Send nominations to Joshua Winchell, Designated Federal Officer and Coordinator, Wildlife and Hunting Heritage Conservation Council, U.S. Fish and Wildlife Service, National Wildlife Refuge System, 5275 Leesburg Pike, Falls Church, VA 22041-3803.
Joshua Winchell, at address above, or by telephone at (703) 358-2639.
The Council conducts its operations in accordance with the provisions of the Federal Advisory Committee Act (5 U.S.C. App.; FACA). It reports to the Secretary of the Interior and the Secretary of Agriculture through the Fish and Wildlife Service, in consultation with the Director of the Bureau of Land Management; the Director of the National Park Service; the Chief, U.S. Forest Service; the Chief, Natural Resources Conservation Service; and the Administrator of the Farm Service Agency. The Council functions solely as an advisory body. The Council's duties consist of, but are not limited to, providing recommendations for:
(a) Implementing the
(b) Increasing public awareness of and support for the Wildlife Restoration Program;
(c) Fostering wildlife and habitat conservation and ethics in hunting and shooting sports recreation;
(d) Stimulating sportsmen and women's participation in conservation and management of wildlife and habitat resources through outreach and education;
(e) Fostering communication and coordination among State, tribal, and Federal governments; industry; hunting and shooting sportsmen and women; wildlife and habitat conservation and management organizations; and the public;
(f) Providing appropriate access to Federal lands for recreational shooting and hunting;
(g) Providing recommendations to improve implementation of Federal conservation programs that benefit wildlife, hunting, and outdoor recreation on private lands; and
(h) When requested by the Designated Federal Officer (DFO) in consultation with the Council Chairman, performing a variety of assessments or reviews of policies, programs, and efforts through the Council's designated subcommittees or workgroups.
The Council consists of no more than 18 discretionary members. The Secretary of the Interior and the Secretary of Agriculture appoint discretionary members for 3-year terms. The Secretaries will select discretionary members from among the national interest groups listed below. These members must be senior-level representatives of their organizations and/or have the ability to represent their designated constituency.
(1) State fish and wildlife resource management agencies;
(2) Wildlife and habitat conservation/management organizations;
(3) Game bird hunting organizations;
(4) Waterfowl hunting organizations;
(5) Big game hunting organizations;
(6) Sportsmen and women community at large;
(7) Archery, hunting, and/or shooting sports industry;
(8) Hunting and shooting sports outreach and education organizations;
(9) Tourism, outfitter, and/or guide industries related to hunting and/or shooting sports; and
(10) Tribal resource management organizations.
The Council functions solely as an advisory body and in compliance with provisions of the FACA.
Individuals who are federally registered lobbyists are ineligible to serve on all FACA and non-FACA boards, committees, or councils in an individual capacity. The term “individual capacity” refers to individuals who are appointed to exercise their own individual best judgment on behalf of the government, such as when they are designated Special Government Employees, rather than being appointed to represent a particular interest.
Bureau of Safety and Environmental Enforcement, Interior.
60-Day notice.
To comply with the Paperwork Reduction Act of 1995 (PRA), BSEE is inviting comments on a collection of information that we will submit to the Office of Management and Budget (OMB) for review and approval. The information collection request (ICR) concerns a renewal to the paperwork requirements in the regulations under
You must submit comments by May 26, 2015.
You may submit comments by either of the following methods listed below.
• Electronically go to
• Email
Cheryl Blundon, Regulations and
The authorities and responsibilities described above are among those delegated to the Bureau of Safety and Environmental Enforcement (BSEE). Therefore, this ICR addresses the regulations at 30 CFR 282,
BSEE will use the information required by 30 CFR 282 to determine if lessees are complying with the regulations that implement the mining operations program for minerals other than oil, gas, and sulphur. Specifically, BSEE will use the information:
• To ensure that operations for the production of minerals other than oil, gas, and sulphur in the OCS are conducted in a manner that will result in orderly resource recovery, development, and the protection of the human, marine, and coastal environments.
• To ensure that adequate measures will be taken during operations to prevent waste, conserve the natural resources of the OCS, and to protect the environment, human life, and correlative rights.
• To determine if suspensions of activities are in the national interest, to facilitate proper development of a lease including reasonable time to develop a mine and construct its supporting facilities, and to allow for the construction or negotiation for use of transportation facilities.
• To identify and evaluate the cause(s) of a hazard(s) generating a suspension, the potential damage from a hazard(s) and the measures available to mitigate the potential for damage.
• For technical evaluations that provide a basis for BSEE to make informed decisions to approve, disapprove, or require modification of the proposed activities.
We protect proprietary information according to the Freedom of Information Act (5 U.S.C. 552) and DOI's implementing regulations (43 CFR 2), and §§ 282.5, 282.6, and 282.7. Responses are mandatory or are required to obtain or retain a benefit.
Agencies must also estimate the non-hour paperwork cost burdens to respondents or recordkeepers resulting from the collection of information. Therefore, if you have other than hour burden costs to generate, maintain, and disclose this information, you should comment and provide your total capital and startup cost components or annual operation, maintenance, and purchase of service components. For further information on this burden, refer to 5 CFR 1320.3(b)(1) and (2), or contact the Bureau representative listed previously in this notice.
We will summarize written responses to this notice and address them in our submission for OMB approval. As a result of your comments, we will make any necessary adjustments to the burden in our submission to OMB.
Bureau of Land Management, Interior.
Public land order.
This order transfers administrative jurisdiction over 76.60 acres of public lands from the Bureau of Land Management to the National Park Service for administration as part of the Wind Cave National Park in Custer County, South Dakota.
Doris Morrow, National Park Service, 601 Riverfront Drive, Omaha, Nebraska 68102-4226, 402-661-1784,
Public Law 109-71, enacted September 21, 2005, revised the Wind Cave National Park boundary and directed the Secretary of the Interior to transfer administrative jurisdiction of the public lands described in this order to the National Park Service for administration as part of Wind Cave National Park.
By virtue of the authority vested in the Secretary of the Interior and as directed by Public Law 109-71 (119 Stat. 2011) (2005), it is ordered as follows:
Administrative jurisdiction of the following described lands is hereby transferred from the Bureau of Land Management to the National Park Service:
The areas described aggregate 76.60 acres in Custer County.
Bureau of Land Management, U.S. Department of the Interior.
Notice of public meeting.
In accordance with the Federal Land Policy and Management Act (FLPMA) and the Federal Advisory Committee Act of 1972 (FACA), the U.S. Department of the Interior, Bureau of Land Management (BLM) Boise District Resource Advisory Council (RAC), will hold a meeting as indicated below.
The meeting will be held April 21, 2015, at the Ontario, Oregon Clarion Inn, located at 1249 Tapadera Avenue, Ontario, Oregon 97914, beginning at 9:00 a.m. and adjourning at 4:00 p.m. Members of the public are invited to attend. A public comment period will be held at 11:00 a.m.
Marsha Buchanan, Supervisory Administrative Specialist and RAC Coordinator, BLM Boise District, 3948 Development Ave., Boise, Idaho 83705, Telephone (208) 384-3364.
The 15-member Council advises the Secretary of the Interior, through the BLM, on a variety of planning and management issues associated with public land management in southwestern Idaho. During the April meeting the Boise District Council will meet with the Southeast Oregon Council to discuss the Tri-State project. Following that discussion the Boise Council will introduce new members and organize for the upcoming term, to include
Bureau of Land Management, Interior.
Notice of Filing of Plats of Survey; Colorado.
The Bureau of Land Management (BLM) Colorado State Office is publishing this notice to inform the public of the intent to officially file the survey plat listed below and afford a proper period of time to protest this action prior to the plat filing. During this time, the plat will be available for review in the BLM Colorado State Office.
Unless there are protests of this action, the filing of the plat described in this notice will happen on April 27, 2015.
BLM Colorado State Office, Cadastral Survey, 2850 Youngfield Street, Lakewood, CO 80215-7093.
Randy Bloom, Chief Cadastral Surveyor for Colorado, (303) 239-3856.
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 above individual during normal business hours. The FIRS is available 24 hours a day, seven days a week, to leave a message or question with the above individual. You will receive a reply during normal business hours.
The plat incorporating the field notes of the dependent resurvey in Township 13 South, Range 69 West, Sixth Principal Meridian, Colorado, was accepted on March 11, 2015.
United States International Trade Commission.
March 31, 2015 at 9:30 a.m.
Room 101, 500 E Street SW., Washington, DC 20436, Telephone: (202) 205-2000.
Open to the public.
1. Agendas for future meetings: None.
2. Minutes.
3. Ratification List.
4. Vote in Inv. Nos. 701-TA-432, 731-TA-1024-1028, and AA1921-188 (Second Review) (Prestressed Concrete Steel Wire Strand from Brazil, India, Japan, Korea, Mexico, and Thailand). The Commission is currently scheduled to complete and file its determinations and views of the Commission on April 10, 2015.
5. Outstanding action jackets: None.
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 to review-in-part an initial determination (“ID”) (Order No. 13) issued by the presiding administrative law judge (“ALJ”) in the above-captioned investigation. Particularly, the Commission has determined to review the determination on domestic industry in the ID. Upon review, the Commission affirms a finding of domestic industry with modifications. The Commission's determination results in a determination of a violation of section 337 of the Tariff Act of 1930, as amended (19 U.S.C. 1337 or “section 337”). Accordingly, the Commission requests written submissions, under the schedule set forth below, on remedy, public interest, and bonding.
Clark S. Cheney, Office of the General Counsel, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone 202-205-2661. Copies of non-confidential documents filed in connection with this investigation are or will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone 202-205-2000. General information concerning the Commission may also be obtained by accessing its Internet server (
The Commission instituted this investigation on August 6, 2014, based on a complaint filed by Choon's Design, Inc., of Wixom, Michigan (“Choon's”). 79 FR 45844-45
On December 5, 2014, Choon's moved for a summary determination of a violation of section 337 and for issuance of a general exclusion order. On December 17, 2014, the Commission investigative attorney (“IA”) submitted a response supporting the motion. No other responses to the motion were received.
On February 3, 2015, the ALJ issued an ID granting Choon's motion for summary determination of violation and recommending the issuance of a general exclusion order.
On February 18, 2015, Choon's filed a response to the IA's petition. Choon's took no position as to whether patent prosecution costs or visiting Chinese manufacturers count as domestic industry investments. Choon's agreed with the IA that certain domestic expenditures should be included in the domestic investment total and that the economic prong of the domestic industry requirement has been met.
The Commission has determined to review only the domestic industry economic prong determination in the ID. Upon review, the Commission affirms a finding that Choon's has shown a substantial investment in the exploitation of the '565 patent through engineering, and research and development of articles protected by the '565 patent, but the Commission modifies certain portions of the ID regarding the expenditures comprising the domestic industry investments. The Commission's modifications will be specified in a later Commission opinion.
In connection with the final disposition of this investigation, the Commission may (1) issue an order that could result in the exclusion of the subject articles from entry into the United States, and/or (2) issue one or more cease and desist orders that could result in one or more respondents being required to cease and desist from engaging in unfair acts in the importation and sale of such articles. Accordingly, the Commission is interested in receiving written submissions that address the form of remedy, if any, that should be ordered. If a party seeks exclusion of an article from entry into the United States for purposes other than entry for consumption, the party should so indicate and provide information establishing that activities involving other types of entry either are adversely affecting it or likely to do so. For background, see
If the Commission contemplates some form of remedy, it must consider the effects of that remedy upon the public interest. The factors the Commission will consider include the effect that an exclusion order and/or cease and desist orders would have on (1) the public health and welfare, (2) competitive conditions in the U.S. economy, (3) U.S. production of articles that are like or directly competitive with those that are subject to investigation, and (4) U.S. consumers. The Commission is therefore interested in receiving written submissions that address the aforementioned public interest factors in the context of this investigation. If the Commission orders some form of remedy, the U.S. Trade Representative, as delegated by the President, has 60 days to approve or disapprove the Commission's action.
Written Submissions: Parties to the investigation, interested government agencies, and any other interested parties are encouraged to file written submissions on the issues of remedy, the public interest, and bonding. Complainant and the IA are also requested to submit proposed remedial orders for the Commission's consideration. Complainant is also requested to state the date on which the '565 patent expires and the HTSUS subheadings under which the accused products are imported.
Written submissions must be filed no later than close of business on April 3, 2015. Reply submissions must be filed no later than the close of business on April 10, 2015. Such submissions should address the ALJ's recommended determinations on remedy and bonding which were made in Order No. 13. No further submissions on any of these issues will be permitted unless otherwise ordered by the Commission.
Persons filing written submissions must file the original document electronically on or before the deadlines stated above and submit eight true paper copies to the Office of the Secretary by noon the next day pursuant to section 210.4(f) of the Commission's Rules of Practice and Procedure (19 CFR 210.4(f)). Submissions should refer to the investigation number (“Inv. No. 337-TA-923”) in a prominent place on the cover page and/or the first page.
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.
Department of Justice.
Notice of a new system of records and removal of one system of records notice.
Pursuant to the Privacy Act of 1974, 5 U.S.C. 552a, and Office of Management and Budget (OMB) Circular No. A-130, notice is hereby given that the Department of Justice (Department or DOJ) proposes to establish a new Department-wide system of records entitled, “Department of Justice,
In accordance with 5 U.S.C. 552a(e)(4) and (11), the public is given a 30-day period in which to comment. Therefore, please submit any comments by April 27, 2015.
The public, OMB, and Congress are invited to submit any comments to the Department of Justice, ATTN: Privacy Analyst, Office of Privacy and Civil Liberties, U.S. Department of Justice, National Place Building, 1331 Pennsylvania Avenue NW., Suite 1000, Washington, DC 20530, or by facsimile at (202) 307-0693. To ensure proper handling, please reference the CPCLO Order Number indicated above on your correspondence.
Tricia Francis, Executive Office for United States Attorneys, FOIA/Privacy Act Staff, 600 E Street NW., Suite 7300, Washington, DC 20530, or by facsimile at (202) 252-6047.
This Department-wide system notice replaces the notice for the system entitled, “United States Attorney's Office,
In accordance with 5 U.S.C. 552a(r), the Department has provided a report to OMB and Congress on this new system of records.
Department of Justice,
Unclassified.
Records in this system are located at United States Attorneys' Offices and Department of Justice litigating sections with authority to prosecute criminal cases (“DOJ prosecuting offices”) as well as the Federal Bureau of Investigation, the Drug Enforcement Administration, the Bureau of Alcohol, Tobacco, Firearms and Explosives, the United States Marshals Service, the Office of the Inspector General, and the Office of Professional Responsibility (“DOJ investigative agencies”). For office locations, see
Individuals who may serve as affiants or testify as witnesses in criminal proceedings brought by the United States Attorneys' Offices and Department of Justice litigating sections with authority to prosecute criminal cases, including the Criminal Division, National Security Division, Civil Rights Division, Antitrust Division, Environment and Natural Resources Division, Tax Division, and Civil Division.
This system contains potential witness impeachment information, including records of disciplinary actions. Potential impeachment information has been generally defined as impeaching information which is material to the defense of a federal criminal prosecution. It also includes information that either casts a substantial doubt upon the accuracy of any evidence, including witness testimony, the prosecutor intends to rely on to prove an element of any crime charged or might have a significant bearing on the admissibility of
This system is established and maintained under the authority of 28 U.S.C. 516 and 547.
The purpose of this system is to ensure that the Department's prosecutors and investigative agencies receive sufficient information to meet their obligations under
Primary users of this system will be Agency Officials, who are senior officials serving as the points of contact concerning potential impeachment information within each of the Department's investigative agencies; Requesting Officials, who are senior officials serving as the points of contact concerning potential impeachment information within each of the Department's prosecuting offices; and Assistant United States Attorneys and other Department attorneys who are prosecuting cases and have an obligation to disclose impeachment material under the
A record maintained in the system of records may be disseminated as a routine use of such record as follows:
(a) A record will be provided to a court and/or defense attorney in satisfaction of the Department's obligations under the
(b) In an appropriate proceeding before a court, grand jury, or administrative or adjudicative body, when the Department of Justice determines that the records are arguably relevant to the proceeding; or in an appropriate proceeding before an administrative or adjudicative body when the adjudicator determines the records to be relevant to the proceeding.
(c) Where a record, either alone or in conjunction with other information, indicates a violation or potential violation of law—criminal, civil, or regulatory in nature—the relevant records may be referred to the appropriate federal, state, local, territorial, tribal, or foreign law enforcement authority or other appropriate entity charged with the responsibility for investigating or prosecuting such violation or charged with enforcing or implementing such law.
(d) To any person or entity that the Department has reason to believe possesses information regarding a matter within the jurisdiction of the Department, to the extent deemed to be necessary by the Department in order to elicit such information or cooperation from the recipient for use in the performance of an authorized activity.
(e) A record relating to a case or matter may be disseminated in connection with a federal, state, or local administrative or regulatory proceeding or hearing in accordance with the procedures governing such proceeding or hearing.
(f) A record relating to a case or matter may be disseminated in an appropriate federal, state, local, or foreign court or grand jury proceeding in accordance with established constitutional, substantive, or procedural law or practice.
(g) A record relating to a case or matter that has been referred by an agency for investigation, prosecution, or enforcement, or that involves a case or matter within the jurisdiction of an agency, may be disseminated to such agency to notify the agency of the status of the case or matter or of any decision or determination that has been made, or to make such other inquiries and reports as are necessary during the processing of the case or matter.
(h) To the news media and the public, including disclosures pursuant to 28 CFR 50.2, unless it is determined that release of the specific information in the context of a particular case would constitute an unwarranted invasion of personal privacy.
(i) To a Member of Congress or staff acting upon the Member's behalf when the Member or staff requests the information on behalf of, and at the request of, the individual who is the subject of the record.
(j) To the National Archives and Records Administration for purposes of records management inspections conducted under the authority of 44 U.S.C. 2904 and 2906.
(k) To a former employee of the Department for purposes of: Responding to an official inquiry by a federal, state, or local government entity or professional licensing authority, in accordance with applicable Department regulations; or facilitating communications with a former employee that may be necessary for personnel-related or other official purposes where the Department requires information and/or consultation assistance from the former employee regarding a matter within that person's former area of responsibility.
(l) To appropriate agencies, entities, and persons when (1) the Department suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised; (2) the Department has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by the Department or another agency or entity) that rely upon the compromised information; and (3) the disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with the Department's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
(m) To such recipients and under such circumstances and procedures as are mandated by federal statute or treaty.
None.
Records in this system are stored in paper and/or electronic format. Electronic records are stored in databases and/or on hard disks, removable storage devices, or other electronic media. Paper records may be stored in individual file folders and file cabinets with controlled access, and/or other appropriate GSA-approved security containers.
Individual records are accessed by use of data-retrieval capabilities of computers. Hard-copy formats are accessed via manual retrieval. Data will be retrieved through a number of criteria, including witness or affiant name, case name, or other personal identifier.
Records are safeguarded in accordance with applicable laws, rules, and policies, including the Department's automated systems security and access policies and the Attorney General's
Records are retained and destroyed in accordance with applicable schedules and procedures issued or approved by the National Archives and Records Administration (NARA). Retention periods vary depending on the type of the record. The General Records Schedule (GRS) for
The system managers for this system are the
Address inquiries to the System Managers listed above.
For Antitrust Division information contact: FOIA/PA Unit, DOJ/Antitrust Division, 450 Fifth Street NW., Suite 1000, Washington, DC 20530-0001.
For the Bureau of Alcohol, Tobacco, Firearms and Explosives information contact: Disclosure Division, DOJ/Bureau of Alcohol, Tobacco, Firearms and Explosives, 99 New York Avenue NE., Room 1E 400, Washington, DC 20226.
For Civil Division information contact: FOIA/PA Office, DOJ/Civil Division, Room 7304, 20 Massachusetts Avenue NW., Washington, DC 20530.
For Civil Rights Division information contact: FOIA/PA Branch, DOJ/Civil Rights Division, 950 Pennsylvania Avenue NW., Room 3234, Washington, DC 20530-0001.
For Criminal Division information contact: FOIA/PA Unit, DOJ/Criminal Division, Keeney Building, Suite 1127, Washington, DC 20530-0001.
For Drug Enforcement Administration information contact: FOIA/PA Unit (SARF), DOJ/Drug Enforcement Administration, 8701 Morrissette Drive, Springfield, VA 22152.
For Environment and Natural Resources Division information contact: FOIA/PA Office, Law and Policy Section, DOJ/Environment and Natural Resources Division, P.O. Box 4390, Ben Franklin Station, Washington, DC 20044-4390.
For Executive Office for United States Attorneys information contact: FOIA/PA Staff, DOJ/EOUSA, 600 E Street NW., Room 7300, Washington, DC 20530-0001. Contact information for individual United States Attorneys' Offices in the 94 Federal judicial districts nationwide can be located at
For Federal Bureau of Investigation information contact: Federal Bureau of Investigation, Record/Information Dissemination Section, 170 Marcel Drive, Winchester, VA 22602-4483.
For National Security Division information contact: FOIA Public Liaison, DOJ/National Security Division, 950 Pennsylvania Avenue NW., Room 6150, Washington, DC 20530-0001.
For Office of the Inspector General information contact: FOIA Contact, DOJ/Office of the Inspector General, Office of General Counsel, 950 Pennsylvania Avenue NW., Room 4726, Washington, DC 20530.
For Office of Professional Responsibility information contact: Special Counsel for FOIA/PA, DOJ/Office of Professional Responsibility, 950 Pennsylvania Avenue NW., Suite 3266, Washington, DC 20530.
For Tax Division information contact: Assistant Attorney General, Tax Division, U.S. Department of Justice, 950 Pennsylvania Avenue NW., Washington, DC 20530.
For United States Marshals Service information contact: FOIA/PA Officer, Office of General Counsel, DOJ/U.S. Marshals Service, CS4, 10th Floor, 2604 Jefferson Davis Highway, Alexandria, VA 22301.
A request for access to a record in this system must be submitted in writing and comply with 28 CFR part 16. The envelope and the letter should be clearly marked “Privacy Act Access Request.” The request should include a general description of the records sought and must include the requester's full name, current address, and date and place of birth. The request must be signed and dated and either notarized or submitted under the penalty of perjury. Although no specific form is required, requesters may obtain a form (Form DOJ-361) for use in certification of identity from the FOIA/Privacy Act Mail Referral Unit, Justice Management Division, United States Department of Justice, 950 Pennsylvania Avenue NW., Washington, DC 20530-0001, or from the Department's Web site at
Individuals seeking to contest or amend information maintained in the system should direct their requests to the address indicated in the “Record Access Procedures” section, above. The request must comply with 28 CFR 16.46 and state clearly and concisely what information is being contested, the reasons for contesting it, and the proposed amendment to the record(s). Some information may be exempt from the amendment provisions, as described in the section entitled “Exemptions Claimed for the System.” An individual who is the subject of a record in this system may seek amendment of those records that are not exempt. A determination whether a record may be amended will be made at the time a request is received.
Sources of records contained in this system include, but are not limited to, individuals covered by the system; reports of Federal, state, and local law enforcement agencies; client agencies of the Department; other non-Department of Justice investigative agencies; other Federal, state, and local law enforcement information; data, memoranda, and reports from the Court and agencies thereof; disciplinary records; publicly available information, including electronic court records; and the work product of Assistant United States Attorneys and other DOJ attorneys, staff, and legal assistants working on particular cases.
The Attorney General has exempted this system from subsections (c)(3) and (4); (d)(1), (2), (3), and (4); (e)(1), (2), (3), (4)(G), (H), and (I), (5), and (8); (f); and (g) of the Privacy Act pursuant to 5 U.S.C. 552a(j) and (k). The exemptions will be applied only to the extent that the information in the system is subject to exemption pursuant to 5 U.S.C. 552a(j) and (k). Rules have been promulgated in accordance with the requirements of 5 U.S.C. 553(b), (c) and (e) and have been published in the
Office of the Associate Attorney General, Justice.
Announcement of successful applications for pilot project.
The Associate Attorney General, exercising authority delegated by the Attorney General, is granting the requests of two Indian tribes to be designated as participating tribes under section 204 of the Indian Civil Rights Act of 1968, as amended, on an accelerated basis, under the voluntary pilot project described in section 908(b)(2) of the Violence Against Women Reauthorization Act of 2013.
This announcement is effective immediately.
Mr. Tracy Toulou, Director, Office of Tribal Justice, Department of Justice, 950 Pennsylvania Avenue NW., Room 2310, Washington, DC 20530, email
Mr. Tracy Toulou, Director, Office of Tribal Justice, Department of Justice, at (202) 514-8812 (not a toll-free number) or
Section 908(b)(2) of the Violence Against Women Reauthorization Act of 2013 (VAWA 2013) establishes a voluntary pilot project for Indian tribes that wish to commence exercising jurisdiction on an accelerated basis over certain crimes of domestic violence and dating violence and certain criminal violations of protection orders in Indian country. This announcement provides public notice that the Associate Attorney General, exercising authority delegated by the Attorney General, is granting the requests of two Indian tribes to be designated as participating tribes under section 204 of the Indian Civil Rights Act of 1968, as amended, on an accelerated basis, under the voluntary pilot project described in section 908(b)(2) of VAWA 2013. The two tribes are (in alphabetical order):
• The Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation, and
• the Sisseton-Wahpeton Oyate of the Lake Traverse Reservation.
In deciding to grant the two tribes' requests, the Department of Justice followed the procedures described in the Department's final notice on the Pilot Project for Tribal Jurisdiction over Crimes of Domestic Violence, 78 FR 71645 (Nov. 29, 2013). The Department of Justice coordinated with the Department of the Interior, consulted with affected Indian tribes, and concluded that the criminal justice system of each of the three tribes has adequate safeguards in place to protect defendants' rights, consistent with 25 U.S.C. 1304.
Prior to exercising SDVCJ, each of the two tribes will notify its community that the tribe will soon commence prosecuting “special domestic violence criminal jurisdiction” (SDVCJ) cases. That notification will include sending press releases to the print and electronic media outlets in the tribe's area.
The Department of Justice will post on its Tribal Justice and Safety Web site (
Bureau of Alcohol, Tobacco, Firearms and Explosives, Department of Justice.
30-day notice.
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF) will submit 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
The purpose of this notice is to allow for an additional 30 days for public comment until April 27, 2015.
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 William Majors, Chief, Firearms and Explosives Import Branch, 244 Needy Road, Martinsburg, WV 25405. 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 20503 or send email 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:
• Evaluate 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;
• 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;
• Enhance the quality, utility, and clarity of the information to be collected; and
• 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,
Overview of this Information Collection 1140-0087:
(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.
Employment and Training Administration, Labor.
Notice.
The Department of Labor, as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents can be properly assessed. Currently, the Employment and Training Administration is soliciting comments concerning the collection of data regarding the Youth Build Reporting System (expires May 31, 2015).
A copy of the proposed information collection request (ICR) can be obtained by contacting the office listed below in the
Written comments must be submitted to the office listed in the addressee's section below on or before May 26, 2015.
Submit written comments to Jenn Smith, Room N-4511, Employment and Training Administration, 200 Constitution Avenue NW., Washington, DC 20210. Telephone number: 202-693-3597 (this is not a toll-free number). Fax: 202-693-3113. Email:
This is a request for the Department of Labor, Employment and Training Administration's (ETA) to extend the reporting and recordkeeping requirements of the YouthBuild (YB) program. This reporting structure features standardized data collection for program participants through quarterly Management Information System (MIS) performance reports and Wok Site
The quarterly performance report (ETA-9136) includes aggregate and participant-level information on demographic characteristics, types of services received, placements, outcomes, and follow-up status. Specifically, these reports collect data on individuals who receive education, occupational skill training, leadership development services, and other services essential to preparing at-risk youth for in-demand occupations through YouthBuild programs. There are no changes proposed for ETA-9136 in this information collection request package. The Work Site Description and Housing Census (ETA-9143) requests information on the proposed work sites for low-income or homeless individual or families on which YouthBuild participants will be trained and participate in construction skills activities. This form also requests annual information on the number of houses or apartments that were built or renovated each year and allows ETA to demonstrate on an annual basis the increase in affordable housing units supported by YouthBuild.
The accuracy, reliability, and comparability of program reports submitted by grantees using federal funds are fundamental elements of good public administration and are necessary tools for maintaining and demonstrating system integrity. The use of a standard set of data elements, definitions, and specifications at all levels of the workforce system helps improve the quality of performance information that is received by ETA.
The Department of Labor is particularly interested in comments which:
* Evaluate 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;
* 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;
* enhance the quality, utility, and clarity of the information to be collected; and
* 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 submitted in response to this comment request will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
National Science Foundation.
Notice.
The National Science Foundation (NSF) is announcing plans to request reinstatement and approval of this data collection. In accordance with the requirement of Section 3506(c)(2)(A) of the Paperwork Reduction Act of 1995, we are providing opportunity for public comment on this information collection.
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 shall have practical utility; (b) the accuracy of the Agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information on respondents, including through the use of automated collection techniques or other forms of information technology; and (d) ways to minimize the burden of the collection of information on
Written comments should be received by May 26, 2015 to be assured of consideration. Comments received after that date will be considered to the extent practicable.
Written comments regarding the information collection and requests for copies of the proposed information collection request should be addressed to Suzanne Plimpton, Reports Clearance Officer, National Science Foundation, 4201 Wilson Blvd., Rm. 295, Arlington, VA 22230, or by email to
Suzanne Plimpton on (703) 292-7556 or send email to
In the most recent FY 2013 Facilities Survey, a census of 588 academic institutions was conducted. The sampling frame for the survey was the FY 2012 Higher Education Research and Development Survey conducted by the National Center for Science and Engineering Statistics. Data are collected through a Web-based interface, although institutions have the option of printing and completing a PDF that can be sent by mail.
The National Science Board's Executive Committee, pursuant to NSF regulations (45 CFR part 614), the National Science Foundation Act, as amended (42 U.S.C. 1862n-5), and the Government in the Sunshine Act (5 U.S.C. 552b), hereby gives notice of the scheduling of a teleconference for the transaction of National Science Board business, as follows:
Wednesday, March 25, 2015, 10:30-11:30 a.m. EDT.
Chairman's remarks and discussion of legislative issues.
Closed.
This meeting will be held by teleconference. Please refer to the National Science Board Web site
Postal Service
Notice.
The Postal Service gives notice of filing a request with the Postal Regulatory Commission to add a domestic shipping services contract to the list of Negotiated Service Agreements in the Mail Classification Schedule's Competitive Products List.
Elizabeth A. Reed, 202-268-3179.
The United States Postal Service® hereby gives notice that, pursuant to 39 U.S.C. 3642 and 3632(b)(3), on March 20, 2015, it filed with the Postal Regulatory Commission a
On December 4, 2014, BATS Exchange, Inc. (the “Exchange” or
The Exchange proposes to replace current Exchange Rule 20.6 (“Current Rule”), entitled “Obvious Error,” with new Exchange Rule 20.6 (“Proposed Rule”), entitled “Nullification and Adjustment of Options Transactions including Obvious Errors.” Exchange Rule 20.6 relates to the adjustment and nullification of transactions that occur on the Exchange's equity options platform (“BATS Options”).
The Exchange has been working with other options exchanges to identify ways to improve the process related to the adjustment and nullification of erroneous options transactions. The Proposed Rule is the culmination of a coordinated effort by the options exchanges to address the August 22, 2013, halt of trading in Nasdaq-listed securities (“Nasdaq SIP Failure”). Following the Nasdaq SIP Failure, the Chair of the Commission met with the heads of the securities exchanges to discuss potential initiatives aimed at addressing market resilience.
The Exchange proposes to adopt various definitions that will be used in the Proposed Rule, as described below.
First, the Exchange proposes to adopt a definition of “Customer,” to make clear that this term would not include any broker-dealer or Professional Customer.
Second, the Exchange proposes to adopt definitions for both an “erroneous sell transaction” and an “erroneous buy transaction.” As proposed, an erroneous sell transaction is one in which the price received by the person selling the option is erroneously low, and an erroneous buy transaction is one in which the price paid by the person purchasing the option is erroneously high.
Third, the Exchange proposes to adopt a definition of “Official,” which would mean an Officer of the Exchange or such other employee designee of the Exchange that is trained in the application of the Proposed Rule.
Fourth, the Exchange proposes to adopt a new term, a “Size Adjustment Modifier,” which would apply to individual transactions and would modify the applicable adjustment for transactions under certain circumstances, as discussed in further detail below. As proposed, the Size Adjustment Modifier will be applied to individual transactions as follows:
When reviewing a transaction as potentially erroneous, the Exchange needs to first determine the “Theoretical Price” of the option,
The Exchange also proposes to set forth in the Proposed Rule various provisions governing specific situations where the NBB or NBO is not available or may not be reliable. Specifically, the Exchange is proposing additional detail specifying situations in which there are no quotes or no valid quotes (as defined below), when the national best bid or offer (“NBBO”) is determined to be too
The Exchange proposes to determine the Theoretical Price if there are no quotes or no valid quotes for comparison purposes. As proposed, quotes that are not valid are all quotes in the applicable option series published at a time where the last NBB is higher than the last NBO in such series (a “crossed market”), quotes published by the Exchange that were submitted by either party to the transaction in question, and quotes published by another options exchange against which the Exchange has declared self-help. Thus, in addition to scenarios where there are literally no quotes to be used as Theoretical Price, the Exchange will exclude quotes in certain circumstances if such quotes are not deemed valid.
The Exchange proposes to determine the Theoretical Price if the bid/ask differential of the NBB and NBO for the affected series just prior to the erroneous transaction was equal to or greater than the Minimum Amount set forth below and there was a bid/ask differential less than the Minimum Amount during the 10 seconds prior to the transaction. If there was no bid/ask differential less than the Minimum Amount during the 10 seconds prior to the transaction then the Theoretical Price of an option series is the last NBB or NBO just prior to the transaction in question. The Exchange proposes to use the following chart (“Wide Quote Chart”) to determine whether a quote is too wide to be reliable:
As described above, while the Exchange proposes to determine Theoretical Price when the bid/ask differential equals or exceeds the amount set forth in the chart above and within the previous 10 seconds there was a bid/ask differential smaller than such amount, if a quote has been persistently wide for at least 10 seconds the Exchange will use such quote for purposes of Theoretical Price.
The Exchanges proposes that, for a transaction occurring as part of the Opening Process,
The Exchange proposes to adopt numerical thresholds similar to those in place under the Current Rule that would qualify transactions as “Obvious Errors.” As proposed, a transaction will qualify as an Obvious Error if the Exchange receives a properly submitted filing and the execution price of a transaction is higher or lower than the Theoretical Price for the series by an amount equal to at least the amount shown below:
Under the Proposed Rule, a party that believes that it participated in a transaction that was the result of an Obvious Error must notify the Exchange's Trade Desk in the manner specified from time to time by the Exchange in a circular distributed to Members.
The Exchange also proposes to adopt notification timeframes that must be met in order for a transaction to qualify as an Obvious Error. Specifically, as proposed, a filing must be received by the Exchange within 30 minutes of the execution with respect to an execution of a Customer order and within 15 minutes of the execution for any other participant. The Exchange also proposes to provide additional time for trades that are routed through other options exchanges to the Exchange. Under the Proposed Rule, any other options exchange will have a total of 45 minutes for Customer orders and 30 minutes for non-Customer orders, measured from the time of execution on the Exchange, to file with the Exchange for review of transactions routed to the Exchange from that options exchange and executed on the Exchange (“linkage trades”). This includes filings on behalf of another options exchange filed by a third-party routing broker if such third-party broker identifies the affected transactions as linkage trades. In order to facilitate timely reviews of linkage trades, the Exchange will accept filings from either the other options exchange or, if applicable, the third-party routing broker that routed the applicable order(s). The additional 15 minutes provided with respect to linkage trades shall only apply to the extent the options exchange that originally received and routed the order to the Exchange itself received a timely filing from the entering participant (
Pursuant to the Proposed Rule, an Official may review a transaction believed to be erroneous on his/her own motion in the interest of maintaining a fair and orderly market and for the protection of investors. A transaction reviewed pursuant to the proposed provision may be nullified or adjusted only if it is determined by the Official that the transaction is erroneous in accordance with the provisions of the Proposed Rule, provided that the time deadlines for filing a request for review described above shall not apply. The Proposed Rule would require the Official to act as soon as possible after becoming aware of the transaction; action by the Official would ordinarily be expected on the same day that the transaction occurred. However, because a transaction under review may have occurred near the close of trading or due to unusual circumstances, the Proposed Rule provides that the Official shall act no later than 8:30 a.m. Eastern Time on the next trading day following the date of the transaction in question.
The Exchange also proposes to state that a party affected by a determination to nullify or adjust a transaction after an Official's review on his or her own motion may appeal such determination, as described below. The Proposed Rule would make clear that a determination by an Official not to review a transaction or determination not to nullify or adjust a transaction for which a review was conducted on an Official's own motion is not appealable and further that if a transaction is reviewed and a determination is rendered pursuant to another provision of the
If it is determined that an Obvious Error has occurred based on the objective numeric criteria and time deadlines described above, the Exchange will adjust or nullify the transaction as described below and promptly notify both parties to the trade electronically or via telephone. The Exchange proposes different adjustment and nullification criteria for Customers and non-Customers.
As proposed, where neither party to the transaction is a Customer, the execution price of the transaction will be adjusted by the Official pursuant to the table below.
Further, as proposed, any non-Customer Obvious Error exceeding 50 contracts will be subject to the Size Adjustment Modifier described above.
In contrast to non-Customer orders, where trades will be adjusted if they qualify as Obvious Errors, pursuant the Proposed Rule, a trade that qualifies as an Obvious Error will be nullified where at least one party to the Obvious Error is a Customer. The Exchange also proposes, however, that if any Member submits requests to the Exchange for review of transactions pursuant to the Proposed Rule, and in aggregate that Member has 200 or more Customer transactions under review concurrently and the orders resulting in such transactions were submitted during the course of 2 minutes or less, where at least one party to the Obvious Error is a non-Customer, the Exchange will apply the non-Customer adjustment criteria described above to such transactions.
The Exchange further proposes to adopt separate numerical thresholds for review of transactions for which the Exchange does not receive a filing requesting review within the Obvious Error timeframes set forth above. Based on this review, these transactions may qualify as “Catastrophic Errors.” As proposed, a Catastrophic Error will be deemed to have occurred when the execution price of a transaction is higher or lower than the Theoretical Price for the series by an amount equal to at least the amount shown below:
Under the Proposed Rule, parties have additional time to submit transactions for review as Catastrophic Errors. As proposed, notification requesting review must be received by the Exchange's Trade Desk by 8:30 a.m. Eastern Time on the first trading day following the execution. For transactions in an expiring options series that take place on an expiration day, a party must notify the Exchange's Trade Desk within 45 minutes after the close of trading that same day. As is true for requests for review under the Obvious Error provision of the Proposed Rule, a party requesting review of a transaction as a Catastrophic Error must notify the Exchange's Trade Desk in the manner specified from time to time by the Exchange in a circular distributed to Members. By definition, any execution that qualifies as a Catastrophic Error is also an Obvious Error.
The Proposed Rule would specify the action to be taken by the Exchange if it is determined that a Catastrophic Error has occurred, as described above, and would require the Exchange to promptly notify both parties to the trade electronically or via telephone. In the event of a Catastrophic Error, the execution price of the transaction will be adjusted by the Official pursuant to the table below.
Furthermore, the Exchange proposes to adopt a new provision that calls for coordination between the options exchanges in certain circumstances and provides limited flexibility in the application of other provisions of the Proposed Rule in order to promptly respond to a widespread market event.
The proposed criteria for determining an SME are as follows:
(A) Transactions that are potentially erroneous would result in a total Worst-Case Adjustment Penalty of $30,000,000, where the Worst-Case Adjustment Penalty is computed as the sum, across all potentially erroneous trades, of: (i) $0.30 (
(B) Transactions involving 500,000 options contracts are potentially erroneous;
(C) Transactions with a notional value (
(D) 10,000 transactions are potentially erroneous.
As described above, the Exchange proposes to adopt the Worst Case Adjustment Penalty, proposed as criterion (A), which is the only criterion that can on its own result in an event being designated as a significant market event. If the Worst Case Adjustment criterion is equal to or exceeds $30,000,000, then an event is an SME.
As described above, under the Proposed Rule, if the Worst Case Adjustment Penalty is less than $30,000,000, then an SME has occurred if the sum of all applicable event statistics (expressed as a percentage of the relevant thresholds in criteria (A) through (D) above), is greater than or equal to 150% and 75% or more of at least one category is reached. The Proposed Rule further provides that no single category can contribute more than 100% to the sum and any category contributing more than 100% will be rounded down to 100%.
To ensure consistent application across options exchanges, in the event of a suspected SME, the Exchange shall initiate a coordinated review of potentially erroneous transactions with all other affected options exchanges to determine the full scope of the event. Under the Proposed Rule, the Exchange will promptly coordinate with the other options exchanges to determine the appropriate review period as well as select one or more specific points in time prior to the transactions in question and use one or more specific points in time to determine Theoretical Price. Other than the selected points in time, if applicable, the Exchange will determine Theoretical Price as described above.
If it is determined that an SME has occurred then, using the parameters agreed with respect to the times from which Theoretical Price will be calculated, if applicable, an Official will determine whether any or all transactions under review qualify as Obvious Errors. The Proposed Rule would require the Exchange to use the criteria for determining whether an Obvious Error has occurred, as described above, for each transaction that was part of the SME. Upon taking any final action, the Exchange would be required to promptly notify both parties to the trade electronically or via telephone.
The execution price of each affected transaction will be adjusted by an Official to the price provided below, unless both parties agree to adjust the transaction to a different price or agree to bust the trade.
Thus, the proposed adjustment criteria for SMEs are identical to the proposed adjustment levels for Obvious Errors generally. In addition, in the context of an SME, any error exceeding 50 contracts will be subject to the Size Adjustment Modifier described above. Also, the adjustment criteria would apply equally to all market participants (
Another significant distinction between the proposed Obvious Error provision and the proposed SME provision is that if the Exchange, in consultation with other options exchanges, determines that timely adjustment is not feasible due to the extraordinary nature of the situation, then the Exchange will nullify some or all transactions arising out of the SME during the review period selected by the Exchange and other options exchanges. To the extent the Exchange, in consultation with other options exchanges, determines to nullify less than all transactions arising out of the SME, those transactions subject to nullification will be selected based upon objective criteria with a view toward maintaining a fair and orderly market and the protection of investors and the public interest. Furthermore, the Proposed Rule provides that rulings by the Exchange pursuant to the SME provision would be non-appealable.
The Proposed Rule also proposes to make clear that the determination as to whether a trade was executed at an erroneous price may be made by mutual agreement of the affected parties to a particular transaction. The Proposed Rule provides that a trade may be nullified or adjusted on the terms that all parties to a particular transaction agree, provided, however, that such agreement to nullify or adjust must be conveyed to the Exchange in a manner prescribed by the Exchange prior to 8:30 a.m. Eastern Time on the first trading day following the execution. The Exchange also proposes to explicitly state that it is considered conduct inconsistent with just and equitable principles of trade for any Member to use the mutual adjustment process to circumvent any applicable Exchange rule, the Act or any of the rules and regulations thereunder.
The Exchange additionally proposes to modify Interpretation and Policy .01 to Exchange Rule 20.3 (Trading Halts), which describes the Exchange's authority to declare trading halts in one or more options traded on the Exchange. Currently, Interpretation and Policy .01 states that the Exchange “may” nullify any transaction that occurs: (a) During a trading halt in the affected option on the Exchange; or (b) with respect to equity options (including options overlying ETFs), during a trading halt on the primary listing market for the underlying security. To ensure consistency with the trading halt provision of Proposed Rule 20.6, the Exchange proposes to modify Interpretation and Policy .01 to Exchange Rule 20.3 to state that in either situation described above, the Exchange “shall” nullify such transactions.
The Exchange proposes to adopt language in the Proposed Rule stating that a trade resulting from an erroneous print(s) disseminated by the underlying market that is later nullified by that underlying market shall be adjusted or busted as set forth in the Obvious Error provisions of the Proposed Rule, provided a party notifies the Exchange's Trade Desk in a timely manner, as further described below. The Exchange proposes to define a trade resulting from an erroneous print(s) as any options trade executed during a period of time for which one or more executions in the underlying security are nullified and for one second thereafter. The Exchange also proposes to require that if a party believes that it participated in an erroneous transaction resulting from an erroneous print(s) pursuant to the proposed erroneous print provision it must notify the Exchange's Trade Desk
The Exchange also proposes to add a provision stating that a trade resulting from an erroneous quote(s) in the underlying security shall be adjusted or busted as set forth in the Obvious Error provisions of the Proposed Rule, provided a party notifies the Exchange's Trade Desk in a timely manner, as further described below. Pursuant to the Proposed Rule, an erroneous quote occurs when the underlying security has a width of at least $1.00 and has a width at least five times greater than the average quote width for such underlying security during the time period encompassing two minutes before and after the dissemination of such quote. For purposes of the Proposed Rule, the average quote width will be determined by adding the quote widths of sample quotations at regular 15-second intervals during the four-minute time period referenced above (excluding the quote(s) in question) and dividing by the number of quotes during such time period (excluding the quote(s) in question).
As proposed, transactions resulting from the triggering of a stop or stop-limit order by an erroneous trade in an option contract shall be nullified by the Exchange, provided a party notifies the Exchange's Trade Desk in a timely manner as set forth below. If a party believes that it participated in an erroneous transaction pursuant to the Proposed Rule it must notify the Exchange's Trade Desk within the timeframes set forth in the Obvious Error rule above, with the allowed notification timeframe commencing at the time of notification of the nullification of transaction(s) that triggered the stop or stop-limit order.
The Exchange also proposes to adopt language that provides the Exchange with authority to take necessary actions when another options exchange nullifies or adjusts a transaction pursuant to its respective rules and the transaction resulted from an order that has passed through the Exchange and been routed on to another options exchange on behalf of the Exchange. Specifically, if the Exchange routes an order pursuant to the Intermarket Option Linkage Plan
The Exchange proposes to maintain its current appeals process in connection with the Proposed Rule. Specifically, if a member of BATS Options (“Options Member”) affected by a determination made under the Proposed Rule requests within the time permitted below, the Obvious Error Panel will review decisions made by the BATS Official, including whether an obvious error occurred and whether the correct determination was made.
The Obvious Error Panel will be comprised of the Exchange's Chief Regulatory Officer (“CRO”) or a designee of the CRO, a representative of one (1) Options Member engaged in market making (any such representative, a “MM Representative”) and representatives from two (2) Options Members satisfying one or both of the criteria set forth below (any such representative, a “Non-MM Representative”). To qualify as a Non-MM Representative a person must: Be employed by an Options Member whose revenues from options market making activity do not exceed ten percent (10%) of its total revenues; or have as his or her primary responsibility the handling of Public Customer orders or supervisory responsibility over persons with such responsibility, and not have any responsibilities with respect to market making activities.
The Exchange shall further designate at least ten (10) MM Representatives and at least ten (10) Non-MM Representatives to be called upon to serve on the Obvious Error Panel as needed. To assure fairness, in no case shall an Obvious Error Panel include a person affiliated with a party to the trade in question. Also, to the extent reasonably possible, the Exchange shall call upon the designated representatives to participate on an Obvious Error Panel on an equally frequent basis.
Under the Proposed Rule a request for review on appeal must be made in writing via email or other electronic means specified from time to time by the Exchange in a circular distributed to Options Members within thirty (30) minutes after the party making the appeal is given notification of the initial determination being appealed. The Obvious Error Panel shall review the facts and render a decision as soon as practicable, but generally on the same trading day as the execution(s) under review. On requests for appeal received after 3:00 p.m. Eastern Time, a decision will be rendered as soon as practicable, but in no case later than the trading day following the date of the execution under review.
The Obvious Error Panel may overturn or modify an action taken by the BATS Official under this Rule. All determinations by the Obvious Error Panel shall constitute final action by the Exchange on the matter at issue.
If the Obvious Error Panel votes to uphold the decision made pursuant to the Proposed Rule, the Exchange will assess a $500.00 fee against the Options Member(s) who initiated the request for appeal. In addition, in instances where the Exchange, on behalf of an Options Member, requests a determination by another market center that a transaction is clearly erroneous, the Exchange will pass any resulting charges through to the relevant Options Member.
Any determination by an Officer or by the Obvious Error Panel shall be rendered without prejudice as to the rights of the parties to the transaction to submit their dispute to arbitration.
The Exchange is proposing to adopt Interpretation and Policy .01 to Proposed Rule 20.6 (“LULD Options
During a Limit or Straddle State, options prices may deviate substantially from those available immediately prior to or following such States. Thus, determining a Theoretical Price in such situations would often be very subjective, creating unnecessary uncertainty and confusion for investors. Because of this uncertainty, the Exchange is proposing to amend Rule 20.6 to provide that the Exchange will not review transactions as Obvious Errors or Catastrophic Errors when the underlying security is in a Limit or Straddle State.
The Exchange notes that there are additional protections in place outside of the Obvious and Catastrophic Error Rule that will continue to safeguard customers. First, the Exchange rejects all un-priced options orders received by the Exchange (
The Exchange has agreed to provide the Commission with relevant data to assess the impact of this proposed rule change. As part of its analysis, the Exchange will evaluate (1) the options market quality during Limit and Straddle States, (2) assess the character of incoming order flow and transactions during Limit and Straddle States, and (3) review any complaints from Members and their customers concerning executions during Limit and Straddle States. The Exchange has also agreed to provide to the Commission data requested to evaluate the impact of the inapplicability of the Obvious Error and Catastrophic Error provisions, including data relevant to assessing the various analyses noted above.
In connection with this proposed rule change, the Exchange will provide to the Commission and the public a dataset containing the data for each Straddle State and Limit State in NMS Stocks underlying options traded on the Exchange beginning in the month during which the proposed rule change is approved, limited to those option classes that have at least one (1) trade on the Exchange during a Straddle State or Limit State. For each of those option classes affected, each data record will contain the following information:
• Stock symbol, option symbol, time at the start of the Straddle or Limit State, an indicator for whether it is a Straddle or Limit State.
• for activity on the Exchange:
• executed volume, time-weighted quoted bid-ask spread, time-weighted average quoted depth at the bid, time-weighted average quoted depth at the offer;
• high execution price, low execution price;
• number of trades for which a request for review for error was received during Straddle and Limit States;
• an indicator variable for whether those options outlined above have a price change exceeding 30% during the underlying stock's Limit or Straddle State compared to the last available option price as reported by OPRA before the start of the Limit or Straddle State (1 if observe 30% and 0 otherwise). Another indicator variable for whether the option price within five minutes of the underlying stock leaving the Limit or Straddle state (or halt if applicable) is 30% away from the price before the start of the Limit or Straddle State.
In addition, by May 29, 2015, the Exchange shall provide to the Commission and the public assessments relating to the impact of the operation of the Obvious Error rules during Limit and Straddle States as follows: (1) Evaluate the statistical and economic impact of Limit and Straddle States on liquidity and market quality in the options markets; and (2) Assess whether the lack of Obvious Error rules in effect during the Straddle and Limit States are problematic. The timing of this submission would coordinate with Participants' proposed time frame to submit to the Commission assessments as required under Appendix B of the Plan. The Exchange notes that the pilot program is intended to run concurrent with the pilot period of the Plan, which has been extended to October 23, 2015. The Exchange proposes to reflect this date in the Proposed Rule.
Finally, the Exchange proposes to include Interpretation and Policy .02 to the Proposed Rule, which would make clear that to the extent the provisions of the proposed Rule would result in the Exchange applying an adjustment of an erroneous sell transaction to a price lower than the execution price or an erroneous buy transaction to a price higher than the execution price, the Exchange will not adjust or nullify the transaction, but rather, the execution price will stand.
Additional information relating to the proposed rule change can be found in the Notice.
As noted previously, the Commission received two comment letters on the proposed rule change and a response letter from the Exchange.
The Goldman Letter supports the goal and much of the substance of the Proposed Rule, including the efforts to ensure predictability in the case of an SME.
The SIFMA Letter generally supports the proposed rule change, but notes that there are critical aspects that will require additional time to allow for exchange and industry discussion, including the development of a method to ensure greater objectivity and uniformity with respect to the calculation of Theoretical Price.
The Goldman and SIFMA Letters both advocate for the Commission and the exchanges to work towards the establishment of pre-trade controls designed to prevent erroneous trades before they occur.
In its response to commenters, the Exchange reiterates its belief that the Proposed Rule will provide greater transparency and finality with respect to the adjustment and nullification of erroneous options transactions.
With respect to the proposal to adjust or nullify erroneous transactions in connection with an SME, the Exchange notes that the Proposed Rule would permit the Exchange to coordinate with other options exchanges in certain circumstances and would provide limited flexibility in the application of the general obvious error provisions of the Proposed Rule in order to allow the Exchange to promptly respond to a widespread market event that meets the criteria of an SME.
The Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission believes that the proposal to adopt Rule 20.6 will help assure greater objectivity, transparency, and clarity with respect to the adjustment and nullification of erroneous options transactions. The Commission notes that the Proposed
The Commission notes that the Exchange represented in its filing that the Exchange and all other options exchanges have been working to further improve the review of potentially erroneous transactions as well as their subsequent adjustment by creating a more objective and uniform way to determine Theoretical Price in the event a reliable NBBO is not available, as in, for example, such cases where there is a wide quote or no valid quote, as described above.
The Commission appreciates the suggestions and responses offered by both commenters to improve the process by which the Exchange addresses the harmonization of rules related to the adjustment and nullification of erroneous options transactions.
Finally, the Commission notes that the proposed rule change will become operative on May 8, 2015. This delayed implementation is to ensure that other options exchanges will have sufficient time to put in place similar rules consistent with this proposed rule change and to coordinate the date of implementation of such harmonized rules.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether Amendment No. 2 to 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 Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
The Commission finds good cause to approve the proposed rule change, as modified by Amendment Nos. 1 and 2, prior to the 30th day after the date of publication of notice of Amendment No. 2 in the
The Commission believes Amendment No. 2 would provide market participants with additional clarity by making technical, non-substantive corrections to certain portions of the filing.
As discussed above, the Commission believes that the revisions in Amendment No. 2 are being made to provide additional clarity to the proposed rule change and to provide additional certainty and consistency by eliminating the discretion of the Exchange to determine Theoretical Price in certain circumstances. The Commission believes Amendment No. 2 is consistent with the purpose of the proposed rule change and is consistent with the protection of investors and the public interest. Accordingly, the Commission finds good cause, pursuant to Section 19(b)(2) of the Act,
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”),
The Exchange proposes to amend Rules 6.74B and 24B.5B relating to the Solicitation Auction Mechanism (“SAM”). The text of the proposed rule change is provided below (additions are
A Trading Permit Holder that represents agency orders may electronically execute orders it represents as agent (“Agency Order”) against solicited orders provided it submits the Agency Order for electronic execution into the solicitation auction mechanism (the “Auction”) pursuant to this Rule.
(a) Auction Eligibility Requirements. A Trading Permit Holder (the “Initiating Trading Permit Holder”) may initiate an Auction provided all of the following are met:
(1) The Agency Order is in a class designated as eligible for Auctions as determined by the Exchange and within the designated Auction order eligibility size parameters as such size parameters are determined by the Exchange (however, the eligible order size may not be less than 500 standard option contracts or 5,000 mini-option contracts);
(2) Each order entered into the Auction shall be designated as all-or-none
(3) The minimum price increment for an Initiating Trading Permit Holder's single price submission shall be determined by the Exchange on a series basis and may not be smaller than one cent.
(b) Auction Process. The Auction shall proceed as follows:
(1) Auction Period and Requests for Responses.
(A) To initiate the Auction, the Initiating Trading Permit Holder must mark the Agency Order for Auction processing, and specify a single price at which it seeks to cross the Agency Order with a solicited order
(B) When the Exchange receives a properly designated Agency Order for Auction processing, a Request for Responses message indicating the price, side, and size will be sent to all Trading Permit Holders that have elected to receive such messages.
(C)-(G) No change.
(2) Auction Conclusion and Order Allocation. The Auction shall conclude at the sooner of subparagraphs (b)(2)(A)
(A) The Agency Order will be executed against the solicited order at the proposed execution price, provided that:
(I) The execution price must be equal to or better than the
(II)-(III) No change.
A FLEX Trader that represents agency orders may electronically execute orders it represents as agent (“Agency Order”) against solicited orders provided it submits the Agency Order for electronic execution into the solicitation auction mechanism (the “SAM Auction”) pursuant to this Rule.
(a) No change.
(b) SAM Auction Process. Only one SAM Auction may be ongoing at any given time in a series and SAM Auctions in the same series may not queue or overlap in any manner. In addition, unrelated FLEX Orders may not be submitted to the electronic book for the duration of a SAM Auction. The SAM Auction may not be cancelled and shall proceed as follows:
(1) SAM Auction Period and Requests for Responses (“RFR”).
(i) No change.
(ii) When the Exchange receives a properly designated Agency Order for SAM Auction processing, an RFR message indicating the price
(iii)-(vii) No change.
(2)-(3) No change.
The text of the proposed rule change is also 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 make changes to its existing SAM auction rules in Rule 6.74B and Flexible Exchange Option Solicitation Auction Mechanism (“FLEX SAM”) rules in Rule 24B.5B. The Exchange believes that the proposed amendments would ensure greater consistency between the Exchange's SAM auction rules and Order Protection Rule 6.81
Rules 6.74B and 24B.5B permit Trading Permit Holders (“TPHs”) and FLEX Traders to electronically execute an all-or-none (“AON”) orders for 500 or more standard (or FLEX) options contracts or 5,000 or more mini-options contracts that they represent as agent (“Agency Order”) against solicited orders provided the TPH (or FLEX Trader) submits the Agency Order for electronic execution into SAM for auction (the “Auction”) pursuant to Rule 6.74B or Rule 24B.5B (for FLEX orders).
Although TPHs are subject to the Exchange's Order Protection Rule 6.81 and thus, prevented from trading through the displayed national best bid and offer (“NBBO”), including within the context of SAM auctions, Rule 6.74B does not specifically require Initiating TPHs to stop Agency Orders at or within the NBBO or expressly prohibit Agency Orders from being executed against solicited orders at prices outside the NBBO.
Specifically, the Exchange is proposing to amend Rules 6.74B(a)(2), 6.74B(b)(1)(A), and 6.74B(b)(2)(A)(I) to provide that Agency Orders submitted into SAM must be stopped with a solicited order priced at or within the national best bid or offer (“NBBO”) as of the time of the initiation of the Auction (
The Exchange believes that requiring SAM orders to be stopped and executed at a price equal to, or better than, the NBBO as of the time of receipt of the Agency Order in the OHS is consistent with the Order Protection Rule 6.81. As proposed, the range of permissible crossing prices and executions would be defined based on a snapshot of the market at the time when the Agency Order is received.
The following example demonstrates how the Exchange's proposal would provide an additional layer of order protection within the Rules. Assume that the NBBO for a particular option is $1.00-$1.20 with quotes on both sides for 100 contracts each. The CBOE BBO is $0.95-$1.25. An Initiating TPH submits an Agency Order to buy 500 contracts against a solicited order to sell 500 contracts into SAM priced at $1.21. An RFR is transmitted to TPHs that have elected to receive auction messages without any response. In this case, under current Rule 6.74B(b)(2)(A), the Agency Order would be executable against the solicited order because the execution price of $1.21 improves the CBOE best offer price of $1.25. Such execution, however, would be in violation of Rule 6.81 because the Agency Order would have been executed outside of the NBBO of $1.00-$1.20. The Exchange proposes to remedy this inconsistency in the Rules by changing references to the BBO to NBBO and defining the term “initial auction NBBO” to mean priced at or within the NBBO as of the time of the initiation of the Auction (
The Exchange's proposal would not, however, change the priority of public customer orders resting in the book. Assume again that the NBBO for a particular option is $1.00-$1.20 with quotes on both sides for 100 contracts each. Assume this time, however, that there is also a public customer order to sell 50 contracts resting in the book at $1.20. The CBOE BBO is $0.95-$1.20. An Initiating TPH submits an Agency Order to buy 500 contracts against a solicited order to sell 500 contracts into SAM priced at $1.20. An RFR is transmitted to TPHs that have elected to receive auction messages with a single response to sell 150 contracts also at $1.20. In this case, under both current Rule 6.74B(b)(2)(A) and the proposed rule changes, because there is a public customer order resting in the book on the opposite side of the Agency Order at the proposed price without sufficient size (considering all resting orders (
The Exchange also proposes to amend Rules 6.74B(b)(1)(B) and 24B.5B(b)(1)(ii) to further make clear that upon receiving a properly designated Agency Order for SAM or FLEX SAM Auction processing, the Exchange's RFR message would indicate the price, side, and size of the Agency Order that the Initiating TPH is seeking to cross. Rules 6.74B(b)(1)(B) and 24B.5B(b)(1)(ii) both currently provide that the Exchange will send an RFR message to all TPHs that have elected to receive such messages, indicating the price and size of the Agency Order that the Initiating TPH is seeking to cross, but neither Rule 6.74B(b)(1)(B) or 24B.5B(b)(1)(ii) currently specify that the RFR will also indicate the side (
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.
In particular, the Exchange believes that the proposed changes would ensure further consistency within the Exchange's Rules. The Exchange also believes that the proposed rule changes would further the objectives of the Act to protect investors by promoting the intermarket price protection goals of the Exchange's Order Protection Rule 6.81 and the Options Intermarket Linkage Plan.
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. Rather, the Exchange believes that the proposed rule would bolster intermarket competition by promoting fair competition among individual markets, while at the same time assuring that market participants receive the benefits of markets that are linked together, through facilities and rules, in a unified system, which promotes interaction among the orders of buyers and sellers. The Exchange believes its proposal would help ensure intermarket competition across all exchanges, aid in preventing intermarket trade-throughs, and facilitate compliance with best execution practices. In addition, the Exchange believes that the proposed rule change would help promote fair and orderly markets by helping to ensure compliance with the Order Protection Rule. Thus, the Exchange does not believe the proposal creates any significant impact on competition.
The Exchange neither solicited nor received written comments on the proposed rule change.
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) of 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 will institute proceedings to determine whether the proposed rule change 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.
It appears to the Securities and Exchange Commission that there is a lack of current and accurate information concerning the securities of Winsonic Digital Media Group, Ltd. (“Winsonic”) because it has not filed any periodic
The Commission is of the opinion that the public interest and the protection of investors require a suspension of trading in the securities of Winsonic.
Therefore, it is ordered, pursuant to Section 12(k) of the Securities Exchange Act of 1934, that trading in the securities of Winsonic is suspended for the period from 9:30 a.m. EDT on March 24, 2015, through 11:59 p.m. EDT on April 7, 2015.
By the Commission.
Notice is hereby given, pursuant to the provisions of the Government in the Sunshine Act, Public Law 94-409, that the Securities and Exchange Commission will hold an Open Meeting on March 30, 2015, at 10:30 a.m., in Room 10800 at the Commission's headquarters building, to hear oral argument in cross-appeals by Francis V. Lorenzo and the Division of Enforcement from an initial decision of an administrative law judge.
On December 31, 2013, the law judge found that Lorenzo violated the antifraud provisions of Section 17(a) of the Securities Act of 1933, Section 10(b) of the Securities Exchange Act of 1934, and Exchange Act Rule 10b-5 when he sent two potential investors emails containing false and misleading information about his firm's client. The law judge ordered Lorenzo to cease and desist from violations of the antifraud provisions, barred him from the securities industry, and ordered him to pay a civil money penalty of $15,000.
The issues likely to be considered at oral argument include whether Lorenzo violated the antifraud provisions as alleged and, if so, the extent to which he should be sanctioned for those violations.
The duty officer determined that no earlier notice thereof was possible. For further information, please contact the Office of the Secretary at (202) 551-5400.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange is filing a proposal to amend the MIAX Options Fee Schedule.
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 current MIAX Market Maker
The sliding scale for MIAX Market Maker transaction fees is based on the substantially similar fees of the Chicago Board Options Exchange, Incorporated (“CBOE”).
The Exchange proposes to amend its current MIAX Market Maker sliding scale for transactions to adopt transaction fees for non-Penny Pilot options classes. Specifically, the Exchange proposes to reduce a MIAX Market Maker's per contract transaction fee based on percentages of total national Market Maker volume of any options classes that trade on the exchange during the calendar month, based on the following scale:
The proposed sliding scale would apply to all MIAX Market Makers for transactions in all non-Penny Pilot options classes except mini-options. A MIAX Market Maker's initial $0.29 per contract rate will be reduced if the MIAX Market Maker reaches the volume thresholds set forth in the sliding scale
The Exchange believes the proposed sliding scale for non-Penny Pilot options classes is objective in that the fee reductions are based solely on reaching stated volume thresholds. The specific volume thresholds of the tiers were set based upon business determinations and an analysis of current volume levels. The specific volume thresholds and rates were set in order to encourage MIAX Market Makers to reach for higher tiers. The Exchange believes that the proposed changes to the tiered fee schedule may incent firms to display their orders on the Exchange and increase the volume of contracts traded here in order to qualify for lower fee rates in the higher tiers.
As mentioned above, the Exchange notes that the proposed sliding fee scale for MIAX Market Makers structured on contract volume thresholds is based on the substantially similar fees of the CBOE.
The Exchange proposes to offer MIAX Market Makers the opportunity to reduce transaction fees by $0.02 per contract in standard options in non-Penny Pilot options classes in the same manner as Penny Pilot options classes. As proposed, any Member or its affiliates of at least 75% common ownership between the firms as reflected on each firm's Form BD, Schedule A, that qualifies for Priority Customer Rebate Program volume tiers 3, 4, or 5 and is a MIAX Market Maker will be assessed $0.27 per contract for tier 1, $0.19 per contract for tier 2, $0.14 per contract for tier 3, $0.09 per contract for tier 4, and $0.07 per contract for tier 5 for transactions in standard options in non-Penny Pilot options classes in lieu of the applicable transaction fees in the Market Maker sliding scale.
The Exchange believes that these incentives will encourage MIAX Market Makers to transact a greater number of orders on the Exchange.
The Exchange believes that its proposal to amend its fee schedule is consistent with Section 6(b) of the Act
The Exchange believes that its proposal to assess transaction fees in non-Penny Pilot options classes, which differs from Penny Pilot options classes, is consistent with other options markets that also assess different transaction fees for non-Penny Pilot options classes as compared to Penny Pilot options classes. The Exchange believes that establishing different pricing for non-Penny Pilot options and Penny Pilot options is reasonable, equitable, and not unfairly discriminatory because Penny Pilot options are more liquid options as compared to non-Penny Pilot options. Additionally, other competing options exchanges differentiate pricing in a similar manner today in other types of transaction fees.
The proposed volume based discount fee structure is not discriminatory in that all MIAX Market Makers are eligible to submit (or not submit) liquidity, and may do so at their discretion in the daily volumes they choose during the course of the billing period. All similarly situated MIAX Market Makers are subject to the same fee structure, and access to the Exchange is offered on terms that are not unfairly discriminatory. Volume based discounts have been widely adopted by options and equities markets, and are equitable because they are open to all MIAX Market Makers on an equal basis and provide discounts that are reasonably related to the value of an exchange's market quality associated with higher volumes. The proposed fee levels and volume thresholds are reasonably designed to be comparable to those of other options exchanges employing similar fee programs, and also to attract additional liquidity and order flow to the Exchange.
The Exchange's proposal to provide MIAX Market Makers the opportunity to reduce transaction fees by $0.02 per contract in standard options in non-Penny Pilot option classes, provided certain criteria are met, is reasonable because the Exchange desires to offer all such market participants an opportunity to lower their transaction fees. The Exchange's proposal to offer MIAX Market Makers the opportunity to reduce transaction fees by $0.02 per contract in standard options in non-Penny Pilot option classes, provided certain criteria are met, is equitable and not unfairly discriminatory because the Exchange offers all market participants, excluding Priority Customers, a means to reduce transaction fees by qualifying for volume tiers in the Priority Customer Rebate Program. The Exchange believes that offering all such market participants the opportunity to lower transaction fees by incentivizing them to transact Priority Customer order flow in turn benefits all market participants.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive. In such an environment, the Exchange must continually adjust its fees to remain competitive with other exchanges and to attract order flow. The Exchange believes that the proposed rule change reflects this competitive environment because it modifies the Exchange's fees in a manner that
Written comments were neither solicited nor received.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act.
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 January 22, 2015, the Chicago Board Options Exchange, Incorporated (the “Exchange” or “CBOE”) filed with the Securities and Exchange Commission (the “Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
Currently Exchange Rules 6.41 (with respect to equities) and 24.8 (with respect to indexes), provide that bids and offers must be expressed in terms of dollars per unit of the underlying security or index, as applicable. However, the Exchange explains that sometimes a customer will request an execution in a complex order at a total cash price for the order (rather than at a price per contract for each leg) and the total number of contracts of each leg.
Accordingly, the Exchange proposes to adopt Interpretation and Policy .01 to each of Exchange Rules 6.41 and 24.8. The Interpretations will impose requirements requiring how brokers must determine final leg execution prices when a broker receives from a customer a complex order for open-outcry handling at a total cash price, and the complex order does not break down into a per-unit price for each leg based on the existing market for the leg that corresponds to the total price.
After careful review, the Commission finds that the proposed rule change is consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On September 5, 2014, NYSE Arca, Inc. (“Exchange”) 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 issue an order approving or disapproving the proposed rule change so that it has sufficient time to consider the proposed rule change, as modified by Amendment No. 1 thereto.
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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange is filing a proposal to amend the MIAX Options Fee Schedule.
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 Fee Schedule to provide for additional incentives for achieving certain Priority Customer Rebate Program volume tiers and sending additional Priority Customer Orders into PRIME.
The Exchange proposes to offer Members the opportunity to qualify for a $0.02 per contract rebate in standard options if the Member or its affiliates of at least 75% common ownership between the firms as reflected on each firm's Form BD, Schedule A, qualifies in a given month for Priority Customer Rebate Program volume tiers 3, 4, or 5 in the Fee Schedule.
The Exchange believes that these incentives will encourage Members to transact a greater number of orders on the Exchange.
The Exchange believes that its proposal to amend its fee schedule is consistent with Section 6(b) of the Act
The Exchange believes that the proposed Priority Customer Rebate Program rebates for Priority Customer orders submitted into PRIME are fair, equitable and not unreasonably discriminatory. The rebate program is reasonably designed because it will incent providers of Priority Customer order flow to send that Priority Customer order flow to the Exchange in order to receive a credit in a manner that enables the Exchange to improve its overall competitiveness and strengthen its market quality for all market participants. The proposed rebate program is fair, equitable, and not unreasonably discriminatory because it will apply equally to all Priority Customer orders submitted as a PRIME Agency Order. All similarly situated Priority Customer orders are subject to the same rebate schedule, and access to the Exchange is offered on terms that are not unfairly discriminatory. In addition, the proposed rebate program is equitable and not unfairly discriminatory because, while only Priority Customer order flow qualifies for the rebate program, an increase in Priority Customer order flow will bring greater volume and liquidity, which benefit all market participants by providing more trading opportunities and tighter spreads. Market participants want to trade with Priority Customer order flow. To the extent Priority Customer order flow is increased by the proposal, market participants will increasingly compete for the opportunity to trade on the Exchange including sending more orders and providing narrower and larger sized quotations in the effort to trade with such Priority Customer order flow. The resulting increased volume and liquidity will benefit those Members who receive the lower tier levels, or do not qualify for the rebate program at all, by providing more trading opportunities and tighter spreads.
The Exchange believes excluding Priority Customer-to-Priority Customer Orders, Priority Customer responses, contra-side orders, and Priority Customer-to-Priority Customer PRIME transactions from the number of options contracts executed on the Exchange by any Member for purposes of the volume threshold and the rebate program is reasonable, equitable, and not unfairly discriminatory because participating Members could otherwise game the rebate program and volume thresholds by executing excess volumes in these types of transactions in which no transaction fees are charged on the Exchange. Further, the Exchange
The Exchange believes that the proposal to allow the aggregation of trading activity of separate Members or its affiliates for purposes of the fee reduction is fair, equitable and not unreasonably discriminatory. The Exchange believes the proposed rule change is reasonable because it would allow aggregation of the trading activity of separate Members or its affiliates for purposes of the fee reduction only in very narrow circumstances, namely, where the firm is an affiliate, as defined herein. Furthermore, other exchanges, as well as MIAX, have rules that permit the aggregation of the trading activity of affiliated entities for the purposes of calculating and assessing certain fees.
The Exchange does not believe that the proposed rule change will impose any burden on competition not necessary or appropriate in furtherance of the purposes of the Act. The Exchange believes the proposal is consistent with robust competition by increasing the intermarket competition for order flow from market participants. To the extent that there is additional competitive burden on market participants without Priority Customer order flow and those market participants that are not able to aggregate order flow with affiliates, the Exchange believes that this is appropriate because the proposal should incent Members to direct additional order flow to the Exchange and thus provide additional liquidity that enhances the quality of its markets and increases the volume of contracts traded here. To the extent that this purpose is achieved, all the Exchange's market participants should benefit from the improved market liquidity. Enhanced market quality and increased transaction volume that results from the anticipated increase in order flow directed to the Exchange will benefit all market participants and improve competition on the Exchange. The Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive. In such an environment, the Exchange must continually adjust its fees to remain competitive with other exchanges and to attract order flow. The Exchange believes that the proposal reflects this competitive environment.
Written comments were neither solicited nor received.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) of the Act.
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”),
Nasdaq proposes to amend and restate certain Nasdaq rules that govern the Nasdaq Market Center in order to provide a clearer and more detailed description of certain aspects of its functionality. The text of the proposed rule change is available at
In its filing with the Commission, NASDAQ 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. NASDAQ has prepared summaries, set forth in Sections A, B, and C below, of the most significant aspects of such statements.
Nasdaq proposes to amend and restate certain Nasdaq rules that govern the Nasdaq Market Center in order to provide a clearer and more detailed description of certain aspects of its functionality. The proposed rule change is responsive to the request of Commission Chair White that each self-regulatory organization (“SRO”) conduct a comprehensive review of each order type offered to members, and how it operates in practice.
At present, most of the rules governing Nasdaq Order Types and Order Attributes are found in Rule 4751 (Definitions). Nasdaq is proposing to restate Rule 4751 as Rule 4701, which is currently not in use, with certain amended definitions being adopted therein. Nasdaq is also proposing to remove definitions pertaining to Order Types and Order Attributes and adopt them as separate new Rules 4702 (Order Types) and 4703 (Order Attributes). While Nasdaq is also proposing certain conforming changes to other rules, in subsequent proposed rule changes Nasdaq plans to restate the remainder of the rules numbered 4752 through 4780 so that they appear sequentially following Rule 4703.
New Rule 4701 will adopt revised definitions applicable to the Rule 4000 Series of the Nasdaq rules:
• The terms “Best Bid”, “Best Offer”, “National Best Bid and National Best Offer”, “Protected Bid”, “Protected Offer”, “Protected Quotation”, and “Intermarket Sweep Order” shall have the meanings assigned to them under Rule 600 under SEC Regulation NMS;
• The term “Nasdaq Market Center,” or “System”, which defines the components of the securities execution and trade reporting system owned and operated by The NASDAQ Stock Market LLC, is being modified to state that the System includes a montage for “Quotes” and “Orders”, referred to as the “Nasdaq Book”, that collects and ranks all Quotes and Orders submitted by “Participants”.
• The term “Quote” is being modified to make it clear that a Quote is an Order with Attribution (as defined in Rule 4703) entered by a Market Maker or Nasdaq ECN for display (price and size) next to the Participant's MPID in the
• The definition of the term “Order” is being amended to mean an instruction to trade a specified number of shares in a specified System Security
• The term “ET” means Eastern Standard Time or Eastern Daylight Time, as applicable.
• The term “Market Hours” is being defined to mean the period of time beginning at 9:30 a.m. ET and ending at 4:00 p.m. ET (or such earlier time as may be designated by Nasdaq on a day when Nasdaq closes early). The term “System Hours” means the period of time beginning at 4:00 a.m. ET and ending at 8:00 p.m. ET (or such earlier time as may be designated by Nasdaq on a day when Nasdaq closes early). The term “Pre-Market Hours” means the period of time beginning at 4:00 a.m. ET and ending immediately prior to the commencement of Market Hours. The term “Post-Market Hours” means the period of time beginning immediately after the end of Market Hours and ending at 8:00 p.m. ET.
• The term “marketable” with respect to an Order to buy (sell) means that, at the time it is entered into the System, the Order is priced at the current Best Offer or higher (at the current Best Bid or lower).
• The term “market participant identifier” or “MPID” means a unique four-letter mnemonic assigned to each Participant in the Nasdaq Market Center. A Participant may have one or more than one MPID.
• The term “minimum price increment” means $0.01 in the case of a System Security priced at $1 or more per share, and $0.0001 in the case of a System Security priced at less than $1 per share.
• The definition of the term “System Book Feed”, which means a data feed for System Securities, is being amended to clarify that it is the data feed generally known as the TotalView ITCH feed.
Proposed Rule 4702 provides that Participants may express their trading interest in the Nasdaq Market Center by entering Orders. The Nasdaq Market Center offers a range of Order Types that behave in the manner specified for each particular Order Type. Each Order Type may be assigned certain Order Attributes that further define its behavior. All Order Types and Order Attributes operate in a manner that is reasonably designed to comply with the requirements of Rules 610 and 611 under Regulation NMS. Specifically, Orders are reasonably designed to prevent trade-throughs of Protected Quotations to the extent required by Rule 611 under Regulation NMS, and to prevent the display of quotations that lock or cross Protected Quotations to the extent required by Rule 610 under Regulation NMS.
Proposed Rule 4702 further provides that Nasdaq maintains several communications protocols for Participants to use in entering Orders and sending other messages to the Nasdaq Market Center:
• OUCH is a Nasdaq proprietary protocol;
• RASH is a Nasdaq proprietary protocol;
• QIX is a Nasdaq proprietary protocol;
• FLITE is a Nasdaq proprietary protocol;
• FIX is a non-proprietary protocol.
Upon entry, an Order is processed to determine whether it may execute against any contra-side Orders on the Nasdaq Book in accordance with the parameters applicable to the Order Type and Order Attributes selected by the Participant and in accordance with the priority for Orders on the Nasdaq Book provided in Rule 4757.
Thereafter, as detailed in proposed Rules 4702 and 4703, and current Rule 4758 (Order Routing), there are numerous circumstances in which the
Nasdaq is amending Rule 4756 to make it clear that the redesignation of a sell Order as a long sale, short sale, or exempt short sale can be done only with respect to Orders entered through OUCH or FLITE; Orders entered through RASH, QIX, or FIX would have to be cancelled and reentered to change their designation. Similarly, Rule 4756 is being amended to clarify that modification of an Order by the Participant to decrease its size is not possible with respect to an MOO Order, an LOO Order, an OIO Order, an MOC Order, an LOC Order, an IO Order, or a Pegged Order (including a Discretionary Order that is Pegged). Such an Order would have to be cancelled and reentered by the Participant to reduce its size.
In addition, the proposed rule notes that all Orders are also subject to cancellation and/or repricing and reentry onto the Nasdaq Book in the circumstances described in Rule 4120(a)(12) (providing for compliance with Plan to Address Extraordinary Market Volatility) and Rule 4763 (providing for compliance with Regulation SHO). In all circumstances where an Order is repriced pursuant to those provisions, it is processed by the System as a new Order with respect to potential execution against Orders on the Nasdaq Book, price adjustment, routing, reposting to the Nasdaq Book, and subsequent execution against incoming Orders. If multiple Orders at a given price are repriced, the Order in which they are reentered is random, based on the respective processing time for each such Order;
Proposed Rule 4702 further describes the behavior of each Order Type. Except where otherwise stated, each Order Type is available to all Participants, although certain Order Types and Order Attributes may require the use of a specific protocol. As a result, a Participant would be required to use that protocol in order to use Order Types and Order Attributes available through it. Moreover, a small number of Order Types and Order Attributes are available only to registered Market Makers in the security for which they are registered.
The Price to Comply Order is an Order Type designed to comply with Rule 610(d) under Regulation NMS by having its price and display characteristics adjusted to avoid the display of quotations that lock or cross any Protected Quotation in a System Security during Market Hours. The Price to Comply Order is also designed to provide potential price improvement. The Nasdaq Market Center does not have a “plain vanilla” limit order that attempts to execute at its limit price and is then posted at its price or rejected if it cannot be posted; rather, the Price to Comply Order, with its price and display adjustment features, is one of the primary Order Types used by Participants to access and display liquidity in the Nasdaq Market Center. The price and display adjustment features of the Order Type enhance efficiency and investor protection by offering an Order Type that first attempts to access available liquidity and then to post the remainder of the Order at prices that are designed to maximize their opportunities for execution.
When a Price to Comply Order is entered, the Price to Comply Order will be executed against previously posted Orders on the Nasdaq Book that are priced equal to or better than the price of the Price to Comply Order, up to the full amount of such previously posted Orders, unless such executions would trade through a Protected Quotation. Any portion of the Order that cannot be executed in this manner will be posted on the Nasdaq Book (and/or routed if it has been designated as Routable).
During Market Hours, the price at which a Price to Comply Order is posted is determined in the following manner. If the entered limit price of the Price to Comply Order would lock or cross a Protected Quotation and the Price to Comply Order could not execute against an Order on the Nasdaq Book at a price equal to or better than the price of the Protected Quotation, the Price to Comply Order will be displayed on the Nasdaq Book at a price one minimum price increment lower than the current Best Offer (for a Price to Comply Order to buy) or higher than the current Best Bid (for a Price to Comply Order to sell) but will also be ranked on the Nasdaq Book with a non-displayed price equal to the current Best Offer (for a Price to Comply Order to buy) or to the current Best Bid (for a Price to Comply Order to sell). The posted Order will then be available for execution at its non-displayed price, thus providing opportunities for price improvement to incoming Orders.
For example, if a Price to Comply Order to buy at $11 would lock a Protected Offer of $11, the Price to Comply Order will be ranked at a non-displayed price of $11 but will be displayed at $10.99. An incoming Order to sell at a price of $11 or lower would execute against the Price to Comply Order at $11.
During Pre-Market Hours and Post-Market Hours, a Price to Comply Order will be ranked and displayed at its entered limit price without adjustment. This is the case because Nasdaq's rule with respect to locked and crossed markets, as adopted pursuant to Rule 610(d) under Regulation NMS and approved by the Commission, applies only during Market Hours.
Depending on the protocol used to enter a Price to Comply Order, Participants have different options with respect to adjustment of the Price to Comply Order following its initial entry and posting to the Nasdaq Book. Specifically, if a Price to Comply Order is entered through RASH, QIX, or FIX, during Market Hours the price of the Price to Comply Order will be adjusted in the following manner after initial entry and posting to the Nasdaq Book (unless the Order is assigned a Routing Order Attribute that would cause it to be routed to another market center rather than remaining on the Nasdaq Book):
• If the entered limit price of the Price to Comply Order locked or crossed a Protected Quotation and the NBBO changes, the displayed and non-displayed price of the Price to Comply Order will be adjusted repeatedly in accordance with changes to the NBBO; provided, however, that if the quotation of another market center moves in a manner that would lock or cross the displayed price of a Price to Comply Order, the prices of the Price to Comply Order will not be adjusted. For example, if a Price to Comply Order to buy at $11.02 would cross a Protected Offer of $11, the Order will be ranked at its non-displayed price of $11 but will be displayed at $10.99. If the Best Offer then moves to $11.01, the displayed price will be changed to $11 and the Order will be ranked at a non-displayed price of $11.01. However, if another market center then displays an offer of $11 (thereby locking the previously displayed price of the Price to Comply Order, notwithstanding Rule 610(d) under Regulation NMS), the price of the Price to Comply Order will not be changed.
• If the original entered limit price of the Price to Comply Order would no longer lock or cross a Protected Quotation, the Price to Comply Order will be ranked and displayed at that price and will receive a new timestamp, and will not thereafter be adjusted under this provision.
If a Price to Comply Order is entered through OUCH or FLITE, during Market Hours the price of the Price to Comply Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• If the entered limit price of the Price to Comply Order crossed a Protected Quotation and the NBBO changes so that the Price to Comply Order could be displayed at a price at or closer to its entered limit price without locking or crossing a Protected Quotation, the Price to Comply Order may either remain on the Nasdaq Book unchanged or may be cancelled back to the Participant, depending on its choice. For example, if a Price to Comply Order to buy at $11.02 would cross a Protected Offer of $11, the Order will be ranked at a non-displayed price of $11 but will be displayed at $10.99. If the Best Offer changes to $11.01, the Order will not be repriced, but rather will either remain with a displayed price of $10.99 but ranked at a non-displayed price of $11 or be cancelled back to the Participant, depending on its choice. A Participant's choice with regard to maintaining the Price to Comply Order or cancelling it is set in advance for each port through which the Participant enters Orders.
• If the entered limit price of the Price to Comply Order locked a Protected Quotation, the price of the Price to Comply Order will be adjusted after initial entry only as follows. If the entered limit price would no longer lock a Protected Quotation, the Price to Comply Order may either remain on the Nasdaq Book unchanged, may be cancelled back to the Participant, or may be ranked and displayed at its original entered limit price, depending on the Participant's choice. For example, if a Price to Comply Order to buy at $11 would lock a Protected Offer of $11, the Price to Comply Order will be ranked at a non-displayed price of $11 but will be displayed at $10.99. If the Best Offer changes to $11.01, the Price to Comply Order may either remain with a displayed price of $10.99 but ranked at a non-displayed price of $11, be cancelled back to the Participant, or be ranked and displayed at $11, depending on the Participant's choice. A Participant's choice with regard to maintaining the Price to Comply Order, cancelling it, or allowing it to be displayed is set in advance for each port through which the Participant enters Orders. If the Price to Comply Order is ranked and displayed at its original entered limit price, it will receive a new timestamp, and will not thereafter be adjusted under this provision.
With regard to the foregoing options, it is important to emphasize that the Price to Comply Order receives a new timestamp whenever its price is changed, and also receives a new timestamp if the Price to Comply Order would no longer lock a Protected Quotation and is therefore displayed at its original entered limit price. Thus, there are no circumstances under which a Price to Comply Order that originally locked or crossed a Protected Quotation would “jump the queue” and be displayed at its original entered limit price while retaining its original time priority. In fact, as discussed throughout this filing, Nasdaq does not offer any functionality that enables a Participant to “jump the queue” by displaying a previously entered non-displayed Orders without also receiving a new timestamp.
The following Order Attributes may be assigned to a Price to Comply Order. The effect of each Order Attribute is discussed in detail below with respect to proposed new Rule 4703.
• Price. As described above, the price of the Order may be adjusted to avoid locking or crossing a Protected Quotation, and may include a displayed price as well as a non-displayed price.
• Size.
• Reserve Size (available through RASH, FIX and QIX only).
• A Time-in-Force other than “Immediate or Cancel” (“IOC”).
• Designation as an “ISO”. In accordance with Regulation NMS, a Price to Comply Order designated as an ISO would be processed at its entered limit price, since such a designation reflects a representation by the Participant that it has simultaneously
• Routing (available through RASH, FIX and QIX only).
• “Primary Pegging” and “Market Pegging” (available through RASH, FIX, and QIX only).
• “Discretion” (available through RASH, FIX and QIX only).
• Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross.
• Display. A Price to Comply Order is always displayed, although, as provided above, it may also have a non-displayed price and/or Reserve Size.
A “Price to Display Order” is an Order Type designed to comply with Rule 610(d) under Regulation NMS by avoiding the display of quotations that lock or cross any Protected Quotation in a System Security during Market Hours. Price to Display Orders are available solely to Participants that are Market Makers and are always Attributable.
When a Price to Display Order is entered, if its entered limit price would lock or cross a Protected Quotation, the Price to Display Order will be repriced to one minimum price increment lower than the current Best Offer (for a Price to Display Order to buy) or higher than the current Best Bid (for a Price to Display Order to sell). For example, if a Price to Display Order to buy at $11 would cross a Protected Offer of $10.99, the Price to Display Order will be repriced to $10.98. The Price to Display Order (whether repriced or not repriced) will then be executed against previously posted Orders on the Nasdaq Book that are priced equal to or better than the adjusted price of the Price to Display Order, up to the full amount of such previously posted Orders, unless such executions would trade through a Protected Quotation. Any portion of the Order that cannot be executed in this manner will be posted on the Nasdaq Book (and/or routed if it has been designated as Routable).
During Market Hours, the price at which a Price to Display Order is displayed and ranked on the Nasdaq Book will be its entered limit price if the Price to Display Order was not repriced upon entry, or the adjusted price if the Price to Comply Order [sic] was repriced upon entry, such that the price will not lock or cross a Protected Quotation. During Pre-Market Hours and Post-Market Hours, a Price to Display Order will be displayed and ranked at its entered limit price without adjustment.
As is the case with a Price to Comply Order, a Price to Display Order may be adjusted after initial entry.
• If the entered limit price of the Price to Display Order locked or crossed a Protected Quotation and the NBBO changes, the price of the Order will be adjusted repeatedly in accordance with changes to the NBBO; provided, however, that if the quotation of another market center moves in a manner that would lock or cross the price of a Price to Display Order, the price of the Price to Display Order will not be adjusted.
• If the original entered limit price of the Price to Display Order would no longer lock or cross a Protected Quotation, the Price to Display Order will be displayed and ranked at that price and will receive a new timestamp, and will not thereafter be adjusted under this provision.
If a Price to Display Order is entered through OUCH or FLITE, during Market Hours the Price to Display Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• If the entered limit price of the Price to Display Order locked or crossed a Protected Quotation and the NBBO changes so that the Price to Display Order could be ranked and displayed at a price at or closer to its original entered limit price without locking or crossing a Protected Quotation, the Price to Display Order may either remain on the Nasdaq Book unchanged or may be cancelled back to the Participant, depending on the Participant's choice. For example, if a Price to Display Order to buy at $11.02 would cross a Protected Offer of $11, the Order will be ranked and displayed at $10.99. If the Best Offer changes to $11.01, the Price to Display Order will not be repriced, but rather will either remain at its current price or be cancelled back to the Participant, depending on its choice. A Participant's choice with regard to maintaining the Price to Display Order or cancelling it is set in advance for each port through which the Participant enters Orders.
The following Order Attributes may be assigned to a Price to Display Order:
• Price. As described above, the price of the Order may be adjusted to avoid locking or crossing a Protected Quotation.
• Size.
• Reserve Size (available through RASH, FIX and QIX only).
• A Time-in-Force other than IOC.
• Designation as an ISO. In accordance with Regulation NMS, a Price to Display Order designated as an ISO would be processed at its entered
• Routing (available through RASH, FIX and QIX only).
• Primary Pegging and Market Pegging (available through RASH, FIX and QIX only).
• Discretion (available through RASH, FIX and QIX only).
• Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross.
• Attribution. All Price to Display Orders are Attributable Orders.
• Display. A Price to Display Order is always displayed (but may also have Reserve Size).
A “Non-Displayed Order” is an Order Type that is not displayed to other Participants, but nevertheless remains available for potential execution against incoming Orders until executed in full or cancelled. Thus, the Order Type provides a means by which Participants may access and/or offer liquidity without signaling to other Participants the extent of their trading interest. The Order may also serve to provide price improvement vis-à-vis the NBBO. Under Regulation NMS, a Non-Displayed Order may lock a Protected Quotation and may be traded-through by other market centers.
When a Non-Displayed Order is entered, the Non-Displayed Order will be executed against previously posted Orders on the Nasdaq Book that are priced equal to or better than the price of the Non-Displayed Order, up to the full amount of such previously posted Orders, unless such executions would trade through a Protected Quotation. Any portion of the Non-Displayed Order that cannot be executed in this manner will be posted to the Nasdaq Book (unless the Non-Displayed Order has a Time-in-Force of IOC) and/or routed if it has been designated as Routable.
During Market Hours, the price at which a Non-Displayed Order is posted is determined in the following manner. If the entered limit price of the Non-Displayed Order would lock a Protected Quotation, the Non-Displayed Order will be placed on the Nasdaq Book at the locking price. If the Non-Displayed Order would cross a Protected Quotation, the Non-Displayed Order will be repriced to a price that would lock the Protected Quotation and will be placed on the Nasdaq Book at that price.
As is the case with a Post to Comply Order, a Non-Displayed Order may be adjusted after initial entry.
• If the original entered limit price of a Non-Displayed Order is higher than the Best Offer (for an Order to buy) or lower than the Best Bid (for an Order to sell) and the NBBO moves toward the original entered limit price of the Non-Displayed Order, the price of the Non-Displayed Order will be adjusted repeatedly in accordance with changes to the NBBO. For example, if a Non-Displayed Order to buy at $11.02 would cross a Protected Offer of $11, the Non-Displayed Order will be priced and posted at $11. If the Best Offer then changes to $11.01, the price of the Non-Displayed Order will be changed to $11.01. The Order may be repriced repeatedly in this manner, receiving a new timestamp each time its price is changed, until the Non-Displayed Order is posted at its original entered limit price.
• If, after being posted to the Nasdaq Book, the NBBO changes so that the Non-Displayed Order would cross a Protected Quotation, the Non-Displayed Order will be repriced at a price that would lock the new NBBO and receive a new timestamp.
If a Non-Displayed Order is entered through OUCH or FLITE, during Market Hours the Non-Displayed Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• If the original entered limit price of the Non-Displayed Order locked or crossed a Protected Quotation and the NBBO changes so that the Non-Displayed Order could be posted at a price at or closer to its original entered limit price without crossing a Protected Quotation, the Non-Displayed Order may either remain on the Nasdaq Book unchanged or may be cancelled back to the Participant, depending on its choice. For example, if a Non-Displayed Order to buy at $11.02 would cross a Protected Offer of $11, the Order will be priced at $11. If the Best Offer changes to $11.01, the Order will not be repriced, but rather will either remain at its current $11 price or be cancelled back to the Participant, depending on its choice. A Participant's choice with regard to maintaining the Non-Displayed Order or cancelling it is set in advance for each port through which the Participant enters Orders.
• If, after a Non-Displayed Order is posted to the Nasdaq Book, the NBBO changes so that the Non-Displayed Order would cross a Protected Quotation, the Non-Displayed Order will be cancelled back to the
• If a Non-Displayed Order entered through OUCH or FLITE is assigned a Midpoint Pegging Order Attribute,
• Price. As described above, the price of the Order may be adjusted to avoid crossing a Protected Quotation.
• Size.
• “Minimum Quantity”.
• Time-in-Force.
• Designation as an ISO. In accordance with Regulation NMS, a Non-Displayed Order designated as an ISO would be processed at its entered limit price, since such a designation reflects a representation by the Participant that it has simultaneously routed one or more additional limit orders, as necessary, to execute against the full displayed size of any Protected Quotations that the Non-Displayed Order would cross. As discussed above, a Non-Displayed Order would be accepted at a price that locked a Protected Quotation, even if the Order was not designated as an ISO, because the non-displayed nature of the Order allows it to lock a Protected Quotation under Regulation NMS. Accordingly, the System would not interpret receipt of a Non-Displayed Order marked ISO that locked a Protected Quotation as the basis for determining that the Protected Quotation had been executed for purposes of accepting additional Orders at that price level.
• Routing (available through RASH, FIX and QIX only).
• Primary Pegging and Market Pegging (available through RASH, FIX and QIX only).
• Pegging to the Midpoint.
• Discretion (available through RASH, FIX and QIX only).
• Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross.
A “Post-Only Order” is an Order Type designed to have its price adjusted as needed to post to the Nasdaq Book in compliance with Rule 610(d) under Regulation NMS by avoiding the display of quotations that lock or cross any Protected Quotation in a System Security during Market Hours, or to execute against locking or crossing quotations in circumstances where economically beneficial to the Participant entering the Post-Only Order. Post-Only Orders are always displayed, although as discussed below, they may also have a non-displayed price in circumstances similar to a Price to Comply Order. Post-Only Orders are thus designed to allow Participants to help control their trading costs, while also “provid[ing] displayed liquidity to the market and thereby contribut[ing] to public price discovery—an objective that is fully consistent with the Act.”
During Market Hours, a Post-Only Order is evaluated at the time of entry with respect to locking or crossing other Orders on the Nasdaq Book, Protected Quotations, and potential execution as follows:
• If a Post-Only Order would lock or cross a Protected Quotation, the price of the Order will first be adjusted. If the Order is Attributable, its adjusted price will be one minimum price increment lower than the current Best Offer (for bids) or higher than the current Best Bid (for offers). If the Order is not Attributable, its adjusted price will be equal to the current Best Offer (for bids) or the current Best Bid (for offers). However, the Order will not post or execute until the Order, as adjusted, is evaluated with respect to Orders on the Nasdaq Book.
• If the adjusted price of the Post-Only Order would not lock or cross an Order on the Nasdaq Book, the Order will be posted in the same manner as a Price to Comply Order (if it is not Attributable) or a Price to Display Order (if it is Attributable). Specifically, if the Post-Only Order is not Attributable, it will be displayed on the Nasdaq Book at a price one minimum price increment lower than the current Best Offer (for bids) or higher than the current Best Bid (for offers) but will be ranked on the Nasdaq Book with a non-displayed price equal to the current Best Offer (for bids) or to the current Best Bid (for offers). For example, if a Post-Only Order to buy at $11 would lock a Protected Offer of $11, the Order will be ranked at a non-displayed price of $11 but will be displayed at $10.99. If the Post-Only Order is Attributable, it will be ranked and displayed on the Nasdaq Book at a price one minimum increment lower than the current Best Offer (for bids) or higher than the current Best Bid (for offers). Thus, in the preceding example, the Post-Only Order to buy would be ranked and displayed at $10.99.
• If the adjusted price of the Post-Only Order would lock or cross an Order on the Nasdaq Book, the Post Only Order will be repriced, ranked, and displayed at one minimum price increment below the current best-priced Order to sell on the Nasdaq Book (for bids) or above the current best-priced Order to buy on the Nasdaq Book (for offers); provided, however, the Post-Only Order will execute if (i) it is priced below $1.00 and the value of price improvement associated with executing against an Order on the Nasdaq Book (as measured against the original limit price of the Order) equals or exceeds the sum of fees charged for such execution and the value of any rebate that would be provided if the Order posted to the Nasdaq Book and subsequently
• If the Post-Only Order would not lock or cross a Protected Quotation but would lock or cross an Order on the Nasdaq Book, the Post Only Order will be repriced, ranked, and displayed at one minimum price increment below the current best-priced Order to sell on the Nasdaq Book (for bids) or above the current best-priced Order to buy on the Nasdaq Book (for offers); provided, however, the Post-Only Order will execute if (i) it is priced below $1.00 and the value of price improvement associated with executing against an Order on the Nasdaq Book equals or exceeds the sum of fees charged for such execution and the value of any rebate that would be provided if the Order posted to the Nasdaq Book and subsequently provided liquidity, or (ii) it is priced at $1.00 or more and the value of price improvement associated with executing against an Order on the Nasdaq Book equals or exceeds $0.01 per share. For example, if a Participant entered a Post-Only Order to buy at $11.02, the Best Offer was $11.04, and there was a Non-Displayed Order on the Nasdaq Book to sell at $11.02, the Post-Only Order would be ranked and displayed at $11.01. However, if a Participant entered a Post-Only Order to buy at $11.03, the Order would execute against the Order on the Nasdaq Book at $11.02, receiving $0.01 per share price improvement.
• If a Post-Only Order is entered with a Time-in-Force of IOC, the price of an Order to buy (sell) will be repriced to the lower of (higher of) (i) one minimum price increment below (above) the price of the Order or (ii) the current Best Offer (Best Bid). The Order will execute against any Order on the Nasdaq Book with a price equal to or better than the adjusted price of the Post-Only Order. If the Post-Only Order cannot execute, it will be cancelled. For example, if a Post-Only Order to buy at $11 with a Time-in-Force of IOC was entered and the current Best Offer was $11.01, the Order would be repriced to $10.99; however, if the Best Offer was $10.98, the Order would be repriced to $10.98.
• If a Post-Only Order would not lock or cross an Order on the Nasdaq Book or any Protected Quotation, it will be posted on the Nasdaq Book at its entered limit price.
During Pre-Market and Post-Market Hours, a Post-Only Order will be processed in a manner identical to Market Hours with respect to locking or crossing Orders on the Nasdaq Book, but will not have its price adjusted with respect to locking or crossing the quotations of other market centers.
If a Post-Only Order is entered through RASH, QIX, or FIX, during System Hours the Post-Only Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• If the original entered limit price of the Post-Only Order is not being displayed, the displayed (and non-displayed price, if any) of the Order will be adjusted repeatedly in accordance with changes to the NBBO or the best price on the Nasdaq Book, as applicable; provided, however, that if the quotation of another market center moves in a manner that would lock or cross the displayed price of a Post-Only Order, the price(s) of the Post-Only Order will not be adjusted.
If a Post-Only Order is entered through OUCH or FLITE, the Post-Only Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• During Market Hours, if the original entered limit price of the Post-Only Order locked or crossed a Protected Quotation, the Post-Only Order may be adjusted after initial entry in the same manner as a Price to Comply Order (or a Price to Display Order, if it is Attributable). Thus, in the case of a Non-Attributable Post-Only Order that crossed a Protected Quotation, if the NBBO changed so that the Post-Only Order could be ranked and displayed at a price at or closer to its original entered limit price without locking or crossing a Protected Quotation, the Post-Only Order may either remain on the Nasdaq Book unchanged or may be cancelled back to the Participant, depending on its choice. In the case of a Non-Attributable Post-Only Order that locked a Protected Quotation, if the limit price would no longer lock a Protected Quotation, the Post-Only Order may either remain on the Nasdaq Book unchanged, may be cancelled back to the Participant, or may be ranked and displayed at its original entered limit price, depending on the Participant's choice, and will not thereafter be adjusted under this provision.
• During System Hours, if the original entered limit price of the Post-Only Order locked or crossed an Order on the Nasdaq Book and the Nasdaq Book changes so that the original entered limit price would no longer lock or cross an Order on the Nasdaq Book, the Post-Only Order may either remain on the Nasdaq Book unchanged or may be cancelled back to the Participant, depending on the Participant's choice. For example, if a Post-Only Order to buy at $11 would lock an Order on the Nasdaq Book priced at $11, the Post-Only Order will be ranked and displayed at $10.99. If the Order at $11 is cancelled or executed, the Post-Only Order may either remain with a displayed price of $10.99 or be cancelled back to the Participant, depending on the Participant's choice. A Participant's choice with regard to maintaining the Post-Only Order or cancelling it is set in advance for each port through which the Participant enters Orders.
The following Order Attributes may be assigned to a Post-Only Order:
• Price. As described above, the price of the Order may be adjusted to avoid locking or crossing a Protected Quotation, and may include a displayed price as well as a non-displayed price.
• Size.
• Time-in-Force.
• Designation as an ISO. In accordance with Regulation NMS, a Post-Only Order designated as an ISO that locked or crossed a Protected Quotation would be processed at its entered limit price, since such a designation reflects a representation by the Participant that it has simultaneously routed one or more additional limit orders, as necessary, to execute against the full displayed size of any Protected Quotations that the Post-Only Order would lock or cross.
• Attribution.
• Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross.
• Display. A Post-Only Order is always displayed, although as provided above, may also have a non-displayed price.
A “Midpoint Peg Post-Only Order” is an Order Type with a Non-Display Order Attribute that is priced at the midpoint between the NBBO and that will execute upon entry against locking or crossing quotes only in circumstances where economically beneficial to the party entering the Order. Because the Order is priced at the midpoint, it can provide price improvement to incoming Orders when it is executed after posting to the Nasdaq Book. The Midpoint Peg Post-Only Order is available during Market Hours only.
A Midpoint Peg Post-Only Order must be assigned a limit price. When a Midpoint Peg Post-Only Order is entered, it will be priced at the midpoint between the NBBO, unless such midpoint is higher than (lower than) the limit price of an Order to buy (sell), in which case the Order will be priced at its limit price. If the NBBO is locked, the Midpoint Peg Post-Only Order will be priced at the locking price, if the NBBO is crossed, it will nevertheless be priced at the midpoint between the NBBO, and if there is no NBBO,
For purposes of any cross in which a Midpoint Peg Post-Only Order participates, a Midpoint Peg Post-Only Order to buy (sell) that is locking a preexisting Order shall be deemed to have a price equal to the price of the highest sell Order (lowest buy Order) that would be eligible to execute against the Midpoint Peg Post-Only Order in
If a Midpoint Peg Post-Only Order is entered through RASH, QIX, or FIX, the Midpoint Peg Post-Only Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• The price of the Midpoint Peg Post-Only Order will be updated repeatedly to equal the midpoint between the NBBO; provided, however, that the Order will not be priced higher (lower) than the limit price of an Order to buy (sell). In the event that the midpoint between the NBBO becomes higher than (lower than) the limit price of an Order to buy (sell), the price of the Order will stop updating, but will resume updating if the midpoint becomes lower than (higher than) the limit price of an Order to buy (sell). Similarly, if a Midpoint Peg Post-Only Order is on the Nasdaq Book and subsequently there is no NBBO, the Order will be cancelled. The Midpoint Peg Post-Only Order receives a new timestamp each time its price is changed.
If a Midpoint Peg Post-Only Order is entered through OUCH or FLITE, the Midpoint Peg Post-Only Order may be adjusted in the following manner after initial entry and posting to the Nasdaq Book:
• The price at which the Midpoint Peg Post-Only Order is ranked on the Nasdaq Book is the midpoint between the NBBO, unless the Order has a limit price that is lower than the midpoint between the NBBO for an Order to buy (higher than the midpoint between the NBBO for an Order to sell), in which case the Order will be ranked on the Nasdaq Book at its limit price. The price of the Order will not thereafter be adjusted based on changes to the NBBO. If, after being posted to the Nasdaq Book, the NBBO changes so that midpoint between the NBBO is lower than (higher than) the price of a Midpoint Peg Post-Only Order to buy (sell), the Midpoint Peg Post-Only Order will be cancelled back to the Participant. For example, if the Best Bid is $11 and the Best Offer is $11.06, a Midpoint Peg Post-Only Order to buy would post at $11.03. If, thereafter, the Best Offer is reduced to $11.05, the Midpoint Peg Post-Only Order will be cancelled back to the Participant.
The following Order Attributes may be assigned to a Midpoint Peg Post-Only Order:
• Price of more than $1 per share. A Midpoint Peg Post-Only Order that would be assigned a price of $1 or less per share will be rejected or cancelled, as applicable.
• Size.
• A Time-in-Force other than IOC; provided, however, that regardless of the Time-in-Force entered, a Midpoint Post-Only Order may not be active outside of Market Hours. A Midpoint Peg Post-Only Order entered prior to the beginning of Market Hours will be rejected. A Midpoint Peg Post-Only Order remaining on the Nasdaq Book at 4:00 p.m. ET will be cancelled by the System; provided, however, that if the Nasdaq Closing Cross for the security that is the subject of the Order occurs prior to the cancellation message being fully processed, a Midpoint Peg Post-Only Order may participate in the Nasdaq Closing Cross.
• Pegging to the midpoint is required for Midpoint Peg Post-Only Orders entered through RASH, QIX or FIX. As discussed above, the price of a Midpoint Peg Post-Only Order entered through OUCH or FLITE will be pegged to the midpoint upon entry and not adjusted thereafter.
• Minimum Quantity.
• Non-Display. All Midpoint Peg Post-Only Orders are Non-Displayed.
A “Supplemental Order” is an Order Type with a Non-Display Order Attribute that is held on the Nasdaq Book in order to provide liquidity at the NBBO through a special execution process described in Rule 4757(a)(1)(D). A Supplemental Order may be entered through the OUCH protocol only. The Order allows a Participant to provide greater depth of liquidity at the NBBO without signaling the full extent of its trading interest to other Participants.
Upon entry, a Supplemental Order will always post to the Nasdaq Book at a price equal to the Best Bid (for buys) or the Best Offer (for sells). Thereafter, the Supplemental Order may execute against an Order that is designated as eligible for routing, after the Order has executed against all other liquidity on the Nasdaq Book but before routing. An Order will execute against a Supplemental Order(s) only at the NBBO, only if the NBBO is not locked or crossed, and only if the Order can be executed in full. If a Supplemental Order is not executed in full, the remaining portion of the Supplemental Order shall remain on the Nasdaq Book as a Supplemental Order until the Supplemental Order is fully executed, the Supplemental Order is cancelled by the Participant that entered the Supplemental Order, or the size of the Supplemental Order is reduced to less than one normal unit of trading (in which case the Supplemental Order will be cancelled automatically).
The following Order Attributes may be assigned to a Supplemental Order:
• Price. The Price of a Supplemental Order to buy is always equal to the Best Bid, and the price of a Supplemental Order to sell is always equal to the Best Offer.
• Size. All Supplemental Orders must be entered with a size of one or more normal units of trading. When a Supplemental Order is reduced to less than one normal unit of trading, the remainder of the Supplemental Order will be cancelled automatically.
• A Time-in-Force other than IOC. A Supplemental Order may be entered at any time during Pre-Market Hours or Market Hours, but is available for potential execution only during Market Hours. Any Supplemental Orders still on the Nasdaq Book at the conclusion of Market Hours will be cancelled. Supplemental Orders may not participate in the Nasdaq Opening Cross or the Nasdaq Closing Cross.
• Primary Pegging. A Supplemental Order is not pegged to the NBBO through the regular Primary Pegging Order Attribute, and therefore does not have its price adjusted continually. However, if an incoming Order is potentially executable against a Supplemental Order, the System will set the price of the Supplemental Order at the NBBO on the same side of the market, with no offset. As a result, a Supplemental Order may only execute at the NBBO.
• Non-Display. All Supplemental Orders are Non-Displayed.
A “Market Maker Peg Order” is an Order Type designed to allow a Market Maker to maintain a continuous two-sided quotation at a price that is compliant with the quotation requirements for Market Makers set forth in Rule 4613(a)(2).
Upon entry, the price of a Market Maker Peg Order to buy (sell) is automatically set by the System at the Designated Percentage (as defined in Rule 4613) away from the Reference Price in order to comply with the quotation requirements for Market Makers set forth in Rule 4613(a)(2). For example, if the Best Bid is $10 and the Designated Percentage for the security is 8%, the price of a Market Marker Peg Order to buy would be $9.20. If the limit price of the Order is not within the Designated Percentage, the Order will be sent back to the Participant.
Once a Market Maker Peg Order has posted to the Nasdaq Book, its price is adjusted if needed as the Reference Price changes. Specifically, if as a result of a change to the Reference Price, the difference between the price of the Market Maker Peg Order and the Reference Price reaches the Defined Limit (as defined in Rule 4613), the price of a Market Maker Peg Order to buy (sell) will be adjusted to the Designated Percentage away from the Reference Price. In the foregoing example, if the Defined Limit is 9.5% and the Best Bid increased to $10.17, such that the price of the Market Maker Peg Order would be more than 9.5% away, the Order will be repriced to $9.35, or 8% away from the Best Bid. Note that calculated prices of less than the minimum increment will be rounded in a manner that ensures that the posted price will be set at a level that complies with the percentages stipulated by this rule. If the limit price of the Order is outside the Defined Limit, the Order will be sent back to the Participant.
Similarly, if as a result of a change to the Reference Price, the price of a Market Maker Peg Order to buy (sell) is within one minimum price variation more than (less than) a price that is 4% less than (more than) the Reference Price, rounded up (down), then the price of the Market Maker Peg Order to buy (sell) will be adjusted to the Designated Percentage away from the Reference Price. For example, if the Best Bid is $10 and the Designated Percentage for the security is 8%, the price of a Market Marker Peg Order to buy would initially be $9.20. If the Best Bid then moved to $9.57, such that the price of the Market Maker Peg Order would be a minimum of $0.01 more than a price that is 4% less than the Best Bid, rounded up (
A Market Maker may enter a Market Maker Peg Order with a more aggressive offset than the Designated Percentage, but such an offset will be expressed as a price difference from the Reference Price. Such a Market Maker Peg Order will be repriced in the same manner as a Price to Display Order with Attribution and Primary Pegging. As a result, the price of the Order will be adjusted whenever the price to which the Order is pegged is changed.
A new timestamp is created for a Market Maker Peg Order each time that its price is adjusted. In the absence of a Reference Price, a Market Maker Peg Order will be cancelled or rejected. If, after entry, a Market Maker Peg Order is priced based on a Reference Price other than the NBBO and such Market Maker Peg Order is established as the Best Bid or Best Offer, the Market Maker Peg Order will not be subsequently adjusted in accordance with this rule until a new Reference Price is established. If a Market Maker Peg Order is repriced 1,000 times, it will be cancelled. This restriction is designed to conserve System resources by limiting the persistence of Orders that update repeatedly without any reasonable prospect of execution.
Notwithstanding the availability of Market Maker Peg Order functionality, a Market Maker remains responsible for entering, monitoring, and resubmitting, as applicable, quotations that meet the requirements of Rule 4613.
The following Order Attributes may be assigned to a Market Maker Peg Order:
• Price. As discussed above, the price of Market Maker Peg Order is established by the Nasdaq Market Center based on the Reference Price, the Designated Percentage (or a narrower offset established by the Market Maker), the Defined Limit, and the 4% minimum difference from the NBBO.
• Size.
• A Time-in-Force other than IOC or “Good-till-Cancelled”.
• Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross.
• If the Market Maker designates a more aggressive offset, Primary Pegging is required.
• Attribution. All Market Maker Peg Orders are Attributable.
• Display. Market Marker Peg Orders are always Displayed.
A “Market On Open Order” or “MOO Order” is an Order Type entered without a price that may be executed only during the Nasdaq Opening Cross. Subject to the qualifications provided below, MOO Orders may be entered, cancelled, and/or modified between 4 a.m. ET and immediately prior to 9:28 a.m. ET. An MOO Order may not be cancelled or modified at or after 9:28 a.m. ET. An MOO Order shall execute only at the price determined by the Nasdaq Opening Cross.
The following Order Attributes may be assigned to a Market On Open Order:
• Price. An MOO Order is entered without a price and shall execute only at the price determined by the Nasdaq Opening Cross.
• Size.
• Time-in-Force. An MOO Order may execute only in the Nasdaq Opening Cross. However, a Participant may designate the Time-in-Force for an MOO Order either by designating a Time-in-Force of “On Open” or by entering another Order Type with a Market Pegging Attribute and flagging the Order to participate in the Nasdaq Opening Cross. An MOO Order entered through RASH or FIX with a Time-in-Force of IOC and flagged to participate in the Nasdaq Opening Cross that is entered after the time of the Nasdaq Opening Cross will be accepted but will be
• Participation in the Nasdaq Opening Cross is required for this Order Type.
A “Limit On Open Order” or “LOO Order” is an Order Type entered with a price that may be executed only in the Nasdaq Opening Cross, and only if the price determined by the Nasdaq Opening Cross is equal to or better than the price at which the LOO Order was entered. Subject to the qualifications provided below, LOO Orders may be entered, cancelled, and/or modified between 4 a.m. ET and immediately prior to 9:28 a.m. ET.
The following Order Attributes may be assigned to a Limit On Open Order:
• Price.
• Size.
• Time-in-Force. In general, an LOO Order may execute only in the Nasdaq Opening Cross. However, a Participant may designate the Time-in-Force for an LOO Order either by designating a Time-in-Force of “On Open,” in which case the Order will execute solely in the Nasdaq Opening Cross, or by entering another Order Type and Time-in-Force and flagging the Order to participate in the Nasdaq Opening Cross. In the latter case, if the Participant designates a Time-in-Force of IOC, the Order will participate solely in the Nasdaq Opening Cross. If the Participant enters a Time-in-Force that continues after the time of the Nasdaq Opening Cross, the Order will participate in the Nasdaq Opening Cross like an LOO Order, while operating thereafter in accordance with its designated Order Type and Order Attributes (if not executed in full in the Nasdaq Opening Cross). Such an Order may be referred to as an “Opening Cross/Market Hours Order.” If such an Order has a Time-in-Force that continues until at least the time of the Nasdaq Closing Cross, the Order may be referred to as a “Cross to Cross Order.”
• Following the Nasdaq Opening Cross, an Opening Cross/Market Hours Order may not operate as a Post-Only Order, Midpoint Peg Post-Only Order, a Supplemental Order, a Retail Order, or an RPI Order. In the case of a Market Maker Peg Order entered prior to 9:28 a.m. ET that is also designated to participate in the Nasdaq Opening Cross, the price of the Order for purposes of operating as an LOO Order will be established on entry and will not thereafter be pegged until after the completion of the Nasdaq Opening Cross. An Opening Cross/Market Hours Order that is entered between 9:28 a.m. and the time of the Nasdaq Opening Cross will be (i) held and entered into the System after the completion of the Nasdaq Opening Cross if it has been assigned a Pegging Attribute or Routing Attribute, (ii) treated as an Opening Imbalance Only Order and entered into the System after the completion of the Nasdaq Opening Cross if entered through RASH, QIX, or FIX but not assigned a Pegging Attribute or Routing Attribute, or (iii) treated as an Opening Imbalance Only Order and cancelled after the Nasdaq Opening Cross if entered through OUCH or FLITE. An Opening Cross/Market Hours Order entered through RASH or FIX after the time of the Nasdaq Opening Cross will be accepted but the Nasdaq Opening Cross flag will be ignored. A Routable Order flagged to participate in the Nasdaq Opening Cross with a Time-in-Force other than IOC and entered at or after 9:28 a.m. will be held and entered into the System after the Nasdaq Opening Cross. All other LOO Orders and Opening Cross/Market Hours Orders entered at or after 9:28 a.m. will be rejected.
• Participation in the Nasdaq Opening Cross is required for this Order Type.
An “Opening Imbalance Only Order” or “OIO Order” is an Order Type entered with a price that may be executed only in the Nasdaq Opening Cross and only against MOO Orders, LOO Orders, or Early Market Hours Orders (as defined in Rule 4752). OIO Orders may be entered between 4:00 a.m. ET until the time of execution of the Nasdaq Opening Cross, but may not be cancelled or modified at or after 9:28 a.m. ET. If the entered price of an OIO Order to buy (sell) is higher than (lower than) the highest bid (lowest offer) on the Nasdaq Book, the price of the OIO Order will be modified repeatedly to equal the highest bid (lowest offer) on the Nasdaq Book; provided, however, that the price of the Order will not be moved beyond its stated limit price. Thus, for example, if an OIO Order to buy was entered with a price of $11 and the current highest bid on the Nasdaq Book was $10.99, the OIO Order would be priced at $10.99. If the highest bid subsequently became $10.98, the OIO Order would again be repriced. However, if the highest bid moved to $11.01, the OIO Order would not be repriced.
The following Order Attributes may be assigned to an Opening Imbalance Only Order:
• Price.
• Size.
• Time-in-Force. An OIO Order may execute only in the Nasdaq Opening Cross. An OIO Order entered after the time of the execution of the Nasdaq Opening Cross will be rejected.
• Participation in the Nasdaq Opening Cross is required for this Order Type.
A “Market On Close Order” or “MOC Order” is an Order Type entered without a price that may be executed only during the Nasdaq Closing Cross. Subject to the qualifications provided below, MOC Orders may be entered, cancelled, and/or modified between 4 a.m. ET and immediately prior to 3:50 p.m. ET. Between 3:50 p.m. ET and immediately prior to 3:55 p.m. ET, an MOC Order can be cancelled and/or modified only if the Participant requests that Nasdaq correct a legitimate error in the Order (
The following Order Attributes may be assigned to a Market On Close Order:
• Price. An MOC Order is entered without a price and shall execute only at the price determined by the Nasdaq Closing Cross.
• Size.
• Time-in-Force. An MOC Order may execute only in the Nasdaq Closing Cross. However, a Participant may designate the Time-in-Force for an MOC Order either by designating a Time-in-Force of “On Close” or by entering a Time-in-Force of IOC and flagging the Order to participate in the Nasdaq Closing Cross. All MOC Orders entered after 3:50 p.m. ET will be rejected. Participation in the Nasdaq Closing Cross is required for this Order Type.
A “Limit On Close Order” or “LOC Order” is an Order Type entered with a price that may be executed only in the Nasdaq Closing Cross, and only if the
The following Order Attributes may be assigned to a Limit On Close Order:
• Price.
• Size.
• Time-in-Force. In general, an LOC Order may execute only in the Nasdaq Closing Cross. However, a Participant may designate the Time-in-Force for an LOC Order either by designating a Time-in-Force of “On Close,” in which case the Order will execute solely in the Nasdaq Closing Cross, or by entering another Order Type and Time-in-Force and flagging the Order to participate in the Nasdaq Closing Cross. In the latter case, if the Participant designates a Time-in-Force of IOC, the Order will participate solely in the Nasdaq Closing Cross. If the Participant enters a Time-in-Force that continues after the time of the Nasdaq Closing Cross, the Order will participate in the Nasdaq Closing Cross like an LOC Order, while operating thereafter in accordance with its designated Order Type and Order Attributes (if not executed in full in the Nasdaq Closing Cross). Such an Order may be referred to as a “Closing Cross/Extended Hours Order.”
• Following the Nasdaq Closing Cross, a Closing Cross/Extended Hours Order may not operate as a Post-Only Order, Midpoint Peg Post-Only Order, Supplemental Order, Retail Order, or RPI Order. In the case of a Market Maker Peg Order entered prior to 3:50 p.m. ET that is also designated to participate in the Nasdaq Closing Cross, the price of the Order for purposes of operating as an LOC Order will be established on entry and will not thereafter be pegged until after the completion of the Nasdaq Closing Cross. A Closing Cross/Extended Hours Order that is entered between 3:50 p.m. and the time of the Nasdaq Closing Cross will be (i) rejected if it has been assigned a Pegging Attribute, (ii) treated as an Imbalance Only Order and then entered into the System after the completion of the Nasdaq Closing Cross if entered through RASH, QIX, or FIX but not assigned a Pegging Attribute, and (iii) treated as an Imbalance Only Order and cancelled after the Nasdaq Closing Cross if entered through OUCH or FLITE. A Closing Cross/Extended Hours Order entered through OUCH, FLITE, RASH, or FIX with a Time-in-Force other than IOC after the time of the Nasdaq Closing Cross will be accepted but the Nasdaq Closing Cross flag will be ignored. All other LOC Orders and Closing Cross/Extended Hours Orders entered at or after 3:50 p.m. ET will be rejected.
• Participation in the Nasdaq Closing Cross is required for this Order Type.
An “Imbalance Only Order” or “IO Order” is an Order entered with a price that may be executed only in the Nasdaq Closing Cross and only against MOC Orders or LOC Orders. IO Orders may be entered between 4:00 a.m. ET until the time of execution of the Nasdaq Closing Cross, but may not [sic] cancelled or modified at or after 3:50 p.m. ET. Between 3:50 p.m. ET and immediately prior to 3:55 p.m. ET, however, an IO Order can be cancelled and/or modified if the Participant requests that Nasdaq correct a legitimate error in the Order (
The following Order Attributes may be assigned to an Imbalance Only Order:
• Price.
• Size.
• Time-in-Force. An IO Order may execute only in the Nasdaq Closing Cross. An IO Order entered after the time of the Nasdaq Closing Cross will be rejected.
• Participation in the Nasdaq Closing Cross is required for this Order Type.
These Order Types are currently described in Rule 4780 and were operated under a pilot program that expired on December 31, 2014. Because Nasdaq has opted not to extend this pilot, it is proposing to delete Rule 4780. Accordingly, these Order Types are not described in the restated rules.
Proposed Rule 4702 lists the Order Attributes that may be assigned to specific Order Types. Proposed Rule 4703 details the parameters of each Order Attribute.
The “Time-in-Force” assigned to an Order means the period of time that the Nasdaq Market Center will hold the Order for potential execution. Participants specify an Order's Time-in-Force by designating a time at which the Order will become active and a time at which the Order will cease to be active. The available times for activating Orders are:
• The time of the Order's receipt by the Nasdaq Market Center;
• the Nasdaq Opening Cross (or 9:30 a.m. ET in the case of a security for which no Nasdaq Opening Cross occurs);
• Market Hours, beginning after the completion of the Nasdaq Opening Cross (or at 9:30 a.m. ET in the case of a security for which no Nasdaq Opening Cross occurs);
• the Nasdaq Closing Cross (or the end of Market Hours in the case of a security for which no Nasdaq Closing Cross occurs);
• 8:00 a.m. ET, in the case of an Order using the SCAN routing strategy
• the beginning of the Display-Only Period, in the case of a security that is the subject of a trading halt and for which trading will resume pursuant to a halt cross; and
• the resumption of trading, in the case of a security that is the subject of a trading halt and for which trading resumes without a halt cross.
The available times for deactivating Orders are:
• “Immediate” (
• the end of Market Hours;
• the end of System Hours;
• one year after entry; or
• a specific time identified by the Participant; provided, however, that an Order specifying an expire time beyond the current trading day will be cancelled at the end of the current trading day.
Notwithstanding the Time-in-Force originally designated for an Order, a Participant may always cancel an Order after it is entered.
The following Times in Force are referenced elsewhere in Nasdaq's Rules by the designations noted below:
• An Order that is designated to deactivate immediately after determining whether the Order is marketable may be referred to as having a Time in Force of “Immediate or Cancel” or “IOC”. Except as provided in Rule 4702 with respect to Opening Cross/Market Hours Orders and Closing Cross/Extended Hours Orders, MOO, LOO, OIO, MOC, LOC and OI Orders all have a Time in Force of IOC, because they are designated for execution in the Nasdaq Opening Cross or the Nasdaq Closing Cross, as applicable, and are cancelled after determining whether they are executable in such cross. Such an Order may also be referred to as having a Time-in-Force of “On Open” or “On Close”, respectively. An MOO, LOO, OIO, MOC, LOC or IO Order, or any other Order with a Time-in-Force of IOC entered between 9:30 a.m. ET and 4:00 p.m. ET, may be referred to as having a Time-in-Force of “Market Hours Immediate or Cancel” or “MIOC”. An Order with a Time-in-Force of IOC that is entered at any time between 4:00 a.m. ET and 8:00 p.m. ET may be referred to as having a Time-in-Force of “System Hours Immediate or Cancel” or “SIOC”.
• An Order that is designated to deactivate at 8:00 p.m. may be referred to as having a Time in Force of “System Hours Day” or “SDAY”.
• An Order that is designated to deactivate one year after entry may be referred to as a “Good-till-Cancelled” or “GTC” Order. If a GTC Order is designated as eligible for execution during Market Hours only, it may be referred to as having a Time in Force of “Market Hours Good-till-Cancelled” or “MGTC”. If a GTC is designated as eligible for execution during System Hours, it may be referred to as having a Time in Force of “System Hours Good-till-Cancelled” or “SGTC”.
• An Order that is designated to deactivate at the time specified in advance by the entering Participant may be referred to as having a Time-in-Force of “System Hours Expire Time” or “SHEX”.
• An Order that is designated to activate at any time during Market Hours and deactivate at the completion of the Nasdaq Closing Cross may be referred to as having a Time-in-Force of “Market Hours Day” or “MDAY”. An Order entered with a Time-in-Force of MDAY after the completion of the Nasdaq Closing Cross will be rejected.
• An Order that is designated to activate when entered and deactivate at the completion of the Nasdaq Closing Cross may be referred to as having a Time in Force of “Good-till-Market Close” or “GTMC”. GTMC Orders entered after 4:00 p.m. ET will be rejected.
• A Participant entering an Order using the SCAN routing strategy prior to 8:00 a.m. ET may designate the Order to activate upon entry, or at 8:00 a.m. ET. The latter option may be referred to as “ESCN”.
Except as otherwise provided, an Order may be entered in any whole share size between one share and 999,999 shares. Orders for fractional shares are not permitted. The following terms may be used to describe particular Order sizes:
• “normal unit of trading” or “round lot” means the size generally employed by traders when trading a particular security, which is 100 shares in most instances;
• “mixed lot” means a size of more than one normal unit of trading but not a multiple thereof; and
• “odd lot” means a size of less than one normal unit of trading.
With limited exceptions, all Orders must have a price, such that they will execute only if the price available is equal to or better than the price of the Order. The maximum price that the System will accept is $199,999.99. MOO and MOC Orders are not assigned a price by the entering party and execute at the price of the Nasdaq Opening Cross and Nasdaq Closing Cross, respectively. Moreover, certain Orders have a price that is determined by the Nasdaq Market Center based on the NBBO or other reference prices, rather than by the Participant. As described below with respect to the Pegging Order Attribute, an Order may have a price that it pegged to the opposite side of the market, in which case the Order will behave like a “market order” or “unpriced order” (
Pegging is an Order Attribute that allows an Order to have its price automatically set with reference to the NBBO; provided, however, that if Nasdaq is the sole market center at the Best Bid or Best Offer (as applicable), then the price of any Displayed Order with Pegging will be set with reference to the highest bid or lowest offer disseminated by a market center other than Nasdaq.
• Primary Pegging means Pegging with reference to the Inside Quotation on the same side of the market. For example, if the Inside Bid was $11, an Order to buy with Primary Pegging would be priced at $11.
• Market Pegging means Pegging with reference to the Inside Quotation on the opposite side of the market. For example, if the Inside Offer was $11.06, an Order to buy with Market Pegging would be priced at $11.06.
• Midpoint Pegging means Pegging with reference to the midpoint between the Inside Bid and the Inside Offer (the “Midpoint”). Thus, if the Inside Bid was $11 and the Inside Offer was $11.06, an Order with Midpoint Pegging would be priced at $11.03. An Order with Midpoint Pegging is not displayed. An Order with Midpoint Pegging may be executed in sub-pennies if necessary to obtain a midpoint price.
Primary Pegging and Market Pegging are available through RASH, QIX, and FIX only. An Order entered through OUCH or FLITE with Midpoint Pegging will have its price set upon initial entry to the Midpoint, unless the Order has a limit price that is lower than the Midpoint for an Order to buy (higher than the Midpoint for an Order to sell), in which case the Order will be ranked on the Nasdaq Book at its limit price. Thereafter, if the NBBO changes so that the Midpoint is lower than (higher than) the price of an Order to buy (sell), the Pegged Order will be cancelled back to the Participant.
An Order entered through RASH, QIX or FIX with Pegging will have its price set upon initial entry and will thereafter have its price reset in accordance with changes to the relevant Inside Quotation. An Order with Pegging receives a new timestamp whenever its price is updated and therefore will be evaluated with respect to possible execution (and routing, if it has been assigned a Routing Order Attribute) in the same manner as a newly entered Order. If the price to which an Order is pegged is not available, the Order will be rejected.
Pegging functionality allows a Participant to have the System adjust the price of the Order continually in order to keep the price within defined parameters. Thus, the System performs price adjustments that would otherwise be performed by the Participant through cancellation and reentry of Orders. The fact that a new timestamp is created for a Pegged Order whenever it has its price adjusted allows the Order to seek additional execution opportunities and ensures that the Order does not “jump the queue” with respect to any Orders that were previously at the Pegged Order's new price level.
If an Order with Primary Pegging is updated 1,000 times, it will be cancelled; if an Order with other forms of Pegging is updated 10,000 times, it will be cancelled. This restriction is designed to conserve System resources by limiting the persistence of Orders that update repeatedly without any reasonable prospect of execution.
Minimum Quantity is an Order Attribute that allows a Participant to provide that an Order will not execute unless a specified minimum quantity of shares can be obtained. Thus, the functionality serves to allow a Participant that may wish to buy or sell a large amount of a security to avoid signaling its trading interest unless it can purchase a certain minimum amount. An Order with a Minimum Quantity Order Attribute may be referred to as a “Minimum Quantity Order.” For example, a Participant could enter an Order with a Size of 1000 shares and specify a Minimum Quantity of 500 shares.
A Participant may specify two alternatives with respect to the processing of a Minimum Quantity Order at time of entry:
• First, the Participant may specify that the minimum quantity condition may be satisfied by execution against multiple Orders. In that case, upon entry, the System would determine whether there were one or more posted Orders executable against the incoming Order with an aggregate size of at least the minimum quantity (500 shares in the above example). If there were not, the Order would post on the Nasdaq Book in accordance with the characteristics of its underlying Order Type.
• Second, the Participant may specify that the minimum quantity condition must be satisfied by execution against one or more Orders, each of which must have a size that satisfies the minimum quantity condition. If there are such Orders but there are also other Orders that do not satisfy the minimum quantity condition, the Minimum Quantity Order will be partially executed and the remainder of the Order will be cancelled. For example, if a Participant entered an Order to buy at $11 with a size of 1,500 shares and a minimum quantity condition of 500 shares, and there were three Orders to sell at $11 on the Nasdaq Book, two with a size of 500 shares each and one with a size of 200 shares, the two 500 share Orders would execute and the remainder of the Minimum Quantity Order would be cancelled. Alternatively, if the Order would lock or cross Orders on the Nasdaq Book but none of the resting Orders would satisfy the minimum quantity condition, an Order with a minimum quantity condition to buy (sell) will be repriced to one minimum price increment lower than (higher than) the lowest price (highest price) of such Orders. For example, if there was an Order to buy at $11 with a minimum quantity condition of 500 shares, and there were resting Orders on the Nasdaq Book to sell 200 shares at $10.99 and 300 shares at $11, the Order would be repriced to $10.98 and ranked at that price.
Upon entry, an Order with a Minimum Quantity Order Attribute must have a size of at least one round lot. An Order entered through OUCH or FLITE may have a minimum quantity condition of any size of at least one round lot. An Order entered through RASH, QIX or FIX must have a minimum quantity of one round lot or any multiple thereof, and a mixed lot minimum quantity condition will be rounded down to the nearest round lot. In the event that the shares remaining in the size of an Order with a Minimum Quantity Order Attribute following a partial execution thereof are less than the minimum quantity specified by the Participant entering the Order, the minimum quantity value of the Order will be reduced to the number of shares remaining. An Order with a Minimum Quantity Order Attribute may not be displayed; if a Participant marks an Order with both a Minimum Quantity Order Attribute and a Display Order Attribute, the System will accept the Order but will give a Time-in-Force of IOC, regardless of the Time-in-Force marked by the Participant. An Order marked with a Minimum Quantity
Routing is an Order Attribute that allows a Participant to designate an Order to employ one of several Routing Strategies offered by Nasdaq, as described in Rule 4758; such an Order may be referred to as a “Routable Order.” Upon receipt of an Order with the Routing Order Attribute, the System will process the Order in accordance with the applicable Routing Strategy. In the case of a limited number of Routing Strategies, the Order will be sent directly to other market centers for potential execution. For most other Routing Strategies, the Order will attempt to access liquidity available on Nasdaq in the manner specified for the underlying Order Type and will then be routed in accordance with the applicable Routing Strategy. Shares of the Order that cannot be executed are then returned to Nasdaq, where they will (i) again attempt to access liquidity available on Nasdaq and (ii) post to the Nasdaq Book or be cancelled, depending on the Time-in-Force of the Order. Under certain Routing Strategies, the Order may be routed again if the System observes an accessible quotation of another market center, and returned to Nasdaq again for potential execution and/or posting to the Nasdaq Book.
In connection with the trading of securities governed by Regulation NMS, all Orders shall be routed for potential execution in compliance with Regulation NMS. Where appropriate, Routable Orders will be marked as Intermarket Sweep Orders.
Discretion is an Order Attribute under which an Order has a non-displayed discretionary price range within which the entering Participant is willing to trade; such an Order may be referred to as a “Discretionary Order.”
Under the circumstances described below, the Nasdaq Market Center processes an Order with Discretion by generating a Non-Displayed Order with a Time-in-Force of IOC (a “Discretionary IOC”) that will attempt to access liquidity available within the discretionary price range. The Discretionary IOC will not be permitted to execute, however, if the price of the execution would trade through a Protected Quotation. If more than one Order with Discretion satisfies conditions that would cause the generation of a Discretionary IOC simultaneously, the order in which such Discretionary IOCs are presented for execution is random, based on the respective processing time for each such Order. Whenever a Discretionary IOC is generated, the underlying Order with Discretion will be withheld or removed from the Nasdaq Book and will then be routed and/or placed on the Nasdaq Book if the Discretionary IOC does not exhaust the full size of the underlying Order with Discretion, with its price determined by the underlying Order Type and Order Attributes selected by the Participant.
• If an Order has been assigned a Discretion Order Attribute, but has not been assigned a Routing Order Attribute, upon entry of the Order, the Nasdaq Market Center will automatically generate a Discretionary IOC with a price equal to the highest price for an Order with Discretion to buy (lowest price for an Order with Discretion to sell) within the discretionary price range and a size equal to the full size of the underlying Order to determine if there are any Orders within the discretionary price range on the Nasdaq Book. If the Discretionary IOC does not exhaust the full size of the Order with Discretion, the remaining size of the Order with Discretion will post to the Nasdaq Book in accordance with the parameters that apply to the underlying Order Type. Thus, for example, if a Participant enters a Price to Display Order to buy at $11 with a discretionary price range of up to $11.03, upon entry the Nasdaq Market Center will generate a Discretionary IOC to buy priced at $11.03. If there is an Order on the Nasdaq Book to sell priced at $11.02 and an execution at $11.02 would not trade through a Protected Quotation, the Discretionary IOC will execute against the Order on the Nasdaq Book, up to the full size of each Order. Any remaining size of the Price to Display Order would post to the Nasdaq Book in accordance with its parameters.
• After the Order posts to the Nasdaq Book, the Nasdaq Market Center System will examine whether at any time there is an Order on the Nasdaq Book with a price in the discretionary price range against which the Order with Discretion could execute. In doing so, the Nasdaq Market Center System will examine all Orders (including Orders that are not Displayed). If the Nasdaq Market Center System observes such an Order, it will generate a Discretionary IOC with a price equal to the highest price for an Order to buy (lowest price for an Order to sell) within the discretionary price range and a size equal to the full size of the Order.
• If an Order that uses a passive routing strategy (
• If an Order that uses a reactive routing strategy (
• If an Order that uses a passive routing strategy has been assigned a Discretion Order Attribute and does have a pegged discretionary price range, upon entry of the Order, the Nasdaq Market Center will examine all Orders (including Orders that are not Displayed) on the Nasdaq Book to determine if there is an Order on the Nasdaq Book with a price in the discretionary price range against which the Order with Discretion could execute. If the Nasdaq Market Center System observes such an Order, it will generate a Discretionary IOC with a price equal to the price of the Order on the Nasdaq Book and a size equal to the applicable size of the Order on the Nasdaq Book. The Nasdaq Market Center System will also determine if there are any accessible quotations with prices that are within the discretionary price range at destinations on the applicable routing table for the selected routing strategy. If there are such quotations, the Nasdaq Market Center System will generate one or more Discretionary IOCs to route to such destinations, with a price and size that match the price and size of the market center's quotation. If necessary to maximize execution opportunities and comply with Regulation NMS, the System may mark such Discretionary IOCs as Intermarket Sweep Orders. If the Discretionary IOC(s) do not exhaust the full size of the Order with Discretion, the remaining size of the Order with Discretion will post to the Nasdaq Book in accordance with the parameters that apply to the underlying Order Type. Thereafter, the Order will not generate further Discretionary IOCs unless the Order is updated in a manner that causes it to receive a new timestamp, in which case the Order will behave in the same manner as a newly entered Order.
• If an Order that uses a reactive routing strategy has been assigned a Discretion Order Attribute and does have a pegged discretionary price range, upon entry of the Order, the Nasdaq Market Center will examine all Orders (including Orders that are not Displayed) on the Nasdaq Book to determine if there is an Order on the Nasdaq Book with a price in the discretionary price range against which the Order with Discretion could execute. If the Nasdaq Market Center System observes such an Order, it will generate a Discretionary IOC with a price equal to the price of the Order on the Nasdaq Book and a size equal to the applicable size of the Order on the Nasdaq Book. The Nasdaq Market Center System will also determine if there are any accessible quotations with prices that are within the discretionary price range at destinations on the applicable routing table for the selected routing strategy. If there are such quotations, the Nasdaq Market Center System will generate one or more Discretionary IOCs to route to such destinations, with a price and size that match the price and size of the market center's quotation. If necessary to maximize execution opportunities and comply with Regulation NMS, the System may mark such Discretionary IOCs as Intermarket Sweep Orders. If the Discretionary IOC(s) do not exhaust the full size of the Order with Discretion, the remaining size of the Order with Discretion will post to the Nasdaq Book in accordance with the
Reserve Size is an Order Attribute that permits a Participant to stipulate that an Order Type that is displayed may have its displayed size replenished from additional non-displayed size. An Order with Reserve Size may be referred to as a “Reserve Order.” At the time of entry, the displayed size of such an Order selected by the Participant must be one or more normal units of trading; an Order with a displayed size of a mixed lot will be rounded down to the nearest round lot. A Reserve Order with displayed size of an odd lot will be accepted but with the full size of the Order displayed. Reserve Size is not available for Orders that are not displayed; provided, however, that if a Participant enters Reserve Size for a Non-Displayed Order with a Time-in-Force of IOC, the full size of the Order, including Reserve Size, will be processed as a Non-Displayed Order.
Whenever a Participant enters an Order with Reserve Size, the Nasdaq Market Center will process the Order as two Orders: A Displayed Order (with the characteristics of its selected Order Type) and a Non-Displayed Order. Upon entry, the full size of each such Order will be processed for potential execution in accordance with the parameters applicable to the Order Type. For example, a Participant might enter a Price to Display Order with 200 shares displayed and an additional 3,000 shares non-displayed. Upon entry, the Order would attempt to execute against available liquidity on the Nasdaq Book, up to 3,200 shares. Thereafter, unexecuted portions of the Order would post to the Nasdaq Book as a Displayed Price to Display Order and a Non-Displayed Order; provided, however, that if the remaining total size is less than the display size stipulated by the Participant, the Displayed Order will post without Reserve Size. Thus, if 3,050 shares executed upon entry, the Price to Display Order would post with a size of 150 shares and no Reserve Size.
When an Order with Reserve Size is posted, if there is an execution against the Displayed Order that causes its size to decrease below a normal unit of trading, another Displayed Order will be entered at the level stipulated by the Participant while the size of the Non-Displayed Order will be reduced by the same amount. Any remaining size of the original Displayed Order will remain on the NASDAQ Book. The new Displayed Order will receive a new timestamp, but the Non-Displayed Order (and the original Displayed Order, if any) will not; although the new Displayed Order will be processed by the System as a new Order in most respects at that time, if it was designated as Routable, the System will not automatically route it upon reentry. For example, if a Price to Comply Order with Reserve Size posted with a Displayed Size of 200 shares, along with a Non-Displayed Order of 3,000 and the 150 shares of the Displayed Order was executed, the remaining 50 shares of the original Price to Comply Order would remain, a new Price to Comply Order would post with a size of 200 shares and a new timestamp, and the Non-Displayed Order would be decremented to 2,800 shares.
A Participant may stipulate that the Displayed Order should be replenished to its original size. Alternatively, the Participant may stipulate that the original and subsequent displayed size will be an amount randomly determined based on factors selected by the Participant.
When the Displayed Order with Reserve Size is executed and replenished, applicable market data disseminated by Nasdaq will show the execution and decrementation of the Displayed Order, followed by replenishment of the Displayed Order. In all cases, if the remaining size of the Non-Displayed Order is less than the fixed or random amount stipulated by the Participant, the full remaining size of the Non-Displayed Order will be displayed and the Non-Displayed Order will be removed.
Attribution is an Order Attribute that permits a Participant to designate that the price and size of the Order will be displayed next to the Participant's MPID in market data disseminated by Nasdaq. An Order with Attribution is referred to as an “Attributable Order” and an Order without attribution is referred to as a “Non-Attributable Order.”
Designation of an Order as an Intermarket Sweep Order, or ISO, is an Order Attribute that allows the Order to be executed within the Nasdaq Market Center by Participants at multiple price levels without respect to Protected Quotations of other market centers within the meaning of Rule 600(b) under Regulation NMS. ISOs are immediately executable within the Nasdaq Market Center against Orders against which they are marketable. An Order designated as an ISO may not be assigned a Routing Order Attribute; provided, however, that an Order using the Directed Order strategy may be designated as an ISO with respect to the market center to which it is directed.
Simultaneously with the routing of an ISO to the System, one or more additional limit orders, as necessary, are routed by the entering Participant to execute against the full displayed size of any Protected Quotation with a price that is superior to the price of the Order identified as an Intermarket Sweep Order (as defined in Rule 600(b) under Regulation NMS). These additional routed orders must be identified as Intermarket Sweep Orders.
Upon receipt of an ISO, the System will consider the stated price of the ISO to be available for other Orders to be entered at that price, unless the ISO is not itself accepted at that price level (for example, a Post-Only Order that has its price adjusted to avoid executing against an Order on the Nasdaq Book) or the ISO is not Displayed.
In addition, as described with respect to various Order Types, such as the Price to Comply Order, Orders on the Nasdaq Book that had their price adjusted may be eligible to be reentered at the stated price of the ISO. For example, if a Price to Comply Order to buy at $11 would lock a Protected Offer at $11, the Price to Comply Order will be posted with a non-displayed price of $11 and a displayed price of $10.99. If the System then receives an ISO to buy at $11, the ISO will be posted at $11 and the Price to Comply Order will be reentered at $11 (if the Participant opted to have its Orders reentered). The respective priority of such reentered Orders will be maintained among multiple repriced Orders; however, other new Orders may also be received after receipt of the ISO but before the repricing of the Price to Comply Order is complete; accordingly, the priority of an Order on the Nasdaq Book vis-à-vis a newly entered Order is not guaranteed.
Display is an Order Attribute that allows the price and size of an Order to be displayed to market participants via market data feeds. All Orders that are Attributable are also displayed, but an Order may be displayed without being Attributable. As discussed in Rule 4702, a Non-Displayed Order is a specific Order Type, but other Order Types may also be non-displayed if they are not assigned a Display Order Attribute; however, depending on context, all Orders that are not displayed may be referred to as “Non-Displayed Orders.” An Order with a Display Order Attribute may be referred to as a “Displayed Order.”
All Order Types except Supplemental Orders, Retail Orders, and RPI Orders participate in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross if the Order has a Time-in-Force that would cause the Order to be in effect at the time of the Nasdaq Opening Cross and/or Nasdaq Closing Cross. MOO Orders, LOO Orders, and IOI Orders participate in the Nasdaq Opening Cross in the manner specified in Rule 4752. Other Order Types eligible to participate in the Nasdaq Opening Cross operate as “Market Hours Orders” or “Open Eligible Interest” as specified in Rule 4752. MOC Orders, LOC Orders and IO Orders participate in the Nasdaq Closing Cross in the manner specified in Rule 4754. Other Order Types eligible to participate in the Nasdaq Closing Cross operate as “Close Eligible Interest” in the manner specified in Rule 4754.
Although Nasdaq, like many exchanges, offers a wide range of possible combinations of Order Types and Order Attributes in order to provide options that support of [sic] a range of legitimate trading strategies, Nasdaq believes that an analysis of the extent of usage of particular Order Type permutations is important to promoting a deeper understanding of current market structure. Based on analysis of a month of data for the period from August 26, 2013 through September 29, 2013, Nasdaq offers the following observations about the usage of different Order Types on its market:
• 23.38% of entered Order volume was Price to Comply Orders with no Order Attributes other than price and size. Such Orders were involved in 10.67% of execution volume.
• 28.22% of entered Order volume was Post-Only Orders with no Order Attributes other than price and size. Such Orders were involved in 11.79% of execution volume.
• Non-Displayed Orders with a Time-in-Force of IOC and no special Order Attributes accounted for 4.25% of entered Order volume and 14.03% of execution volume. Non-Displayed Orders with a Time-in-Force of IOC marked as ISOs but with no other special Order Attributes accounted for 2.17% of entered Order volume and 23.89% of execution volume.
• Non-Displayed Orders with a Time-in-Force longer than IOC but no special Order Attributes accounted for 19.15% of entered Order volume and 1.48% of execution volume.
• Post-Only Orders marked ISO but with no other special Order Attributes accounted for 7.65% of entered Order volume and 6.75% of execution volume. Price to Comply Orders marked ISO but with no other special Order Attributes accounted for 2.75% of entered Order volume and 1.24% of execution volume.
• MOO, LOO, IOI, MOC, LOC and IO Orders accounted for 1.3% of entered Order volume and 8.73% of execution volume.
• All other Order Type and Order Attribute combinations accounted for 10.31% of entered Order volume and 21.27% of execution volume. Of these, the predominant Order Type was Price to Comply Orders using special Order Attributes, accounting for 4.94% of entered Order volume and 15.82% of execution volume. Moreover, in the case of 76.15% of the entered volume and 61.82% of the executed volume of these Orders (
Thus, while a range of combinations of Order Types and Order Attributes can exist in Nasdaq, Nasdaq believes that these data support the conclusion that many of these possible combinations are not used to any appreciable extent. Rather, the vast majority of Order entry and Order execution volume is attributable to a small number of simple combinations: IOC Orders designed to access posted liquidity, various forms of priced limit Orders designed to access available liquidity and thereafter post to the Nasdaq Book to provide liquidity, and Post-Only Orders, which promote price discovery by offering displayed liquidity at a price that may narrow the bid/offer spread on Nasdaq and/or provide price improvement to subsequent Orders. The inclusion of an ISO Order Attribute on Orders is done in full compliance with Regulation NMS and serves to provide notice to Nasdaq that liquidity has been accessed on other markets at a given price level in
Nasdaq believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
Most of the System functionality described in the proposed rule change has already been described in previous proposed rule changes by Nasdaq and approved or permitted to take effect on an immediate basis by the Commission. However, Nasdaq believes that the reiteration of several principles underlying its Order Types and Order Attributes might be helpful in promoting a fuller understanding of these rules' operation and their consistency with the Act.
The functionality underlying Price to Comply Orders and Price to Display Orders provides a means by which Participants may enter a displayed limit order in compliance with Regulation NMS without the Participant definitively ascertaining whether the price of the Order would lock or cross a Protected Quotation. In the absence of the repricing functionality associated with the Order, Nasdaq would need to reject the Order if it locked or crossed a Protected Quotation.
By accepting a Price to Comply Order with a locking, non-displayed price and displayed price that is one minimum increment inferior to the locking price, Nasdaq allows this Order Type to achieve several purposes. First, the displayed price of the Order promotes price discovery by establishing a new NBBO or adding to liquidity available at the NBBO. Second, the non-displayed price of the Order allows the Order to provide price improvement when the Order is executed. A Price to Display Order similarly promotes price discovery by establishing a new NBBO or adding liquidity available at the NBBO. It also provides one of the Order Types through which a Market Maker may offer displayed liquidity that is Attributable to its MPID. Notably, given the price adjustment functionality of the Order, it allows a Market Maker to offer Attributable liquidity at the NBBO.
In addition, the repricing functionality associated with Price to Comply Orders and Price to Display Orders, whereby an Order that has been repriced by the System upon entry may be cancelled or reentered if a previously unavailable price level becomes available, promotes price discovery and provision of greater liquidity by facilitating the display of an Order at its chosen limit price. Because a reentered Order always receives a new timestamp, moreover, the functionality does not present fairness concerns that might arise if an Order that was not displayed became displayed at a different price level while retaining the timestamp that it received when originally entered.
The Non-Displayed Order provides a means by which Participants may access and/or offer liquidity without signaling to other Participants the extent of their trading interest. Moreover, because the Non-Displayed Order may lock a Protected Quotation, it provides a means by which a Participant may provide price improvement. For example, if the Best Bid was $11 and the Best Offer was $11.01, a Non-Displayed Order to buy at $11.01 would provide $0.01 price improvement to an incoming sell Order priced at the Best Bid.
In addition, the repricing functionality associated with Non-Displayed Order promotes provision of greater liquidity and eventual price discovery (via reporting of Order executions) because it facilitates the posting of a Non-Displayed Order at its chosen limit price. In addition, the functionality that cancels Non-Displayed Orders when crossed by a Protected Quotation helps to prevent trade-throughs by ensuring that a Non-Displayed Order will not execute at a price inferior to the Price of a Protected Quotation. Because a reentered Order always receives a new timestamp, moreover, the functionality does not present fairness concerns that might arise if an Order was able to move price while retaining an earlier timestamp.
The primary purpose of Post-Only Orders is to “provide displayed liquidity to the market and thereby contribute to public price discovery—an objective that is fully consistent with the Act.”
In addition, the processing of Post-Only Orders with respect to locking or crossing Protected Quotations serves the same purposes as the processing discussed above with respect to Price to Comply Orders and Price to Display Orders. By accepting a Non-Attributable Post-Only Order that locks or crosses a Protected Quotation with a locking, non-displayed price and displayed price that is one minimum increment inferior to the locking price, Nasdaq allows the displayed price of the Order to promote price discovery by establishing a new NBBO or adding to liquidity available at the NBBO, while also allowing the non-displayed price of the Order to provide price improvement when the Order is executed. An Attributable Post-Only Order similarly promotes price discovery by establishing a new NBBO or adding liquidity available at the NBBO.
The repricing functionality associated with Post-Only Orders, whereby an Order that has been repriced by the System upon entry may be cancelled or reentered if a previously unavailable price level becomes available, promotes price discovery and provision of greater liquidity by facilitating the display of an Order at its chosen limit price. Because a reentered Order always receives a new timestamp, moreover, the functionality does not present fairness concerns that might arise if an Order that was not displayed became displayed at a different price level while retaining the timestamp that it received when originally entered.
A Post-Only Order may be designated as an ISO and accepted at a price that locks or crosses a Protected Quotation, since such designation reflects a representation by the Participant that it has simultaneously routed one or more additional limit orders, as necessary, to execute against the full displayed size of any Protected Quotations that the Post-Only Order would lock or cross.
Like a Post-Only Order, a Midpoint Peg Post-Only Order allows a Participant to control its trading costs by executing upon entry when receiving price improvement but otherwise posting to the Nasdaq Book. Thereafter, the Order Type serves to provide price improvement to other incoming Orders by executing a price between the NBBO. Although the Order Type has a Non-Display Order Attribute, the Order further serves to promote price discovery when it executes by evincing the existence of trading interest at a price better than the NBBO.
Supplemental Orders allow a Participant to provide greater depth of liquidity at the NBBO without signaling the full extent of its trading interest to other Participants. The Order Type thereby may promote more rapid and complete execution of incoming Orders, potentially eliminating the need for such Orders to be routed in order to access liquidity available at other market centers. The requirement that a Supplemental Order may execute only at the NBBO ensures that the Order Type may not be used to provide inferior executions.
Market Maker Peg Orders allow a Market Maker to maintain a continuous two-sided quotation at a price that is compliant with the requirements for Market Makers set forth in Rule 4613(a)(2). Thus, the Order Type serves the function of ensuring that Market Makers offer Displayed and Attributable liquidity at prices that bear a reasonable relation to the NBBO. Of course, Market Makers may also provide liquidity at prices closer to the NBBO than those established by the Market Maker Peg Order, but the Order Type enables the Market Maker to provide a backstop of liquidity at prices that are not unreasonably distant from the NBBO.
The variety of Order Types associated with the Nasdaq Opening Cross and the Nasdaq Closing Cross—Market On Open Orders, Limit On Open Orders, Opening Imbalance Only Orders, Market On Close Orders, Limit On Close Orders, and Imbalance Only Orders—all provide means for a Participant to enter Orders into Nasdaq's single price auction process for establishing the market open and market close price each day. As detailed in approved Rules 4752 and 4754, the auction processes seek to establish a price that maximizes execution opportunities for Cross-eligible Orders. MOO and MOC Orders allow a Participant to execute shares at whatever price the Cross is executed, thereby maximizing execution opportunities; LOO and LOC Orders allow a Participant to set a price limit on potential executions; and OIO and IO Orders allow a Participant to provide liquidity to MOO and LOO or MOC and LOC Orders that would not otherwise execute in the Cross, at a price pegged to the Nasdaq inside price leading up to the Cross. Nasdaq believes that all of these Order Types promote the interest of investors in conducting an orderly process for establishing the opening and closing prices of securities.
Several of the available Order Attributes merely provide means to designate the basic parameters of any Order: These include price, size, Time-in-Force, Attribution, Display, and Participation in the Nasdaq Opening Cross and/or the Nasdaq Closing Cross. The proposed rules clearly state limitations applicable to each of these parameters, such as available Times-in-Force and limitations on the permissible prices and sizes of Orders.
The Pegging Order Attribute allows a Participant to have the System adjust the price of the Order continually in order to keep the price within defined parameters. Thus, the System performs price adjustments that would otherwise be performed by the Participant through cancellation and reentry of Orders. The fact that a new timestamp is created for a Pegged Order whenever it has its price adjusted allows the Order to seek additional execution opportunities and ensures that the Order does not “jump the queue” with respect to any Orders that were previously at the Pegged Order's new price level. Thus, while the Order Attribute may be seen as introducing additional complexity with respect to the operation of the Nasdaq market, it is in effect merely a process for removing and entering Orders at new prices based on changed market conditions.
The Minimum Quantity Order Attribute allows a Participant that may wish to buy or sell a large amount of a security to avoid signaling its trading interest unless it can purchase a certain minimum amount. Thus, the Order Attribute supports the interest of institutional investors and others in being able to minimize the impact of their trading on the price of securities.
The Routing Order Attribute, which is thoroughly described in existing Rule 4758, provides an optional means by which a Participant may direct Nasdaq to seek opportunities to execute an Order at other market centers. The System is designed to pursue execution opportunities on behalf of Participants in an aggressive manner by, in most
The Discretion Order Attribute allows a Participant to expand opportunities for an Order to access liquidity by allowing it to execute at any price within a specified range. Thus, while there is some complexity associated with the processing of Discretionary Orders, the Order Attribute merely allows the System to ascertain whether, under the conditions provided for in the rule, the Participant could access liquidity at a price within the range that the Participant has designated. If so, the Order Attribute generates an IOC Order to access the liquidity. Moreover, it should be noted that although in some circumstances, the System will examine Orders on the Nasdaq Book that are not Displayed to ascertain the existence of execution opportunities, the System would convey information to the Participant regarding such Orders only by executing against them. Thus, the discretionary price range reflects an actionable commitment by the Participant to trade at prices in that range. As a result, the Order Attribute promotes price discovery through executions that occur in the price range. Finally, it should be noted that Discretionary IOCs access liquidity, and therefore the Order Attribute does not present an opportunity for a Participant to obtain a rebate with respect to executions against previously posted Orders.
The Reserve Size Order Attribute allows a Participant to display trading interest at a given price while also posting additional non-displayed trading interest. The functionality assists the Participant in managing this trading interest by eliminating the need for the Participant to enter additional size following the execution of the displayed trading interest. Thus, the functionality achieves a balance between promoting price discovery through displayed size and allowing a Participant to guard against price impact by hiding the full extent of its trading interest. The random reserve feature of the Order further assists a Participant in not revealing the extent of its trading interest because it diminishes the likelihood that other Participants will conclude that the Order is a Reserve Size Order if they repeatedly view it being replenished at the same size. Similarly, the manner in which Nasdaq disseminates data regarding the execution and replenishment of a Reserve Size Order ensures that the process is indistinguishable to other Participants from the execution of an Order without Reserve Size followed by the entry of a new Order; this processing also ensures that only the displayed portion of the Reserve Size Order is treated as a Protected Quotation.
The Intermarket Sweep Order attribute is a function of Regulation NMS, which provides for an Order to execute without respect to Protected Quotations if it is designated as an ISO and if one or more additional limit orders, as necessary, are routed to execute against the full displayed size of any Protected Quotation with a price that is superior to the price of the Order identified as an ISO. As recently reaffirmed by the Commission, Regulation NMS allows such additional orders to be routed by an exchange or by the Participant that enters the ISO.
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. As previously stated, the Exchange is not proposing substantively to modify the operation of any of its current Order Types or Order Attributes or the operation of the System; rather, the proposed rule change is intended to provide more detail regarding the System's functionality. The proposed rule change is not designed to address any competitive issues, but rather to provide additional specificity and transparency to Participants and the investing public regarding Nasdaq's Order Types, Order Attributes, and System functionality. Since the Exchange does not propose substantively to modify the operation of Order Types, Order Attributes, or System functionality, the proposed changes will not impose any 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 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.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend Rule 1009 (Criteria for Underlying Securities) to allow the listing of options overlying Exchange-Traded Fund Shares (“ETFs”) that are listed pursuant to generic listing standards on equities exchanges for series of portfolio depositary receipts (“PDRs”) and index fund shares (“IFSs”) based on international or global indexes, pursuant to which a comprehensive surveillance agreement
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 Commentary .06 to Rule 1009 to allow the listing of options overlying ETFs
Rule 19b-4(e) provides that the listing and trading of a new derivative securities product by an SRO shall not be deemed a proposed rule change, pursuant to paragraph (c)(l) of Rule 19b-4
The surveillance agreement requirement (also known as the “requirement” or “regime”) was initially put into effect for options on ETFs well over a decade ago but has proven to have anti-competitive effects that are detrimental to investors.
The Exchange allows for the listing and trading of options on ETFs. Commentary .06 to Rule 1009 provides the listings standards for options on ETFs, which includes [sic] ETFs with non-U.S. component securities, such as ETFs based on international or global indexes. Currently, Commentary .06 to Rule 1009 regarding options on ETFs has a three-level surveillance agreement requirement (reproduced in relevant part):
(i) Whether any non-U.S. component stocks on which the Fund Shares are based that are not subject to comprehensive surveillance agreements do not in the aggregate represent more than 50% of the weight of the index or portfolio;
(ii) stocks for which the primary market is in any one country that is not subject to a comprehensive surveillance agreement do not represent 20% or more of the weight of the index; and
(iii) stocks for which the primary market is in any two countries that are not subject to comprehensive surveillance agreements do not represent 33% or more of the weight of the index.
The surveillance agreement requirement was instituted in 2001 when ETFs were, comparatively speaking, in a developmental state.
The current surveillance requirement has, at times, resulted in the investing public having to forego the opportunity to hedge risk or engage in other listed options strategies in a competitive environment. ETFs may lack active options contracts that would be more likely to develop if multiple exchanges could compete to offer and promote them. For example, an investor in the iShare [sic] MSCI Indonesia ETF (EIDO) is not permitted to sell call options or purchase protective puts simply because the Exchange cannot obtain a surveillance agreement with Bursa Efek Indonesia. However, an investor in iShare [sic] MSCI Emerging Markets Fund (EEM) is afforded the right to engage in listed options trading to hedge risk or execute other beneficial options strategies. Both underlying exchange-traded funds, EIDO and EEM, are listed for trading in the U.S., subject to constant regulatory scrutiny, and permitted to be purchased and sold via registered broker/dealers, yet, options can now be offered only on EEM. The Exchange believes this disparate treatment between investors of foreign-based instruments, especially between those that buy and sell options contracts on ETFs, which currently require surveillance agreements, as opposed to those that buy and sell shares of the underlying ETFs, which currently do not have the same onerous surveillance agreement requirement that ETF options have,
The current surveillance agreement requirements, as well as all other requirements to list options on ETFs,
The Exchange notes that the Commission has previously approved generic listing standards pursuant to Rule 19b-4(e) of the Exchange Act
In addition, the Commission has previously approved proposals for the listing and trading of options on ETFs based on international indexes as well as global indexes (
Options on ETFs listed pursuant to these generic standards for international and global indexes would be traded, in all other respects, under the Exchange's existing trading rules and procedures that apply to options on ETFs and would be covered under the Exchange's surveillance program for options on ETFs.
Pursuant to proposed Commentary .06(b)(i) to Rule 1009, the Exchange may list and trade options on an ETF without a CSSA provided that the ETF is listed pursuant to generic listing standards for series of PDRs and IFSs based on international or global indexes, in which case a comprehensive surveillance agreement is not required. As noted, one such rule, which discusses things such as weighting, capitalization, trading volume, minimum number of components, and where components are listed, is NASDAQ Rule 5705(b)(3)(A)(ii) regarding ETFs (IFSs and PDRs).
The Exchange believes that this proposed listing standard for options on ETFs is reasonable for international and global indexes, and, when applied in conjunction with the other listing requirements, will result in options overlying ETFs that are sufficiently broad in scope and not readily susceptible to manipulation. The Exchange also believes that allowing the Exchange to list options overlying ETFs that are listed on equities exchanges pursuant to generic standards for series of PDRs and IFSs based on international or global indexes under which a CSSA is not required, will result in options overlying ETFs that are adequately diversified in weighting for any single security or small group of securities to significantly reduce concerns that trading in options overlying ETFs based on international or global indexes could
The Exchange believes that ETFs based on international and global indexes that have been listed pursuant to the generic standards are sufficiently defined so as to make options overlying such ETFs not susceptible instruments for manipulation. The Exchange believes that the threat of manipulation is, as discussed below, sufficiently mitigated for underlying ETFs that have been listed on equities exchanges pursuant to generic listing standards for series of PDRs and IFSs based on international or global indexes under which a comprehensive surveillance agreement is not required and for the overlying options; the Exchange does not see the need for a CSSA to be in place before listing and trading options on such ETFs. The Exchange notes that its proposal does not replace the need for a CSSA as provided in current Commentary .06(b) to Rule 1009. The provisions of Commentary .06(b), including the need for a CSSA, remain materially unchanged and will continue to apply to options on ETFs that are not listed on an equities exchange pursuant to generic listing standards for series of PDRs and IFSs based on international or global indexes. Instead, proposed Commentary .06(b)(i) adds an additional listing mechanism for certain qualifying options on ETFs to be listed on the Exchange.
Finally, to account for proposed Commentary .06(b) to Rule 1009 and make Commentary .06 easier to follow, the Exchange proposes technical changes to the formatting of this section of the rule. The Exchange proposes re-numbering Commentary .06(b)(i), (ii) and (iii) as Commentary .06(b)(ii)(A), (B), and (C), respectively; and re-numbering Commentary .06(b)(iv) and (v) as Commentary .06(b)(iii) and (iv), respectively. This is merely re-numbering and there are no changes to the language of these sections of Commentary .06.
The proposal does not raise a concern regarding economic risk or manipulation. The proposal does not increase the risk of manipulation of the ETF itself, as the ETF trades in the U.S. and trading is subject to the U.S. surveillance requirement and follows Exchange rules. One might try to argue that the proposal raises a concern about a theoretical manipulation risk of the underlying international components of the ETF trading in the U.S. If such manipulation were successful, the argument would go, then the ETF could be fairly priced relative to its components but the price of the components potentially may not reflect fair market value. The Exchange firmly believes that the proposal does not raise any such theoretical concern.
For manipulation to be successful the expected cost of the contemplated manipulation must be less than the expected gain. In other words, manipulation will not be attempted if the prospective profit from the attempt is zero or less, even ignoring the quite real costs associated with regulatory risk. In approving the rules for narrow based indices, it was thought that the costs of manipulating such an index based on component securities with the same parameters as those proposed ETFs would be prohibitive relative to any prospective gains. The Exchange's proposal does not suggest a different paradigm.
Moreover, the Commission reviewed and approved the ability to list ETFs without surveillance agreements if they meet the generic listing standards for ETFs based on international or global indices. The Exchange believes that the argument and economic conclusion that allowing the listing of options on these same underlying ETFs with components outside the U.S. that are sufficiently large, transparent, diversified, and liquid to make manipulation unprofitable is valid.
A second theoretical source of manipulation risk may be seen to be the creation/redemption process for ETFs. If the creation/redemption process could be manipulated then the market price of the ETF could materially differ from the fair value of the ETF derived from a fair market value of the components. Again, the Exchange does not agree that this is a significant manipulation risk for ETFs, let alone options on ETF. As noted, ETFs are a much more mature asset class today than in 2001 when the current rules were adopted. The development of ETFs as an established asset class and the listing and trading of ETFs, including the creation/redemption process, has developed immensely since the introduction of ETFs, and options on them. Since manipulation of the creation/redemption process would create economic profits for the manipulator, but such manipulation has not been manifest during the significant expansion of ETFs as an international asset class, this offers convincing evidence that manipulation risk in the creation/redemption process is, indeed, theoretical and not an increased risk with this proposal regarding the listing of ETF options. The Exchange believes that its proposal will not lead to increased economic risk.
The Exchange requests approval of its proposal to allow the listing of options overlying ETFs (PDRs and IFSs) based on international or global indexes, without a comprehensive surveillance agreement. The proposal will, as discussed, be beneficial to investors and is in conformity with the Act.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act
The proposal would promote just and equitable principles of trade. The surveillance agreement requirement was instituted in 2001 when ETFs were, comparatively speaking, in a developmental state.
The proposal would in general protect investors and the public interest. The Exchange believes that modifying the surveillance agreement requirement for ETFs would not hinder the Exchange from performing surveillance duties designed to protect investors and the public interest. There are various data consolidators, vendors, and outlets that can be used to access data and information regarding ETFs and the underlying securities (
The proposal would remove impediments to and perfect the mechanism of a free and open market and a national market system. Multiple listing of ETFs, options, and other securities and competition are some of the central features of the current national market system. The Exchange believes that the surveillance agreement requirement has led to clearly anti-competitive results in a market that is based on competition. As such, the Exchange believes that the surveillance agreement requirement for options on certain ETFs is no longer necessary and proposes new Commentary .06(b)(i) to Rule 1009. The proposed rule change will significantly benefit market participants. As discussed at length, the proposed rule will negate the negative anti-competitive effect of the current surveillance agreement requirement that has resulted in de facto regulatory monopolies where only solitary exchanges, or only a few exchanges, are able to list certain ETF options products. The Exchange believes this is inconsistent with Commission policies and the developing national market system, as well as the competitive nature of the market, and therefore proposes amendment.
Finally, the Exchange's proposal for limiting the necessity of surveillance agreements to list options on ETFs does not, as discussed above, raise a concern regarding manipulation. The Exchange believes that its proposal is not indicative of increased economic risk.
For the above reasons, the Exchange believes the proposed rule change is consistent with the requirements of Section 6(b)(5) 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. To the contrary, the Exchange believes that the proposal is, as discussed, decidedly pro-competitive and is a competitive response to the inability to list products because of the surveillance agreement requirement. The Exchange believes that the proposed rule change will result in additional investment options and opportunities to achieve the investment objectives of market participants seeking efficient trading and hedging vehicles, to the benefit of investors, market participants, and the marketplace in general. Competition is one of the principal features of the national market system. The Exchange believes that this proposal will expand competitive opportunities to list and trade products on the Exchange as noted.
No written comments were either solicited or received.
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
A proposed rule change filed pursuant to 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.
The Advisory Committee on International Economic Policy (ACIEP) will meet between 2:00 and 5:00 p.m., on Tuesday, April 14, 2015, in Room 4477 of the Harry S Truman Building at the U.S. Department of State, 2201 C Street NW., Washington, DC. The meeting will be hosted by the Assistant Secretary of State for Economic and Business Affairs, Charles H. Rivkin and Committee Chair Paul R. Charron. The ACIEP serves the U.S. government in a solely advisory capacity, and provides advice concerning topics in international economic policy. The meeting will examine “The President's Trade Agenda.” It is expected that the ACIEP subcommittees will provide updates on their work.
This meeting is open to public participation, though seating is limited. Entry to the building is controlled. To obtain pre-clearance for entry, members of the public planning to attend should
Personal data is requested pursuant to Public Law 99-399 (Omnibus Diplomatic Security and Antiterrorism Act of 1986), as amended; Public Law 107-56 (USA PATRIOT Act); and Executive Order 13356. The purpose of the collection is to validate the identity of individuals who enter Department facilities. The data will be entered into the Visitor Access Control System (VACS-D) database. Please see the Security Records System of Records Notice (State-36) at
For additional information, contact Gregory Maggio, Office of Economic Policy Analysis and Public Diplomacy, Bureau of Economic and Business Affairs, at (202) 647-2231, or
Federal Aviation Administration (FAA), Department of Transportation (DOT).
Notice of availability; request for comments.
This document announces the availability of the FAA National Facilities Realignment and Consolidation Report, Year 1 Part 1. The report was developed in response to Section 804 of the FAA Modernization and Reform Act of 2012 (Pub. L. 112-95). The report and recommendations contained therein have been developed collaboratively with the National Air Traffic Controllers Association (NATCA) and the Professional Aviation Safety Specialists (PASS) Labor Unions and with input from stakeholders. The FAA seeks comments on this report.
Send comments on or before May 11, 2015.
Send comments identified by docket number FAA-2015-0693 using any of the following methods:
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Martha Christie, Future Facilities Group Manager, AJW-2A, Federal Aviation Administration, 800 Independence Avenue SW., Washington, DC 20591; email:
Section 804 of the FAA Modernization and Reform Act of 2012 (Pub. L. 112-95) requires the FAA to develop a plan for realigning and consolidating facilities in an effort to support the transition to NextGen and reduce costs where such cost reductions can be implemented without adversely affecting safety. To address Section 804 requirements, the FAA formed a collaborative workgroup of representatives from the FAA and NATCA and PASS Labor Unions to develop a comprehensive process to analyze different realignment and consolidation scenarios. The collaborative process takes into account the following factors and criteria when prioritizing facilities for realignment analysis: NextGen readiness; the Terminal Automation program schedule; operational and airspace factors; existing facility conditions and workforce needs; industry stakeholder input; and the costs and benefits associated with each potential realignment alternative.
In 2014, the collaborative workgroup initiated activities to evaluate existing Terminal Radar Approach Control (TRACON) facilities and prioritize them for annual analysis; develop an initial set of realignment scenarios and define alternatives for each scenario; collect facility and operational data, and document system requirements; document facility, equipment, infrastructure, operational and safety data; capture qualitative workforce considerations, including training, transition, facility, and potential workforce impacts of potential realignments; consider potential impacts on operations, airspace modifications, route/fixes changes, arrival/departure procedures, intra/inter-facility coordination, and aviation community interaction; collect and consider industry stakeholder inputs; document and quantify benefits and cost of potential realignments; and develop a recommendation for each realignment scenario. The recommendations for the first two scenarios analyzed by the Section 804 collaborative workgroup are contained in the report entitled “FAA National Facilities Realignment and Consolidation Report Year 1, Part 1 Recommendations,” a copy of which has been placed in the docket for this notice. The docket may be accessed at
The realignment recommendations outlined in the Year 1 Part 1 report are the result of a collaborative process that involved a multi-disciplinary team of FAA subject matter experts, financial analysts, operational experts, and Labor and FAA leadership participants. The Section 804 process serves as a stable foundation for future realignment analyses and recommendations. The process aims to maximize operational, administrative, and maintenance efficiencies and deliver the highest value to stakeholders.
The FAA is requesting comments on this report pursuant to Section 804 of the FAA Modernization and Reform Act of 2012. The agency will consider all comments received on or before May 11, 2015. Following a 60-day comment review period, the final report along with public comments will be submitted to Congress. The FAA continues to analyze data collected from facilities across the United States and evaluate possible realignment scenarios. The FAA will make its next recommendations when it submits Part 2 of the report in mid-2015.
National Highway Traffic Safety Administration (NHTSA), Department of Transportation (DOT).
Request for public comment on proposed collection of information.
Before a Federal agency can collect certain information from the public, it must receive approval from the Office of Management and Budget (OMB). Under procedures established by the Paperwork Reduction Act of 1995, before seeking OMB approval, Federal agencies must solicit public comment on proposed collections of information, including extensions and reinstatement of previously approved collections. This document describes one collection of information for which NHTSA intends to seek OMB approval.
Comments must be received on or before May 26, 2015.
You may submit comments identified by docket number at the heading of this notice by any of the following methods:
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For additional information or access to background documents, contact Wayne McKenzie, Office of Crash Avoidance Standards (NVS-121), National Highway Traffic Safety Administration, West Building W43-462, 1200 New Jersey Avenue SE., Washington, DC 20590. Mr. McKenzie can be reached at (202) 366-1729.
Under the Paperwork Reduction Act of 1995, before an agency submits a proposed collection of information to OMB for approval, it must publish a document in the
(i) 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;
(ii) 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;
(iii) How to enhance the quality, utility, and clarity of the information to be collected; and
(iv) How 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 or other forms of information technology,
In compliance with these requirements, NHTSA asks public comment on the following proposed collection of information:
The manufacturers of new tractors and trailers are required to certify that their products are equipped with retroreflective material complying with the requirements of the standard. The Federal Motor Carriers Safety Administration (FMCSA) enforces this and other standards through roadside inspections of trucks. There is no practical field test for the performance requirements, and labeling is the only objective way of distinguishing trailer conspicuity grade material from lower performance material. Without labeling, FMCSA will not be able to enforce the performance requirements of the standard and the compliance testing of new tractors and trailers will be complicated. Labeling is also important to small trailer manufacturers because it may help them certify compliance. Because wider stripes or material of lower brightness also can provide the minimum safety performance, the marking system serves the additional role of identifying the minimum stripe width required for retroreflective conspicuity of the particular material.
Signal Specialties, Inc. (SSI), a noncarrier, has filed a verified notice of exemption
The Line was part of a longer line extending between St. Joseph, Mo., and Laclede, Mo. This longer line was abandoned by a predecessor to BNSF in 1984.
SSI certifies that its projected annual revenues as a result of this transaction will not exceed those that would qualify it as a Class III rail carrier and will not exceed $5 million.
SSI further certifies that the trackage rights agreement does not include a provision or agreement that may limit future interchange with a third-party connecting carrier.
The transaction may be consummated on or after April 9, 2015 (30 days after the supplemental notice of exemption was filed).
If the verified notice contains false or misleading information, the exemption is void
An original and 10 copies of all pleadings, referring to Docket No. FD 35909, must be filed with the Surface Transportation Board, 395 E Street SW., Washington, DC 20423-0001. In addition, a copy of each pleading must be served on Kevin M. Sheys, Nossaman LLP, 1666 K St. NW., Suite 500, Washington, DC 20006.
Board decisions and notices are available on our Web site at “
By the Board, Rachel D. Campbell, Director, Office of Proceedings.
Nuclear Regulatory Commission.
Proposed rule.
The U.S. Nuclear Regulatory Commission (NRC) is proposing to amend its regulations that govern low-level radioactive waste (LLRW) disposal facilities to require new and revised site-specific technical analyses, to permit the development of site-specific criteria for LLRW acceptance based on the results of these analyses, to facilitate implementation, and to better align the requirements with current health and safety standards. This proposed rule would affect LLRW disposal licensees or license applicants that are regulated by the NRC or the Agreement States.
Submit comments on the proposed rule by July 24, 2015. Submit comments specific to the information collection aspects of this proposed rule by May 26, 2015. Comments received after these dates will be considered if it is practical to do so, but the NRC is able to ensure consideration only for comments received on or before these dates.
You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):
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For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Gary Comfort, telephone: 301-415-8106, email:
The U.S. Nuclear Regulatory Commission (NRC) is proposing to amend its regulations that govern low-level radioactive waste (LLRW) disposal facilities to require new and revised site-specific technical analyses and to permit the development of criteria for LLRW acceptance based on the results of these analyses. These amendments would ensure that LLRW streams that are significantly different from those considered during the development of the current regulations (
Major provisions of the proposed rule include changes to:
• Revise the existing technical analysis for protection of the general population to include a 1,000-year compliance period;
• Add a new site-specific technical analysis for the protection of inadvertent intruders that would include a 1,000-year compliance period and a dose limit;
• Add new analyses that would include a 10,000-year protective assurance period and annual dose minimization target;
• Add a new analysis for certain long-lived LLRW that would include a post-10,000-year performance period;
• Add new analyses that would identify and describe the features of the design and site characteristics that provide defense-in-depth protections;
• Add a new requirement to update the technical analyses at closure; and
• Add a new requirement to develop site-specific criteria for the future acceptance of LLRW for disposal based on either the results of these technical analyses or the existing LLRW classification requirements.
The NRC prepared a draft regulatory analysis to determine the expected quantitative costs and benefits of the proposed rule, as well as qualitative factors to be considered in the NRC's rulemaking decision. The analysis concluded that the proposed rule would result in net costs to the industry and the NRC. The key findings of the analysis are as follows:
• Cost to the Industry. The proposed rule would result in an average implementation cost per licensee of $1,000,000, followed by an estimated annual cost of $4,000. Overall, the industry will incur an estimated implementation cost of $4 million, followed by an estimated annual cost of $16,000.
• Cost to the Agreement States. The proposed rule would result in additional costs to the Agreement States with all costs resulting from implementation. On average, each Agreement State would incur an estimated implementation cost of $525,000. Overall, the Agreement States will incur an estimated implementation cost of $2.1 million.
• Cost to the NRC. The NRC would incur an implementation cost for drafting and implementing a final rulemaking based on the proposed rule. This cost is estimated to be $333,000. Because the NRC does not have any LLRW disposal licensees, no annual NRC cost is expected. The NRC would also incur an estimated implementation cost of $216,000 for drafting a final guidance document based on the final rule.
The regulatory analysis also considered, in a qualitative fashion, direct benefits that would accrue and the indirect benefits from risks that could be avoided if the NRC adopted the rule. The principal qualitative benefits of the proposed action would include: (1) Ensuring that LLRW streams that are significantly different from those considered during the development of the current regulations can be disposed of safely and meet the performance objectives for land disposal of LLRW; (2) facilitating the use of site-specific
The draft regulatory analysis concludes that the proposed rule should be adopted because the proposed regulatory initiatives enhance public health and safety by ensuring the safe disposal of LLRW that was not analyzed in the regulatory basis for the original part 61 of Title 10 of the
Please refer to Docket ID NRC-2011-0012 when contacting the U.S. Nuclear Regualtory Commission (NRC) about the availability of information for this action. You may obtain publicly-available information related to this action by any of the following methods:
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Please include Docket ID NRC-2011-0012 in your comment submission.
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The NRC's licensing requirements for the disposal of commercial low-level radioactive waste (LLRW) in near-surface disposal facilities can be found in part 61 of Title 10 of the
The current 10 CFR part 61 emphasizes an integrated systems approach to the disposal of commercial LLRW, including site selection, disposal facility design and operation, LLRW characteristics, and disposal facility closure. To reduce reliance on institutional controls, the current 10 CFR part 61 emphasizes passive (
Subparts of the existing 10 CFR part 61 cover general provisions and procedural licensing matters; performance objectives; technical requirements for near-surface disposal; financial assurance; state and tribal participation; and records, reports, tests, and inspections. The regulations cover all phases of near-surface commercial LLRW disposal from site selection through facility design, licensing, operations, closure, postclosure stabilization, and the end of active institutional controls. The overall philosophy that underlies the regulatory requirements of 10 CFR part 61 is provided in 10 CFR 61.7, “Concepts.”
The following are key provisions in current 10 CFR part 61:
• Standards for: (1) Protection of the general population in 10 CFR 61.41, “Protection of the general population from the releases of radioactivity;” (2) protection of an inadvertent intruder in 10 CFR 61.42, “Protection of individuals from inadvertent intrusion;” (3) protection of individuals during facility operations in 10 CFR 61.43, “Protection of individuals during operations;” and (4) site stability in 10 CFR 61.44, “Stability of disposal site after closure.” These standards are collectively known as the “Performance Objectives” in subpart C of 10 CFR part 61.
• Specification of the minimum geologic and geomorphic characteristics for an acceptable near-surface LLRW disposal site in 10 CFR 61.50, “Disposal site suitability requirements for land disposal.”
• A LLRW classification system (LLRW being categorized as Class A, Class B, Class C, or greater-than-Class C) for commercial LLRW in 10 CFR 61.55, “Waste classification,” based on the concentration of certain radionuclides.
• Specification of the LLRW characteristics in 10 CFR 61.56, “Waste characteristics,” that commercial LLRW forms must meet to be acceptable for disposal.
• Requirements for caretaker oversight in the form of institutional controls of LLRW disposal facilities in 10 CFR 61.59, “Institutional requirements,” for a period of 100 years following facility closure.
Currently, to grant a license, the NRC must conclude that there is reasonable assurance that the performance objectives will be met. To demonstrate that a license applicant will meet these performance objectives, 10 CFR part 61 license applicants need to prepare the analyses required by 10 CFR 61.13, “Technical analyses.”
To demonstrate that the general population is protected from releases of radioactivity, license applicants are required to prepare an analysis of exposure pathways leading to potential radiological doses to the general population. The current 10 CFR part 61 does not impose a specific performance timeframe for use in the analysis to protect the general population, and there are currently differences among Agreement States regarding the analysis timeframe. For example, some Agreement States have required licensees to analyze the disposal facility for only 500 years, while others have required analyses to the peak dose. For certain long-lived LLRW, a shorter timeframe for the analysis could result in a situation where the long-term impacts from the disposal of long-lived LLRW are not adequately identified in a licensee's analysis. Conversely, the increasing uncertainties associated with very long timeframes could diminish the value of the information generated with technical analyses for applicants, regulators, and other stakeholders. The NRC has drafted this proposed rule to balance the consideration of the risks from disposal of long-lived LLRW with significant uncertainties that may be associated with long-term analyses.
License applicants must also demonstrate that potential inadvertent intruders into the LLRW disposal facility will be protected. Inadvertent intruders might occupy the site at any time after institutional controls over the LLRW disposal facility are no longer effective and may not be aware of the radiation hazard from the LLRW. Under the current regulations, protection of inadvertent intruders is demonstrated by compliance with the LLRW classification (10 CFR 61.55) and segregation requirements (10 CFR 61.52, “Land disposal facility operation and disposal site closure”), and by providing adequate barriers to inadvertent intrusion. The NRC developed the LLRW classification requirements as part of the original 10 CFR part 61 rulemaking. Explicit dose limits for an inadvertent intruder are not currently provided in 10 CFR part 61 because an intruder dose assessment is not required, but the LLRW classification concentration limits for radionuclides, in tables 1 and 2 of 10 CFR 61.55, were based on a dose of 5 milliSieverts per year (mSv/yr) (500 millirem per year (mrem/yr)) to an inadvertent intruder. The LLRW classification tables were developed assuming that only a fraction of the LLRW being disposed would approach the LLRW classification limits (note that the dose to an intruder exposed to a large volume of disposed LLRW at the classification limits could exceed 5 mSv/yr (500 mrem/yr)). By complying with the LLRW classification and segregation requirements, an inadvertent intruder will be protected if the underlying assumptions are not violated.
In the existing 10 CFR part 61 regulations, 10 CFR 61.13(a) through (d) require the technical analyses needed to demonstrate that the performance objectives are met. The regulations in 10 CFR part 61 are risk-informed and performance-based, and ensure public health and safety are protected in the operation of any commercial LLRW disposal facility. Applicants can demonstrate how their proposals meet the respective performance objectives for the specific near-surface disposal method selected (47 FR 57446). The NRC is proposing to modify the current regulations to ensure that LLRW streams that are significantly different than those considered in the development of the existing 10 CFR part 61 are adequately considered during the licensing of LLRW disposal facilities, to require licensees to explicitly identify how disposal site characteristics and design provide defense-in-depth, and to ensure that the 10 CFR part 61 performance objectives will be met for disposal of those LLRW streams.
The NRC developed current 10 CFR part 61 based on assumptions regarding the types of LLRW likely to go into a commercial disposal facility. These were based on a survey of LLRW generators and the results were published in 1982 in NUREG-0945, “Final Environmental Impact Statement on 10 CFR part 61, `Licensing Requirements for Land Disposal of Radioactive Waste' ” (ADAMS Accession Nos. ML052590184, ML052920727, and ML052590187). The results of this survey ultimately formed the regulatory basis for the source terms used in the analysis to define the allowable isotopic concentration limits
As part of the initial 10 CFR part 61 rulemaking, the NRC considered inadvertent intrusion scenarios and the physical stability and isotopic concentration of the LLRW when it developed the 10 CFR part 61 LLRW classification system. These isotopic concentration limits were based on the NRC's understanding of the characteristics and volumes of commercial LLRW reasonably expected for commercial disposal through the year 2000, as well as the potential disposal methods likely to be used.
In the Statement of Considerations for the final rule (47 FR 57457), the Commission noted the following:
The Commission also noted that “to the extent practicable, wasteforms or containers should be designed to maintain gross physical properties and identity over 300 years, approximately the time required for Class B waste to decay to innocuous levels . . . ” (47 FR 57457).
In addition to determining the acceptability of LLRW for disposal in a near-surface land disposal facility, the LLRW classification system is also integral to determining Federal and State responsibilities for LLRW and requirements for transfers of LLRW intended for disposal. The Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) defines Federal and State responsibilities for the disposal of LLRW based on 10 CFR 61.55, as in effect on January 26, 1983. Specifically, the Act assigns responsibility for disposal of Class A, Class B, and Class C commercial LLRW to the States and responsibility for disposal of commercial LLRW with concentrations that exceed the limits for Class C LLRW to the Federal Government.
Appendix G to 10 CFR part 20, “Requirements for Transfers of Low-Level Radioactive Waste Intended for Disposal at Licensed Land Disposal Facilities and Manifests” (60 FR 15664; March 27, 1995), imposes manifest requirements on shipments of LLRW consigned for disposal. Manifests for LLRW shipments must identify the LLRW classification and a certification that the LLRW is “. . . properly classified, described, packaged, marked, and labeled. . . .”
On May 3, 2011, the NRC published preliminary proposed rule language (76 FR 24831) and an associated regulatory basis document, “Technical Analysis Supporting Definition of Period of Performance for Low-level Waste Disposal” (ADAMS Accession No. ML111030586) for public comment. The NRC staff conducted a public meeting on May 18, 2011, in Rockville, Maryland, to discuss the preliminary proposed rule language and its associated regulatory basis document. A summary and transcript of this meeting can be found in ADAMS under Accession No. ML111570329. The comment period ended on June 18, 2011, and the NRC received 15 comment letters from public interest groups, industry, and government organizations.
As a result of additional direction from the Commission in a SRM-COMWDM-11-0002/COMGEA-11-0002, “Revisions to Part 61,” dated January 19, 2012 (ADAMS Accession No. ML120190360), the NRC staff published, for public comment (77 FR 72997; December 7, 2012), a second version of the preliminary proposed rule language (ADAMS Accession No. ML12311A444) and an associated regulatory basis document, “Regulatory Basis for Proposed Revisions to Low-Level Waste Disposal Requirements (10 CFR part 61)” (ADAMS Accession No. ML12356A242). The comment period ended on January 7, 2013, and the NRC received an additional 24 comment letters from public interest groups, industry, and government organizations. Since these early comment periods were outside of the formal proposed rule notice-and-comment rulemaking process, the NRC staff did not and does not plan to prepare formal responses to the comments received on the preliminary documents. However, the NRC staff did consider these comments in the development of the proposed rule and some of the comments did result in modifications to the preliminary proposed rule language.
The NRC staff also briefed the Advisory Committee on Reactor Safeguards (ACRS), Radiation Protection and Nuclear Materials Subcommittee, on June 23 and August 17, 2011, and the full committee on July 13 and September 8, 2011. The NRC staff again briefed the ACRS, Radiation Protection and Nuclear Materials Subcommittee, on April 9, 2013, and the full committee on July 10, 2013. Summaries and transcripts of these meetings can be found at the ACRS' Web site,
Based on early comments and interactions with the ACRS, the NRC staff revised the preliminary proposed rule language.
The NRC is proposing to amend 10 CFR part 61 to require LLRW disposal licensees or license applicants to prepare a safety case that includes a defense-in-depth analysis and new and revised site-specific technical analyses to ensure that LLRW streams that are significantly different from the LLRW streams considered in the current 10 CFR part 61 regulatory basis can be disposed of safely and meet the performance objectives in subpart C of 10 CFR part 61. These new and revised analyses would also more easily identify any additional measures that would be prudent to implement for continued disposal of radioactive LLRW at a particular facility.
The NRC is also proposing to amend 10 CFR part 61 to require LLRW disposal facility licensees or license applicants to develop site-specific criteria for the acceptability of LLRW for disposal. These amendments maintain
Table 1 compares the proposed new and revised technical analyses to the current 10 CFR part 61 requirements. The inadvertent intruder assessment would be a new requirement under 10 CFR 61.13 to demonstrate compliance with the performance objective to protect inadvertent intruders at 10 CFR 61.42. The inadvertent intruder assessment would have to demonstrate that the annual dose would not exceed a proposed 5 mSv (500 mrem) limit over a newly defined 1,000-year compliance period. A performance assessment would also be required for the protection of the general population from releases of radioactivity. This analysis would update the current exposure-pathway analysis to use a more modern performance-assessment methodology that would better align 10 CFR part 61 with the Commission's policy regarding the use of probabilistic risk assessment methods in nuclear regulatory analysis (60 FR 42622; August 16 1995). The performance assessment would also use a newly defined 1,000-year compliance period. The performance assessment would retain the current 0.25 mSv (25 mrem) annual dose limit and the as low as reasonably achievable (ALARA) concept, but the dose methodology would be consistent with the dose methodology specified in the standards for radiation protection set forth in the current 10 CFR part 20.
Given the significant uncertainties inherent in demonstrating compliance with the performance objectives over a long timeframe, a protective assurance period analysis would be required to demonstrate that the annual dose would be minimized below 5 mSv (500 mrem) or a level that is supported as reasonably achievable based on technological and economic considerations from the end of the compliance period through 10,000 years. Further, this analysis would need to consider new site features and processes occurring at the site that are different than what is considered during the compliance period.
Finally, a qualitative analysis covering a performance period of 10,000 years or more after site closure will also be required in 10 CFR 61.13 for those sites disposing of long-lived waste or if necessitated by site-specific conditions. This analysis would be required to assess how the disposal facility and site characteristics limit the potential long-term radiological impacts, consistent with available data and current scientific understanding, for the protection of the general population and the inadvertent intruder.
Defense-in-depth is an integral part of the safety case presented by the disposal applicant or licensee. Therefore, the defense-in-depth analyses are required in each one of the periods that are analyzed, as noted in Table 1.
This proposed rule would affect existing and future LLRW disposal facilities that are regulated by the NRC or an Agreement State.
Recently, the industry and the NRC have identified new LLRW streams that were not envisioned during the development of 10 CFR part 61. These LLRW streams include depleted uranium (DU) from enrichment facilities, LLRW from the U.S. Department of Energy (DOE) operations, and blended LLRW streams in quantities greater than previously expected. In addition, new technologies might result in the generation of different LLRW streams not previously evaluated during the development of the current 10 CFR part 61 regulations.
The renewed interest in licensing new uranium enrichment facilities in the United States has brought disposal of DU LLRW to the forefront of commercial LLRW disposal issues. In the regulatory basis supporting the development of current 10 CFR part 61, the NRC did not consider the relatively high concentrations and large quantities of DU LLRW that are generated by enrichment facilities. Additionally, the NRC did not anticipate that the DOE would dispose of large quantities of DU LLRW or any other defense-related LLRW in commercial disposal facilities. With the existing DOE DU stockpile at the Paducah and Portsmouth Gaseous Diffusion Plants, and the recent licensing of the Louisiana Energy Services National Enrichment Facility and the United States Enrichment Corporation American Centrifuge Plant, the DOE and the industry might need to dispose of more than 10
In a 2008 analysis provided in SECY-08-0147, “Response to Commission Order CLI-05-20 Regarding Depleted Uranium,” dated October 7, 2008 (ADAMS Accession No. ML081820762), involving a land disposal scenario for large quantities of DU, the NRC staff identified conditions that would likely not meet the current performance objectives in 10 CFR 61.41 and 10 CFR 61.42, if large quantities of DU were disposed under those conditions (
The blending of different classes of LLRW could also result in LLRW streams with concentrations that are inconsistent with the assumptions used to develop tables 1 and 2 of 10 CFR 61.55. Blending of LLRW would enable some materials that would otherwise have been disposed of as a higher class (
Other unanticipated LLRW streams may also need to be considered for future disposal at LLRW disposal facilities. For example, the Energy Policy Act of 2005 expanded the NRC's regulatory authority under the Atomic Energy Act of 1954, as amended (AEA), to include discrete sources of naturally occurring radioactive material (including radium-226) that might be produced, extracted, or converted as a byproduct material. The regulatory basis for the current 10 CFR part 61 considered only a small quantity of radium-226 bearing LLRW in the development of the 10 CFR part 61 LLRW classification system.
Further, as part of its regulatory effectiveness strategy described in NUREG-1614, Volume 6, “Strategic Plan Fiscal Years 2014-2018” (ADAMS Accession No. ML14246A439), the Commission strives, through its regulatory processes, to use risk-informed and performance-based approaches, where appropriate, to enhance the effectiveness and efficiency of the regulatory framework. The NRC concluded that amending the regulations to permit licensees or license applicants to develop criteria for LLRW acceptance from the results of the site-specific technical analyses as an alternative to the LLRW classification requirements allows for increased use of site-specific information to develop risk insights to support the safe disposal of LLRW. The new amendments also provide flexibility to determine how licensees can best meet the performance objectives for the specific design and operational practices of their disposal facility, as well as the specific environmental characteristics of their site.
Finally, the concept of “defense-in-depth” is currently not explicit in 10 CFR part 61. On February 11, 2011 (ADAMS Accession No. ML110680621), the NRC Chairman, Gregory B. Jaczko, created a Risk Management Task Force (RMTF), to develop a strategic vision and options for adopting a more comprehensive and holistic risk-informed, performance-based regulatory approach for reactors, materials, waste, fuel cycle, and transportation that would continue to ensure the safe and secure use of nuclear material. The RMTF issued NUREG-2150, “A Proposed Risk Management Regulatory Framework,” dated April 30, 2012 (ADAMS Accession No. ML12109A277). Three recommendations for LLRW were proposed in NUREG-2150. One of these recommendations was that the NRC should develop an explicit characterization of how defense-in-depth, within the proposed risk management framework, applies to the LLRW program and build this into current and future staff guidance documents and into training and development activities for the staff. This proposed rule would add a defense-in-depth requirement in 10 CFR part 61 to address the LLRW recommendations in NUREG-2150.
For the NRC licensees and license applicants, the rule would become effective 1 year after the final rule is published in the
The NRC considered a number of options in developing this proposed rule. The agency decided that requiring a safety case comprised of a collection of information that demonstrates the safety of a land disposal facility and includes site-specific technical analyses and defense-in-depth protections for all LLRW inventories would be the most comprehensive approach. This approach would ensure that as LLRW streams are generated, analyses would be performed to determine if the performance objectives would be met for disposal of all isotopic concentrations and volumes of LLRW. Under the proposed rule, all sites would be required to complete performance assessments and intruder assessments for the compliance period and the protective assurance period. In addition, land disposal sites with long-lived LLRW, or land disposal sites with site-specific conditions that would necessitate it, would be required to complete performance period analyses for the performance period.
This rulemaking would require licensees and license applicants to prepare a performance assessment, a new intruder assessment, and new defense-in-depth analyses to demonstrate that its disposal site and design meet the performance objectives. Licensees and license applicants under 10 CFR part 61 would be required to prepare the following as part of their site-specific technical analyses: (a) A revised analysis, called a performance assessment, to demonstrate the protection of the general population from releases of radioactivity (10 CFR 61.41); (b) a new analysis, called an intruder assessment, to demonstrate the protection of inadvertent intruders (10 CFR 61.42); (c) performance period analyses to evaluate how the disposal system may mitigate the long-term risk from disposal of long-lived LLRW (10 CFR 61.13(e)); and (d) new analyses that demonstrate the disposal site includes defense-in-depth protections. The site-specific technical analyses would be required to be updated at facility closure, to provide assurance of compliance with the performance objectives for the disposal of LLRW streams that were not analyzed in the original 10 CFR part 61 regulatory basis.
The first performance objective of subpart C of 10 CFR part 61, which provides protection of the general population from releases of radioactivity, would continue to be demonstrated with a technical analysis that would be revised and renamed in 10 CFR 61.13 as a “performance assessment.”
Many features, events, and processes can influence the ability of a LLRW disposal facility to limit releases of radioactivity to the environment. Disposal system behavior is influenced by the LLRW disposal facility design, the characteristics of the LLRW, and the geologic and environmental characteristics of the disposal site. A performance assessment evaluates the projected behavior of an LLRW disposal system and the uncertainties in the projected performance of the system. The performance assessment identifies the specific characteristics of the disposal site (
Currently, the descriptions of the technical information, technical analysis, and requirement to demonstrate compliance with the protection of the general population from releases of radioactivity can be found in 10 CFR 61.12, “Specific technical information,” 10 CFR 61.13(a), and 10 CFR 61.41, respectively, although these analyses are not called a “performance assessment.” In addition, these technical analyses do not have a prescribed compliance period. The original guidance documents associated with these requirements can be found in NUREG-1300, “Environmental Standard Review Plan for the Review of a License Application for a Low-Level Radioactive Waste Disposal Facility” (ADAMS Accession No. ML053010347); NUREG-1199, Revision 2, “Standard Format and Content of a License Application for a Low-Level Radioactive Waste Disposal Facility” (ADAMS Accession No. ML022550605); and NUREG-1200, Revision 3, “Standard Review Plan for the Review of a License Application for a Low-Level Radioactive Waste Disposal Facility” (ADAMS Accession No. ML061370484).
Proposed 10 CFR 61.41 would require licensees or license applicants to complete a performance assessment to estimate peak dose within the compliance period following closure of the disposal facility. The proposed compliance period is defined as 1,000 years following closure of the facility.
After the compliance period, licensees or license applicants would be required to provide analyses of the disposal facility performance from the end of the compliance period to 10,000 years. This period of time is referred to the protective assurance period. The analysis for the protective assurance period is an extension of the performance assessment to the timeframe following the compliance period. From a technical standpoint, the analysis for the protective assurance period is likely to be very similar to the compliance period performance assessment, but, given the uncertainty in projecting the performance of the disposal site over long time periods, uses a different metric (
The definition of compliance and protective assurance periods would add important technical parameters to the current technical analyses. Appropriate time periods are important for the evaluation of LLRW streams that were not considered in the original 10 CFR part 61 rulemaking as well as for evaluation of long-lived LLRW that were considered in the original rulemaking. The NRC believes that the results of a performance assessment would assist in demonstrating that the protection of the general population from releases of radioactivity can be achieved. The proposed 10 CFR 61.41, new definitions, technical analyses requirements, and concepts are risk-informed and flexible. Proposed 10 CFR 61.41 uses a risk-informed regulatory
The proposed amendments formally introduce the concept of features, events, and processes (FEPs), which ensure appropriate comprehensiveness of any site-specific technical analysis. For the protective assurance period, the performance assessment would need to reflect new FEPs different from the compliance period that address significant uncertainties inherent in the long timeframes only if scientific information compelling such changes is available. The NRC staff has developed a draft guidance document, NUREG-2175, “Guidance for Conducting Technical Analyses for 10 CFR part 61,” to facilitate the development of information and analyses that will support licensees or license applicants in addressing the regulatory requirements. This draft guidance document is being made available for public comment concurrent with this proposed rule. (See Docket ID NRC-2015-0003 in the Proposed Rules section of this issue of the
In 10 CFR part 61, the NRC recognizes that it is possible, though unlikely, that an inadvertent intruder might occupy a disposal site in the future and engage in normal pursuits without knowing that they are receiving radiation exposure. Therefore, the second performance objective in subpart C of 10 CFR part 61 is the protection of inadvertent intruders. Currently, 10 CFR part 61 does not require a site-specific analysis to demonstrate the protection of an inadvertent intruder. Instead, the safety of an inadvertent intruder is demonstrated by compliance with the LLRW classification system and the disposal requirements imposed for each class of LLRW. The connection between the LLRW classification system and protection of an inadvertent intruder is reflected in the LLRW classification tables in 10 CFR 61.55. The regulatory basis for the current 10 CFR part 61, published in NUREG-0945, contains an analysis of a reference disposal facility that evaluates the impacts of LLRW disposal on an inadvertent intruder. This analysis supported the concentration-based LLRW classification tables developed for 10 CFR 61.55.
Consistent with the development of the LLRW classification system, the technical analysis requirements currently found in 10 CFR 61.13(b) specify that the analyses of the protection of inadvertent intruders must include a demonstration that there is reasonable assurance that the LLRW classification and segregation requirements will be met and that adequate barriers to inadvertent intrusion will be provided. The regulations ensure the safety of the inadvertent intruder through the LLRW classification system and the LLRW disposal requirements imposed for each class of LLRW. However, as they are presently written, the regulations do not explicitly require an analysis of inadvertent intruder doses. Differences between LLRW disposal inventories, disposal practices, and the underlying assumptions used to develop the LLRW classification tables in 10 CFR 61.55 can result in varying doses with respect to the protection of an inadvertent intruder. Therefore, the new proposed regulatory provisions require licensees and license applicants to conduct an analysis of inadvertent intruder doses.
The proposed revisions would add a requirement for licensees and license applicants to conduct a site-specific intruder assessment to demonstrate compliance with 10 CFR 61.42. The proposed intruder assessment would quantitatively estimate the radiological exposure of an inadvertent intruder at an LLRW disposal facility following an assumed loss of institutional controls at the end of the active institutional control period. The results of the intruder assessment would then be compared to the performance objective in 10 CFR 61.42. The intruder assessment would identify the intruder barriers, examine the capability of the barriers, and address the effects of uncertainty on the performance of the barriers. The capabilities of the barriers to inhibit contact with the disposed LLRW or limit the radiological exposure of an inadvertent intruder and the time period over which the capability persists must be demonstrated and a technical basis must be provided. In performing the proposed intruder assessment, licensees would be expected to employ a methodology similar to that used for a performance assessment, but the intruder assessment would assume that an inadvertent intruder occupies the LLRW disposal site after closure, engages in normal activities, and is unknowingly exposed to radiation from the LLRW.
With the intruder assessment requirement, the NRC is proposing to specify an intruder dose limit for the compliance period and protective assurance period as described in the original 10 CFR part 61 analysis to develop the LLRW classification tables. The regulatory basis for 10 CFR part 61 assumed that inadvertent intrusion occurred following a cessation of a caretaker or active institutional control period. Institutional control of the site was expected to occur beyond the active institutional control period, although it could not be assured because of the long timeframes involved. Therefore, an intruder was assumed to occupy the LLRW disposal facility and engage in normal activities, such as agriculture or dwelling construction. The analysis assumed that the intruder directly contacted the disposed LLRW, and was exposed to radionuclides through inhalation of contaminated soil and air, direct radiation, and ingestion of contaminated food and water. The NRC based the LLRW classification tables in 10 CFR 61.55 on radionuclide concentrations that would yield a 5 mSv/yr (500 mrem/yr) dose.
The dose limit used to develop the current LLRW classification tables was selected from a range of values that were consistent with exposure guidelines of different orders of magnitude: 0.25 mSv/yr (25 mrem/yr), 5 mSv/yr (500 mrem/yr), and 50 mSv/yr (5,000 mrem/yr). In NUREG-0945, the NRC selected the 5 mSv/yr (500 mrem/yr) dose based primarily on safety as reflected in the effective dose limit in 10 CFR part 20 at that time and public opinion gained through the four regional workshops held on the preliminary draft of 10 CFR part 61. The NRC continues to believe that this dose limit provides an acceptable level of protection to an inadvertent intruder. The NRC is proposing to add an annual intruder dose limit to 10 CFR 61.42 to ensure protection of any inadvertent intruder who occupies the disposal site or contacts the LLRW at any time after active institutional controls are removed.
Given the uncertainty in projecting performance of disposal sites over long time periods such as those beyond the compliance period, the amendments proposed in 10 CFR 61.42 would require that annual doses be minimized, as estimated by an intruder assessment, for the protective assurance period. The minimization target is for annual doses to be below 5 mSv/yr (500 mrem/yr) or a level that is supported as reasonably achievable based on technological and economic considerations. The NRC is seeking feedback on the proposed
Given the uncertainty in predicting human behavior into the distant future and to limit associated speculation, the NRC is proposing to change the definition of the inadvertent intruder to limit the scenarios to reasonably foreseeable activities that are realistic and consistent with activities in and around the disposal site at the time of closure.
As discussed in Section M of this document, the NRC has prepared a draft guidance document that describes acceptable approaches for determining reasonably foreseeable intruder activities that are consistent with activities in and around the disposal site at the time of closure to be assessed in the intruder assessment. The draft guidance describes how licensees or license applicants can take credit for physical characteristics (
The proposed approach, consistent with the current approach, is to assume that the active institutional controls will fail after the end of the active institutional control period. The NRC does not believe that controls will fail, but rather that the durability of the controls cannot be assured. In addition, the NRC is not assuming the probability is 100 percent that contact with the LLRW by an intruder will occur. As in the current regulation, engineered barriers and disposal practices, such as greater disposal depth, are to be considered in the intruder assessment. For example, with a protective cover of at least 5 m (16 feet) thickness, consideration of a scenario in which a dwelling foundation is excavated in a disposal unit would not be reasonable. A 5 mSv (500 mrem) dose limit for the intruder, compared to a 0.25 mSv (25 mrem) annual dose limit for the public during the compliance period in 10 CFR 61.41, demonstrates the NRC expectation that the intruder scenario is unlikely. As previously stated, the NRC is making available the draft guidance document (see Docket ID NRC-2015-0003) for public comment concurrent with the publication of this proposed rule and is seeking comments on whether the approaches described in the guidance are adequate or if further specification for inadvertent intruder scenarios in the proposed rule is necessary.
As previously indicated, the current 10 CFR part 61 provides LLRW classification and segregation requirements. The NRC considered, based on comments received on the preliminary proposed rule language (76 FR 24831), whether additional requirements such as minimum depth of disposal were needed for large quantities of long-lived LLRW (
The current regulations in 10 CFR part 61 limit radiological risks from land disposal of LLRW regardless of the half-life of the LLRW. To ensure protection of public health and safety, 10 CFR part 61 includes regulations regarding analyses, LLRW classification, site-selection, LLRW characteristics, and other requirements. A long-term analysis (
The long-term analyses, termed “performance period analyses” as set forth in 10 CFR 61.13(e), would require licensees or license applicants to prepare long-term analyses (
The metric for the performance period analyses would be to minimize releases to the public to the extent reasonably achievable. The NRC considered a variety of approaches for metrics to evaluate the performance period analyses. The aforementioned metric was selected because it would allow socioeconomic information to be considered in a risk-informed manner. Considering the timeframes involved, uncertainties may be considerable and therefore the precision typically assigned to a dose limit is not warranted. Whereas the calculated dose in a numerical model may be precise, the significance of that dose to a future generation is unknowable in the present. Although a dose limit is not prescribed, it is recommended that doses or concentrations and fluxes of radionuclides in the environment are calculated as they are appropriate to use to compare alternatives using a common metric. The NRC believes the value of information an applicant would provide to describe its actions to mitigate long-
The proposed performance period analyses must identify and describe the features of the design and site characteristics that will demonstrate that the performance objectives set forth in 10 CFR 61.41(c) and 10 CFR 61.42(c) will be met. These analyses would also help determine whether any additional measures are needed at a disposal site to ensure the protection of the general population and the inadvertent intruder from disposal of long-lived LLRW with average concentrations exceeding the values listed in the proposed table A of 10 CFR 61.13(e), or if necessitated by site-specific conditions, and to determine whether limitations on the disposal of some LLRW streams at certain sites may be needed to properly manage the disposal of LLRW.
An ending time for the performance period analyses is not specified in the proposed regulation. A number of factors influenced this decision. First, the analyses may demonstrate the time when the peak impact is likely to occur such that further calculation beyond this time is unnecessary. Because long-term impacts are going to be driven by site-specific characteristics and the particular LLRW that is disposed, the timing of peak impacts may differ substantially from site to site. A licensee or license applicant must demonstrate that impacts are minimized to the extent reasonably achievable, ensuring that facilities and disposal cells are not under-designed. Second, the analyses that are developed for the performance period may differ from traditional projections of long-term radiological doses. Performance period analyses may demonstrate that the performance period metrics have been satisfied irrespective of peak radiological impacts. The proposed approach is based on the position that there are many uncertainties in the risks imposed on future generations, especially from processes or events other than LLRW disposal. In addition, there is uncertainty in the projected radiological risk to future populations from LLRW disposal, which may be based on a number of assumptions about the behavior and characteristics of future society. The proposed approach focuses on a demonstration of how the natural and engineered barriers of the disposal system could limit releases of material rather than the radiological impact to an individual or group. The NRC is seeking feedback on the proposed approach, especially with regard to whether a dose limit is needed for the long-term analyses or whether the proposed metric combined with barrier analyses is more appropriate.
The defense-in-depth principle has served as a cornerstone of the NRC's deterministic regulatory framework for nuclear reactors, and it provides an important tool for making regulatory decisions, with regard to complex facilities, in the face of significant uncertainties. The NRC also has applied the concept of defense-in-depth elsewhere in its regulations to ensure safety of licensed facilities through requirements for multiple, independent layers, and, where possible, redundant safety systems. Traditionally, the reliance on independence and redundancy of barriers has been used to provide assurance of safety when reliable, quantitative assessments of barrier reliability are unavailable. The NRC maintains, as it has in other regulations for disposal, such as for high-level radioactive waste, that the application of the defense-in-depth concept to a LLRW land disposal facility is appropriate and reasonable. Therefore, the NRC is now proposing additional analyses to ensure that the land disposal facility includes defense-in-depth protections.
However, implementation of defense-in-depth protections, in the context of a LLRW land disposal facility, should be consistent with the NRC's goal of achieving a regulatory program and associated requirements that are risk-informed and performance-based. While waste is being disposed, and before a LLRW land disposal facility is closed, defense-in-depth protections would typically be comparable to other operating nuclear fuel cycle facilities licensed by the NRC. Application of defense-in-depth principles for regulation of disposal facility performance for long time periods following closure, however, must account for the difference between a closed land disposal facility and an operating facility with active safety systems and the potential for active control and intervention. A closed land disposal facility is essentially a passive system, and assessment of its safety over long timeframes is best evaluated through consideration of the relative likelihood of threats to its integrity and performance. Although it is relatively easy to identify multiple, independent and redundant layers that comprise the engineered features and site characteristics, the capabilities of any of these design features and site characteristics may not be either independent or totally redundant. The NRC continues to believe that multiple layers of defense must each make a definite contribution to the isolation of the waste, so that the NRC may find, with reasonable assurance, that no single layer of defense will be exclusively relied upon to achieve the overall safety objectives over timeframes of hundreds to thousands of years. Disposal of LLRW is also predicated on the expectation that a portion of the site in combination with engineered features will minimize the migration of radionuclides away from the disposal site. However, the capabilities of site characteristics and engineered features over the long timeframes are subject to interpretation and include many uncertainties. These uncertainties can be quantified generally and are addressed by requiring the use of a multiple layers. Similarly, although the composition and configuration of engineered features, as well as their capacity to limit releases or function as intruder barriers, may be defined with a degree of precision in the near-term that may not be possible for site characteristics, it is recognized that except for a few archaeologic analogues, there is no experience base for the performance of complex, engineered structures over periods longer than a few hundred years. Therefore, the NRC expects that licensees will rely on both the characteristics and the engineered features, in combination, to provide reasonable assurance that the overall performance of the disposal site will be adequate over long time periods.
Currently, 10 CFR 61.50, which is also being revised in this rulemaking, requires that LLRW disposal sites not be susceptible to erosion, flooding, seismicity, or other disruptive events or processes to such a degree or frequency that compliance with the 10 CFR part 61 performance objectives cannot be demonstrated with reasonable assurance. Currently, 10 CFR 61.44 also includes a performance objective for stability at the disposal site after closure. It states that the disposal facility must be sited, designed, used, operated, and closed to achieve long-term stability of the disposal site and to eliminate, to the extent practicable, the need for ongoing active maintenance of the disposal site following closure. To demonstrate with areasonable assurance
Site stability analyses focus on stability of the wasteform, stability of the engineered disposal facility, and geologic/geomorphic stability of the disposal site. For disposal of traditional LLRW (
The NRC proposes to revise 10 CFR 61.44 to specify that stability of the disposal site must be demonstrated for the compliance and protective assurance periods. This change was necessary to clarify that the post-closure site stability requirements apply to the compliance and protective assurance periods created in this proposed rule.
Currently, 10 CFR 61.28, “Contents of application for closure,” requires licensees to submit an application to amend the license for closure. This application must include (1) a final revision and specific details of the disposal site closure plan, and (2) an environmental report or a supplement to an environmental report. Currently, 10 CFR 61.28 does not require licensees to prepare updated site-specific technical analyses. The proposed rule would require licensees to include updated safety case and technical analyses in their applications to amend their licenses for closure, to provide greater assurance of compliance with the performance objectives that ensure the safe disposal of LLRW streams significantly different from those considered in the original 10 CFR part 61 regulatory basis (
Currently, 10 CFR 61.7 discusses a number of timeframes that licensees or license applicants should consider in selecting a site, designing stable wasteforms or containers, controlling access to the site, and developing intruder barriers. The timeframes discussed are provided within the context of a LLRW management system that attempts to ensure that LLRW decays to innocuous levels prior to public exposure to radiation. The concentrations and quantities of long-lived LLRW for disposal would be limited thereby limiting potential exposures. For instance, 10 CFR 61.7(a)(2) indicates that in choosing a disposal site, site characteristics should be considered for the indefinite future and evaluated for at least a 500-year timeframe. However, 10 CFR part 61 does not provide a value for the time period
The NRC evaluated what other countries and international agencies use to manage the radiological risks from the disposal of long-lived LLRW. Some organizations impose a requirement to identify impacts from the disposal of long-lived LLRW using technical analyses. Results of the analyses are used to impose appropriate restrictions on LLRW disposal, if necessary. Almost every country that the NRC looked at places restrictions on how much LLRW can be disposed of in the near surface or does not allow near-surface disposal of long-lived LLRW. Most countries place explicit numerical limits on concentrations of long-lived alpha-emitting LLRW. These concentration limits are set by regulators based on generic technical analyses or policy decisions. The concentration limits are not developed based on the results of site-specific technical analyses. Site-specific technical analyses are performed, but only for LLRW that satisfies the generic limits. This approach is very similar to what was done for the initial development of 10 CFR part 61. The current requirements in 10 CFR part 61 supplement technical analyses with LLRW concentration limits and other disposal requirements, such as minimum disposal depth for certain types of LLRW. The development of concentrations limits by generic analysis or policy works well for countries that only have one disposal site. However, if numerous sites are regulated in this manner the concentration limits must be based on the most limiting conditions in order to assure that public health and safety is protected.
In general, different international programs have used regulatory approaches that vary considerably in methodology used to achieve protection of future generations from the disposal of LLRW. However, countries and international safety organizations consistently apply limiting conditions on the near-surface disposal of LLRW (
The NRC has considered a variety of options for selection of the analysis timeframe for the assessment of LLRW disposal.
• Analyses-based approach to safety, and
• Design- and control-based approach to safety.
These two approaches are not mutually-exclusive and each can contain elements of the other approach. Traditionally, for the disposal of LLRW, analyses-based approaches projecting performance of the disposal facility into the future have been used. Disposal of municipal and industrial waste that is non-radioactive have used the design- and control-based approach to safety. The primary decision is what specific regulatory requirements are needed to ensure that public health and safety will be protected.
Analyses-based approach: A variety of different options were considered with respect to the analyses-based approaches. A key consideration of these approaches is the obligation of the current generation to protect future generations from the disposal of LLRW. Though this section discusses the NRC's options for analyses timeframes, the technical analyses should be considered in context with all the requirements of the regulation. The primary decision variables with respect to analyses timeframes considered by the NRC were:
• How many tiers should be used for the analyses?
• What should be the duration of the tiers?
• What limits should be prescribed to each tier?
Table 2 provides a summary of the analyses-based approaches considered by the NRC. A more in-depth discussion of the advantages and disadvantages of each approach can be found in the NRC's “Technical Analysis Supporting Definition of Period of Performance for Low-level Waste Disposal,” and “Regulatory Basis for Proposed Revisions to Low-Level Waste Disposal Requirements (10 CFR part 61)”.
(a) Current—no change approach: In this approach, a compliance period is not specified for the assessment of the performance objectives. All four currently operating commercial low-level waste disposal facilities are located in Agreement States, and they all have different requirements for the compliance period. No additional action would be required by the NRC to maintain the current approach.
(b) Peak dose approach: This approach would require the calculation of peak dose for the compliance determination regardless of when the peak occurs (which could be greater than 10,000 years if large amounts of DU are disposed at the site). If regulatory limits are met, this approach ensures that all future generations would be provided with the same level of protection as the current generation. It would also ensure that the burden from the disposal of LLRW by the present generation is not deferred to any future generations, no matter how distant in the future.
(c) Regulator-derived concentration limits approach: This approach would involve using a single tier for the analyses of up to a few thousand years, complemented with regulator-derived concentration and quantity limits for long-lived isotopes. This approach is used by some other countries. The NRC believes this approach can be effective at mitigating the impact of long-term uncertainties while avoiding unnecessary speculation and ensuring protection of public health and safety for present and future generations. The challenge of using this approach is that it would be difficult to take into account different site, disposal facility, and other characteristics when determining regulator-derived concentration and quantity limits for long-lived isotopes. The NRC believes that this approach could work well for a single LLRW disposal site (which is most common in foreign nations), but would be difficult to implement in a risk-informed manner for numerous disposal sites. To ensure protection of public health and safety, the limits that would be derived using this approach may need to be set at values derived for the most limiting conditions (
(d) Limited duration approach: This approach would assign a 1,000-year compliance period to the analysis using a single tier. No limits would be prescribed for impacts that would occur after this period. Proposed guidance would indicate that it may be useful to evaluate longer-term impacts and consider modifications to the disposal system, if practical. A challenge with this approach is that, without limits on the disposal of long-lived isotopes, the dose estimated in a 1,000-year analysis timeframe may not be close in magnitude to the peak dose even for disposal of traditional LLRW. Another shortcoming of this approach is that a performance assessment could demonstrate that the performance objectives would be met within the first 1,000 years but then be exceeded by a large margin afterwards. In fact, this result would be expected, especially for the disposal of DU where the maximum dose achieved within 1,000 years is only about 1/1000th of the peak dose. Because Agreement States have selected different compliance periods, staff anticipates that the lack of a standard approach with respect to long-term impacts (after 1,000 years) will likely result in differences in interpretation among Agreement States. The approach would also create ambiguity with respect to the Commission's objectives for the management of long-term impacts. The decisions for additional action under this approach will be subjective, with case-by-case decisions being made by different regulators using different metrics.
(a) Risk-informed analyses approach: This approach sets standards for the analyses timeframes to ensure consistency, but then affords flexibility to licensees with respect to the technical analyses used to demonstrate compliance with the subpart C performance objectives. To ensure the long-term protection of public health and safety from the disposal of LLRW, the risk-informed analyses approach would be characterized by:
• A compliance period of up to 10,000 years.
• A second tier (
The analyses for the second tier would include: (1) A screening process to identify if performance period analyses are necessary, and (2) performance period analyses, if applicable. The performance requirement for the performance period analyses would be to minimize releases to the extent reasonably achievable. The analyses that could be used for the second tier would be described in guidance. The regulations would describe the analyses at a high-level.
Under this two-tiered approach, licensees or license applicants of LLRW disposal facilities that dispose of short-lived LLRW or limited quantities of long-lived LLRW would perform their compliance analyses, and no additional analyses would be required. If LLRW has average concentrations exceeding the values developed by the NRC, or if necessitated by site-specific conditions, then the licensees or license applicants would have to perform analyses for the second tier. Guidance would describe the use of a conservative screening analysis or, if desired, a site-specific technical analysis for the second tier. The screening analysis would be based on a conservative approach (
(b) Risk-informed analysis with long-term dose limits approach: This approach is conceptually similar to the previous two-tiered approach but differs in that a dose limit for the second tier (
(c) Site-specific approach: A final option using a two-tiered approach would be described as involving a compliance period of somewhere between a few hundred to 1,000 years, which would cover what the NRC believes is a reasonably foreseeable period for estimating future human activities. If uncertainty associated with the societal component of the problem is managed by specifying reasonably conservative scenarios, then the compliance period could be as long as 10,000 years. The time period for the second tier of this approach would not be defined in the regulation, instead it would be determined on a site-specific basis. Under this option a dose limit could be established for the second tier or an alternative metric could be used.
a) Uncertainty limitation approach: This three-tiered approach involves a compliance period, a protective assurance period, and a performance period.
The
The NRC recognizes that there is merit in considering timeframes longer than 1,000 years for some types of waste. Therefore, this approach would also establish a
• What are the projected doses?
• What other technologies are available to reduce those projected doses (
• If the doses are projected to be above 5 mSv/yr (500 mrem/yr), can they be reduced using technology in an economically justifiable manner?
• Could the waste stream be disposed at a different site? Is this site not suitable for this waste (
The third tier of the approach is the
(b) Uncertainty informed approach: This approach would provide decision points and regulatory limits that would consider major sources of uncertainty associated with the projection of radiological risk from the disposal of LLRW. This approach would be divided into three timeframes—compliance period, assessment period, and performance period—and is referred to as the Compliance, Assessment, and Performance approach (CAP).
The
The
The
The objective of the CAP approach is to balance the need to consider radiological risks to future generations, even over long periods of time, with the uncertainties that could impact the interpretation of the results of the performance calculations. For LLRW inventories with long-lived radionuclides and with in-growth of more mobile progeny, the CAP approach is one way to ensure that the long-term risks would be incorporated into decision making. This three-tiered approach would ensure that the potential long-term radiological risks are communicated to decision makers while properly reflecting the uncertainties associated with the calculations. In the NRC's “Technical Analysis Supporting Definition of Period of Performance for Low-level Waste Disposal,” examples were given for defining the tiers and providing associated dose limits, however, specific values for each variable were not selected.
Design- and control-based approach: The NRC considered an approach to managing long-lived LLRW that requires periodic review and reassessment (
Under current 10 CFR part 61, after satisfactory disposal site closure, licenses are transferred to the State or Federal Government, one of which is required to own the disposal site. A 5-year period during which the licensee would remain at the disposal site to ensure that the site is stable and ready for institutional control is required, though the Commission would be able to prescribe longer periods of time to demonstrate that the disposal site is stable, if warranted.
The NRC proposed option is an approach to analyses timeframes that is based on a three-tiered conceptual framework. The proposed option includes a compliance period of 1,000 years applicable to both a performance assessment used to demonstrate compliance with 10 CFR 61.41 and to an intruder assessment used to demonstrate compliance with 10 CFR 61.42.
The second tier of the proposed option includes a 10,000 year protective assurance period, during which doses, as estimated by technical analyses, would be minimized. The objective of the minimization process would be to keep doses below 500 mrem/yr or to a level that is reasonably achievable based on technological and economic considerations. Should doses exceed the minimzation target, changes to the disposal site design, inventory limits, or alternative methods of disposal would be needed to ensure doses are minimized to avoid unacceptable consequences unless those changes can be shown to not be technically or economically practical. Given the significant uncertainties inherent in these long timeframes, the performance assessment should reflect changes in features, events, and processes of the natural environment such as climatology, geology, and geomorphology only if scientific information compelling such changes from the compliance period is available. The NRC is not proposing that features, events, and processes that are dynamic be arbitrarily fixed as static. Rather that
The third tier of the proposed option includes a performance period of undefined duration during which a licensee must demonstrate that effort has been made to minimize releases to the extent reasonably achievable. This metric for the third tier would afford the flexibility for consideration of long-term radiological doses, cost-benefit type of analyses, and concentration and fluxes of radionuclides in the environment. The duration is undefined to allow for consideration of site- and waste-specific factors as well as different methods to demonstrate that the requirements have been met. This approach was informed by the views expressed by various members of the public about the consideration of long-term uncertainties. Conditions have been established to determine when the performance period analyses should be performed, therefore risk-informing the approach. In order to determine if performance period analyses are necessary, it is proposed that a licensee or license applicant compare LLRW disposal site-averaged concentrations of long-lived radionuclides to values provided in the proposed table A of 10 CFR 61.13(e). This requirement would ensure that the analyses are performed only when dictated by the radiological characteristics of the LLRW or if necessitated by site-specific conditions. The concentration values are primarily, but not solely, based on the Class A LLRW concentration values from table 1 of 10 CFR 61.55. Unlike the existing table 1, the proposed table A includes non-transuranic long-lived isotopes, as well as transuranic long-lived isotopes. It is appropriate to include the non-transuranic isotopes in the performance period analyses if they could potentially be disposed of in significant concentrations and quantities. The radiological risk is estimated using the dose conversion factors of individual isotopes at the concentration provided (10 nanoCuries per gram (nCi/g)). The dose conversion factors for all isotopes have variability; there are different values of dose conversion factors for different solubility classes of an isotope as well as different values of dose conversion factors for different isotopes. When deriving the 10 nCi/g concentration value for transuranic isotopes in Class A LLRW, the NRC applied the same conversion of concentration to dose for all of these isotopes. The dose conversion factors for non-transuranic isotopes are generally comparable to the transuranic isotopes, and the NRC believes it is appropriate to simplify the variability similar to what was done in the original rulemaking. This simplification results in a single concentration value for all long-lived alpha emitting radionuclides rather than a table of values for different isotopes. The concentrations provided in the proposed table A of 10 CFR 61.13(e) are only used to determine if performance period analyses are necessary. As explained in detail in the draft guidance document, the complexity of the analyses would be driven by the projected impacts. The results of the performance period analyses would determine if any resultant actions are necessary (
The specification of certain LLRW for which the performance period calculations apply to eliminates the need for all licensees or license applicants to develop performance period analyses. However, the language “or if necessitated by site-specific conditions” is needed because it is difficult to determine an absolute threshold for all sites below which the projected radiological risk, especially for 10 CFR 61.41, would be acceptably low. The risk to the public from the land disposal of LLRW can be driven by many variables, including but not limited to, concentration of LLRW, quantity of LLRW, disposal facility design, hydrogeology, release pathways, and receptor location and behavior. It is technically challenging to reduce this multi-dimension problem into one-dimension (
The reasons for selecting this option are:
• The tiered analysis that is required allows for tailoring of the analysis to the problem.
• The 1,000 year compliance period, appropriate for the disposal of short-lived LLRW, would ensure consistency among Agreement State regulators.
• By providing a 1,000-year compliance period, it would limit speculation and limit the impact of uncertainties on the compliance period decision making.
• By providing a protective assurance period, it would ensure that radiological impacts are minimized up to 10,000 years after closure. The miminization process would strive to maintain doses below 5 mSv/yr (500 mrem/yr) thereby providing protection to the public from the disposal of long-lived LLRW.
• By providing a goal rather than a limit for the second tier (
• Selective constraints are provided while affording regulatory flexibility, where warranted.
The NRC's perspective is that impacts should be reliably calculated for the compliance period. The NRC is proposing to manage the increasing uncertainties associated with long timeframes by limiting the timeframe of the analyses and the scope of the analyses. Licensing decisions should be based on information that is reasonable, reliable, and knowable based on current understanding. The proposed approach limits the consideration of uncertainties associated with long timeframes.
One of the factors underlying the proposed approach was the DU LLRW stream. The DU radiological characteristics are somewhat unique in that DU is very long-lived and there is potentially a large quantity of DU that needs to be disposed. In addition, the hazard of DU increases over very long periods of time because of the slow decay of uranium and the in-growth of progeny. The time at which the concentration of radionuclides in the LLRW is within one order of magnitude of the peak concentration is sensitive to the assumed isotopic mass fractions in the initial LLRW. For depleted uranium this time is approximately 10,000 years or longer. The recommended approach is suitable for depleted uranium because though the impacts after 1,000 years would not be part of a compliance decision, they would be considered in the licensing process and a licensee must demonstrate that the impacts have been minimized after 1,000 years.
Performing analyses that ensure public health and safety are protected
Given the significant uncertainties inherent in demonstrating compliance with the performance objectives over a very long timeframe and to ensure a reasonable analysis, the analyses would be required to demonstrate that the annual dose should be minimized below 5 mSv (500 mrem) or a level that is supported as reasonably achievable based on technological and economic considerations from the end of the compliance period through 10,000 years. This 500 mrem/yr minimization target was chosen to limit releases to values that have been previously established by the NRC in 10 CFR part 20. For example, paragraph (e) in 10 CFR 20.1403, “Criteria for license termination under restricted conditions,” and paragraph (d) in 10 CFR 20.1301, “Dose limits for individual members of the public,” require annual dose limits of 5 milliSievert (500 mrem) in limited cases. This approach is designed to provide a target for minimization that takes into account the significant uncertainties over these long periods of time. As discussed in the guidance document, the minimization process most likely will result in projected impacts that are significantly lower then this mimization target. The NRC is seeking feedback on the proposed approach, especially with regard to whether a 5 milliSievert (500 mrem) annual dose goal is appropriate for the protective assurance period and whether it is appropriate to consider alternative, higher levels based on technological and economic considerations.
The NRC's current WAC can be found in subpart D of 10 CFR part 61, which specifies technical requirements for land disposal facilities for commercial LLRW. The technical requirements specify the classes and characteristics of LLRW that are acceptable for near-surface disposal, as well as other requirements. Currently, 10 CFR 61.55 provides the primary criteria related to LLRW acceptance and identifies the classes of LLRW acceptable for near-surface disposal (
The LLRW classification system is well integrated with the requirements for LLRW characteristics and disposal facility operation. This integration stemmed from the generic nature of the original regulatory basis for 10 CFR part 61. The integrated requirements are intended to ensure that the performance objectives are met.
In addition to reviewing other regulatory approaches, the NRC also considered the original regulatory basis for 10 CFR part 61 in the development of the proposed revisions to 10 CFR 61.58. The principle basis used for setting the current 10 CFR part 61 classification limits, LLRW characteristic requirements, and operational requirements was limiting exposures to a potential inadvertent intruder at a reference LLRW disposal facility. Other considerations, such as long-term environmental impacts, LLRW disposal facility stability, institutional control costs, and financial impacts to small entities, were also considered. The NRC developed the LLRW classification system in 10 CFR part 61 from an analysis performed in 1981 of a representative LLRW disposal facility that was operated consistent with then-current practices and considered a projected set of LLRW streams (46 FR 38081; July 24, 1981). Specifically, the LLRW class limits were derived from an analysis that considered a combination of factors including radionuclide characteristics and concentrations, the wasteform, the methods of emplacement, and to some extent, the site characteristics. These factors influenced the concentration of radionuclides transferred from the disposed LLRW to the access points for the intruder scenarios. These factors are dependent upon the LLRW disposed, methods of emplacement, engineering design, and site characteristics, which can vary from facility to facility.
For example, one of the factors the NRC considered is site characteristics, which plays a role in the movement of radionuclides between environmental media (
Regardless of whether the assumptions regarding the LLRW, operational practices, facility design, or site characteristics of the reference LLRW disposal facility are consistent with current facilities, the NRC believes that the 10 CFR part 61 LLRW classification system remains protective of public health and safety for the LLRW streams that were analyzed in the development of the regulations because of the reasonably conservative nature of the analysis used to develop the LLRW classification system. However, inconsistency between actual site conditions and practices at an LLRW disposal facilities and the generic assumptions used to develop the LLRW classification system may cause the radionuclide concentration limits to be either overly restrictive or permissive. If radionuclide concentration limits are overly restrictive based on actual site characteristics, facility design, and operational practices, the LLRW classification system would ensure the safe disposal of LLRW, but it would impose unnecessary regulatory burdens on licensees and LLRW generators. Whereas, if the generic concentration limits at a LLRW disposal facility are overly permissive based on actual site characteristics, facility design, and operational practices, the LLRW classification system alone may not adequately ensure the protection of public health and safety. If the Commission found that the LLRW classification requirements were overly permissive at a particular disposal facility, it could impose additional requirements to ensure that the 10 CFR part 61 performance objectives would be met. Therefore, it's the 10 CFR part 61 performance objectives that ultimately ensure protection of public health and safety. However, the inconsistency between the generic assumptions and current practices highlights the need for flexibility to develop site-specific WAC. The site-specific WAC would provide assurance that public health and safety can be protected, while offering the possibility for the relief of unnecessary regulatory burdens for facilities with superior site characteristics, design, and operational practices. The specifics of WAC background information, other regulatory approaches regarding LLRW acceptance practices, technical considerations, and public comments are discussed further in Section 5.2, “Flexibility for Site-Specific Waste Acceptance Criteria,” of the regulatory basis document issued in December 2012.
In addition to considering the original regulatory basis for 10 CFR part 61, the NRC also performed a review of other regulatory approaches, domestic and international, regarding LLRW acceptance practices to develop the proposed revisions to 10 CFR 61.58. In general, practices vary but are constrained between specification of criteria by the regulatory agency and development of site-specific WAC by LLRW disposal facility operators. In all cases, the regulatory authority maintains oversight of disposal, including approval of the LLRW acceptance requirements.
The NRC considered three options for revising the regulatory framework associated with waste acceptance criteria for the near-surface disposal of LLRW. In the first option, the NRC considered maintaining the current approach for determining LLRW acceptability, namely the generic LLRW classification system. The NRC staff also considered a second option, in which the current LLRW classification system is replaced with criteria allowing flexibility for licensees or license applicants to determine site-specific WAC. Finally, the NRC considered a third option that would add flexibility to establish site-specific WAC to the existing LLRW classification system. These options are summarized as follows:
Option 1.
However, new practices that differ from the assumptions of the original analyses create uncertainty regarding the protectiveness of the LLRW classification system. For instance, new LLRW streams that were not considered during the development of 10 CFR part 61 are being considered for disposal (
Currently, 10 CFR part 61 allows for alternative provisions for LLRW acceptability (
At present, only one of the four Agreement States that has an operating near-surface LLRW disposal facility has adopted a corresponding regulation to 10 CFR 61.58. Currently, Agreement States are not required to adopt 10 CFR 61.58, therefore, the Agreement State compatibility designation for 10 CFR 61.58 must be changed in order to require Agreement States to adopt an alternative provision for LLRW classification and characteristics. Agreement State compatibility designation for 10 CFR 61.58 is discussed further in Section VI, “Agreement State Compatibility,” of this notice.
Option 2.
Removal of the current LLRW classification system from 10 CFR part 61 would present challenges because the LLRW classification requirements are well integrated with other requirements of 10 CFR part 61. For instance, license requirements for the operation of a LLRW disposal facility may reference the LLRW classes of 10 CFR 61.55. Therefore, complete replacement of the LLRW classification system would likely expand the effect of the rule revisions beyond the intended scope of this rulemaking.
Further, removal of the LLRW classification system from 10 CFR part 61 would not result in total abandonment of the system because the classification of LLRW is referenced in the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985). The Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) establishes Federal and State responsibilities for the disposal of LLRW based on the LLRW classification system in 10 CFR part 61 as it existed on January 26, 1983. Specifically, Section 3 of the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) states that the responsibilities of each State shall include the disposal of LLRW generated within the State (other than by the Federal Government) that consists of, or contains, Class A, Class B, or Class C LLRW, as defined by 10 CFR 61.55, in effect on January 26, 1983. Likewise, the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) states that the Federal Government responsibilities shall include LLRW with concentrations of radionuclides that exceed the Class C limits established in 10 CFR 61.55 in effect on January 26, 1983.
Because the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) relies on 10 CFR part 61 as it existed in 1983, removing the LLRW classification system from 10 CFR part 61 would not change the assignment of responsibilities for the disposal of commercial LLRW to the States and Federal Government. Therefore, the existing LLRW classification system would remain relevant to assigning responsibilities to the States and Federal Government, regardless of its presence in 10 CFR part 61.
Removal of the LLRW classification system from 10 CFR part 61, however, may create confusion among stakeholders about how responsibility is assigned. One possible approach to avoid confusion would be to maintain a version of the LLRW classification system in an appendix to 10 CFR part 61, for the sole purpose of aiding in the determination of Federal and State responsibilities for the disposal of LLRW. Alternatively, the LLRW classification requirements could be included in appendix G to 10 CFR part 20, where LLRW is manifested for shipment. The purpose of appendix G to 10 CFR part 20 is to address the various regulatory information needs for the transfer and disposal of LLRW. These informational needs, which were identified in the Statement of Consideration that accompanies the final rule (60 FR 15664) include, among others, access to information needed for assessments to demonstrate compliance with the performance objectives in 10 CFR part 61. This includes information necessary for the States and Compacts to carry out their responsibilities. Therefore, preserving the LLRW classification requirements in appendix G to 10 CFR part 20 would minimize confusion for shippers to provide accurate information that allows the States and Compacts to carry out their responsibilities.
The NRC is assuming that changes to the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) will not be made to accommodate any revisions to the 10 CFR part 61 regulations. Instead, as previously noted, the NRC has developed a proposal that would implement this option without requiring changes to the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985).
Option 3.
For licensees that choose to develop WAC based on the LLRW classification system in 10 CFR 61.55, this approach would not result in a significant additional burden to their current operating practices since they are currently using acceptance practices with essentially the same type of criteria. Licensees typically develop these site-specific WAC from the existing 10 CFR part 61 requirements and the NRC guidance.
Because the hybrid waste acceptance approach would not alter the LLRW classification requirements in 10 CFR part 61, the approach also would maintain consistency between the LLRW classification requirements in 10 CFR part 61 and the assignment of Federal and State responsibilities in the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985), for the disposal of commercial LLRW. For instance, States may choose to permit the acceptance of LLRW designated as a Federal responsibility (
The NRC also considered whether licensees and license applicants should have the flexibility to consider alternative active institutional control periods to derive site-specific WAC, under both the site-specific waste acceptance and hybrid waste acceptance approaches. To allow this flexibility when developing site-specific WAC, the NRC would need to revise 10 CFR 61.59 to permit licensees or license applicants
During the original development of 10 CFR part 61, in NUREG-0782, “Draft Environmental Impact Statement (EIS) on 10 CFR part 61 `Licensing Requirements for Land Disposal of Radioactive Waste' ” (ADAMS Accession No. ML052590348), the NRC considered a range of time periods for active institutional controls but decided that 100 years is an appropriate period for determining how long the government would be able to ensure custodial care for a near-surface disposal facility. When the public commented that longer times would be appropriate, the NRC determined that, while the longevity of government may reasonably be assumed to extend beyond 100 years, the limit is tied to the possibility of bureaucratic error, which is more difficult to assess. For example, the government could, at some future date, unintentionally permit activities on the site as a result of an incomplete records search. The NRC indicated that it saw no compelling reason to abandon a 100-year institutional control period. Further, the institutional control period is a regulatory component of defense-in-depth by limiting the period of time over which oversight would need to be effective. Federal regulations for disposal of a variety of waste, including municipal and hazardous wastes, allow for a wide range of institutional control periods. International approaches for LLRW disposal vary for the period over which institutional controls are assumed to function, but generally they are limited to 300 years or less. Therefore, allowing unlimited flexibility would appear to be inconsistent with current international practice regarding the longevity of institutional controls.
Since the 100-year time duration is an integral assumption in the analyses that originally derived the radionuclide concentration limits set forth in 10 CFR 61.55, the hybrid waste acceptance approach would also need to maintain the current 100-year limit for licensees or license applicants that continue to use the LLRW classification system. The NRC maintains its earlier assessment and sees no new compelling reason to consider a revision to 10 CFR 61.59. Therefore, the NRC proposes to maintain the 100-year limit set out in 10 CFR 61.59.
In the proposed rule, the NRC is proposing the hybrid waste acceptance approach (Option 3) as the regulatory LLRW acceptance framework for the near-surface disposal of LLRW. The hybrid waste acceptance approach provides a framework for the use of either the generic LLRW classification system specified in 10 CFR 61.55 or the results of the technical analyses required in 10 CFR 61.13. Either approach, when combined with the other revisions recommended for this rulemaking, would provide reasonable assurance that public health and safety would be protected. The hybrid waste acceptance approach would provide a framework for determining LLRW acceptability at a disposal facility while achieving the following:
• Providing flexibility to develop site-specific WAC;
• minimizing revisions to 10 CFR part 61;
• maintaining consistency with the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985);
• limiting additional regulatory burden on licensees and license applicants;
• providing States flexibility to exercise their regulatory authority within a national framework; and
• maintaining consistency with the range of domestic and international practices for the disposal of LLRW.
The implementation of the hybrid waste acceptance approach would require revisions to 10 CFR part 61 that allow land disposal facilities flexibility to establish site-specific WAC based either on the LLRW classification system specified in 10 CFR 61.55 or the results of the analyses required in 10 CFR 61.13 for any land disposal facility. The use of the LLRW classification system would be limited to a near surface disposal facility because the LLRW classification requirements were originally developed as technical requirements for disposal in a near-surface LLRW disposal facility. The revisions would specify the minimum content of the WAC and the proposed 10 CFR 61.52(a)(12) would limit the disposal facility to disposing only LLRW that meet the WAC.
The revisions would also require licensees or license applicants to develop approaches and methods for generators to characterize LLRW, to certify that LLRW meets acceptance criteria in order to demonstrate compliance with the WAC, and to annually review the content and implementation of the LLRW acceptance program. Requiring licensees and license applicants to specify acceptable methods to characterize LLRW, ensures that generators appropriately characterize the LLRW and that the data are sufficient to demonstrate that the disposal facility's WAC are met. Certification requirements ensure an appropriate administrative process developed by the licensees or license applicants is used by generators to demonstrate that the WAC are met, that necessary records are maintained, and that certified LLRW is managed to maintain its certification. Resource burdens associated with administrative and recordkeeping processes used to demonstrate compliance with disposal facility's WAC requirements are further discussed in Section X, “Paperwork Reduction Act Statement,” of this document and the accompanying draft regulatory analysis.
Additionally, implementation of the hybrid waste acceptance approach requires revisions to specific manifesting requirements specified in sections I, II, and III of appendix G to 10 CFR part 20 and the related guidance in NUREG/BR-0204, “Instructions for Completing NRC's Uniform Low-Level Radioactive Waste Manifest” (ADAMS Accession No. ML071870172), that provide information considered important for demonstrating compliance with the performance objectives and for States and Compacts to carry out their responsibilities under the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985). The proposed revisions to appendix G to 10 CFR part 20 ensure that specific manifesting requirements, which were previously linked directly to the LLRW classification requirements, are revised to maintain consistency with the proposed requirements for LLRW acceptance in 10 CFR part 61. The proposed revisions to appendix G to 10 CFR part 20 also ensure that information important for States and Compacts to carry out their responsibilities under the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985) will continue to be reported.
The NRC is proposing additional changes to the 10 CFR part 61 regulations to facilitate implementation and better align the requirements with current health and safety standards. These changes would include: (1) Adding new definitions to 10 CFR 61.2, “Definitions,” and updating concepts in 10 CFR 61.7; (2) implementing changes to appendix G to 10 CFR part 20, to conform to proposed LLRW acceptance requirements; (3) modifying site suitability requirements in 10 CFR 61.50, to be consistent with the proposed analyses framework; and (4) Updating the dose calculation system used in 10 CFR part 61.
Currently, 10 CFR 61.2 defines common terms used in 10 CFR part 61 and 10 CFR 61.7 provides conceptual information for the disposal facility LLRW classification and near-surface disposal, and licensing process for LLRW disposal facilities. These concepts include descriptions of: (a) The parameters for near-surface disposal in engineered facilities and the layout of land and buildings necessary to carry out the disposal; (b) the safety objectives for near-surface LLRW disposal, which emphasize the stability of the wasteforms and disposal sites; and (c) the licensing processes that the licensees or license applicants go through during the preoperational, operational, and site closure periods.
The NRC proposes to add definitions and concepts to 10 CFR 61.2 and 10 CFR 61.7, respectively, to support the site-specific technical analyses and LLRW acceptance requirements. These terms and concepts are needed to provide consistency and facilitate implementation of the proposed 10 CFR part 61 regulations.
The NRC is proposing to add definitions for “compliance period,” “defense-in-depth,” “intruder assessment,” “long-lived waste,” “performance assessment,” “performance period,” “protective assurance period,” and “safety case” to facilitate implementation of the proposed requirements for site-specific analyses. The definitions for the various analyses and time periods are necessary to support the requirements for the performance objectives and technical analyses. Three specific definitions deserve to be discussed in greater detail are “long-lived waste” because the proposed performance period analyses are only necessary for the disposal of long-lived LLRW, “defense-in-depth” because licensees will be required to demonstrate how the disposal facility relies upon multiple independent and redundant layers, and “safety case” because the requirements are central to demonstrating that public health and safety will be adequately protected at present and in the foreseeable future.
The performance period analyses are designed to be completed if a facility will be disposing of long-lived LLRW. The proposed “long-lived waste” definition contains three components. The first component is a radionuclide that does not decay sufficiently over the compliance period. The reason the NRC is expressing this as a percentage of initial activity of a radionuclide that remains after 10,000 years, instead of a half-life value such as 3,000 years as suggested by some members of the public, is to ensure that stakeholders understand that the “long-lived waste” definition is conditional on the analyses framework. If the analysis framework were to be changed in the future or if a different framework was used, for instance, in a different country, a half-life of 3,000 years may or may not be appropriate. The second component is a long-lived radionuclide parent that produces short-lived radionuclide progeny. The second component is designed to ensure that the analysis includes radionuclide progeny, such as those resulting from the uranium decay series. The third component is a short-lived radionuclide parent that results in long-lived radionuclide progeny. Examples would include the curium decay series or the isotope Am-241 which produces Np-237, a long-lived radionuclide that can be fairly mobile in the environment. The inventory of LLRW at the time of disposal can differ considerably from the inventory at future times. The “long-lived waste” definition is designed to take this into account.
The concept of defense-in-depth has been implicitly used in LLRW regulations in the past, but it has not previously been explicitly defined in 10 CFR part 61. Defense-in-depth is implicitly provided through the various regulatory requirements. For instance, while 10 CFR 61.59 imposes land ownership and institutional control requirements that are intended to limit the potential for intrusion into a closed disposal facility, licensees may not take credit for these protections beyond 100 years when assessing whether the performance objectives will be met. The NRC's defense-in-depth approach to risk management ensures that safety is not wholly dependent on any single element of the design, construction, maintenance or operation of a regulated facility. With the potential disposal of DU and other long-lived LLRW in shallow land disposal facilities, defense-in-depth takes on additional importance and it is now being defined and explicitly used in this proposed revision to 10 CFR part 61 to provide assurance that safe disposal can be achieved in light of the significant uncertainties associated with projecting doses far into the future. Defense-in-depth for a land disposal facility includes, but is not limited to, the use of remote siting, consideration of waste forms and radionuclide content, engineered features, and natural geologic features of the disposal site.
Regarding the proposed definition for “safety case,” licensing decisions are based on whether there is reasonable assurance that the performance objectives can be met. The technical analyses are used to demonstrate that the performance objectives can be met. These analyses together with defense-in-depth protections and the supporting evidence and reasoning for the strength and reliability of these analyses and protections form the “safety case” for licensing a LLRW facility. The safety case must make a convincing conclusion that public health and safety will be adequately protected from the disposal of LLRW (including long-lived LLRW). A clear case for the safety of a disposal facility would also enhance communication among stakeholders.
Appendix G to 10 CFR part 20 imposes manifest requirements on shipments of LLRW consigned for disposal. The purpose of the requirements in appendix G to 10 CFR part 20 is to address various regulatory information needs for the transfer of LLRW. These information needs, which were identified in the Statement of Consideration accompanying the current regulations (60 FR 15664), include access to information needed for the analyses to demonstrate compliance with the performance objectives and that the States and Compacts believe is necessary to carry out their responsibilities. In particular, manifests for LLRW shipments must identify the LLRW classification and certify that the LLRW is “. . . properly classified, described, packaged, marked, and labeled . . . .” Therefore, the NRC is proposing changes to these requirements to conform to the proposed addition of the LLRW acceptance requirements in 10 CFR 61.58.
To meet these needs, the requirements in appendix G to 10 CFR part 20 require shippers to properly classify, describe, package, mark, and label LLRW that will be transferred and is intended for disposal. Further, shippers must certify that these actions have been completed in accordance with the applicable requirements, including those in 10 CFR part 61 for LLRW classification (
Specifically, sections I.C.12 and I.D.4 of appendix G to 10 CFR part 20 currently require the shipper of LLRW consigned to a LLRW disposal facility to identify the LLRW classification per 10 CFR 61.55 and to state if it meets the structural stability requirements of 10 CFR 61.56(b) on the uniform manifest. Because the proposed revisions to 10 CFR 61.58 allow a licensee or license applicant to use the classification system to develop site-specific WAC, shipping manifest requirements related to LLRW classification will be retained so that States and Compacts continue to receive information allowing them to carry out their responsibilities as defined by the Low-Level Radioactive Waste Policy Act of 1980 (as amended in 1985).
Information on LLRW acceptability at a disposal facility is essential to demonstrate compliance with the performance objectives. Therefore, the NRC proposes adding a requirement to section II of appendix G to 10 CFR part 20 to specify in the uniform manifest whether the LLRW being shipped to a disposal facility conforms to the facility's WAC. The addition of this requirement would also require a revision of NRC Form 541, “Uniform Low-Level Radioactive Waste Manifest-Container and Waste Description,” to conform to this new requirement and the accompanying guidance NUREG/BR-0204, Revision 2.
Further, the proposed requirements for LLRW acceptance would require revisions to the certification requirements of section II of appendix G to 10 CFR part 20. Section II requires LLRW generators, processors, or collectors to certify that the transported LLRW is properly classified. Since the proposed 10 CFR part 61 requirements would require licensees and license applicants to develop criteria for LLRW acceptability using either the existing LLRW classification system or the results of site-specific analyses, this certification requirement would be updated so that shippers are certifying that LLRW consigned to a disposal facility meets the facility's waste acceptance criteria for LLRW acceptability.
The proposed 10 CFR part 61 requirements for LLRW acceptability would also require revisions to section III of appendix G to 10 CFR part 20. Section III of appendix G to 10 CFR part 20 imposes requirements on the control and tracking of LLRW transferred to a disposal facility. Specifically, current sections III.A.1 through 3 and III.C.3 through 5 require the LLRW to be classified according to 10 CFR 61.55 and meet the LLRW characteristics requirements in 10 CFR 61.56. The container must be labeled with the appropriate LLRW class, and the licensee who transfers the LLRW must implement a quality assurance program to assure compliance with 10 CFR 61.55 and 10 CFR 61.56. Since the proposed 10 CFR part 61 requirements would require licensees or license applicants to develop criteria for LLRW acceptability using either the existing LLRW classification system or the results of site-specific technical analyses, these requirements would be revised so that shippers are preparing, labeling, and providing quality assurance in accordance with the disposal facility operator's criteria for LLRW acceptability.
The site suitability requirements in 10 CFR 61.50 specify the minimum characteristics a disposal site must possess to be acceptable for use as a near-surface disposal facility. The primary factors considered for disposal site suitability are isolation of LLRW—which is dependent on the radiological characteristics of the LLRW—and disposal site features that ensure that the long-term performance objectives of subpart C of this part are met, as opposed to short-term convenience or benefits. The concept of site characteristics is explained in 10 CFR 61.7. Site characteristics should be considered in terms of the indefinite future, take into account the radiological characteristics of the LLRW, and be evaluated for at least a 500-year timeframe. Site characteristics and site suitability requirements play an integral role in ensuring that the site is appropriate for the type of LLRW proposed for disposal. When the site suitability requirements were originally developed, it was envisioned that LLRW would primarily contain short-lived radionuclides with low concentrations of long-lived radionuclides. The NRC developed the LLRW classification framework around this concept. However, the regulation at 10 CFR 61.55(a)(6) allows long-lived LLRW not currently listed in table 1 or 2 of 10 CFR 61.55 to be disposed in the near surface as Class A LLRW.
In the proposed revision, it is recognized that not all LLRW may decay to relatively innocuous levels within 500 years and so a technical analysis would be required to determine if site-specific restriction of disposal of LLRW is necessary. The regulation at 10 CFR 61.50 would be revised to clarify the interpretation of site characteristics. The site suitability characteristics have not been changed, but have been reorganized to distinguish the hydrological site characteristics from other characteristics. The hydrological site characteristics have been separated to clarify that for 500 years the hydrological site characteristics must be met regardless of the results of any technical analyses. Historically, most of the problems encountered in LLRW disposal resulted from water impacting the LLRW disposal system. A site that is unlikely to satisfy the hydrological site characteristics (
Currently, 10 CFR 61.41 requires that concentrations of radioactive material released to the general environment “not result in an annual dose exceeding an equivalent of 0.25 mSv (25 mrem) to the whole body, 0.75 mSv (75 mrem) to the thyroid, and 0.25 mSv (25 mrem) to any other organ of any member of the public.” The objective of modeling in a performance assessment that would be
Currently, 10 CFR part 20 provides for the use of current NRC health physics practices for NRC licensees. In May 1991, the NRC updated 10 CFR part 20 based on a dosimetric modeling and effective dose equivalent approach described in the International Commission on Radiological Protection (ICRP) Publications 26 and 30.
The topic of using updated dosimetry has been raised before. In the matter of the NRC's site-specific regulations for a geologic repository for high-level radioactive waste at Yucca Mountain, for example, the Commission was aware of the potential for future updates to the ICRP's recommendations that might be available following promulgation of its regulations in 10 CFR part 63, “Disposal of High-Level Radioactive Wastes in a Geologic Repository at Yucca Mountain, Nevada.” As a consequence, rather than index the site-specific regulations to a particular version of the ICRP, the Commission alternatively allowed the DOE to use “. . . the most current and appropriate . . .” dosimetry in its performance assessment calculations, without specifying which particular version or edition of that guidance to employ. Any updated radiation and organ or tissue weighting factors, however, would need to have been incorporated by the U.S. Environmental Protection Agency (EPA) into Federal radiation protection guidance. The Commission also stated that, “Additionally, as scientific models and methodologies for estimating doses are updated, the DOE may use the most current and appropriate (
The topic of using updated methodology and terminology was also addressed by the Commission in SRM-SECY-12-0064, “Recommendations for Policy and Technical Direction to Revise Radiation Protection Regulations and Guidance,” dated December 17, 2012 (ADAMS Accession No. ML12352A133). The Commission approved the staff's development of the regulatory basis for a revision to 10 CFR part 20 to align with the most recent methodology and terminology for dose assessment. The Commission further directed that appropriate steps should be undertaken to assure that conforming changes are made as soon as practical to make these methods consistent throughout all NRC regulations.
During the development of the regulatory basis that supports this rulemaking, the majority of the public commenters supported the proposal to allow licensees or license applicants the flexibility to use the latest ICRP dose methodologies in a site-specific performance assessment. However, some people questioned the value and the safety significance in removing critical organ dose limits in updating the dose limits in 10 CFR 61.41.
The benefit of updating the dose limit to an effective dose, whether it is the TEDE or a more current effective dose methodology, is that it provides a holistic and consistent evaluation of the risks of radiation, whether the worker or member of the public is exposed from external radiation, inhalation, ingestion, or some combination of these. Because an effective dose methodology compares, and more importantly, sums the doses from different organs, exposure routes, and radionuclides, an overall risk is evaluated. This was not possible with the critical organ system provided by the ICRP Publication 2. When the ICRP Publication 2 was developed, organ weighting factors were unknown. The doses to different organs, in the critical organ system, do not account for the radiosensitivity of the organ, nor did the system use the wider range of organs and tissues evaluated with modern approaches. A holistic approach provides a large benefit in LLRW disposal dose assessment because of the range of radionuclides that co-mingled within the LLRW. Each radionuclide has its own predominant exposure pathway and dose rate, depending on the manner in which a member of the public may get exposed. Without a holistic method that sums the total exposures across exposure pathways and radionuclides, a risk-informed, performance-based decision is harder to make, as the doses between scenarios or situations would not be comparable especially when one is trying to optimize the resources to provide maximum protection within the disposal system.
The critical organ dose approach was developed to limit doses from the intake of radioactive materials. In the critical organ dose approach, doses to a limited number of individual organ systems were calculated based on models of the movement of elements within the human body. For example, iodine collects mainly in the thyroid, ingested uranium provides doses largely to the bones and kidneys, ingested cesium provides doses to multiple organ systems with total body or liver being the critical organ.
The TEDE approach, recommended in ICRP Publication 26, and subsequently updated by ICRP Publication 60 and ICRP Publication 103, uses a different approach to limiting the risk from radiation. Because more information on the risk associated with dose to specific organs exists, it is possible to calculate the overall increased risk of stochastic effects (
In the TEDE approach, the dose to individual organs also needs to be considered to ensure that deterministic effects do not occur. For this reason, an organ limit of 0.5 Sv (50 rem) is applied in addition to the TEDE dose limit for workers of 50 mSv (5 rem). Because the dose limit in 10 CFR part 20 for a member of the public is 50 times less than the occupational limit, the same concern for deterministic effects in organs does not occur. As noted in appendix B to 10 CFR part 20, “Annual Limits on Intake (ALIs) and Derived Air Concentrations (DACs) of Radionuclides for Occupational Exposure; Effluent Concentrations; Concentrations for Release to Sewerage,” consideration of nonstochastic effects is unnecessary at the dose levels established for members of the public because the organ dose can never reach the organ limit for the nonstochastic effects of 0.5 Sv/year (50 rem/year), without the TEDE dose being greater than the public dose limit (or any fraction of the public dose limit stated in 10 CFR 61.41(a)). Therefore, in modifying a dose limit such as 10 CFR 61.41(a) to be consistent with 10 CFR part 20, organ dose limits are unnecessary. The TEDE approach protects all the organ systems and provides adequate protection to members of the public, from both individual radionuclides, as well as multiple radionuclides through all exposure routes (
The NRC considered the following three options to revise the 10 CFR part 61 regulations to allow the use of more up-to-date ICRP recommendations for dosimetry modeling purposes:
Option 1.
Option 2.
Option 3.
The NRC is proposing to adopt option 3, the edition-neutral approach, for the revision of the 10 CFR part 61 regulations, to allow the use of more up-to-date ICRP recommendations for dosimetry modeling purposes. The NRC favors this approach because it has already approved and implemented this particular type of regulatory approach in its 10 CFR part 63 regulations. As the ICRP's recommendations have historically been updated more frequently than the Commission's LLRW regulations, adopting an edition-neutral approach in the regulations would obviate the need for updating 10 CFR part 61 at some future date in response to some comparable update to Federal radiation protection guidance and the associated ICRP recommendations provided that the guidance and the ICRP recommendation continue to ensure the Agency's approach to adequate protection. Licensees would need to use the dose calculation method required in 10 CFR part 20 (currently based on ICRP Publication 26). Since 10 CFR part 61 would not refer to a specific dose calculation method, the general radiation protection regulations of 10 CFR part 20 would apply.
Licensees are responsible for demonstrating that their land disposal facilties are constructed, operated, and closed safely. To this end, 10 CFR part 61 establishes requirements that licensees must meet to demonstrate that a land disposal facility will be constructed, operated, and closed so as to provide reasonable assurance that public health and safety and the environment will be protected. While the NRC believes that the existing requirements specified in 10 CFR 61.10 through 10 CFR 61.16, together with the performance objectives of subpart C and the technical requirements of subpart D, ensure that a licensee demonstrates the safety of a land disposal facility, the regulations do not explicitly establish requirements for the development of a safety case.
The safety case concept in the context of radioactive waste disposal, which has been developed internationally, is generally regarded as a collection of arguments and evidence to demonstrate the safety and performance of a disposal facility. A safety case for a land disposal facility covers the suitability of the site and the design, construction and operation of the facility, as well as the assessment of radiation risks and assurance of the adequacy and quality of all of the safety related work associated with the disposal facility. The purpose of a safety case is to provide a sufficient level of detail regarding the description of all safety relevant aspects of the site, the design of the facility, and the managerial control measures and regulatory controls to inform the decision whether to grant a license for the disposal of LLRW and provide the public assurance that the facility will be
The NRC believes that the current 10 CFR part 61 implicitly includes components of the safety case concept. For instance, an important component of the international safety case concept is the safety assessment, which consists of the assessment of radiological impacts as well as an analysis of site and engineering aspects and operational safety. Currently, the NRC's regulations at 10 CFR 61.13 require analyses that achieve the intent of a safety assessment.
The safety case, as specified in the proposed requirements, would include the same type of information currently required to be submitted as part of a license application. To explicitly ensure that a robust safety case is made for each disposal facility, the NRC is proposing requirements that licensees prepare a safety case that demonstrates the assessment of the safety of a land disposal facility. In explicitly specifying a requirement for a safety case, the NRC is proposing to require the incorporation of the safety assessment and defense-in-depth components into the safety case.
The revised regulations would incorporate the 10 CFR 61.13 analyses into the licensee's safety case. Further, the proposed regulations also would require new defense-in-depth analyses in 10 CFR 61.13 which would add an explicit assessment of defense-in-depth provisions to the proposed safety case. Finally, the NRC envisions that the safety case for a land disposal facility would evolve over time as new information is gained during the various phases of the facility's development and operation. Therefore, the NRC expects that the safety case will be updated as new information that could significantly impact safety of the facility is learned and is proposing that the application for closure of a licensed land disposal facility must include a final revision to the safety case.
As previously noted, the NRC is making available for public comment a draft guidance document, “Guidance for Conducting Technical Analyses for 10 CFR part 61” (Docket ID NRC-2015-0003), concurrent with this proposed rule. The draft guidance document is intended to supplement existing guidance on performance assessment (
In the SRM to SECY-11-0032, “Consideration of the Cumulative Effects of Regulation in the Rulemaking Process” (ADAMS Accession No. ML112840466), dated October 11, 2011, the Commission provided direction to the staff on issues related to the implementation of the cumulative effects of regulation process enhancements. The concept of cumulative effects of regulation describes the challenges that licensees, or other impacted entities (such as State partners) face while implementing new regulatory positions, programs, and requirements (
(1) In light of any current or projected cumulative effects of regulation challenges, does the proposed rule's effective date provide sufficient time to implement the new proposed requirements, including changes to programs, procedures, and the facility?
(2) If current or projected cumulative effects of regulation challenges exist, what should be done to address this situation (
(3) Do other (NRC or other agency) regulatory actions (
(4) Are there unintended consequences? Does the proposed rule create conditions that would be contrary to the proposed rule's purpose and objectives? If so, what are the consequences and how should they be addressed?
(5) Is the cost and benefit estimate developed in the regulatory analysis sufficient?
The NRC is requesting public comment on the following questions:
• Is the proposed three-tiered approach (a compliance period, followed by a protective assurance period, followed by a performance period, if applicable) appropriate?
• Is 500 mrem/yr an appropriate analytical threshold for the protective assurance period?
• Should there be a quantitative goal or dose limit associated with the performance period analysis, and if so, what should that goal or dose limit be?
• Is Compatibility Category B appropriate for the compliance period, protective assurance period, and the waste acceptance criteria?
When submitting your comments, remember to:
• Identify the rulemaking with the Regulation Identifier Number (RIN 3150-AI92) and NRC Docket ID (NRC-2011-0012).
• Explain why you agree or disagree with the proposed revisions, and suggest alternatives and substitute language to the proposed changes.
• Describe any assumptions and provide any technical information or data that support your comments.
• If you estimate potential costs or burdens, explain how you arrived at your estimate in sufficient detail to allow for it to be reproduced.
• Provide specific examples to illustrate your concerns, and suggest alternatives.
• Explain your views as clearly as possible.
• Make sure to submit your comments by the comment period deadline.
• The NRC is particularly interested in your comments concerning the issues raised in Section Ill, Discussion, of this notice. In addition, the NRC is requesting comment on the information in the following sections of this document: (1) Section VI, Agreement State Compatibility; (2) Section VII, Plain Writing; (3) Section IX, Draft Environmental Assessment and Draft Finding of No Significant Environmental Impact; (4) Section X, Paperwork Reduction Act Statement; (5) Section XI, Regulatory Analysis; and (6) Section XII, Regulatory Flexibility Certification.
Section 20.1003 defines common terms used in 10 CFR part 20. The NRC is proposing to revise the term “waste” to capture waste streams resulting from the production of medical isotopes that have been permanently removed from a reactor or subcritical assembly, for which there is no further use, and the disposal of which can meet the requirements of this part, consistent with the National Defense Authorization Act for Fiscal Year 2013.
Currently, section II of appendix G to 10 CFR part 20, requires LLRW generators, processors, or collectors to certify that the transported LLRW is properly classified. Since 10 CFR 61.58 would require licensees to develop criteria for LLRW acceptability, using either the existing LLRW classification system or the results of site-specific technical analyses, the NRC proposes to revise the requirements in section II so that shippers are certifying that LLRW consigned to a disposal facility meets the facility's criteria for LLRW acceptability. Section II would also be revised to enhance its readability.
Currently, section III of appendix G to 10 CFR part 20 places requirements on the control and tracking of LLRW transferred to a disposal facility. Currently, sections III.A and III.C only require the LLRW to be classified according to 10 CFR 61.55 and meet the LLRW characteristic requirements in 10 CFR 61.56, and does not provide requirements for compliance with the WAC of the proposed 10 CFR 61.58. Since the amended rule would require site-specific technical analyses, and then have LLRW disposal licensees develop criteria for LLRW acceptability using either the existing LLRW classification system or the results of site-specific technical analyses, the NRC proposes to revise the requirements in sections III.A.1, III.A.2, III.A.3, III.C.3, III.C.4, and III.C.5, to ensure that shippers prepare, label, and provide quality assurance in accordance with the disposal facility operator's criteria for LLRW acceptability, if applicable.
Section 61.2 defines common terms used in 10 CFR part 61. The NRC is proposing to make the following revisions: (1) Revise the definitions of “site closure and stabilization” and “stability” to correct misspellings; (2) revise the definition of “inadvertent intruder” to include the phrase “reasonably foreseeable” to limit speculation of the analyses; and (3) revise the term “waste” to capture waste streams resulting from the production of medical isotopes that have been permanently removed from a reactor or subcritical assembly, for which there is no further use, and the disposal of which can meet the requirements of this part, consistent with the National Defense Authorization Act for Fiscal Year 2013. The NRC is also proposing to add definitions for “compliance period,” “defense-in-depth,” “intruder assessment,” “long-lived waste,” “performance assessment,” “performance period,” “protective assurance period,” and “safety case” to facilitate implementation of the proposed requirements for site-specific analyses. For more information on “compliance period,” “defense-in-depth,” “intruder assessment,” “long-lived waste,” “performance assessment,” “protective assurance analysis,” “protective assurance period,” and “safety case,” see Section III, Discussion, of this document.
Currently, 10 CFR 61.7 provides conceptual information for the licensing of a disposal facility, the LLRW classification system, and near-surface disposal. Paragraph 61.7(a) describes the parameters for near-surface LLRW disposal in engineered facilities and the layout of land and buildings necessary to carry out the disposal. Paragraph 61.7(b) describes the safety objectives for near-surface LLRW disposal and emphasizes the stability of the wasteforms and disposal sites. Paragraph 61.7(c) describes the licensing processes that the applicant and licensee must complete during the preoperational, operational, and site closure periods.
The NRC proposes to revise 10 CFR 61.7(a)(1) and 10 CFR 61.7(a)(2) to enhance readability. An additional sentence would be added to clarify that the additional technical criteria may be developed on a case-by-case basis for land disposal techniques that are not explicitly considered in 10 CFR part 61.
The NRC proposes to redesignate paragraphs (b)(1), (b)(2) through (b)(5), and (c) as paragraphs (b), (f), and (g), respectively. The NRC proposes to revise redesignated paragraphs (b), (f), and (g) to enhance the readability of these paragraphs. Additionally, paragraph (b) would be revised to describe the performance objectives of the 10 CFR part 61 regulations. Paragraph (f)(1) would be revised to clarify that for long-lived waste and certain radionuclides prone to migration, a maximum disposal site inventory based on the characteristics of the disposal site may be established to limit potential exposure and to mitigate the uncertainties associated with long-term stability of the disposal site. Some waste, depending on its radiological characteristics, may not be suitable for disposal if uncertainties cannot be adequately addressed with technical analyses. Paragraph (f)(2) would be revised to clarify that the effective life of these intruder barriers should be at least 500 years and an additional sentence would be added to clarify that the disposal of LLRW above the Class C limit will be evaluated on a case-by-case basis with the technical analyses required in 10 CFR 61.13. Paragraph (f)(3) would be revised to clarify that waste that will not decay to levels which present an acceptable hazard to an intruder within 100 years is typically designated as Class C waste. Also paragraph (f) would provide conceptual
The NRC proposes to add new paragraphs (b), (c), (d), and (e) to 10 CFR 61.7. Proposed 10 CFR 61.7(c) would provide conceptual information for demonstrating compliance with the performance objectives of the technical analyses, which include a performance assessment and an intruder assessment, and performance period analyses for waste containing significant concentrations and quantities of long-lived radionuclides. Additionally, proposed paragraph (c)(5) would provide conceptual information on the requirement for the use of dose methodology that is consistent with those set forth in 10 CFR part 20 and would also describe the flexibility of the licensees' ability to consistently use the latest dose methodology to demonstrate compliance with the performance objectives.
Proposed 10 CFR 61.7(d) would provide conceptual information on the role of defense-in-depth protections with respect to LLRW disposal. Proposed 10 CFR 61.7(e) would provide conceptual information for demonstrating compliance with the performance objectives through a determination of criteria for the acceptance of LLRW.
Currently, 10 CFR 61.8 (b) lists sections that contain the approved information collection requirements in 10 CFR part 61.
The NRC proposes to revise 10 CFR 61.8(b) to include 10 CFR 61.41 and 61.42.
Currently, 10 CFR 61.10 identifies the contents that an application for a land disposal facility must contain. This information includes the general information, specific technical information, institutional information, and financial information set forth in 10 CFR 61.11 through 61.16 and an environmental report.
The NRC is proposing to divide this section into two paragraphs, assigned as paragraphs (a) and (b). Paragraph (a) would retain the current rule language. Paragraph (b) would be added to convey that the information provided in an application comprises the safety case, supports the licensee's demonstration that the disposal facility will be constructed and operated safely, and provides reasonable assurance that the disposal site will be capable of meeting the performance objectives.
Currently, 10 CFR 61.12 lists specific technical information that must be included in an application for a 10 CFR part 61 disposal facility license. This information is needed to demonstrate that the performance objectives of 10 CFR part 61, subpart C, and the applicable technical requirements of 10 CFR part 61, subpart D, “Technical requirements for land disposal facilities,” would be met. The specific technical information includes a description of natural and demographic disposal site characteristics as determined by disposal site selection and characterization activities.
The NRC proposes to revise the introductory text of this section to enhance its readability and identify that the specific technical information supports the safety case. The NRC also proposes to revise 10 CFR 61.12(a) to include geochemistry and geomorphology in the description of the natural and demographic disposal site characteristics. Geochemical and geomorphological characteristics need to be included in the description because they play a role in the transportation of long-lived radionuclides and the long-term erosion of the disposal site, respectively. Paragraphs 61.12(e) and (g) would be revised to enhance the readability of these sections. Proposed 10 CFR 61.12(i) would require applicants to include the criteria for acceptance of LLRW for disposal, and 10 CFR 61.12(j) would require applicants to include the development of technical analyses to the description of the quality assurance program.
Currently, 10 CFR 61.13 lists technical information that must be included in an application for a 10 CFR part 61 disposal facility license to demonstrate that the performance objectives of subpart C of 10 CFR part 61 would be met.
Currently, 10 CFR 61.13 does not specify the safety case and does not indicate how existing licensees would be captured in the requirements to conduct the 10 CFR 61.13 site-specific technical analyses. The NRC proposes to revise the introductory text of 10 CFR 61.13 to specify the requirements for technical analyses as one element of the safety case and to clarify that licensees must conduct the analyses set forth in 10 CFR 61.13 to demonstrate that the performance objectives of subpart C will be met. Licensees with licenses for land disposal facilities in effect on the effective date of this subpart must submit these analyses at the next license renewal or within 5 years of the effective date of this subpart, whichever comes first.
Currently, 10 CFR 61.13(a) does not require considerations of features, events, and processes that can influence the ability of the LLRW disposal facility to limit the releases of radioactivity to the environment; these features, events, and processes are important elements of a performance assessment. The NRC proposes to revise 10 CFR 61.13(a) to require a licensee or applicant prepare a performance assessment to demonstrate compliance with the proposed dose limit in 10 CFR 61.41(a) during the compliance period and a dose goal in 10 CFR 61.41(b) during the protective assurance period. The performance assessment would be required to consider features, events, and processes which can influence the ability of the disposal facility to meet the performance objectives, evaluate environmental pathways, account for uncertainty, consider alternative conceptual models, and identify and differentiate the roles performed by site characteristics and design features of the disposal facility. Further, the proposed revisions to 10 CFR 61.13(a) would require that the performance assessment used to demonstrate compliance with a new 10 CFR 61.41(b) during the protective assurance period reflect new features, events, and processes different from those in the compliance period only if scientific information compelling such changes is available.
In addition, the NRC proposes a new subparagraph 10 CFR 61.13(a)(4) to further clarify that the performance assessment must reflect new features, events, and processes different from the compliance period that address significant uncertainties inherent in the long timeframes associated with demonstrating compliance with § 61.41(b) only if scientific information compelling such changes is available.
Currently, 10 CFR 61.13(b) requires an applicant to prepare analyses that demonstrate there is reasonable assurance an applicant will meet the LLRW classification and segregation requirements and that it will provide adequate barriers to inadvertent intrusion. The NRC proposes to revise 10 CFR 61.13(b) to require a site-specific intruder assessment to demonstrate the protection of inadvertent intruders. The
Currently, 10 CFR 61.13(d) requires an applicant to prepare analyses that demonstrate long-term stability of the site and the need for ongoing active maintenance after closure. However, the analyses are not currently required to provide reasonable assurance that long-term stability of the disposal site can be ensured. The NRC is proposing to require that the analyses also provide reasonable assurance that long-term stability of the disposal site can be ensured.
The NRC proposes to add a new paragraph (e) to 10 CFR 61.13 to require licensees and applicants to prepare performance period analyses that assess how the disposal facility and site characteristics limit the potential long-term radiological impacts, consistent with available data and current scientific understanding. The analyses would be required for LLRW disposal facilities with long-lived LLRW that contains radionuclides with average concentrations exceeding the values listed in proposed table A of 10 CFR 61.13(e), or if necessitated by site-specific conditions. The analyses would identify and describe the features of the design and site characteristics that will demonstrate that the performance objectives set forth in 10 CFR 61.41(b) and 10 CFR 61.42(b) will be met. The NRC also proposes to include table A in this paragraph to facilitate the implementation of this requirement.
Finally, the NRC proposes to add a new paragraph (f) to 10 CFR 61.13 to require licensees and applicants to prepare analyses that demonstrate the land disposal facility includes defense-in-depth protections. The analyses would identify and describe the features of the design and site characteristics that provide multiple independent and redundant layers of defense so that no single layer, no matter how robust, is exclusively relied upon during operations of the facility and after closure during the compliance period, protective assurance period, or performance period.
Currently, 10 CFR 61.23 lists standards that must be met for the Commission to issue a license for receipt, possession, and disposal of LLRW containing or contaminated with source, special nuclear, or byproduct material.
The NRC proposes to revise 10 CFR 61.23(b), (c), (d), and (e) to include the proposed WAC in the list of standards for issuance of a license. In addition, the NRC proposes to add a new paragraph (m) to 10 CFR 61.23 that adds a safety case as one of the standards for issuance of a license.
Currently, 10 CFR 61.25 provides restrictions on the licensee to make changes in the LLRW disposal facility procedures described in the license application.
The NRC proposes to revise 10 CFR 61.25(a) to correct a misspelling, and 10 CFR 61.25(b) to include a provision restricting changes to the WAC.
Currently, 10 CFR 61.28 lists items that must be included in an application for closure. These items include (1) a requirement for a final revision and specific details of the disposal site closure plan, and (2) an environmental (or a supplemental) report.
Proposed revisions to 10 CFR 61.28(a) would add a requirement to submit a final revision to the safety case, which would be required in the proposed revisions in 10 CFR 61.10, and require licensees to provide updated site-specific technical analyses, which would be required in the proposed revisions in 10 CFR 61.13, using the details of the final closure plan and LLRW inventory as would be required in the proposed revisions in 10 CFR 61.13. Under current 10 CFR 61.28(c), which is not being amended by this rulemaking, the NRC can only authorize closure of the LLRW disposal facility if there is reasonable assurance that the long-term performance objectives of subpart C will be met. As a result of the proposed revision to 10 CFR 61.28(a), licensees may be required to take additional action prior to closure to ensure that the LLRW that has already been disposed, including large quantities of depleted uranium and other LLRW streams that were not analyzed in the original 10 CFR part 61 regulatory basis, will meet the long-term performance objectives of subpart C.
Currently, 10 CFR 61.41 specifies a dose limit (organ and whole body equivalent) for protection of the general population from the releases of radioactivity and requires licensees to exercise reasonable effort to keep all doses ALARA.
The NRC proposes to revise 10 CFR 61.41 by adding paragraphs (a), (b), and (c). Proposed 10 CFR 61.41(a) would retain the dose limits and the ALARA concept during the compliance period, and would be updated to use a dose methodology that is consistent with the dose methodology used in 10 CFR part 20. Compliance with the proposed 10 CFR 61.41(a) would be demonstrated through analyses that meet the requirements specified in the proposed 10 CFR 61.13(a).
Proposed 10 CFR 61.41(b) would require that the licensee minimize releases of radioactivity from a disposal facility to the general environment during the protective assurance period. Proposed 10 CFR 61.41(b) would specify that an annual dose, established on the license, shall be below 5 milliSieverts (500 millirems) or a level that is supported as reasonably achievable based on technological and economic considerations in the information submitted for review and approval by the Commission. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in 10 CFR 61.13(a).
Proposed 10 CFR 61.41(c) would require that the licensee make an effort to minimize releases of radioactivity from a disposal facility to the general environment to the extent reasonably achievable at any time during the performance period. Compliance with the proposed 10 CFR 61.41(c) would be demonstrated through analyses that meet the requirements specified in the proposed 10 CFR 61.13(e).
Currently, 10 CFR 61.42 requires the facility to be designed, operated, and closed to ensure the protection of any inadvertent intruder after the lifting of institutional controls.
The NRC proposes to revise 10 CFR 61.42 by adding new paragraphs (a), (b), and (c). Proposed 10 CFR 61.42(a) would retain the current regulatory language and would be updated to add an annual dose limit of 5 mSv/yr (500 mrem/yr) for the intruder assessment during the compliance period.
Proposed 10 CFR 61.42(b) would require that the licensee minimize exposures to any inadvertent intruder during the protective assurance period. Proposed 10 CFR 61.42(b) would also specify that an annual dose, established on the license, shall be below 5 milliSieverts (500 millirems) or a level that is supported as reasonably achievable based on technological and economic considerations in the information submitted for review and approval by the Commission. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in 10 CFR 61.13(b).
Proposed 10 CFR 61.42(c) would require that the licensee make an effort to minimize exposures to any inadvertent intruder to the extent reasonably achievable at any time during the performance period. Compliance with the proposed 10 CFR 61.42(c) would be demonstrated through analyses that meet the requirements specified in the proposed 10 CFR 61.13(e).
Currently, 10 CFR 61.44 requires the disposal facility to be sited, designed, used, operated, and closed to achieve long-term stability of the disposal site and to eliminate to the extent practicable the need for ongoing active maintenance of the disposal site following closure so that only surveillance, monitoring, or minor custodial care are required.
The NRC proposes to revise 10 CFR 61.44 to specify that stability of the disposal site must be demonstrated for the compliance and protective assurance periods.
Currently, 10 CFR 61.50 specifies site suitability requirements for the minimum characteristics a disposal site must possess to be acceptable for use as a near-surface LLRW disposal facility. Site suitability requirements play an integral role in ensuring that the site is appropriate for the type of LLRW proposed for disposal.
The NRC proposes to revise 10 CFR 61.50 to clarify the interpretation of site characteristics. The technical content of the site suitability characteristics would not be changed. However, the site suitability characteristics would be reorganized to distinguish the hydrological site characteristics from other characteristics.
Currently, 10 CFR 61.51 specifies disposal design requirements for a near-surface LLRW disposal facility. Site design requirements play an integral role in ensuring that the site is appropriate for the type of LLRW proposed for disposal.
The NRC proposes to revise 10 CFR 61.51(a)(1) to clarify that site design features must be directed toward providing defense-in-depth protections in addition to long-term isolation and avoidance of continuing active maintenance after site closure.
Currently, 10 CFR 61.52 imposes requirements to ensure the integrity of the LLRW, the proper marking of the disposal unit boundary, and the proper maintenance of the buffer zone.
The NRC proposes to revise 10 CFR 61.52(a)(3) and (a)(8) to enhance its readability and to conform to the proposed new requirements in 10 CFR 61.52(a)(12) and (a)(13).
The NRC proposes to add new paragraphs (a)(12) and (a)(13). Proposed 10 CFR 61.52(a)(12) would only allow the disposal of LLRW meeting the disposal facility's LLRW acceptance criteria, and proposed 10 CFR 61.52(a)(13) would require licensees to prepare updated site-specific analyses using the details of the final closure plan and LLRW inventory.
The NRC proposes to revise 10 CFR 61.55(a)(6) to enhance its readability. The change would not alter the meaning or intent of this regulation.
Currently, 10 CFR 61.56(a) lists minimum requirements for all classes of LLRW, intended to facilitate handling at the disposal site and provide protection of health and safety of personnel at the disposal site.
The NRC proposes to revise 10 CFR 61.56(a) to replace the phrase “all classes of wastes” with the phrase “all waste” which includes all classes of LLRW and WAC.
Currently, 10 CFR 61.57 requires the listing of LLRW class in accordance with 10 CFR 61.55 and does not reference the proposed WAC.
The NRC proposes to revise 10 CFR 61.57 to include any information required by the land disposal facility's criteria for LLRW acceptance developed according to 10 CFR 61.58.
Currently, 10 CFR 61.58 grants exemptions for the classification and characterization of LLRW, on a case-by-case basis, if the Commission finds reasonable assurance of compliance with the performance objectives. In the proposed rule, the alternative requirements in 10 CFR 61.58 would be replaced by the proposed LLRW acceptance requirements.
The NRC proposes to retitle and revise 10 CFR 61.58 to specify the minimum content of the WAC and require disposal facility licensees to develop approaches for generators to characterize LLRW and methods for generators to certify that such LLRW meets the acceptance criteria for demonstration compliance with the site-specific WAC. Proposed 10 CFR 61.58 would also require licensees to annually review their LLRW acceptance plan and to comply with 10 CFR 61.20 when modifying their approved WAC. Additionally, the new regulatory language would indicate that the NRC would incorporate, where consistent with State and Federal law, the WAC into existing licenses.
Currently, 10 CFR 61.80 requires the licensee to keep records on the LLRW received for disposal, to provide annual reports of site and financial activities, and to comply with specified provisions of 10 CFR parts 30, 40, and 70 for any transfer by the licensee of byproduct, source, or special nuclear material.
The NRC proposes to restructure 10 CFR 61.80(i)(2) to meet codification requirements of the Office of the Federal Register. In 10 CFR 61.80(i)(1), the erroneous reference to 10 CFR 60.4 would be corrected to reference 10 CFR 61.4.
The NRC also proposes to add a new paragraph (m) to 10 CFR 61.80. This addition would require licensees and license applicants to maintain their provisions for LLRW acceptance and audits and other reviews of program content and implementation.
For the purpose of Section 223 of the AEA, the NRC is proposing to amend 10 CFR part 61 under one or more of Sections 161b., 161i., or 161o. of the AEA. Willful violations of the rule would be subject to criminal enforcement.
Under the “Policy Statement on Adequacy and Compatibility of Agreement State Programs” approved by the Commission on June 30, 1997, and published in the
The NRC program elements (including regulations) are placed into four compatibility categories (see the proposed compatibility table in this section). In addition, the NRC program elements can be identified as having particular health and safety significance or as being reserved solely to the NRC. Compatibility Category A applies to those program elements that are basic radiation protection standards and scientific terms and definitions that are necessary to understand radiation protection concepts. An Agreement State should adopt Compatibility Category A program elements in an essentially identical manner to provide uniformity in the regulation of agreement material on a nationwide basis. Compatibility Category B includes those program elements that apply to activities that have direct and significant effects in multiple jurisdictions. An Agreement State should adopt Compatibility Category B program elements in an essentially identical manner. Compatibility Category C includes those program elements that do not meet the criteria of Compatibility Categories A or B, but reflect essential objectives that an Agreement State should adopt to avoid conflict, duplication, gaps, or other conditions that would jeopardize an orderly pattern in the regulation of agreement material on a nationwide basis. An Agreement State should adopt the essential objectives of the Compatibility Category C program elements. Compatibility Category D applies to those program elements that do not meet any of the criteria of Compatibility Categories A, B, or C and, therefore, do not need to be adopted by Agreement States for compatibility.
Health and Safety (H&S) program elements are elements that are not required for compatibility, but are identified as having a particular health and safety role (
Proposed definition “compliance period” in 10 CFR 61.2 would be assigned to Compatibility Category B. The NRC believes the program elements of this definition need to be adopted to ensure a consistent regulatory approach across the Nation and inconsistent definitions of this term would have direct and significant transboundary implications. Proposed definition “defense-in-depth” in 10 CFR 61.2 would be assigned to Compatibility Category H&S. The NRC believes the essential objectives of this definition need to be adopted to ensure consistent application of 10 CFR 61.41 and 10 CFR 61.42. Proposed definition of “intruder assessment” in 10 CFR 61.2 would be assigned to Compatibility Category H&S. The NRC believes that the H&S compatibility designation of this definition is appropriate to support paragraphs 61.13(a) and 61.13(b). Proposed definition of “long-lived waste” in 10 CFR 61.2 would be assigned to Compatibility Category B because inconsistent definitions of this term could have direct and significant effects in multiple jurisdictions. Proposed definition “performance period” in 10 CFR 61.2 would be assigned to Compatibility Category C. The NRC believes the essential objectives of this definition need to be adopted to ensure consistent application of 10 CFR 61.41 and 10 CFR 61.42. Proposed definition of “performance assessment” in 10 CFR 61.2 would be assigned to Compatibility Category H&S. The NRC believes that the H&S compatibility designation of this definition is appropriate to support paragraphs 61.13(a) and 61.13(b). Proposed definition “protective assurance period” in 10 CFR 61.2 would be assigned to Compatibility Category B. The NRC believes the program elements of this definition need to be adopted to ensure a consistent regulatory approach across the Nation and inconsistent definitions of this term would have direct and significant transboundary implications. Proposed definition “safety case” in 10 CFR 61.2 would be assigned to Compatibility Category H&S. The NRC believes the essential objectives of this definition need to be adopted to ensure consistent application of 10 CFR 61.40. The compatibility category of other amended definitions in 10 CFR 61.2 would remain unchanged.
Paragraphs 61.7(c)(1), (c)(2), (c)(4), (c)(5), (c)(6)(d), (e), and (f)(4) would be assigned to Compatibility Category H&S to be consistent with the designation of the rest of 10 CFR 61.7. The compatibility category of other amended paragraphs in 10 CFR 61.7 would remain unchanged.
The NRC is proposing to retain the existing Compatibility Category D for paragraph 61.10(a) because this paragraph provides a list of contents of an application that would not be applicable for all Agreement States (
Section 61.12 in its entirety would be reassigned from Compatibility Category D to Compatibility Category H&S. The NRC believes that all the requirements in 10 CFR 61.12 should be designated as Compatibility Category H&S to support the demonstration of the subpart C performance objectives. The NRC believes that the absence of these provisions could create a situation that could result in individual exposures that exceed the basic radiation protection standards of the subpart C performance objectives.
Section 61.13, in its entirety, would be reassigned from Compatibility Category H&S to Compatibility Category C. The NRC believes the essential objectives of this section need to be adopted to ensure consistent application of 10 CFR 61.40.
Proposed paragraph 61.23(m) would be assigned to Compatibility Category H&S. The compatibility category of other amended paragraphs in 10 CFR 61.23 would remain unchanged.
Section 61.28 in its entirety would also be reassigned from Compatibility Category D to Compatibility Category H&S. The NRC believes that all the information in this paragraph has to be included in the application for closure. The NRC believes that the presence of
The NRC is proposing to retain the existing Compatibility Category A for paragraph 61.41(a) because this paragraph provides a basic radiation protection standard. Paragraph 61.41(b) would be assigned to Compatibility Category B. The NRC believes the program elements of this paragraph need to be adopted to ensure a consistent regulatory approach across the Nation and inconsistent application of this paragraph would have direct and significant transboundary implications. Paragraph 61.41(c) would be assigned to Compatibility Category C because the NRC believes that the Agreement States need to adopt the essential objectives of this paragraph.
Similarly, the NRC is proposing to designate paragraph 61.42(a) as Compatibility Category A (instead of Compatibility Category H&S, which is the current compatibility level for 10 CFR 61.42) because of the prescribed annual dose limit of 5 mSv (500 mrem) for the protection of an inadvertent intruder. Paragraph 61.42(b) would be assigned to Compatibility Category B. The NRC believes the program elements of this paragraph need to be adopted to ensure a consistent regulatory approach across the Nation and inconsistent application of this paragraph would have direct and significant transboundary implications. Paragraph 61.42(c) would be assigned to Compatibility Category C because the NRC also believes that the essential objectives of this paragraph need to be adopted by the Agreement States.
Paragraphs 61.52(a)(12) and (a)(13) would be assigned to Compatibility Category H&S. The compatibility categories of 10 CFR 61.52(a)(3) and (a)(8) would remain unchanged.
At present, only one of the four Agreement States that has an operating near-surface LLRW disposal facility has adopted a corresponding regulation to 10 CFR 61.58. Currently, Agreement States are not required to adopt 10 CFR 61.58, therefore, the compatibility designation for this section must be changed in order to require Agreement States to adopt an alternative provision for LLRW classification and characteristics. Therefore, the NRC is retitling, revising and reclassifying the compatibility for 10 CFR 61.58. Section 61.58 would be assigned to Compatibility Category B because the NRC believes the program elements of this section need to be adopted to ensure a consistent regulatory approach across the Nation and inconsistent application of this section would have direct and significant transboundary implications.
Paragraph 61.80(m) would be assigned to Compatibility Category C. The compatibility category of 10 CFR 61.80(i)(1) and (i)(2) would remain unchanged.
The compatibility categories of the remaining sections (10 CFR 20.1003; appendix G to 10 CFR part 20, sections II and III; and 10 CFR 61.8, 61.25, 61.44, 61.50, 61.51, 61.55, 61.56, and 61.57) would remain unchanged.
The NRC invites comment on the compatibility category designations in this proposed rule and suggests that commenters refer to the Handbook for NRC Management Directive 5.9 for more information. Comments on the proposed compatibility categories need to be received by the end of the public comment period.
The following table lists the parts and sections that would be revised and their corresponding categorization under the “Policy Statement on Adequacy and Compatibility of Agreement State Programs.”
The Plain Writing Act of 2010 (Pub. L. 111-274) requires Federal agencies to write documents in a clear, concise, and well-organized manner. The NRC has written this document to be consistent with the Plain Writing Act as well as the Presidential Memorandum, “Plain Language in Government Writing,” published June 10, 1998 (63 FR 31883). The NRC requests comment on the proposed rule with respect to the clarity and effectiveness of the language used.
The National Technology Transfer and Advancement Act of 1995 (Pub. L. 104-113) requires that Federal agencies use technical standards that are developed or adopted by voluntary consensus standards bodies unless the use of such a standard is inconsistent with applicable law or otherwise impractical. In this proposed rule, the NRC is proposing to amend its regulations that govern LLRW disposal facilities to require new and revised site-specific technical analyses and to permit the development of criteria for LLRW acceptance based on the results of these analyses. These amendments would ensure that LLRW streams that are significantly different from those considered in the regulatory basis for the current regulations can be disposed of safely and meet the performance objectives for land disposal of LLRW. These amendments would also increase the use of site-specific information to ensure public health and safety is protected. Additionally, the NRC is also proposing amendments to facilitate implementation and better align the requirements with current health and safety standards. The NRC is not aware of any voluntary consensus standards that address the proposed subject matter of this proposed rule. The NRC will consider using a voluntary consensus standard if an appropriate standard is identified. If a voluntary consensus standard is identified for consideration, the submittal should explain why the standard should be used.
The proposed action is to add new, and amend some of the existing, requirements in 10 CFR part 61. The NRC is proposing to amend its regulations that apply to LLRW disposal facilities to require new and revised site-specific technical analyses, to permit the development of criteria for LLRW acceptance based on the results of these analyses, and to require the application for closure to include updates to the safety case and the technical analyses. These amendments would ensure that LLRW streams that are significantly different from those considered in the regulatory basis for the current regulations can be disposed of safely and meet the performance objectives for land disposal of LLRW. These amendments would also increase the use of site-specific information to ensure public health and safety is protected. These amendments would revise the existing technical analysis for protection of the general population (
The proposed action is to add new, and amend some of the existing, requirements in 10 CFR part 61. The proposed rulemaking would modify the analyses that licensees need to perform
As an alternative to the proposed action, the NRC staff considered the “no-action” alternative. Under this alternative, the NRC would not modify 10 CFR part 61, no performance period analyses would be required, no period of compliance and no protective assurance period would be specified, no intruder assessment would be required, and development of waste acceptance plan would not be required. However, requiring new and revised site-specific technical analyses to demonstrate compliance with the subpart C performance objectives and development of LLRW site-specific acceptance criteria for LLRW acceptance would ensure the safe disposal of waste streams not previously analyzed in the development of part 61 and would provide assurance that these waste streams comply with the subpart C performance objectives. Further, these analyses would identify any additional measures that would be prudent to implement, and these amendments would improve the efficiency of the regulations by making changes to facilitate implementation and better align the requirements with current health and safety standards. Not taking the proposed action would not provide the added assurance that disposal of the LLRW streams not considered in the original 10 CFR part 61 regulatory basis comply with the subpart C performance objectives. Therefore, the NRC has decided to reject the no-action alternative and publish the proposed rule for public comment.
This action would not result in any irreversible commitments of resources.
The NRC sent a copy of this proposed rule containing this draft environmental assessment and the proposed rule to all State Liaison Officers and requested their comments on the assessment. Aside from those sources referenced in this notice, the NRC staff did not use any additional sources and did not contact any additional persons or agencies to develop this environmental assessment.
The Commission has preliminarily determined under the National Environmental Policy Act and the Commission's regulations in subpart A, “National Environmental Policy Act—Regulations Implementing Section 102(2),” of 10 CFR part 51, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” that the proposed amendments to 10 CFR part 61 described in this document would not be a major Federal action significantly affecting the quality of the human environment, and therefore, an environmental impact statement would not be required. The amendments would require LLRW disposal facility licensees and license applicants to conduct new and updated site-specific technical analyses and safety case to demonstrate compliance with the performance objectives in 10 CFR part 61 and develop criteria for LLRW acceptance based on the results of these analyses, which would ensure the safe disposal of LLRW. The amendments would also make additional changes to the regulations to facilitate implementation and better align the requirements with current health and safety standards. The amendments would be primarily procedural and administrative in nature and would have no significant impact on the quality of the human environment.
The preliminary determination of this draft environmental assessment is that there would be no significant impact to the quality of the human environment from this proposed action. The NRC is, however, seeking public comment on this draft environmental assessment and draft finding of no significant impact. Comments on the draft environmental assessment and draft finding of no significant impact may be submitted to the NRC by any of the methods provided in the
This proposed rule contains new or amended collections of information subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq). This proposed rule has been submitted to the Office of Management and Budget (OMB) for review and approval of the information collections.
The NRC Forms 540 and 541 would be updated to allow licensees to indicate the use of LLRW acceptance criteria.
The U.S. Nuclear Regulatory Commission is seeking public comment on the potential impact of the information collections contained in this proposed rule and on the following issues:
1. Is the proposed information collection necessary for the proper performance of the functions of the NRC, including whether the information will have practical utility?
2. Is the estimate of the burden of the proposed information collection accurate?
3. Is there a way to enhance the quality, utility, and clarity of the information to be collected?
4. How can the burden of the proposed information collection on respondents be minimized, including the use of automated collection techniques or other forms of information technology?
A copy of the OMB clearance package and proposed rule is available in ADAMS under Accession No. ML14289A143 or may be viewed free of charge at the NRC's PDR, One White Flint North, 11555 Rockville Pike, Room O-1 F21, Rockville, Maryland, 20852. You may obtain information and comment submissions related to the OMB clearance package by searching on
You may submit comments on any aspect of these proposed information collections, including suggestions for reducing the burden and on the previously stated issues, by the following methods:
•
•
Submit comments by May 26, 2015. Comments received after this date will be considered if it is practical to do so, but the NRC staff is able to ensure consideration only for comments received on or before this date.
The NRC may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the document requesting or requiring the collection displays a currently valid OMB control number.
The Commission has prepared a draft regulatory analysis on this proposed regulation, and it is available in ADAMS under Accession No. ML14289A158. The draft regulatory analysis examines the costs and benefits of the alternatives considered by the Commission.
The Commission requests public comment on the draft regulatory analysis. Comments on the draft analysis may be submitted to the NRC by any of the methods provided in the
In accordance with the Regulatory Flexibility Act of 1980 (5 U.S.C. 605(b)), the Commission certifies that this rule would not, if adopted, have a significant economic impact on a substantial number of small entities. The LLRW licensees and license applicants impacted by this rule do not fall within the scope of the definition of “small entities” given in the Regulatory Flexibility Act or the standards established by the NRC in 10 CFR 2.810, “NRC size standard.”
The NRC is seeking public comment on the potential impact of the proposed rule on small entities. The NRC particularly desires comments from licensees who qualify as small businesses, specifically as to how the proposed rule would affect them and how the rule may be tiered or otherwise modified to impose less stringent requirements on small entities while still adequately protecting the public health and safety and common defense and security. Comments on how the rule could be modified to take into account the differing needs of small entities should specifically discuss:
(a) The size of the business and how the proposed rule would result in a significant economic burden upon it as compared to a larger organization in the same business community;
(b) How the proposed rule could be modified to take into account the business's differing needs or capabilities;
(c) The benefits that would accrue, or the detriments that would be avoided, if the NRC adopts the commenter's suggestion;
(d) How the proposed rule, as modified, would more closely equalize the impact of NRC regulations as opposed to providing special advantages to any individuals or groups; and
(e) How the proposed rule, as modified, would still adequately protect the public health and safety and common defense and security.
Comments should be submitted by any of the methods provided in the
A backfit analysis is not required for this rule. The NRC's backfit provisions appear in the regulations at 10 CFR 50.109, 52.39, 52.63, 52.83, 52.98, 52.145, 52.171, 70.76, 72.62, and 76.76. The requirements in this proposed rule do not involve any provisions that would impose backfits on nuclear power plant licensees as defined in 10 CFR part 50, “Domestic Licensing of Production and Utilization Facilities,” or in 10 CFR part 52, “Licenses, Certifications, and Approvals for Nuclear Power Plants,” or on licensees under 10 CFR part 70, “Domestic Licensing of Special Nuclear Material,” 10 CFR part 72, “Licensing Requirements for the Independent Storage of Spent Nuclear Fuel and High-Level Radioactive Waste, and Reactor-Related Greater Than Class C Waste,” and 10 CFR part 76, “Certification of Gaseous Diffusion Plants.”
Byproduct material, Criminal penalties, Licensed material, Nuclear materials, Nuclear power plants and reactors, Occupational safety and health, Packaging and containers, Radiation protection, Reporting and recordkeeping requirements, Source material, Special nuclear material, Waste treatment and disposal.
Criminal penalties, Low-level waste, Nuclear materials, Reporting and recordkeeping requirements, Waste treatment and disposal.
For the reasons set out in the preamble and under the authority of the Atomic Energy Act of 1954, as amended; the Energy Reorganization Act of 1974, as amended; and 5 U.S.C. 552 and 553, the NRC is proposing to adopt the following amendments to 10 CFR parts 20 and 61.
Atomic Energy Act secs. 53, 63, 65, 81, 103, 104, 161, 182, 186, 223, 234 1701 (42 U.S.C. 2073, 2093, 2095, 2111, 2133, 2134, 2201, 2232, 2236, 2273, 2282, 2297f), Energy Reorganization Act secs. 201, 202, 206 (42 U.S.C. 5841, 5842, 5846); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005 sec. 651(e), Pub. L. 109-58, 119 Stat. 549 (2005) (42 U.S.C. 2014, 2021, 2021b, 2111).
The revisions read as follows:
II. * * *
An authorized representative of the waste generator, processor, or collector shall certify by signing and dating the shipment manifest that the transported materials meet the waste acceptance criteria for disposal for a specific site; are properly classified, described, packaged, marked, and labeled; and are in proper condition for transportation according to the applicable regulations of the U.S. Department of Transportation and the Commission. A collector who signs the certification is certifying that nothing has been done to the collected waste that would invalidate the waste generator's certification.
III. * * *
A. * * *
1. Prepare all wastes according to the land disposal facility's criteria for waste acceptance developed in accordance with § 61.58 of this chapter;
2. Label each disposal container (or transport package if potential radiation hazards preclude labeling of the individual disposal container) of waste in accordance with § 61.57 of this chapter;
3. Conduct a quality assurance program to assure compliance with the land disposal facility's criteria for waste acceptance that has been developed in accordance with § 61.58 of this chapter (the program must include management evaluation of audits);
C. * * *
3. Prepare all wastes according to the land disposal facility's criteria for waste acceptance developed in accordance with § 61.58 of this chapter;
4. Label each package of waste in accordance with § 61.57 of this chapter;
5. Conduct a quality assurance program to assure compliance with the land disposal facility's criteria for waste acceptance that has been developed in accordance with § 61.58 of this chapter (the program shall include management evaluation of audits);
Atomic Energy Act secs. 53, 57, 62, 63, 65, 81, 161, 181, 182, 183, 223, 234 (42 U.S.C. 2073, 2077, 2092, 2093, 2095, 2111, 2201, 2231, 2232, 2233, 2273, 2282); Energy Reorganization Act secs. 201, 202, 206 (42 U.S.C. 5841, 5842, 5846), sec. 211, Pub. L. 95-601, sec. 10, as amended by Pub. L. 102-486, sec. 2902 (42 U.S.C. 5851). Pub. L. 95-601, sec. 10, 14, 92 Stat. 2951, 2953 (42 U.S.C. 2021a, 5851); Government Paperwork Elimination Act sec. 1704 (44 U.S.C. 3504 note); Energy Policy Act of 2005, sec. 651(e), Pub. L. 109-58, 119 Stat. 806-810 (42 U.S.C. 2014, 2021, 2021b, 2111).
The revisions and additions read as follows:
(1) Assumes an inadvertent intruder occupies the site and engages in normal activities or other reasonably foreseeable pursuits that are realistic and consistent with expected activities in and around the disposal site at the time of site closure and that might unknowingly expose the person to radiation from the waste;
(2) examines the capabilities of intruder barriers to inhibit an inadvertent intruder's contact with the waste or to limit the inadvertent intruder's exposure to radiation; and
(3) estimates an inadvertent intruder's potential annual dose, considering associated uncertainties.
(1) Where more than 10 percent of the initial activity of a radionuclide remains after 10,000 years (
(2) Where the peak activity from progeny occurs after 10,000 years (
(3) Where more than 10 percent of the peak activity of a radionuclide (including progeny) within 10,000 years remains after 10,000 years (
(1) Identifies the features, events, and processes that might affect the disposal system;
(2) Examines the effects of these features, events, and processes on the performance of the disposal system; and
(3) Estimates the annual dose to any member of the public caused by all significant features, events, and processes.
(a)
(2) Near-surface disposal of radioactive waste takes place at a near-surface disposal facility, which includes all of the land and buildings necessary to carry out the disposal. The disposal site is that portion of the facility used for disposal of waste and consists of disposal units and a buffer zone. A disposal unit is a discrete portion of the disposal site into which waste is placed for disposal. A buffer zone is a portion of the disposal site that is controlled by the licensee and that lies under the site and between the boundary of the disposal site and any disposal unit. It provides controlled space to establish monitoring locations, which are intended to provide an early warning of radionuclide movement. An early warning allows a licensee to perform any mitigation that might be necessary. In choosing a disposal site, site characteristics should be considered in terms of the indefinite future, take into account the radiological characteristics of the waste, and be evaluated for at least a 500-year timeframe to provide assurance that the performance objectives can be met.
(b)
(c)
(2) A performance assessment is an analysis that is required to demonstrate protection of the general population from releases of radioactivity. A performance assessment identifies the specific characteristics of the disposal site (
(3) Inadvertent intruders might occupy the site in the future and engage
(4) The intruder assessment must demonstrate protection of inadvertent intruders through the assessment of potential radiological exposures should an inadvertent intruder occupy the disposal site following a loss of institutional controls after closure. The intruder can be exposed to radioactivity that has been released into the environment as a result of disturbance of the waste or from radiation emitted from waste that is still contained in the disposal site. The results of the intruder assessment are compared with the appropriate performance objective of subpart C of this part. An intruder assessment can employ a similar methodology to that used for a performance assessment, but the intruder assessment must assume that an inadvertent intruder occupies the disposal site following a loss of institutional controls after closure, and engages in activities that unknowingly expose the intruder to radiation from the waste.
(5) Implementation of dose methodology. The dose methodology used to demonstrate compliance with the performance objectives of this part shall be consistent with the dose methodology specified in the standards for radiation protection set forth in part 20 of this chapter. After the effective date of these regulations, applicants and licensees may use updated factors incorporated by the U.S. Environmental Protection Agency into Federal radiation protection guidance or may use the most current scientific models and methodologies (
(6) Waste with significant concentrations and quantities of long-lived radionuclides may require special processing, design, or site conditions for disposal. Demonstrating protection of the general population from releases of radioactivity and inadvertent intruders from the disposal of this waste requires an assessment of long-term impacts. Performance period analyses are used to evaluate the suitability of this waste for disposal on a case-by-case basis. In general, for disposal facilities with limited quantities of long-lived waste, performance period analyses are not necessary to demonstrate protection of the general population from releases of radioactivity and protection of inadvertent intruders. However, there may be site-specific conditions that require licensees to assess disposal facilities beyond the compliance period even when long-lived waste is limited. These conditions should be evaluated on a case-by-case basis to determine whether analyses beyond the compliance period would be required.
(d)
(e)
(f)
(2) Institutional control of access to the site is required for up to 100 years. This permits the disposal of Class A and B waste without special provisions for intrusion protection, since these wastes contain types and quantities of radionuclides that generally will decay during the 100-year period and will present an acceptable hazard to the intruder. However, waste that is Class A under 10 CFR 61.55(a)(6) may not decay to acceptable levels in 100 years. For waste classified under 10 CFR 61.55(a)(6), safety is provided by
(3) Waste that will not decay to levels that present an acceptable hazard to an intruder within 100 years is typically designated as Class C waste. Class C waste must be stable and be disposed of at a greater depth than the other classes of waste so that subsequent surface activities by an intruder will not disturb the waste. Where site conditions prevent deeper disposal, intruder barriers such as concrete covers may be used. The effective life of these intruder barriers should be at least 500 years. A maximum concentration of radionuclides is specified in tables 1 and 2 of § 61.55 so that at the end of the 500-year period, the remaining radioactivity will be at a level that does not pose an unacceptable hazard to an inadvertent intruder or to public health and safety. Waste with concentrations above these limits is generally unacceptable for near-surface disposal. There may be some instances where waste with concentrations greater than permitted for Class C would be acceptable for near-surface disposal with special processing or design. Disposal of this waste will be evaluated on a case-by-case basis with the technical analyses required in § 61.13.
(4) Regardless of the classification, some waste may require enhanced controls or limitations at a particular land disposal facility. A performance assessment and an intruder assessment are used to identify these enhanced controls and limitations, which are site- and waste-specific. Enhanced controls or limitations could include additional limits on waste concentration or total activity, more robust intruder barriers, deeper burial depth, and waste-specific stability requirements. These enhanced controls or limitations could mitigate the uncertainty associated with the evolutionary effects of the natural environment and the disposal facility performance over the compliance period.
(g)
(2) During the operational phase, the licensee carries out disposal activities in accordance with the requirements of these regulations and any conditions on the license. Periodically, the authority to conduct the above ground operations and dispose of waste will be subject to a license renewal, at which time the operating history will be reviewed and a decision made to permit or deny continued operation. When disposal operations are to cease, the licensee applies for an amendment to the site license to permit site closure. After final review of the licensee's site closure and stabilization plan, the Commission may approve the final activities necessary to prepare the disposal site so that ongoing active maintenance of the site is not required during the period of institutional control.
(3) During the period when the final site closure and stabilization activities are being carried out, the licensee is in a disposal site closure phase. Following that, for a period of 5 years, the licensee must remain at the disposal site for a period of postclosure observation and maintenance to assure that the disposal site is stable and ready for institutional control. The period of postclosure observation and maintenance is used to ensure that the final site closure and stabilization activities have not resulted in unintended instability at the disposal site. The Commission may approve shorter or require longer periods if conditions warrant. At the end of this period, the licensee applies for a license transfer to the disposal site owner.
(4) After a finding of satisfactory disposal site closure, the Commission will transfer the license to the State or Federal Government that owns the disposal site. If the U.S. Department of Energy is the Federal agency administering the land on behalf of the Federal Government the license will be terminated because the Commission lacks regulatory authority over the Department for this activity. Under the conditions of the transferred license, the owner will carry out a program of monitoring to assure continued satisfactory disposal site performance, perform physical surveillance to restrict access to the site, and carry out minor custodial activities. During this period, productive uses of the land might be permitted if those uses do not affect the stability of the site and its ability to meet the performance objectives. At the end of the prescribed period of institutional control, the license will be terminated by the Commission.
(b) The approved information collection requirements contained in this part appear in §§ 61.3, 61.6, 61.9, 61.10, 61.11, 61.12, 61.13, 61.14, 61.15, 61.16, 61.20, 61.22, 61.24, 61.26, 61.27, 61.28, 61.30, 61.31, 61.32, 61.41, 61.42, 61.53, 61.55, 61.57, 61.58, 61.61, 61.62, 61.63, 61.72, and 61.80.
(a) An application to receive from others, possess and dispose of wastes containing or contaminated with source, byproduct or special nuclear material by land disposal must consist of general information, specific technical information, institutional information, and financial information as set forth in §§ 61.11 through 61.16. An environmental report prepared in accordance with subpart A of part 51 of this chapter must accompany the application.
(b) The information provided in an application comprises the safety case and supports the licensee's demonstration that the disposal facility will be constructed and operated safely and provides reasonable assurance that the disposal site will be capable of
The specific technical information, which supports the safety case, must include the following to demonstrate that the performance objectives of subpart C of this part and the applicable technical requirements of subpart D of this part will be met:
(a) A description of the natural and demographic disposal site characteristics as determined by disposal site selection and characterization activities. The description must include geologic, geotechnical, geochemical, geomorphological, hydrologic, meteorologic, climatologic, and biotic features of the disposal site and vicinity.
(e) A description of codes and standards that the applicant has applied to the design and that will apply to construction of the land disposal facilities.
(g) A description of the disposal site closure plan, including those design features that are intended to facilitate disposal site closure and eliminate the need for ongoing active maintenance.
(i) A description of the kind, amount, and specifications of the radioactive material proposed to be received, possessed, and disposed of at the land disposal facility, including the criteria for acceptance of waste for disposal.
(j) A description of the quality assurance program, tailored to low-level radioactive waste disposal, developed and applied by the applicant for:
(1) The determination of natural disposal site characteristics;
(2) The development of technical analyses; and
(3) Quality assurance during the design, construction, operation, and closure of the land disposal facility and the receipt, handling, and emplacement of waste.
The revisions and additions read as follows:
The specific technical information must also include the following analyses needed to demonstrate that the performance objectives of subpart C of this part will be met. The technical analyses are one of the elements of the safety case. Licensees with licenses for land disposal facilities in effect on the effective date of this subpart must submit these analyses at the next license renewal or within 5 years of the effective date of this subpart, whichever comes first.
(a) A performance assessment that demonstrates that there is reasonable assurance that the exposure to humans from the release of radioactivity will meet the performance objective set forth in § 61.41. A performance assessment shall:
(1) Consider features, events, and processes that might affect demonstrating compliance with § 61.41. The features, events, and processes considered must represent a range of phenomena with both beneficial and adverse effects on performance, and must consider the specific technical information required in § 61.12(a) through (i). A technical basis for either inclusion or exclusion of specific features, events, and processes must be provided.
(2) Evaluate specific features, events, and processes in detail if their omission would significantly affect meeting the performance objective specified in § 61.41.
(3) Consider the likelihood of disruptive or other unlikely features, events, or processes for comparison with the limits set forth in § 61.41.
(4) Reflect new features, events, and processes different from the compliance period that address significant uncertainties inherent in the long timeframes associated with demonstrating compliance with § 61.41(b) only if scientific information compelling such changes is available.
(5) Provide a technical basis for either inclusion or exclusion of degradation, deterioration, or alteration processes (
(6) Provide a technical basis for models used in the performance assessment such as comparisons made with outputs of detailed process-level models or empirical observations (
(7) Evaluate pathways including air, soil, groundwater, surface water, plant uptake, and exhumation by burrowing animals.
(8) Account for uncertainties and variability in the projected behavior of the disposal system (
(9) Consider alternative conceptual models of features and processes that are consistent with available data and current scientific understanding, and evaluate the effects that alternative conceptual models have on the understanding of the performance of the disposal facility.
(10) Identify and differentiate between the roles performed by the natural disposal site characteristics and design features of the disposal facility in limiting releases of radioactivity to the general population.
(b) Inadvertent intruder analyses that demonstrate there is reasonable assurance that:
(1) the waste acceptance criteria developed in accordance with § 61.58 will be met,
(2) adequate barriers to inadvertent intrusion will be provided, and
(3) any inadvertent intruder will not be exposed to doses that exceed the limits set forth in § 61.42 as part of the intruder assessment. An intruder assessment shall:
(i) Assume that an inadvertent intruder occupies the disposal site at any time after the period of institutional controls ends, and engages in normal activities including agriculture, dwelling construction, resource exploration or exploitation (
(ii) Identify adequate barriers to inadvertent intrusion that inhibit contact with the waste or limit exposure to radiation from the waste, and provide a basis for the time period over which barriers are effective.
(iii) Account for uncertainties and variability.
(d) Analyses of the long-term stability of the disposal site and the need for ongoing active maintenance after closure must be based upon analyses of active natural processes such as erosion, mass wasting, slope failure, settlement of wastes and backfill, infiltration through covers over disposal areas and adjacent soils, and surface drainage of the disposal site. The analyses must provide reasonable assurance that long-term stability of the disposal site can be ensured and that there will not be a need for ongoing active maintenance of the disposal site following closure.
(e) Analyses that assess how the disposal site limits the potential long-
(f) Analyses that demonstrate the proposed disposal facility includes defense-in-depth protections.
The revisions and addition read as follows:
(b) The applicant's proposed disposal site, disposal design, waste acceptance criteria, land disposal facility operations (including equipment, facilities, and procedures), disposal site closure, and postclosure institutional control demonstrate that they are adequate to protect the public health and safety because they provide reasonable assurance that the general population will be protected from releases of radioactivity as specified in the performance objective in § 61.41.
(c) The applicant's proposed disposal site, disposal site design, waste acceptance criteria, land disposal facility operations (including equipment, facilities, and procedures), disposal site closure, and postclosure institutional control demonstrate that they are adequate to protect the public health and safety because they provide reasonable assurance that individual inadvertent intruders are protected in accordance with the performance objective in § 61.42.
(d) The applicant's proposed waste acceptance criteria and land disposal facility operations (including equipment, facilities, and procedures) demonstrate that they are adequate to protect the public health and safety because they provide reasonable assurance that the standards for radiation protection set out in part 20 of this chapter will be met.
(e) The applicant's proposed disposal site, disposal site design, waste acceptance criteria, land disposal facility operations, disposal site closure, and postclosure institutional control demonstrate that they are adequate to protect the public health and safety because they provide reasonable assurance that long-term stability of the disposed waste and the disposal site will be achieved and will eliminate to the extent practicable the need for ongoing active maintenance of the disposal site following closure.
(m) The applicant's safety case is adequate to support the licensing decision.
(a) Except as provided for in specific license conditions, the licensee shall not make changes in the land disposal facility or procedures described in the license application. The license will include conditions restricting subsequent changes to the facility and the procedures authorized that are important to public health and safety. These license restrictions will fall into three categories of descending importance to public health and safety as follows:
(1) Those features and procedures that may not be changed without;
(i) 60 days prior notice to the Commission;
(ii) 30 days notice of opportunity for a prior hearing; and
(iii) Prior Commission approval;
(2) Those features and procedures that may not be changed without:
(i) 60 days prior notice to the Commission; and
(ii) Prior Commission approval; and
(3) Those features and procedures that may not be changed without 60 days prior notice to the Commission. Features and procedures falling in this paragraph (a)(3) may not be changed without prior Commission approval if the Commission so orders, after having received the required notice.
(b) Amendments authorizing waste acceptance criteria changes, site closure, license transfer, or license termination shall be included in paragraph (a)(1) of this section.
(a) Prior to final closure of the disposal site, or as otherwise directed by the Commission, the applicant shall submit an application to amend the license for closure. This closure application must include a final revision of the safety case and specific details of the disposal site closure plan included as part of the license application submitted under § 61.12(g) that includes each of the following:
(2) The results of tests, experiments, or any other analyses relating to backfill of excavated areas, closure and sealing, waste migration and interaction with emplacement media, or any other tests, experiments, or analysis pertinent to the long-term containment of emplaced waste within the disposal site, including revised analyses for § 61.13 using the details of the final closure plan and waste inventory.
(a) Concentrations of radioactive material that may be released to the general environment in ground water, surface water, air, soil, plants, or animals must not result in an annual dose exceeding an equivalent of 0.25 milliSievert (25 millirems) to any member of the public within the compliance period. Reasonable effort should be made to maintain releases of radioactivity in effluents to the general environment as low as is reasonably achievable during the compliance period. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(a).
(b) Concentrations of radioactive material that may be released to the general environment in ground water, surface water, air, soil, plants, or animals shall be minimized during the protective assurance period. The annual dose, established on the license, shall be below 5 milliSieverts (500 millirems) or a level that is supported as reasonably achievable based on technological and economic considerations in the information submitted for review and approval by the Commission. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(a).
(c) Effort shall be made to minimize releases of radioactivity from a disposal facility to the general environment to the extent reasonably achievable at any time during the performance period. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(e).
(a) Design, operation, and closure of the land disposal facility must ensure protection of any inadvertent intruder into the disposal site who occupies the site or contacts the waste at any time after active institutional controls over the disposal site are removed. The annual dose must not exceed 5 milliSieverts (500 millirems) to any inadvertent intruder within the compliance period. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(b).
(b) Design, operation, and closure of the land disposal facility shall minimize exposures to any inadvertent intruder into the disposal site at any time during the protective assurance period. The annual dose, established on the license, shall be below 5 milliSieverts (500 millirems) or a level that is supported as reasonably achievable based on technological and economic considerations in the information submitted for review and approval by the Commission. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(b).
(c) Effort shall be made to minimize exposures to any inadvertent intruder to the extent reasonably achievable at any time during the performance period. Compliance with this paragraph must be demonstrated through analyses that meet the requirements specified in § 61.13(e).
The disposal facility must be sited, designed, used, operated, and closed to achieve long-term stability of the disposal site for the compliance and protective assurance periods and to eliminate to the extent practicable the need for ongoing active maintenance of the disposal site following closure so that only surveillance, monitoring, or minor custodial care are required.
(a)
(1) To the extent practicable, the disposal site shall be capable of being characterized, modeled, analyzed, and monitored.
(2) The hydrologic characteristics that a site must have for 500 years following closure of the land disposal facility to be acceptable for the disposal of radioactive waste in the near surface include:
(i) Waste disposal shall not take place in a poorly drained site or a site subject to flooding or frequent ponding, or in a 100-year flood plain, coastal high-hazard area or wetland, as defined in Executive Order 11988, “Floodplain Management Guidelines.”
(ii) Upstream drainage areas must be minimized to decrease the amount of runoff which could erode or inundate waste disposal units.
(iii) The disposal site must provide sufficient depth to the water table that ground water intrusion, perennial or otherwise, into the waste will not occur. The Commission will consider an exception to this requirement to allow disposal below the water table if it can be conclusively shown that disposal site characteristics will result in molecular diffusion being the predominant means of radionuclide movement and the rate of movement will result in the performance objectives of subpart C of this part being met. In no case will waste disposal be permitted in the zone of fluctuation of the water table.
(iv) The hydrogeologic unit used for disposal shall not discharge ground water to the surface within the disposal site.
(3) After 500 years, the hydrologic characteristics specified in paragraph (2) of this section shall not significantly affect the ability of the disposal site to meet the performance objectives of subpart C of this part.
(4) Other characteristics of the site shall not significantly affect the ability of the disposal site to meet the performance objectives of subpart C of this part, or preclude defensible modeling and estimation of longer-term impacts. The characteristics include:
(i) Within the region or state where the facility is to be located, a disposal site should be selected so that projected population growth and future developments are not likely to affect the ability of the disposal facility to meet the performance objectives of subpart C of this part.
(ii) Areas must be avoided having known natural resources which, if exploited, would result in failure to meet the performance objectives of subpart C of this part.
(iii) Areas must be avoided where tectonic processes such as faulting, folding, seismic activity, or volcanism may occur with such frequency and extent to significantly affect the ability of the disposal site to meet the performance objectives of subpart C of this part, or may preclude defensible modeling and prediction of long-term impacts.
(iv) Areas must be avoided where surface geologic processes such as mass wasting, erosion, slumping, landsliding, or weathering occur with such frequency and extent to significantly affect the ability of the disposal site to meet the performance objectives of subpart C of this part, or may preclude defensible modeling and prediction of long-term impacts.
(v) The disposal site must not be located where nearby facilities or activities could adversely impact the ability of the site to meet the performance objectives of subpart C of this part or significantly mask the environmental monitoring program.
(b)
(a) * * *
(1) Site design features must be directed toward defense-in-depth, long-term isolation and avoidance of the need for continuing active maintenance after site closure.
(a) * * *
(3) All wastes shall be disposed of in accordance with the requirements of paragraphs (a)(4) through (13) of this section.
(8) A buffer zone of land must be maintained between any buried waste and the disposal site boundary and beneath the disposed waste. The buffer zone shall be of adequate dimensions to allow a licensee to carry out environmental monitoring activities specified in § 61.53(d) of this part and take mitigative measures if needed.
(12) Only waste meeting the acceptance criteria shall be disposed of at the disposal site.
(13) Waste will be disposed of consistent with the description provided in § 61.12(f) and the technical analyses required by § 61.13.
(a) * * *
(6) Classification of wastes with radionuclides other than those listed in tables 1 and 2 of this section. If radioactive waste does not contain any nuclides listed in either table 1 or 2 of this section, it is Class A.
(a) The following requirements are minimum requirements for all waste and are intended to facilitate handling at the disposal site and provide protection of health and safety of personnel at the disposal site.
Each package of waste must be clearly labeled to identify any information required by the land disposal facility's criteria for waste acceptance developed according to § 61.58. Each package of waste disposed in a land disposal facility with waste acceptance criteria developed in accordance with the waste classification requirements must indicate whether it is Class A waste, Class B waste, or Class C waste, in accordance with § 61.55.
(a)
(1) Allowable activities and concentrations of specific radionuclides. Allowable activities and concentrations shall be developed from the technical analyses required by either § 61.13 for any land disposal facility or the waste classification requirements set forth in § 61.55 for a near-surface disposal facility.
(2) Acceptable wasteform characteristics and container specifications. The characteristics and specifications shall meet the minimum requirements for waste characteristics set forth in § 61.56(a) for all waste, and the requirements in § 61.56(b) for waste that requires stability to demonstrate compliance with the performance objectives of subpart C of this part.
(3) Restrictions or prohibitions on waste, materials, or containers that might affect the facility's ability to meet the performance objectives in subpart C of this part.
(b)
(1) Physical and chemical characteristics;
(2) Volume, including the waste and any stabilization or absorbent media;
(3) Weight of the container and contents;
(4) Identities, activities, and concentrations;
(5) Characterization date;
(6) Generating source; and
(7) Any other information needed to characterize the waste to demonstrate that the waste acceptance criteria set forth in § 61.58(a) are met.
(c)
(1) Designate authority to certify and receive waste for disposal at the disposal facility.
(2) Provide procedures for certifying that waste meets the waste acceptance criteria.
(3) Specify documentation required for waste acceptance including waste characterization, shipment (including the requirements set forth in appendix G of 10 CFR part 20), and certification.
(4) Identify records, reports, tests, and inspections that are necessary to comply with the requirements in § 61.80.
(5) Provide approaches for managing waste that has been certified as meeting the waste acceptance criteria in a manner that maintains its certification status.
(d) Licensees with licenses for land disposal facilities in effect on the effective date of this subpart shall comply with the requirements of paragraphs (a), (b), and (c) of this section at the next license renewal or within 5 years of the effective date of this subpart, whichever comes first.
(e) For license applicants, the waste acceptance criteria will be incorporated into the facility license. For licensees with licenses for land disposal facilities in effect on the effective date of this subpart, upon Commission approval and if otherwise consistent with applicable State and Federal law, the NRC will issue an amendment to the license incorporating the waste acceptance criteria in to the existing license.
(f) Each licensee shall annually review the content and implementation of the waste acceptance criteria, waste characterization methods, and certification program.
(g) Applications for modification of approved waste acceptance criteria must be filed in accordance with § 61.20.
(h) In determining whether waste acceptance criteria will be approved, the Commission will apply the criteria set forth in § 61.23.
(i)(1) Each licensee authorized to dispose of waste materials received from other persons under this part shall submit annual reports to the Director, Office of Nuclear Material Safety and Safeguards, by an appropriate method listed in § 61.4, with a copy to the appropriate NRC Regional Office shown in appendix D to 10 CFR part 20. Reports must be submitted by the end of the first calendar quarter of each year for the preceding year.
(2) The reports shall include:
(i) Specification of the quantity of each of the principal radionuclides released to unrestricted areas in liquid and in airborne effluents during the preceding year;
(ii) The results of the environmental monitoring program;
(iii) A summary of licensee disposal unit survey and maintenance activities;
(iv) A summary of activities and quantities of radionuclides disposed of;
(v) Any instances in which observed site characteristics were significantly different from those described in the application for a license; and
(vi) Any other information the Commission may require.
(3) If the quantities of radioactive materials released during the reporting period, monitoring results, or maintenance performed are significantly different from those expected in the materials previously reviewed as part of the licensing action, the report must cover this specifically.
(m) Each licensee shall maintain waste acceptance records including:
(1) Provisions for waste acceptance including the waste acceptance criteria, characterization methods, and certification program.
(2) Audits and other reviews of program content and implementation. The licensee shall retain records of audits and other reviews for 3 years after the record is made.
For the Nuclear Regulatory Commission.
Bureau of Land Management, Interior.
Final rule.
On May 11, 2012, the Bureau of Land Management (BLM) published in the
This final rule is effective on June 24, 2015.
Steven Wells, Division Chief, Fluid Minerals Division, 202-912-7143 for information regarding the substance of the rule or information about the BLM's Fluid Minerals Program. 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 above individual during normal business hours. FIRS is available 24 hours a day, 7 days a week to leave a message or question with the above individual. You will receive a reply during normal business hours.
The BLM final rule on hydraulic fracturing serves as a much-needed complement to existing regulations designed to ensure the environmentally responsible development of oil and gas resources on Federal and Indian lands, which were finalized nearly thirty years ago, in light of the increasing use and complexity of hydraulic fracturing coupled with advanced horizontal drilling technology. This technology has opened large portions of the country to oil and gas development.
The BLM began work on this rule in November 2010, when it held its first public forum amid growing public concern about the rapid expansion of complex hydraulic fracturing. Since that time, the BLM has published two proposed rules and held numerous meetings with the public and state officials, as well as many tribal consultations and meetings. The public comment period was open for more than 210 days. During this period, the BLM received comments from more than 1.5 million individuals and groups. The BLM reviewed and analyzed these comments based on thoughtful analysis and robust dialogue, which resulted in a rule that is more protective than the previous proposed rules and current regulations. It also strengthens oversight and provides the public with more information than is currently available, while recognizing state and tribal authorities and not imposing undue delays, costs, and procedures on operators. The final rule fulfills the goals of the initial proposed rules: To ensure that wells are properly constructed to protect water supplies, to make certain that the fluids that flow back to the surface as a result of hydraulic fracturing operations are managed in an environmentally responsible way, and to provide public disclosure of the chemicals used in hydraulic fracturing fluids.
The final rule also: (1) Improves public awareness of where hydraulic fracturing has occurred and the existence of other wells or geologic faults or fractures in the area, as well as communicates what chemicals have been used in the fracturing process; (2) Clarifies and strengthens existing rules related to well construction to ensure integrity and address developments in technology; (3) Aligns requirements with state and tribal authorities with regard to water zones that require protection; and (4) Provides opportunities to coordinate standards and processes with individual states and tribes to reduce costs, increase efficiencies, and promote the development of more stringent standards by state and tribal governments.
Various types of hydraulic fracturing have long been used on a relatively small scale to complete or to re-complete conventional oil and gas wells. More recently, hydraulic fracturing has been coupled with relatively new horizontal drilling technology in larger-scale operations that have allowed greatly increased access to shale oil and gas resources across the country, sometimes in areas that have not previously or recently experienced significant oil and gas development. These newer wells can, among other complexities, be significantly deeper and cover a larger horizontal area than the operations of the past. This increased complexity requires additional regulatory effort and oversight.
Rapid expansion of this practice and its complexity have caused public concern about whether fracturing can lead to or cause the contamination of underground water sources, whether the chemicals used in fracturing pose risks to human health, and whether there is adequate management of well integrity and the fluids that return to the surface during and after fracturing operations.
The BLM's regulations that address issues surrounding hydraulic fracturing are at least 25-30 years old, and pre-date the current common use of the practice. In 2011, the Natural Gas Subcommittee of the Secretary of Energy's Advisory Board recommended that the BLM undertake a rulemaking to ensure well integrity, water protection, and adequate public disclosure. Prior to that, in 2009 the American Petroleum Institute published a guidance document titled “Hydraulic Fracturing Operations-Well Construction and Integrity Guidelines, First Edition,
Pursuant to the Federal Land Policy and Management Act (FLPMA), Indian mineral leasing laws, and other statutes, the BLM is charged with administering oil and gas operations in a manner that protects Federal and Indian lands while allowing for appropriate development of the resource. The BLM oversees approximately 700 million subsurface acres of Federal mineral estate and carries out some of the regulatory duties of the Secretary of the Interior for an additional 56 million acres of Indian mineral estate across the United States. Currently, nearly 36 million acres of Federal land are under lease for potential oil and gas development in 33 states. As of June 30, 2014, there were approximately 47,000 active oil and gas leases on public lands, and approximately 95,000 oil and gas wells. Like other BLM regulations, this final rule applies to oil and gas operations on public lands (which include split estate lands,
Oil and gas leasing decisions on public lands are made through a thorough, deliberative, and transparent process rooted in Resource Management Plans (RMPs) that cover virtually all BLM-administered public land and related mineral estate. Oil and gas decisions contained within BLM RMPs also apply to lands where the surface is privately owned, but the mineral estate is in Federal ownership. The BLM establishes, amends, and revises RMPs as required by the FLPMA with involvement by the community and stakeholders. As part of the land use planning process, the BLM engages the public in a variety of ways and conducts environmental reviews as required by the National Environmental Policy Act (NEPA), and other applicable natural and cultural resource protection authorities. While the public makes known to the BLM which lands they are interested in leasing, prior to leasing any lands, the BLM undertakes the appropriate NEPA review and provides an opportunity for the public to review and comment on the analyses and documents that the agency prepares.
Relevant existing requirements for oil and gas operations are set out at 43 CFR 3162.3-1 and Onshore Oil and Gas Orders 1, 2 and 7. Most of these requirements have been in place for at least 25 years. This final rule will supplement the existing requirements, which will remain in place. On either Federal leaseholds, or Indian lands, an operator may not begin operations until it has filed an Application for a Permit to Drill (APD) with the BLM and received approval from the BLM to commence operations. Existing Federal law requires the BLM to post notices of APDs for oil and gas development on public lands for public inspection for 30 days, during which time the public may express any concerns to the BLM's authorized officer as the agency conducts a site-specific environmental analysis of the proposed well site proposal. Those concerns and other issues identified earlier in the process, or during site examinations, may result in conditions of approval (COA) on the operator's drilling permit that require, forbid, or control specified activities or disturbances. Examples of COAs include providing for road improvements and erosion control measures, or applying seasonal restrictions on some activities. In addition, baseline water testing is a best management practice that the BLM encourages. The BLM may require water testing and monitoring, particularly if water quality impacts are a significant concern based on local conditions, and where the BLM or a cooperating landowner or manager manages the surface estate where testing could yield useful water quality information. This is consistent with what several states, including California, Colorado, and Wyoming, are already doing. The BLM does not post for public inspection notices of APDs for Indian oil and gas leases or agreements because there is no requirement in the Indian leasing statutes similar to that in Section 17 of the Mineral Leasing Act.
Under Onshore Oil and Gas Order 1, Approval of Operations, the location of the well must be identified and important aspects of the proposed operations described. Onshore Order 2 requires all usable water zones to be protected by steel casing and cement, and requires the casing, once in place, to be pressure tested. Casing and cement must meet specific design criteria, which BLM engineers verify as part of the permit review process. When a well is no longer capable of producing, Onshore Order 2 mandates minimum standards for the placement, quality, and verification of cement plugs to ensure that any remaining oil and gas cannot migrate into usable water zones. BLM inspectors witness aspects of drilling and plugging operations to ensure that the operator is in compliance with Onshore Order 2 and the permit to drill.
With this rule, the BLM establishes new requirements to ensure wellbore integrity, protect water quality, and enhance public disclosure of chemicals and other details of hydraulic fracturing operations. The rule requires an operator planning to conduct hydraulic fracturing to do the following:
• Submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM with the APD or a Sundry Notice and Report on Wells (Form 3160-5) as a Notice of Intent (NOI) to hydraulically fracture an existing well;
• Design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, defined generally as those waters containing less than 10,000 parts per million of total dissolved solids (TDS);
• Monitor cementing operations during well construction;
• Take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful;
• Perform a successful mechanical integrity test (MIT) prior to the hydraulic fracturing operation;
• Monitor annulus pressure during a hydraulic fracturing operation;
• Manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis;
• Disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated through affidavit to be trade secrets;
• Provide documentation of all of the above actions to the BLM.
Specifically, this final rule will add to existing requirements by providing information to the BLM and the public on the location, geology, water resources, location of other wells or fracture zones in the area, and fracturing plans for the operation before the well is permitted. To ensure well integrity, the final rule will require specified best practice performance standards for all wells, including cement return and pressure testing for surface casing, cement evaluation logs for intermediate and production casing, and remediation plans and cement evaluation logs for any surface casing that does not meet performance standards.
The final rule eliminates the use of “type wells” in demonstrating well integrity, and requires that specified best practices be used and demonstrated for all wells, not just a sample well. For surface casing, the final rule does not require a cement evaluation log (CEL) for each well, substituting other equally or more protective performance standards, including cement returns and pressure testing. For any surface casing not meeting these performance standards, an approved remedial plan and CEL will be required. For intermediate and production casing not cemented to the surface, a CEL will be required for all wells.
The final rule will require interim storage of all produced water in rigid enclosed, covered, or netted and screened above-ground tanks, subject to very limited exceptions in which lined pits could be used.
Public disclosure of all chemicals, subject to limited exceptions for trade secret material, will be required after fracturing operations are complete. The existing database, FracFocus (
FracFocus is managed by the Ground Water Protection Council (GWPC), a non-profit organization of state water quality regulatory agencies, and by the Interstate Oil and Gas Compact Commission (IOGCC), a multi-state government agency charged with balancing oil and gas development with environmental protection. The BLM will continue to work with FracFocus in coordination with the U.S. Department of Energy (DOE) to ensure that the recommendations of the Secretary of Energy's Advisory Board for improvement of the database are made.
• Reducing the number of human errors in disclosures
• Expanding the public's ability to search records
• Providing public extraction of data in a “machine readable” format and
• Updating educational information on chemical use, oil and gas production, and potential environmental impacts.
As a part of the MOU with GWPC, FracFocus will automatically notify the BLM when an operator uploads chemical disclosure information about a Federal or Indian well. The BLM will obtain the information from FracFocus and keep those records in compliance with all pertinent record management requirements.
The BLM developed this final rule with the intention of improving public awareness and strengthening oversight of hydraulic fracturing operations without introducing unnecessary new procedures or delays in the process of developing oil and gas resources on public and Indian lands. Some states, including Alaska, Arkansas, Colorado, Illinois, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah, and Wyoming have regulations in place addressing hydraulic fracturing operations. Operators with leases on Federal lands must comply with both the BLM's regulations and with state operating requirements, including state permitting and notice requirements to the extent they do not conflict with BLM regulations. To address concerns from states and tribes about possible duplicative efforts, the final rule provides that in situations in which specific state or tribal regulations are demonstrated to be equal to or more protective than the BLM's rules, the state or tribe may obtain a variance. Such a variance will allow for enforcement of the more protective state or tribal rule.
For many years, the BLM has maintained a number of agreements with certain states and tribes concerning implementation of the various regulatory programs in logical and effective ways. The BLM will work with states and tribes to establish formal agreements that will capitalize on the strengths of partnerships, and reduce duplication of effort for agencies and operators, particularly by implementing the final rule as consistently as possible with state or tribal regulations.
The provisions in this final rule provide for the BLM's consistent oversight and establish a baseline for environmental protection across all public and Indian lands undergoing hydraulic fracturing. The BLM has analyzed the costs and the benefits of this proposed action in an accompanying Regulatory Impact Analysis available in the rulemaking docket. The BLM estimates that the rule will impact about 2,800 hydraulic fracturing operations per year, but that it could impact up to 3,800 operations per year based on previous levels of activity on Federal lands and growing activity on Indian lands. The BLM estimates that the compliance cost will be about $11,400 per well, or about $32 million per year. On average this equates to approximately 0.13 to 0.21 percent of the cost of drilling a well.
Many of the requirements generally are consistent with industry guidance, the voluntary practice of operators, and some are required by state regulations. So to the extent that industry is already in compliance, the cost of several of the provisions may be overestimated. The improvements also provide significant benefits to all Americans by avoiding potential damages to water quality, the environment, and public health. The rule creates a consistent, predictable, regulatory framework, in accordance with the BLM's stewardship responsibilities for hydraulic fracturing under the FLPMA and the Indian mineral leasing statutes.
Well stimulation techniques, such as hydraulic fracturing, are commonly used by oil and natural gas producers to increase the volumes of oil and natural gas that can be extracted from wells. Hydraulic fracturing techniques are particularly effective in enhancing oil and gas production from shale gas or oil formations. Until quite recently, shale formations rarely produced oil or gas in commercial quantities because shale does not generally allow the flow of hydrocarbons to wellbores unless
Some simple types of hydraulic fracturing techniques have been used on a small scale in oil and gas production for decades. However, as discussed in different parts of the preamble, hydraulic fracturing operations in recent years have become more complex, involving the exploration of and production from significantly deeper formations and across much larger subsurface areas through the use of horizontal drilling techniques.
The BLM estimates that about 90 percent of the approximately 2,800 new wells spudded in 2013 on Federal and Indian lands were stimulated using hydraulic fracturing techniques. Over the past 10 years, there have been significant technological advances in horizontal drilling, which is now frequently combined with hydraulic fracturing. This combination, together with the discovery that these techniques can release significant quantities of oil and gas from large shale deposits, has led to production from geologic formations in parts of the country that previously did not produce significant amounts of oil or gas. The expansion of exploration and production across the United States has significantly increased public awareness of hydraulic fracturing and the potential impacts that it may have on water quality and water consumption, and increased calls for stronger regulation and safety protocols. The BLM's engineers and field managers have decades of experience exercising oversight of these wells during the evolution of this technology. This expertise, together with input from the public, industry, state, academic and other experts discussed below, forms the basis for the decision that new rules are needed and for the requirements contained in this rule.
The BLM's existing hydraulic fracturing regulations are found at 43 CFR 3162.3-2. Those regulations were established in 1982 and last revised in 1988, long before the latest hydraulic fracturing technologies were developed or became widely used. The Department of the Interior (Department) held a forum on hydraulic fracturing on November 30, 2010, in Washington, DC, attended by the Secretary of the Interior and more than 130 interested parties. The BLM later hosted public forums (in Bismarck, North Dakota on April 20, 2011; Little Rock, Arkansas on April 22, 2011; and Golden, Colorado on April 25, 2011) to collect broad input on the issues surrounding hydraulic fracturing. More than 600 members of the public attended the April 2011 forums. Some of the comments frequently heard during these forums included concerns about water quality, water consumption, and a desire for improved environmental safeguards for surface operations. Commenters also strongly encouraged the agency to require public disclosure of the chemicals used in hydraulic fracturing operations on Federal and Indian lands. Some commenters from the oil and gas industry suggested changes that would make the implementation of the rule more practicable from their perspective, while others opposed adoption of any such rules affecting hydraulic fracturing on the Federal mineral estate.
Around the time of the BLM's forums, at the direction of President Obama, the Secretary of Energy convened a Shale Gas Production Subcommittee (Subcommittee) of the Secretary of Energy Advisory Board to evaluate hydraulic fracturing issues. The Subcommittee met with industry, service providers, state and Federal regulators, academics, environmental groups, and many other stakeholders. On August 18, 2011, the Subcommittee issued initial recommendations in its “90-day Interim Report.” The Subcommittee issued its final report, titled “Shale Gas Production Subcommittee Second Ninety Day Report” on November 18, 2011. The Subcommittee recommended, among other things, that more information be provided to the public about hydraulic fracturing operations, irrespective of whether those operations occur on the Federal mineral estate, including disclosure of the chemicals used in fracturing fluids. The Subcommittee also recommended the adoption of stricter standards for wellbore construction and testing. The final report also recommended that operators engaging in hydraulic fracturing undertake pressure testing to ensure the integrity of all casings, as well as the use of FracFocus as a means to report the use of hydraulic fracturing chemicals. These reports are available to the public from the Department of Energy's Web site at
On May 11, 2012, the BLM published in the
After reviewing the comments on the proposed rule, the BLM published a supplemental notice of proposed rulemaking on May 24, 2013 (78 FR 31636). The BLM received numerous requests for extension of the comment period on the supplemental proposed rule. Because of the complexity of the rule and well stimulation procedures, the BLM extended the comment period on the rule for 60 days. The closing date of the extended comment period was August 23, 2013. The BLM received over 1.35 million comments on the supplemental proposed rule. Substantive comments on the initial proposed and supplemental proposed rules that informed the BLM's decisions on the final rule are discussed in the section-by-section discussion of this preamble.
This final rule applies to all wells regulated by the BLM, whether on Federal, tribal, or individual Indian trust or restricted fee lands. The lands covered by the rule have not changed since the rule was first proposed.
Tribal consultation is a critical part of this rulemaking effort, and the Department is committed to making sure tribal leaders play a significant role as the BLM and the tribes work together
In June 2012, the BLM held additional regional consultation meetings in Salt Lake City, Utah; Farmington, New Mexico; Tulsa, Oklahoma; and Billings, Montana. Eighty-one tribal members representing 27 tribes attended the meetings. In these sessions, the BLM and tribal representatives engaged in substantive discussions of the proposed hydraulic fracturing rule. A variety of issues were discussed, including, but not limited to, the applicability of tribal laws, validating water sources, inspection and enforcement, wellbore integrity, and water management, among others. Additional individual consultations with tribal representatives have taken place since that time. Also, consultation meetings were held at the National Congress of American Indian Conference in Lincoln, Nebraska, on June 18, 2012, and at New Town, North Dakota on July 13, 2012.
After publication of the supplemental proposed rule, the BLM again held regional meetings with tribes in Farmington, New Mexico, and Dickinson, North Dakota in June 2013. Representatives from six tribes attended. The discussions included a variety of tribal-specific and general issues. One change resulting from those discussions is the re-drafting of final section 3162.3-3(k) to clarify that tribal and state variances are separate from variances for a specific operator. The BLM again offered to follow up with one-on-one consultations, and several such meetings were held with individual tribes. Several tribes, tribal members, and associations of tribes provided comments on the supplemental proposed rule. The BLM understands the importance of tribal sovereignty and self-determination, and seeks to continuously improve its communications and government-to-government relations with tribes. Responses from tribal representatives informed the agency's actions in defining the scope of acceptable hydraulic fracturing operations. One of the outcomes of these meetings is the requirement in this rule that operators certify to the BLM that operations on Indian lands comply with applicable tribal laws.
In March 2014, the BLM invited tribes to participate in another meeting in Denver, Colorado. Representatives from seven tribes attended. There was significant discussion of issues raised in the comments on the supplemental proposed rule. The BLM subsequently held several consultations with individual tribes.
The BLM has been and will continue to be proactive about tribal consultation under the Department's Tribal Consultation Policy, which emphasizes trust, respect, and shared responsibility in providing tribal governments an expanded role in informing Federal policy that impacts Indian lands.
Several tribal representatives and tribal organizations commented that the hydraulic fracturing rule should not apply on Indian land, or that tribes should be allowed to decide not to have the rule apply on their land (that is, “opt out” of the rule). However, the Indian Mineral Leasing Act (IMLA) provides in a pertinent part as follows: “All operations under any oil, gas, or other mineral lease issued pursuant to the terms . . . of this title or any other Act affecting restricted Indian lands shall be subject to the rules and regulations promulgated by the Secretary of the Interior.” 25 U.S.C. 396d. The Department has consistently applied uniform regulations governing mineral resource development on Indian and Federal lands. Thus, an “opt out” provision would not be consistent with the Department's responsibilities under IMLA, and the final rule does not provide such an option.
There has also been a suggestion that the Secretary should delegate her regulatory authority to the tribes if the tribe has regulations that meet or exceed the standards in the BLM regulation. The IMLA does not authorize the Secretary to delegate her regulatory responsibilities to the tribes, and therefore the final rule does not include a delegation provision. Nonetheless, there are opportunities for tribes to assert more control over oil and gas operations on tribal land by entering into Tribal Energy Resource Agreements under the Indian Energy Development and Self-Determination Act (part of the Energy Policy Act of 2005), and to pursue contracts under the Indian Self-Determination and Education Assistance Act of 1975.
Also, the final rule defers to state (on Federal land) or tribal (on Indian land) designations of aquifers as either requiring protection from oil and gas operations, or as exempt from the requirement to isolate water-bearing zones in section 3162.3-3(b), so long as those designations are not inconsistent with protections required pursuant to the SDWA (also see the definition of “usable water”). Revised section 3162.3-3(k) provides that for lands within the jurisdiction of a state or a tribe, that state or tribe could work with the BLM to craft a variance that would allow compliance with state or tribal requirements to be accepted as compliance with the rule, for state or tribal provisions that are found to meet or exceed this rule's standards. The BLM would enforce the variance as the Federal rule and the appropriate State or tribe would enforce the variance under its authority.
The BLM will continue its coordination with states and tribes to establish or review and strengthen existing agreements related to oil and gas regulation and operations. During the rulemaking process, the BLM hosted multiple discussions with state governments to enhance coordination with oil and gas permitting, inspection, and enforcement. In August 2013, and then again in March 2014, the Acting Assistant Secretary for Land and Minerals Management invited the Governors and their representatives from those states with significant oil and gas operations, to meet with the BLM and discuss the objectives of the ongoing rulemaking as well as potential options for establishing agreements to assist in implementing the BLM's oil and gas program. The BLM's overall intent for these discussions is to minimize duplication and maximize flexibility though its coordination with states and tribes. We anticipate that these new and improved agreements will reduce regulatory burdens and increase efficiency, while fulfilling the Secretary's responsibilities mandated by statutes as steward for the public lands and trustee for Indian lands. As this rule is implemented, the BLM will continuously review these agreements along with the new variance process allowed by the rule, and consider improvements as necessary.
On Federal lands, the BLM enforces BLM regulations and lease conditions,
The BLM is working closely with the GWPC and the IOGCC, in coordination with the DOE, to provide for the disclosure of chemicals in the hydraulic fracturing fluids by the operators to the BLM through the existing public access Web site,
As of March 1, 2015, this online database includes information provided by operators concerning oil and gas wells in 20 states, and it is our understanding that a few more states are considering use of this database. It includes information from over 72,700 wells and from more than 500 companies. The list of states currently using FracFocus and the states considering using FracFocus are listed as follows:
The Secretary of Energy Advisory Board's Task Force on FracFocus 2.0 has identified a number of areas in which FracFocus needs improvement.
The BLM recognizes the efforts of some states to regulate hydraulic fracturing and seeks to avoid duplicative regulatory requirements. It is important to recognize that a major impetus for a separate BLM rule is that states are not legally required to meet the stewardship standards that apply to public lands and do not have trust responsibilities for Indian lands under Federal laws. Thus, the rule may expand on or set different standards from those of states that regulate hydraulic fracturing operations. This final rule encourages efficiency in the collection of data and the reporting of information by allowing operators in states that require disclosure on FracFocus to meet both the state and the BLM requirements through a single submission to FracFocus.
The BLM encourages the public disclosure of all chemicals used in any hydraulic fracturing operation. However, because the identities of some chemicals may be entitled to protection under Federal law as trade secrets, the BLM is allowing that information to be withheld if the operator and any other owner of the trade secret submit affidavits containing specific information explaining the reasons for the claim for protection. If the BLM has questions about the validity of the claim for protection, the BLM can require the operator to provide the withheld information to the bureau, and then would make a determination as to whether the data is properly withheld from the public.
The BLM has an extensive process in place to ensure that operators conduct oil and gas operations in an environmentally sound manner that protects resources. This rule adds specific requirements for hydraulic fracturing operations, which supplement the existing requirements. The following is a description of these existing processes and requirements:
Typically, the first step in the development or revision of an RMP is for the BLM to hold public scoping meetings to identify the primary issues that the BLM should consider and address in the RMP. If, for example, the public identifies tracts of land that are heavily used for recreational activities or that hold special environmental significance, the BLM may consider closing these tracts to oil and gas leasing or placing restrictions on development. Restrictions can include limiting the timing of oil and gas activities to avoid certain impacts, setbacks from sensitive resources, establishing limits on surface disturbance, and prohibiting surface occupancy entirely. Some areas, such as wilderness areas or land within an
Once various land use options have been developed the BLM generally analyzes the environmental impacts of the alternatives through an Environmental Impact Statement (EIS), which offers additional opportunity for public involvement. For proposed land use decisions, such as keeping areas open for oil and gas leasing, environmental impacts are assessed based on a Reasonable Foreseeable Development (RFD) Scenario that projects the estimated levels and types of industry activity and the associated surface disturbance that might occur during the life of the RMP. Because the RMP and EIS generally cover all the Federal land and mineral estate administered by a BLM field office, the impact analysis is typically done on a broad scale. Mitigation measures developed through the draft RMP and EIS process can be implemented as stipulations on oil and gas leases. In addition to compliance with the National Environmental Policy Act (NEPA), the BLM must comply with the National Historic Preservation Act and the Endangered Species Act (ESA) and engage in a consultation process with the U.S. Fish and Wildlife Service under the ESA, if threatened or endangered species or critical habitat may be affected.
Once a draft RMP and EIS are developed, the public has an additional opportunity to review and comment on the analysis and proposed mitigation measures in the EIS. When all comments have been considered, the BLM develops a final RMP and EIS. The Record of Decision finalizes the RMP, selecting a final action to be adopted from a reasonable range of alternatives and explaining the rationale for the decision. Once the Record of Decision is signed, the BLM makes all land use decisions, including oil and gas development decisions, in accordance with the RMP.
An interdisciplinary team consisting of resource specialists develops the NEPA documentation. The interdisciplinary team visits the site to gather on-the-ground data on potential impacts and mitigation measures. After the site visit, an EA is drafted, including coordination with county, state, and Federal agencies, and consultation with Indian tribes, if applicable, in the area proposed for leasing. EAs are posted on the BLM Web site and are available in the public room(s) at BLM field offices for public review and comment, typically for a 30-day period. The BLM reviews and addresses comments received during that 30-day period when it finalizes the EA. Specific mitigation measures are developed in the context of the NEPA review and are included in a notice to potential bidders of an oil and gas lease at a lease sale. If the environmental review concludes with a finding that the proposed lease issuance would result in no significant impacts to the quality of the human environment (FONSI), then the lease parcel can be included in the next scheduled lease sale without any further NEPA analysis. Upon issuance by the BLM, the lease allows the operator to conduct operations on the lease.
Existing section 43 CFR 3162.3-1 and Onshore Order 1 require an operator to get approval from the BLM prior to drilling a well. The operator must submit an APD containing all of the information required by Onshore Order 1. This includes a completed Form 3160-3, Application for Permit to Drill or Re-Enter, a well plat, a drilling plan, a surface use plan, bonding information, and an operator certification.
Upon receiving a drilling proposal on Federal lands, the BLM is required by existing section 3162.3-1(g) to post information for public inspection for at least 30 days before action to approve the APD. The information must include: The company/operator name; the well name/number; and the well location described to the nearest quarter-quarter section (40 acres), or similar land description in the case of lands described by metes and bounds, or maps showing the affected lands and the location of all tracts to be leased and of all leases already issued in the general area. Where the inclusion of maps in such posting is not practicable, the BLM provides maps of the affected lands available to the public for review. The public posting is in the office of the BLM authorized officer and in the appropriate surface managing agency office, if other than the BLM. Some field offices also make this information available on the field office Web site. The public may review the posted information and provide any input they would like the BLM to consider during its environmental analysis. If the public has questions and concerns regarding drilling proposals, they can meet with BLM staff and share those concerns.
The drilling plan is a critical, detailed, and multi-faceted component of the APD that allows BLM engineers and geologists to complete an appraisal of the technical adequacy of, and environmental effects associated with, the proposed project. The drilling plan must include:
• Geological information, including the name and estimated tops of all geologic groups, formations, members, and zones as well as the estimated depths and thickness of formations, members, or zones potentially containing usable water, oil, gas, or prospectively valuable deposits of other minerals that the operator expects to encounter, and their plans for protecting such resources.
• Minimum specifications for blowout prevention equipment that will be used to keep control of well pressures encountered while drilling.
• A description of the proposed casing program, including the size, grade, weight, and setting depth of each casing string.
• Detailed information regarding the proposed cementing program, including the amount and types of cement the operator will use for each casing string, which is critical in establishing a barrier outside the casing between any hydrocarbon bearing zones and usable water zones. BLM engineers evaluate the proposed cementing program to ensure that the volume and strength of the cement is adequate to achieve the desired protections.
• Information regarding the proposed drilling fluid and proposed testing, logging, and coring procedures.
• An estimate of the expected bottom-hole pressure and any anticipated abnormal pressures, temperatures, or potential hazards that the well may encounter. BLM geologists and engineers review this information to determine if any other anticipated hazards exist and to ensure that there will be adequate mitigation to address those hazards.
• Other information that may be pertinent, including the directional drilling plan for deviated or horizontal wells so that BLM engineers can look for potential issues with existing wells.
Just as the drilling plan allows the BLM to ensure the down-hole technical adequacy of the proposed project, the surface use plan provides the BLM with information needed to ensure safe operations, adequate protection of the surface resources, groundwater, and other environmental components in areas where the BLM manages the surface.
The surface managing agency must approve surface use plans where the BLM does not manage the surface. The Bureau of Indian Affairs is considered to be the surface management agency for Indian lands. In the surface use plan, operators must also describe any Best Management Practices (BMPs) they expect to use. BMPs are mitigation measures applied to oil and natural gas drilling and production to help ensure that operators conduct energy development in an environmentally responsible manner. BMPs can protect water, wildlife, air quality, and landscapes. The BLM encourages operators to incorporate BMPs into their plans. Information concerning BMPs is available on the BLM's Web site at:
Where the BLM manages the surface, the operator's surface use plan should incorporate the BLM's “Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development,” which is commonly referred to as “The Gold Book.” The BLM developed “The Gold Book” to assist operators by providing information on obtaining permit approval and conducting environmentally responsible oil and gas operations. It is available on the BLM's Web site at:
In general, the surface use plan must include the following:
• Location and description of, as well as maintenance plan for, existing and new roads the operator plans to use to access the proposed well.
• A map showing all known wells, regardless of their status (producing, abandoned, etc.) within a one-mile radius of the proposed location so that the BLM can ensure the proposal does not conflict with any current surface use. The BLM also uses this well information to identify any potential downhole conflicts or issues between the existing wells and the proposed well.
• A map or diagram showing the location of all production facilities and lines the operator will install if the well is successful (a producing well), as well as any existing facilities.
• Information concerning the water supply, such as rivers, creeks, springs, lakes, ponds, and wells that the operator plans to use for drilling the well.
• A written description of the methods and locations it proposes for safe containment and disposal of each type of waste materials that result from drilling the proposed well. The narrative must include plans for the eventual disposal of drilling fluids and any produced oil or water recovered during testing operations.
• A diagram in the surface use plan of the proposed well site layout.
• A plan for the surface reclamation or stabilization of all disturbed areas.
Another component of the APD is proof of adequate bond coverage as required by existing 43 CFR 3104.1 for Federal lands and 25 CFR 211.24, 212.24, and 225.30, for Indian lands. These regulations require the operator or the lessee to have an adequate bond in place prior to the BLM's approval of the APD. If the BLM determines that the current bond amount is not sufficient, the BLM can require additional bond coverage. The BLM determines the need for bond increases by considering the operator's history of violations, the location and depth of wells, the total number of wells involved, the age and production capability of the field, and any unique environmental issues.
Upon receipt of a complete APD, the BLM will schedule an onsite inspection with the operator so that the BLM and operator may further identify site-specific resource concerns and requirements not originally identified in the application.
The onsite inspection team will include the BLM, a representative of any other surface management agency and the operator or permitting agent. When the onsite inspection is on private surface, the BLM will invite the surface owner to attend. The purpose of the onsite inspection is to discuss the proposal; determine the best location for the well, road, and facilities; identify site-specific concerns and potential environmental impacts associated with the proposal; and discuss the conditions of approval or possible environmental BMPs. If the BLM identifies resource conflicts, the BLM has the authority to require the operator to move surface facilities to locations that would reduce resource impacts while still allowing development of the leased minerals.
The environmental analysis may be conducted for a single well, a group of wells, or for an entire field. The public is welcome to provide input to the BLM for inclusion in the analysis. As discussed previously, the BLM posts notices of all Federal APDs for public inspection in the authorizing office. For large projects, such as field development environmental assessments or environmental impact statements, the BLM will go through public scoping and may issue a draft analysis for public comment prior to completing the final analysis and issuing a decision.
The environmental analysis will identify potential impacts from the proposed action. The BLM will develop any necessary conditions of approval to mitigate those potential impacts. If unacceptable impacts are identified, the BLM will ask the operator to modify its proposal, or the BLM may deny the application. The BLM will attach the conditions of approval to the approved APD that the operator must follow. Examples of conditions of approval include road improvements, additional erosion control, or seasonal restrictions on some activities. In cases where the BLM manages the surface, the BLM may also require baseline water testing prior to drilling.
Onshore Order 2 also requires the operator to:
• Conduct the proposed casing and cementing programs as approved to protect and isolate all usable water zones, lost circulation zones, abnormally pressured zones, and any prospectively valuable deposits of minerals. It also requires the operator to report all indications of usable water.
• Employ technical measures to center the casing in the drilled hole prior to cementing in order to ensure wellbore integrity. It also requires the operator to cement the surface casing up to the surface either during the primary cement job or by remedial cementing, which ensures that all usable water zones behind the surface casing are isolated and protected.
• Wait until the cement for all casing strings achieves a minimum of 500 pounds per square inch (psi) compressive strength at the casing shoe prior to drilling out the casing shoe and utilize proper cementing techniques.
• Pressure test the casing prior to drilling out the casing shoe to ensure the integrity of the casing. The operator must also conduct a pressure integrity test of each casing shoe on all exploratory wells, and on that portion of any well approved for a 5,000 psi blowout preventer. The pressure test ensures the integrity of the cement around the casing shoe.
In addition, Onshore Order 2 identifies the minimum requirements for blowout prevention equipment and the minimum standards for testing the equipment. Proper sizing, installation, and testing of the blowout prevention equipment ensures that the operator maintains control of the well during the drilling process, which is necessary for protection of usable water zones.
The BLM natural resource specialists conduct environmental inspections of drilling operations that focus primarily on the surface use portion of the approved drilling permit. This includes inspection of the access road, the well pad, and pits. While the BLM does not have the budget or personnel to inspect every drilling operation on Federal and Indian minerals, the BLM conducts inspections in accordance with an annual risk-based strategy to ensure compliance with the regulations, lease stipulations, and permits.
Within 30 days after the operator completes a well, the operator is required by existing regulations to submit a BLM Well Completion or Recompletion Report and Log (Form 3160-4), which provides drilling and completion information. Similar to completion of a new well, an existing well can be recompleted to restore productivity and thus produce oil or gas which would have otherwise been abandoned. This document includes the actual casing setting depths and the amount of cement the operator used in the well, together with information regarding the completion interval between, for example, the top and bottom of the formation, the perforated interval, and the number and size of perforation holes. The operator is also required to submit copies of all electric and mechanical logs. The BLM reviews this information to ensure that the operator set the casing and pumped the cement according to the approved permit.
The BLM inspects both well plugging and surface restoration. Well plugging inspections are completed to ensure the plugs are set in accordance with the
The regulations and Onshore Orders that have been in place to this point have served to provide reasonable certainty of environmentally responsible development of oil and gas resources on public lands, but are in need of revision as extraction technology has advanced. The final rule will complement these existing rules by providing further assurance of wellbore integrity, requiring with limited exception public disclosure of chemicals used in hydraulic fracturing, and ensuring safe management of recovered fluids. Taken together these regulations establish baseline environmental safeguards for hydraulic fracturing operations across all public and Indian lands.
As was discussed in the initial and supplemental proposed rules, the BLM is revising its hydraulic fracturing regulations, found at 43 CFR 3162.3-2, and adding a new section 3162.3-3. Existing section 3162.3-3 is retained and renumbered. As stewards of the public lands and minerals and as the Secretary's regulator for operations on oil and gas leases on both public and Indian lands, the BLM has evaluated the increased use of hydraulic fracturing practices over the last decade and determined that the existing rules for hydraulic fracturing require updating.
The FLPMA directs the BLM to manage the public lands so as to prevent unnecessary or undue degradation, and to manage those lands using the principles of multiple use and sustained yield. The FLPMA defines multiple use to mean, among other things, a combination of balanced and diverse resource uses that takes into account long-term needs of future generations for renewable and non-renewable resources. The FLPMA also provides that the public lands be managed in a manner that will protect the quality of their resources, including, but not limited to, ecological, environmental, and water resources. The Mineral Leasing Act and the Mineral Leasing Act for Acquired Lands authorize the Secretary to lease Federal oil and gas resources, and to regulate oil and gas operations on those leases, including surface-disturbing activities.
The Act of March 3, 1909, the Indian Mineral Leasing Act and the Indian Mineral
As discussed in the background section of this preamble, the increased use of well stimulation activities over the last decade has generated concerns among the public about hydraulic fracturing and about the chemicals used in hydraulic fracturing. This final rule is intended to increase transparency for the public regarding the fluids used in the hydraulic fracturing process, provide assurance that wellbore integrity is maintained throughout the fracturing process and ensure that the fluids that flow back to the surface from hydraulic fracturing operations are properly stored, disposed of, or treated. The BLM's engineers and field managers have decades of experience exercising oversight of these wells during the evolution of this technology. This expertise, together with input from the public, industry, state, academic and other experts discussed below, forms the basis for the decision that new rules are needed and for the requirements contained in this rule.
The following chart explains the major changes between the supplemental proposed rule and this final rule. A similar chart explaining the differences between the proposed and supplemental proposed rules appears in the supplemental proposed rule at 78 FR 31641 and a chart explaining the differences between the existing regulations and the original proposed rule appears in the proposed rule at 77 FR 27694.
In this preamble, the BLM discusses many of the comments received on the supplemental and proposed rules. Commenters provided detailed and helpful information that assisted in framing the issues and ultimately in producing this final rule. The Department does not address every comment in this final rule, because the changes in this rule have mooted some comments on the initial proposed rule and the supplemental proposed rule. Other comments were not central to the evaluation the BLM has undertaken, and thus discussion of those few comments would not contribute to the public's understanding of the reasons for the final rule.
Additionally, not every change in the final rule responds to a specific comment. Some revisions clarify the final rule, and still other revisions allow this final rule to be more effective or reduce inefficiencies.
As an administrative matter, this rule would amend the authorities section for the BLM's oil and gas operations regulations at 43 CFR 3160.0-3 to include the FLPMA. Section 310 of the FLPMA authorizes the Secretary of the Interior to promulgate regulations to carry out the purposes of the FLPMA and other laws applicable to the public lands. See 43 U.S.C. 1740. This amendment would not be a major change and would have no effect on lessees, operators, or the public.
This section defines terms related to the regulation and the hydraulic fracturing process. The terms annulus, bradenhead, cement evaluation log, confining zone, hydraulic fracturing, hydraulic fracturing fluid, and proppant are used to describe the requirements of the rule. The term “master hydraulic fracturing plan” (MHFP) would allow operators to gain certain efficiencies in submitting information to the BLM. The actual process is explained in sections 3162.3-3(c) and (d).
The final rule incorporates several changes to the definitions in section 3160.0-5 from the supplemental proposed rule. The definition of cement evaluation log is added to this section by moving it from section 3162.2-3(e)(2) in the supplemental proposed rule to the definitions section of the final rule. Because the final rule uses the term several times, the BLM decided to add the definition to this section.
The term “master hydraulic fracturing plan” is added to take the place of portions of the type well approval in section 3162.3-3(d) of the proposed rule. The final rule retains the ability for operators to submit hydraulic fracturing proposals at the APD or NOI stage for a group of similar wells with a single submission, including the information regarding geology, etc., required in sections 3162.3-3(d)(1) through (d)(7) of this rule. The BLM believes that this will streamline the permitting process without sacrificing the quality of the review. As a matter of current practice, many oil and gas operators use the APD review and approval process to satisfy other BLM approval requirements. For example, the construction of a road to access a drilling location or a pipeline to transport production from a well requires a right-of-way (ROW) in certain cases. Many operators submit their plan of development for their proposed access road or pipeline and a ROW application with their APD. The BLM performs its review of the ROW application at the same time it is reviewing the APD. An MHFP may not be used for the information required to demonstrate well integrity in section 3162.3-3(e). As discussed later, the “type well” concept has been eliminated and each well will be required to be demonstrated to meet the performance standards in this rule.
In addition, the requirement that an MHFP only apply to wells in the same field is eliminated primarily because the term “field” is not well defined. Instead, in the final rule, an MHFP applies to any well where the geologic characteristics are substantially similar. The geographic area for which an MHFP applies will be at the discretion of the field office. The MHFP is similar in concept to the Master Development Plan (MDP) allowed in Onshore Order 1, although the use of one does not necessarily depend upon the use of the other. The MHFP is specific to the technical aspects of hydraulic fracturing of a group of wells; whereas, the MDP's purposes include encouraging logical field development and ensuring consideration of the environmental effects associated with development of the field in the accompanying NEPA analysis and documentation. The MHFP and MDP can apply to different groups of wells.
The term “hydraulic fracturing” was also modified by adding the phrase “by applying fluids under pressure.” This change is based on comments seeking clarification of the types of operations that fall under the scope of this rule.
The term “type well” was eliminated. The BLM determined that the use of a type well CEL as a model for other wells that were geologically similar was not a statistically valid approach for ensuring wellbore integrity. Because geologic conditions and drilling procedures can vary significantly from well to well, sometimes even for wells drilled from the same pad, a CEL on a single sample well cannot reliably be extrapolated to other wells with any level of confidence. Therefore, the “type well” concept, as it applied to CELs, is eliminated in the final rule.
The term “confining zone” is added to the final rule because the BLM is requiring the operator to identify both the confining zone and any known faults or fractures that transect the confining zone in the APD or NOI for hydraulic fracturing approval. The definition of confining zone is based on the U.S Environmental Protection Agency (EPA)'s definition under the Underground Injection Control (UIC) program, modified to apply specifically to hydraulic fracturing.
The term “refracturing” was eliminated from the final rule because the requirements for permitting, performing, monitoring, and reporting hydraulic fracturing operations are identical whether the well is hydraulically fractured for the first time or any subsequent stimulation.
The BLM made several modifications to the definition of the term “usable water” in response to comments received.
The first change in the “usable water” definition was to eliminate paragraph (2) from the definition in the supplemental proposed rule because it would be unreasonable to expect an operator to know that other users could be using an aquifer for agricultural or industrial purposes and because an operator would have no way of knowing if other users could be adversely affected by hydraulic fracturing. Decisions on those matters are for state or tribal water regulators, not the BLM. Thus, paragraph (1)(ii) in the final rule defers to State (for Federal lands) or tribal (for Indian lands) determinations that groundwater that does not meet the definition of “underground sources of drinking water” (USDWs) in EPA's regulations are nonetheless sources of drinking water that must be protected. The other change was to reorganize the clauses in the definition to separate those items that would be deemed usable water from those items that would not be deemed usable water.
Numerous commenters were confused about the threshold for Total Dissolved Solids (TDS) in usable water. Prior to the publication of this rule, BLM regulations (existing section 3162.5-2(d)) require the operator to “isolate freshwater-bearing and other usable water containing 5,000 ppm or less of total dissolved solids . . .,” and Onshore Oil and Gas Order No. 2, Drilling Operations on Federal and Indian Oil and gas leases (53 FR 46798) (Onshore Order 2), section III. B. requires casing and cement to “protect and/or isolate all usable water zones.” Usable water is defined in section II.Y of Onshore Order 2 as “generally those waters containing up to 10,000 ppm of total dissolved solids.” The requirement in the CFR was inconsistent with the requirement in Onshore Order 2.
This rule corrects the inconsistency between the two by removing the 5,000 ppm standard in 43 CFR 3162.5-2(d) and replacing it with language that is consistent with Onshore Order 2. The requirement to protect and/or isolate usable water generally containing up to 10,000 ppm of TDS has been in effect since 1988, when Onshore Order 2 became effective. This rule does not
Because of the inconsistency between the supplemental proposed rule and existing codified regulations, some commenters were under the impression that this rule was increasing the level of protection for usable water from 5,000 ppm to 10,000 ppm, while other commenters believed that this rule was proposing to decrease the level of protection from 10,000 ppm to 5,000 ppm. Neither impression is true. This rule maintains the 10,000 ppm standard that has been in place since 1988. The BLM still believes that a 10,000 ppm threshold is appropriate because it is consistent with the threshold used as part of the definition of “underground sources of drinking water” in EPA regulations implementing the Safe Drinking Water Act (SDWA). The SDWA was enacted in 1974 and is the primary Federal law that ensures the quality of American's drinking water (
• Numerous comments expressed concern that the requirement to protect usable water (section 3162.5-2) as defined would result in significantly increased costs because protecting water with TDS levels up to 10,000 ppm would require running casing and cement much deeper than it is currently run. Because the definition of usable water has not substantially changed in this rule, there will be no significant changes in costs of running casing and cement.
• Many commenters thought that there was no use in protecting water zones with TDS levels greater than 5,000 ppm, because water with a TDS higher than 5,000 is not suitable for human, agricultural, or industrial uses. One comment stated that the BLM considers water with TDS levels greater than 5,000 ppm as hazardous to wildlife. This rule does not change the primary criteria for protecting usable water up to 10,000 ppm, which has been in place for the past 26 years. Given the increasing water scarcity and technological improvements in water treatment equipment, it is not unreasonable to assume aquifers with TDS levels above 5,000 ppm are usable now or will be usable in the future.
• Some commenters expressed a concern that the conflicting definitions in Onshore Order 2 and in this rule will cause confusion for operators. There is no conflict between the definition in this rule and the definition in Onshore Order 2. This rule clarifies the term and incorporates specific inclusions and exclusion as to what is deemed to be usable water.
Several comments stated that the cost of running surface casing and cement deep enough to protect all usable water zones, as defined, would significantly increase the cost of drilling wells. This is an erroneous concern. It is not uncommon for deeper usable water zones to be protected with intermediate or production casing, which is allowed under Onshore Order 2 and this rule. No changes to the final rule were made as a result of these comments.
Several commenters suggested changing the definition of usable water to exclude aquifers that are not economical or feasible to use. The commenters said that these would include aquifers that are too deep, too small, too remote, or are not capable of achieving some set flow rate. No changes to the rule were made as a result of these comments. From a practical standpoint, excluding aquifers based on depth, size, location, flow rate, or other characteristics would be difficult in a national rule for several reasons. For example, the depths to which a water user might drill would depend on such factors as the need for water, the availability of other supplies, and the hydrologic characteristics of the aquifer (natural pressures might raise water in a deep well closer to the surface). Excluding aquifers from protection based on some arbitrary flow rate would be impractical. Measuring the flow rate potential of an aquifer would be a time-consuming and expensive process for operators to perform and for the BLM to review. Just as with oil and gas wells, the flow rate potential of a water well can depend on the specific location, depth, and methodology used. Furthermore, a flow rate that is inadequate for one type of use might be adequate for another type of use. State and tribal agencies, and EPA under the SDWA, have the expertise and authority to consider all the factors in characterizing groundwater.
Several commenters questioned the basis for the 10,000 ppm of TDS in the definition. The 10,000 ppm of TDS used in Onshore Order 2 and this rule is based on part of the definition of “underground source of drinking water” in EPA's regulations implementing SDWA.
Another change made to this definition in response to comments involved three exemptions from the definition of usable water listed in the supplemental proposed rule. The proposed exclusions in paragraphs (2)(i), (2)(ii), and (2)(iii) of the definition have been modified for clarity and to better reflect the roles of EPA and states and tribes in managing groundwater resources.
The proposed exclusion in paragraph (A) of the definition, regarding hydrocarbon zones, was added to the supplemental proposed rule based on comments received on the initial proposal (77 FR 27691). Some commenters noted correctly that developing minerals from a zone that is also a USDW requires specific authorization under the SDWA. The BLM has edited the exclusion in former paragraph (A)
The BLM received several comments objecting to any exemptions for protecting aquifers, as proposed in the definition of “usable water” under 3160.0-5. The commenters stated that it is impossible to predict what will constitute “usable” water in the future, especially considering drought and water scarcity. Therefore, they said that the BLM should be very conservative in protecting all groundwater with a TDS of less than 10,000 ppm. The commenters recommended deleting the exemptions under paragraphs (A), (B), and (C) of the usable water definition. The BLM disagrees that all groundwater with a TDS of less than 10,000 ppm must be deemed usable water in this final rule. The TDS is only one parameter in deciding whether water is usable. The amounts of other types of contaminants, depth, and available alternatives are other considerations. The final rule has modified the exemptions in paragraphs (2)(i), (2)(ii), and (2)(iii) of the usable water definition to clarify the central roles of states, tribes, and the EPA in categorizing groundwater and deciding upon the proper level of protection from
Some of the commenters suggested that the BLM should incorporate the exemption provisions of the SDWA directly into the definition of usable water instead of relying on designations through the SDWA.
No changes to this provision were made as a result of these comments. The BLM has neither the authority nor jurisdiction to designate groundwater as exempt from protection under the SDWA. Furthermore, the final rule protects usable water, which includes, but is not limited to USDWs. Aquifers that are not USDWs might be usable for agricultural or industrial purposes, or to support ecosystems, and the rule defers to the determinations of states (on Federal lands) and tribes (on Indian lands) as to whether such zones must be protected.
One industry group seemed to favor requiring operators to determine the TDS levels of aquifers already deemed by the state or tribe to require protection, and said that the TDS criterion was arbitrary and capricious, but included the same criterion in its proposed definition. That group's argument against the TDS criterion was that it did not consider other constituents, such as hydrocarbons, heavy metals, microorganisms, or toxic compounds, which would make waters unsuitable for use. The BLM's definition of usable water has for many years used a TDS criterion and TDS is a widely recognized criterion for entities contemplating use of particular waters. In the United States, most users prefer waters containing 10,000 ppm TDS or less.
The BLM agrees that different water users would also be concerned about various other water quality criteria. The most common dissolved solids in most aquifers encountered by oil and gas operations on Federal or Indian lands are salts. Operators can estimate salinity levels from drill logs. Other means of measuring TDS are straight forward and economical. The BLM declines to require operators to test aquifers for hydrocarbons, heavy metals, microorganisms or toxic compounds.
A few commenters mentioned that paragraphs (1) and (3) in the definition in the supplemental proposed rule are irrelevant because they would not occur with TDS levels above 10,000 ppm anyway. Paragraph (1) includes in the definition of usable water all groundwater that meets the definition of USDWs in EPA's regulations. However, the 10,000 ppm of TDS threshold established in the first sentence of the definition is based on part of EPA's regulatory definition of “underground source of drinking water” under the SDWA. The commenter concludes, therefore, that paragraph (1) is redundant and unnecessary. Paragraph (3) includes zones designated for protection by a state or a tribe. According to the commenters, however, there are no states or tribes that have designated a TDS threshold higher than 10,000 ppm. While the commenters are correct in their assertions, the BLM must anticipate that, in the future, conditions may change. Given the increasing threat of water scarcity and the advancement of technology, it is foreseeable that a TDS threshold higher than 10,000 ppm may be established under applicable law in the future for aquifers supplying agricultural, industrial, or ecosystem needs. By including these paragraphs in this rule, such zones would automatically be protected from contamination by subsequent hydraulic fracturing without requiring a rule change. No changes to the rule were made as a result of this comment.
Several commenters stated that the BLM has no jurisdiction over the waters of the various states. States and tribes generally administer and regulate rights to use surface water and groundwater within their jurisdictional boundaries. The EPA has authority over USWD in relation to injection wells under the SDWA, although EPA can and does approve states and tribes to implement their programs in lieu of the Federal program. The BLM understands the importance of states and tribes regulating the use of groundwater within their jurisdictions and generally agrees with the commenters. However, the Mineral Leasing Act (30 U.S.C. 181,
The BLM received comments both supporting and objecting to paragraph (2) of the definition in the supplemental proposed rule, which included in the definition of usable water, zones in use for supplying water for agricultural or industrial purposes, regardless of TDS concentration, unless the operator could demonstrate that zone would not be adversely affected. The commenters objecting to this provision said that operators are not in a position to know whether aquifers are in actual use, or to prove that hydraulic fracturing operations would not harm the water user, and that BLM should not be making determinations about groundwater use or harm to users. The BLM agrees with those comments and removed paragraph (2) in the final rule as a result.
Commenters supporting paragraph (2) of the definition in the supplemental rule indicated that even if a zone is not required to be protected according to the definition of usable water, because that zone supplies water that is actually being used for agricultural or industrial purposes, the zone is self-evidently “usable.” The BLM agrees that an aquifer could be in actual use, even if it exceeds 10,000 ppm TDS. However, the rule defers to the state or tribal agency to make such determinations, as appropriate. Entities using water exceeding 10,000 ppm TDS may ask the appropriate state or tribal agency to designate that zone as usable water, in which case it would have to be isolated and protected from contamination during hydraulic fracturing.
One comment suggested that the BLM—not the operator—should make the determination that hydraulic fracturing would not harm aquifers in use, in paragraph (2) of the definition. The BLM did not make any changes to the rule based on this comment because proposed paragraph (2) has been deleted from the final rule based on other comments received.
The final rule includes a new paragraph (1)(ii) that includes in the definition of usable water “[u]nderground sources of drinking water under the law of the state (for Federal lands) or tribe (for Indian lands).” New paragraph (1)(ii) defers to designations of aquifers as sources of drinking by states and tribes, even if the aquifer would not meet the definition of USDW in EPA's regulations. That could occur, for example, if an aquifer cannot supply a public water system, but is used for drinking water by persons not connected to a public water system.
Several commenters found the definition of usable water in the supplemental proposed rule to be
Several comments stated that the BLM should eliminate the usable water exemption for zones that states or tribes have designated as exempt (paragraph (4)(C) of the definition of usable water in the supplemental proposed rule). The issue raised by the commenters is that states and tribes typically base their exemptions on water that is unsuitable for drinking, livestock, or irrigation, and not on groundwater-dependent ecosystems. According to the comments, by adopting state or tribal designations, such aquifers would not have to be protected or isolated during hydraulic fracturing operations and this could damage or destroy the ecosystems that are dependent on them.
The BLM did not make any changes to the rule based on these comments for two reasons. First, while the BLM is responsible for preventing unnecessary or undue degradation of resources on public lands and exercising part of the Secretary's trust responsibility for Indian resources, designating the uses of aquifers is a matter for states and tribes, to the extent not otherwise inconsistent with the SDWA.
Second, the BLM does not agree with the commenter's assertion from a practical standpoint. The majority of groundwater-dependent ecosystems would be dependent on relatively shallow groundwater. Shallow groundwater (typically less than 1000 feet deep) is protected by surface casing, regardless. Some commenters said that the criterion of 10,000 ppm TDS exceeds the recommended standard for USDW. The EPA's definition is as follows: Underground source of drinking water (USDW) means an aquifer or its portion “(a)(1) Which supplies any public water system; or (2) Which contains a sufficient quantity of ground water to supply a public water system; and (i) Currently supplies drinking water for human consumption; or (ii) Contains fewer than 10,000 mg/l total dissolved solids; and (b) Which is not an exempted aquifer” (40 CFR 144.3).
The rule seeks to protect usable water, which includes, but is not limited to, USDWs. In addition to public water supplies, there are many industrial and agricultural applications that can use water of up to or more than 10,000 ppm TDS. The final rule is not revised as a result of these comments.
Some commenters suggested that the 10,000 ppm TDS criterion could conflict with existing state groundwater standards. However, no commenter has explained how a requirement for oil and gas wells on Federal or Indian lands to verify isolation and protection of aquifers with up to 10,000 ppm TDS will preempt or interfere with states' or tribes' regulation of their ground water quality or quantity. If a state or tribe requires aquifers of lower quality to be isolated and protected, operators would need to comply with those requirements.
Several commenters offered their own definitions of usable water. One suggestion was to incorporate the entire EPA definition of a USDW instead of developing the BLM's own definition. The commenters stated that this would improve consistency and foster cooperation between the EPA and the BLM. The final rule references USDWs as one of the criteria that would constitute usable water. However, USDWs do not necessarily include water zones that have been designated by states or tribes as usable water for agriculture, industry, or other needs. The BLM believes that these zones are also worthy of protection. Therefore, the BLM did not accept this suggestion.
Other suggestions recommended defining usable water as only USDWs or zones designated by states or tribes. In the final rule, the BLM adopted this suggestion in part by eliminating paragraph (2) of the definition in the supplemental proposed rule, which would have also included zones being used for agricultural or industrial purposes, regardless of the TDS level.
One commenter stated that the BLM should require that casing used to isolate usable water be set at least 100 feet below the base of usable water to ensure the usable water zone is protected. Another commenter recommended that corrosive zones and flow zones also be isolated. The BLM did not make any changes to the rule based on this comment because the scope of this rule is hydraulic fracturing. Well drilling, including requirements for casing strings and zone isolation, is regulated by Onshore Order 2 and is based on site-specific downhole conditions.
One commenter recommended that the rule refer to “established” usable water zones to add clarity. The BLM did not make any changes to the rule based on this comment because the term “usable water” is clearly defined.
Numerous comments objected to the narrow focus of the definition of hydraulic fracturing and suggested that the BLM reinstate the broader definition from the May 2012 proposed rule. Some of the commenters stated that this rule needs to regulate well stimulation and acidization because these operations pose risks similar to those from hydraulic fracturing and because the existing regulations are inadequate to address these risks. The BLM did not revise the rule based on these comments. This rule specifically addresses risks posed by the combination of high pressures, chemical constituents, and procedures used to hydraulically fracture a well. Some commenters said that “deep hydraulic fracturing” should be exempt from this rule. The definition of hydraulic fracturing includes all hydraulic fracturing operations regardless of depth. The BLM requires protection and isolation of usable water regardless of depth of the well or depth at which hydraulic fracturing occurs. No changes to the rule were made as a result of these comments.
Several commenters said that the rule should be modified to redefine hydraulic fracturing. Commenters indicated that the definition should include a statement regarding applying fluids under pressure. The BLM agrees and has revised the rule as a result of these comments. The BLM believes that an integral part of hydraulic fracturing is the concept of the application of high pressure, and this position is confirmed by a review of technical literature on hydraulic fracturing as well as consultation with state regulatory agencies. The definition in the final rule has been modified accordingly.
Several commenters suggested that the definition of refracturing should be modified to exempt different stages of a multi-stage fracturing operation. The commenters were concerned that under the definition in the supplemental proposed rule, the BLM could consider each stage as a refracture operation, thereby requiring a separate permit. It is not the intent of the BLM to require a separate permit for each stage of a multi-stage hydraulic fracturing operation and final section 3162.3-3(i) is modified to reflect that a hydraulic fracturing operation is considered to be complete only after the last stage is completed. The BLM did not make modifications to the definition of refracturing as a result of these comments because the definition of refracturing was deleted in
Several commenters suggested that the rule should be modified to treat refracturing differently than fracturing. The BLM disagrees with these comments because there is no practical purpose in distinguishing “fracturing” from “refracturing.” The permitting, operational issues, mechanical integrity test requirements, wellbore integrity, disclosure and possible variances for newly drilled wells and older previously fractured wells are the same; therefore, the BLM has removed the term and definition of refracturing in the final rule. The primary purpose of differentiating the two in the proposed rule was to recognize that the information required in section 3162.3-3(e) of the rule may not be available for older wells that would be “refractured.” However, upon further deliberation, the BLM determined that would be case for any well where approval for hydraulic fracturing was given subsequent to the drilling and completion of the well, regardless of whether or not the well had been hydraulically fractured previously. Therefore, the definition of refracturing is deleted from the final rule and all references to the term are removed. The requirements for hydraulic fracturing now apply uniformly to all fracturing operations that meet the definition in the rule. Section 3162.3-3(a) in the final rule was modified to allow for cases where hydraulic fracturing is approved subsequent to the drilling and completion of a well.
Several comments recommended that any hydraulic fracturing done within a certain amount of time of a previous fracturing job or that is done under similar conditions as the original hydraulic fracturing, should not be considered refracturing. The BLM did not make any changes based on this comment because the term “refracturing” was deleted from the final rule. This rule applies whenever pressure is used to fracture reservoir rock, regardless of how or when the operation occurs relative to a previous hydraulic fracturing.
One comment recommended specifically excluding “enhanced oil recovery using carbon dioxide” from the scope of this rule. However, if carbon dioxide or any other gas is used under pressure to fracture reservoir rock, the operation poses much the same risk as if the fracturing was done using a liquid as the fracturing fluid. The term “fluid” in the definition of hydraulic fracturing includes both liquids and gases. However, if the carbon dioxide or other fluid is injected not to fracture reservoir rock, but to stimulate production by other means, it would not be a hydraulic fracturing operation.
Several commenters said that the rule should be modified to define what constitutes the completion of hydraulic fracturing operations. The commenters indicated that the supplemental proposed rule would require the submittal of a completion report within 30 days of completion of hydraulic fracturing operations. The BLM did not revise the rule as a result of these comments. The BLM does not believe that a definition of “completion” is warranted in the context of these regulations. By definition, hydraulic fracturing ends when pressure is released for the last stage of the operation. It is at this point that the 30-day timeframe would begin for each well that is hydraulically fractured.
Several commenters said that the term “micro-seismograms” should be dropped from the list of CEL tools discussed in supplemental section 3163-3(e)(2). Commenters indicated that the term “micro-seismogram” as currently used does not refer to evaluating cement quality and is therefore confusing when included in cement evaluation provisions. The commenters said that conventional cement bond logs (CBL) used for the purposes of evaluating cement integrity around casing can be displayed by a variety of methods. One of those techniques was termed “micro-seismogram” (MSG) and referred to the x-y presentation of the entire received signal. Another presentation method, the variable density log (VDL), only displays the amplitude of that signal. Either, or both, of these presentation methods can be used to evaluate the integrity of the cement bond to casing and formation. It is true that the term “micro-seismogram” has much broader implications than just cement evaluation, and the rule has been modified as a result of these comments. The CEL discussion has been removed from the regulatory text at proposed section 3162.3-3(e)(2) and placed as a unique definition in the final rule in section 3160.0-5. Further, the CEL definition has been revised to remove any references to “micro-seismograms.” The BLM believes that this clarifies the intent of the rule. Additionally, section 3162.3-3(e)(2)(i) has been revised to provide flexibility for the authorized officer to approve other appropriate cement evaluation methods or devices.
Numerous commenters suggested that limiting the multiple well permitting, or type well, availability (referred to as Master Hydraulic Fracturing Plan in this rule) to a “field” in the definition was too restrictive and would nullify most of the benefits of a group submittal. Some commenters recommended that the BLM should better define what is meant by a “field”. Commenters offered numerous suggestions on the extent of what an MHFP should cover including “basin,” “pool,” “area,” “resource play,” “geographic area,” “geologic formation,” “section,” “unitized area,” and “county.” The BLM agrees that the term “field” is potentially too limiting, and has deleted the requirement that wells included in the scope of an MHFP must be in the same field. However, the BLM disagrees that other terms such as those suggested would be preferable. Therefore, in the final rule, the criteria for the scope of an MHFP are wells that are geologically similar. Under this rule, the decision on the geographic or geologic extent of an MHFP is up to the field office reviewing the application and is based on local geology and drilling practices.
Several commenters asked if there would be any limits on the number of wells or the timeframe over which a multiple well permit could apply to other wells in a group submission for hydraulic fracturing. Under the final rule, the MHFP applies to any number of wells that meet the criteria in the definition of an MHFP and there is no specific timeframe for when wells under an MHFP must be drilled. Decisions regarding the applicability of wells under an MHFP are made at the BLM field office based on local geologic conditions and drilling practices.
Several commenters suggested two definitions of type well: One that would apply to permitting and one that would apply to operations such as running a CEL. The BLM did not revise the rule based on these comments because the term “type well” is deleted in the final rule. While the option of permitting a group of wells to be hydraulically fractured is retained in the final rule (now called an MHFP), the requirement to run a CEL on a type well is deleted and replaced with new requirements that will help to ensure adequate cementing and protection of aquifers (see final section 3162.3-3(e)).
The BLM received several comments stating that to be considered a type well, the operator must demonstrate successful replication of operations. No changes to the rule were made as a result of this comment because type
Revised sections 3162.3-2(a) and (b) no longer contain reference to nonroutine or routine fracturing jobs. All other injection activities must still comply with section 3162.3-2, while hydraulic fracturing operations must comply with the requirements under revised section 3162.3-3.
Section 3162.3-3 lists the requirements concerning all hydraulic fracturing operations and paragraph (a) of this section establishes the conditions under which some wells may be exempted from certain requirements (or “grandfathered” in) as a way to transition from the previous regulations to these regulations.
The BLM made several changes to paragraph (a) of the final rule. The term “refracturing” is removed from the activities to which this section applies, because the term “refracturing,” and all references to it are deleted in the final rule.
In addition, a table is added to this section to clarify how the rule will be implemented with regard to wells in various stages of permitting, drilling, and completion. In general, any well that is drilled after June 24, 2015, or that was drilled more than 6 months before June 24, 2015 must comply with all parts of this rule, including the permitting, cementing, mechanical integrity testing, monitoring, handling and storage of recovered fluid, and reporting requirements. However, in order to reduce the economic and workload impacts of implementing this rule, there are three categories in which an operator can hydraulically fracture a well without submitting a new APD or NOI under sections 3162.3-3(c) and (d).
If an operator has an APD approved within the 2 years immediately prior to June 24, 2015, but has not commenced drilling operations, or has commenced drilling prior to June 24, 2015, but has not completed those operations, or has completed drilling operations within the 6 months immediately prior to June 24, 2015, and commences hydraulic fracturing operations within 90 days after June 24, 2015, the operator does not need to submit a new APD or NOI, or await the approval of the BLM before commencing hydraulic fracturing operations. The operator will need to comply with the provisions of paragraphs (b), (e), (f), (g), (h), (i), and (j) of the rule.
Those provisions are added to paragraph (a) to reduce costs and scheduling conflicts that could arise otherwise, while still ensuring safe and responsible hydraulic fracturing operations. Operators typically schedule hydraulic fracturing services 6 months in advance, though the requirements of every market are different. The BLM determined that the 90 days between publication of this the final rule and its effective date, plus an additional 90 days provided in paragraph (a) will be adequate to accommodate most potential scheduling conflicts. If the operator wishes to conduct hydraulic fracturing more than 90 days after June 24, 2015, under each of these three scenarios, however, the operator must comply with all of the paragraphs in this section, including submission of an application and obtaining approval from BLM to conduct hydraulic fracturing operations.
The final category in the table in paragraph (a) is wells for which drilling operations are completed prior to the effective date of the rule and hydraulic fracturing operations are conducted more than 6 months after the effective date of the rule. Operators would need to obtain the BLM's approval to conduct hydraulic fracturing operations, but not all operators would have the cementing verification records that are required for new wells. Rather than prohibit hydraulic fracturing of wells for lack of documentation not required at the time of construction, the rule provides in section 3162.3-3(e)(1)(ii) that operators must provide the relevant documentation that is available, and that the BLM may require additional testing or verifications on a case-by-case basis. For any existing well, an operator may request approval to conduct hydraulic fracturing operations by submitting an NOI under paragraph (c)(2) of the final rule.
Several commenters stated that the rule should be modified to further clarify the scope of this rule as it relates to injection activities. The commenters indicated that the provisions at this section cloud whether or not the majority of this rule applies to other injection or disposal operations. The BLM has revised the rule as a result of these comments. Injection activities have been removed from this section to avoid any confusion because injection is specifically addressed by existing section 3162.3-2. The BLM believes this change provides the necessary clarity regarding scope.
The only change made to this section of the final rule is the deletion of the term “refracturing” because it, and all references to it, are removed from the rule. The BLM received no substantive comments on this section.
This section requires an operator to submit a proposal for hydraulic fracturing to the BLM for approval. The operator may submit an application for a single well or for a group of wells under an MHFP. Prior to this rule, the regulations only required an NOI for “non-routine” hydraulic fracturing operations. The application requirement in the final rule is a new process. The request for approval of hydraulic fracturing may be submitted with either an APD or as an NOI.
Numerous changes were made to this section in the final rule. The description of how to apply for the hydraulic fracturing of multiple wells is moved from section (d) of the supplemental proposed rule to section (c)(3) of the final rule because it has more to do with the permitting process than the information that an operator must submit to the BLM. This section also references an MHFP instead of a type well, as proposed in the supplemental proposed rule. A discussion of the MHFP is given in the definitions section of the preamble.
The final rule revises some of the conditions under which an operator would have to resubmit a request for approval to hydraulically fracture a well. In the supplemental proposed rule (section 3162.3-3(c)(3)(i)), an operator would not have had to get approval to refracture a well if the refracturing was done within 5 years of the original fracturing approval. The premise of this requirement was that an MIT, required prior to fracturing under section 3162.3-3(f) of this rule, is typically valid for a period of 5 years in some state regulations (
The BLM now believes that an MIT should be required prior to any hydraulic fracturing operation because of the high pressures and wellbore configurations used (such as a fracturing string) during hydraulic fracturing operations. Therefore, the final rule is revised to require approval and compliance with all sections of this rule for all fracturing operations, whether the well is being refractured or fractured for the first time (some hydraulic fracturing operations may not have to comply with sections (c), (d), or (e)—see the table in section (a)).
The supplemental proposed rule (section 3162.3-3(c)(3)(i)) would also have required the operator to resubmit an NOI for hydraulic fracturing if fracturing had not commenced within 5 years of the original approval. This requirement is deleted in the final rule because the BLM determined that as long as the proposal for hydraulic fracturing had not changed and there was no new information regarding the geology or potential impacts, the 5-year time frame was unnecessary. If the operator has significant new information about the geology of the area, the stimulation operation or technology to be used or potential impacts, it must submit a new NOI.
The final rule also eliminates paragraph (c)(3)(iii) in the supplemental proposed rule because it dealt with refracturing, a term that is deleted in the final rule along with all references to it.
Some commenters requested that the BLM eliminate the requirement for prior approval of hydraulic fracturing operations, suggesting that it would be unnecessary and costly. As stated in the background section of this rule, the BLM believes this rule is necessary, and prior approval is an essential part of this rule. The information included in the application allows the BLM to evaluate the proposal and to assess the potential impacts of the proposal. Prior approval allows the BLM to mitigate potential impacts through modification of the proposal or by attaching conditions of approval, after compliance with other statutes, such as NEPA.
Several commenters expressed concern that many of the items requested in the application, such as estimated total volume of fluid to be used and anticipated surface treating pressure range, are not known at the time the application is submitted. The BLM recognizes that exact volumes and pressures will not be known at the time the application is submitted, and the provisions at final section 3162.3-3(d) allow flexibility by requiring estimated or anticipated values. The items are necessary to allow the BLM to assess the proposal and ensure adequate storage for the fluids and proper casing strength to withstand the anticipated pressures.
Another commenter suggested eliminating some of the requirements needed for approval because Onshore Oil and Gas Order No. 1, Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Approval of Operations (72 FR 10308) (Onshore Order 1), section III. D. 3, already requires them, and they are included with the APD. As stated in final section 3162.3-3(c)(1), the operator may submit the information required in paragraph (d) of this section with its APD. If the information is already included in the APD, it would not need to be repeated. Another commenter recommended eliminating some of the requirements in the application, since those items will be included in the subsequent report of operations. The information in the application is necessary for the BLM to assess the potential impacts of the proposed operation; additionally, some of the information requested in the application is identified as proposed or estimated. The information required in the Sundry Notice and Report on Wells (Form 3160-5) as a subsequent report (“subsequent report”) is the actual data from the completed hydraulic fracturing operations. No revisions to the rule were made as a result of these comments.
One commenter suggested that the BLM should allow a “type frack” approval instead of a type well approval. While the BLM is unclear what the commenter is specifically referring to, the BLM assumes that the commenter means that the hydraulic fracturing operation itself be approved for a group of wells. The BLM believes that the final rule's MHFP submission addresses this comment. The MHFP will allow an operator to describe a generic hydraulic fracturing process for a group of wells by providing the information required in section 3162.3-3(d) for those wells. No changes to the rule were made as a result of this comment.
Numerous commenters objected to permitting hydraulic fracturing for a group of wells. Some of the commenters stated that geologic conditions are too variable to allow any kind of group permitting while other commenters stated that the extent of the grouping should be explicitly defined and that strict limitations should be placed on the maximum allowable extent of an MHFP. The BLM disagrees with these comments because rigid, detailed criteria for what can be considered in an MHFP is not practical in a national rule of general applicability. The local field office must have some flexibility to define the extent of an MHFP based on local geology, drilling practices, and other applicable criteria. No revisions to the rule were made as a result of this comment. The benefits of an MHFP are that it allows the BLM to frontload its analysis of proposed hydraulic fracturing operations in a given area where the geologic characteristics for each well are substantially similar. It also provides early notice to the public of where such operations are being contemplated, and of the scale or intensity of the development. This frontloaded analysis provides the BLM with the tools necessary to perform a more comprehensive and streamlined review of hydraulic fracturing proposals, while maintaining the appropriate standards that ensure wellbore integrity and useable water protection.
Several commenters suggested that exploratory wells could be used as type wells because they were drilled vertically through the target formations and lithologic and reservoir data was obtained from them. Other commenters suggested that wells drilled by other operators could be used as a type well, while some commenters stated that type wells must be drilled by the same operator because drilling practices vary between operators. No revisions to the rule were made as a result of these comments because the requirement to drill a type well in order to receive approval to hydraulically fracture a group of wells with a single permit submittal is deleted in the final rule. The MHFP, which replaces the type well concept, is required to contain the information in sections 3162.3-3(d)(1) through (d)(7); however, the well integrity information required by section 3162.3-3(e) is not required to be included in the MHFP. Rather, the well integrity information required by section 3162.3-3(e) must now be submitted for each well 48 hours prior to commencing hydraulic fracturing. The MHFP only applies to wells drilled by the same operator. Section 3162.3-3(c)(3) states that “the operator may submit a MHFP,” thereby eliminating the possibility that an MHFP could apply to wells drilled by multiple operators. The BLM decided to restrict MHFPs to wells drilled by the same operator because doing otherwise would be difficult to administer and the BLM believes that drilling by different operators would only apply in rare instances.
Several commenters asked that the BLM allow the type well concept to include fracture modeling. The MHFP, which replaces the type well concept for permitting, requires all information required in sections 3162.3-3(d)(1)
Several commenters stated that the CEL for a type well should be applicable to wells that meet the criteria for group approval, but were submitted under a separate NOI. The BLM did not revise the rule as a result of these comments because the requirements to run CELs on type wells and submit the results of the CEL as part of the group approval package are eliminated in the final rule. Several comments suggested that for group hydraulic fracturing submissions, the operator should be required to certify that the cement, fracturing fluids, and drilling practices for all wells included in the submission comply with the information submitted in the MHFP. The BLM did not incorporate this suggestion into the final rule because a certification is not necessary to ensure compliance with the approved NOI for multiple wells, and because information related to well integrity is now required for each individual well. Any unapproved deviation from the approved NOI and MHFP would be considered a violation and would be enforced under existing subpart 3163, Noncompliance, Assessments, and Penalties. One comment said that the option to permit multiple wells will not help operators who do not drill wells in groups. In the final rule, MHFPs will primarily streamline the permitting process for operators who are hydraulic fracturing multiple wells within an area having similar geology. No revisions to the rule were made as a result of this comment. The fact that not every operator can take advantage of a provision of the rule designed to streamline the process does not make that provision undesirable or unnecessary.
This section specifies that the application must include:
• Information about the geology and the formation, confining zones, usable water (depths estimated), faults and fractures, location of water supply, and transportation method. This information is generally consistent with the requirements in Onshore Order 1;
• Information about the proposed hydraulic fracturing operation, the volume of fluid to be used, the maximum anticipated surface pressure, wellbore trajectory, the estimated direction and length of fractures, and the locations, trajectories, and depths of existing wellbores within a half mile of the wellbore; and
• Information about how the operator will handle recovered fluids, the estimated volume of fluids to be recovered, and the proposed disposal method.
The final rule incorporated several revisions to this section. Requirements relating to an MHFP (referred to as a submission for a group of wells in the supplemental proposed rule) are moved from section (d) to section (c) because section (c) has to do with how to apply for hydraulic fracturing approval. A discussion of the MHFP is given in the definitions section and the response to comments on the type well in the proposed rule are addressed in the discussion of section (c).
Section 3162.3-3(d)(1) in the supplemental proposed rule would have required the operator to identify the geologic formation that would be hydraulically fractured, including measured depths of the top and bottom of the formation. The final rule requires that the operator identify both the measured depths and the true vertical depths of the formation to be hydraulically fractured (paragraph (d)(1)(i)). This section of the final rule also requires the operator to identify the measured and true vertical depths of the confining zone (paragraph (d)(1)(ii)).
The requirement to identify usable water zones is moved from paragraph (d)(2) in the supplemental proposed rule to final paragraph (d)(1)(iii), along with a new requirement to state the measured and true vertical depths of the top and bottom of all usable water zones. The requirement to identify occurrences of usable water with a drill log in the supplemental proposed rule is deleted in the final rule. The BLM determined that it is not always necessary or practical to require a drill log to identify usable water and that there is no reason to be prescriptive about how usable water is identified. The BLM made these changes for several reasons. First, the BLM believes that by grouping all informational requirements relating to wellbore geometry into a single section, the clarity of the regulation is improved. Second, the BLM added a requirement to identify the “true vertical depth” of tops and bottoms of all the geologic zones in order to ascertain the vertical separation between zones. Also, under the final rule, the operator is required to identify the confining zone that is capable of preventing fluid migration between the zone that will be hydraulically fractured and any usable water zones.
Section 3162.3-3(d)(2) is revised in the final rule to require the operator to submit a map showing any faults or fractures within one-half mile of the wellbore trajectory that may transect the confining zone. This will allow the BLM to identify and analyze during the permit review process any potential for hydraulic fracturing fluid to migrate outside of the zone being fractured.
Section 3162.3-3(d)(3) in the supplemental proposed rule is separated in the final rule to improve clarity. This section in the supplemental proposed rule contained requirements for down-hole information (
Several changes are made to supplemental proposed rule section 3162.3-3(d)(4) to improve clarity and to identify potential “frack hits.” “Frack hit” is a common term for a hydraulic fracturing operation that causes an unplanned surge of pressurized fluid into another well, often resulting in surface spills. The supplement rule required three different pressures to be included in the application: Estimated pump pressure (paragraph (d)(3) in the supplemental proposed rule), anticipated surface treating pressure range (paragraph (d)(4)(ii) in the supplemental proposed rule), and maximum injection treating pressure (paragraph (d)(4)(iii) in the supplemental proposed rule). In the final rule, those three pressures are replaced with a single pressure to be reported: The maximum anticipated surface pressure that will be applied during operations. The BLM determined that this was the clearest and most useful pressure because this will be the pressure at which the MIT must be run under section 3162.3-3(f) of the rule. This change is also made to eliminate the term “treating,” which may not be universally understood.
Section 3162.3-3(d)(4)(iii) in the supplemental proposed rule would have required the operator to submit the estimated fracture direction, length, and height, along with a map showing the estimated fracture propagation. The final rule adds several additional requirements to this section that will allow the BLM to determine during the permit review process the potential for “frack hits.” In addition to the fracture propagation (including direction and length), the map must also show the trajectory of the wellbore into which hydraulic fracturing fluid will be injected and the trajectory of all existing wellbores and trajectories within one-half mile of the wellbore that will be used for hydraulic fracturing. Additionally, the required map must identify the true vertical depth of each wellbore shown on the map.
Section (d)(4)(v) in the supplemental proposed rule, requiring the estimated vertical distance to the nearest usable water aquifer above the fracture zone, is reworded for clarity. In the final rule, section (d)(4)(iv) requires the estimated minimum vertical distance between the top of the fracture zone and the nearest usable water zone.
Section (d)(5) in the supplemental proposed rule, regarding the handling of recovered fluid, is reworded in the final rule to conform to changes made to section (h). The only period for which information on handling recovered fluid is necessary under the final rule is the period between the completion of hydraulic fracturing operations and the approval of a water disposal plan under Onshore Order 7. A complete discussion of this change is given under section (h) of this preamble.
Section (d)(5)(iii) in the supplemental proposed rule is clarified in the final rule by better defining “handling” versus “disposal.” In the supplemental proposed rule, disposal included injection, hauling by truck, or transporting by pipeline. The BLM recognizes that hauling by truck or transportation by pipeline are not disposal methods, but transportation methods. In the final rule, the disposal options include injection, storage, and recycling.
Section (d)(6) of the final rule is added to include additional information requirements if the operator requests approval for hydraulic fracturing in an NOI instead of in an APD. One of these requirements (section (d)(6)(i)) is a surface use plan of operations if the hydraulic fracturing operation would include additional surface disturbance. If the request was received as part of an APD, the surface use plan of operations would already be included.
The other requirement is, by reference to paragraph (e), documentation that an adequate cement job was achieved for all casing strings designed to isolate usable water zones.
A few commenters asked that the volume and chemical composition of flowback water be disclosed in the permit application. Section 3162.3-3(d)(5)(i) of the final rule requires the operator to provide the estimated volume of fluid to be recovered in its application. The projected chemical composition of this fluid is not required. Providing the chemical composition of the recovered fluid would require speculation as to the chemistry of fluids in the target zone, and their reactions, if any, with the hydraulic fracturing fluids and therefore would be impractical to request, and not likely to be useful. The BLM has determined that operators often change the chemical composition of hydraulic fracturing fluids after approval of fracturing operations, in response to such factors as availability of chemicals, changes in vendor, and unexpected geologic conditions. Thus, the reliability of the pre-operational estimated composition of flowback fluids likely will not be known with precision at the application stage. It is important at the approval stage, however, for the operator to show that it has an adequate plan to manage and contain the recovered fluids that would prevent them from contaminating surface water or groundwater without regard to their specific chemical composition. The rule presumes that all recovered fluids would pose hazards to surface or ground water if they are not properly isolated. No revisions to the rule were made as a result of these comments.
Some commenters requested that the BLM require up-front disclosure of the chemicals proposed for use in the hydraulic fracturing fluid and that this information be publicly available. Commenters asserted that chemicals must be disclosed both before and after well stimulation in order to achieve the BLM's goals of protecting public health and the environment. The rule is not revised based on these comments. Analysis of the impacts from hydraulic fracturing is done as part of the NEPA analysis conducted prior to the issuance of permits. The exact composition of the fluid proposed for use is not required because the BLM's goal is to ensure that operators contain all fluids regardless of their composition. All fluids are conservatively treated as if they are hazardous and need to be contained. In undertaking NEPA analysis to support the Bureau's decision to issue a permit, the BLM will assume that the chemicals used in conducting hydraulic fracturing operations may be hazardous. The BLM believes that the post-fracturing disclosures and certifications of chemicals and additives provide adequate information for other purposes, such as to inform the community of the chemicals involved, and to assist in clean-up of any spills.
Several commenters suggested that all of the information required in the subsequent report should be disclosed in the application for hydraulic fracturing approval. The BLM did not make any changes to the rule as a result of these comments because not all of the information required in the subsequent report is relevant or available at the time the operator submits the application. When the proposal for hydraulic fracturing is submitted with an APD, items such as well logs are not available because the well has not yet been drilled.
The original proposed rule required the NOI to contain a certification signed by the operator that the proposed treatment fluid complies with all applicable permitting and notice requirements as well as all applicable Federal, tribal, state, and local laws, rules, and regulations. That requirement was deleted in the supplemental proposed rule. Some commenters supported eliminating this requirement while other commenters requested that the originally proposed requirement be reinstituted. As was stated in the preamble of the supplemental proposed rule, the BLM believes that requiring this certification after the operator has completed hydraulic fracturing operations (see final section 3162.3-3(i)(8)) adequately protects Federal and Indian lands and resources and, therefore, the burden on industry of providing the information and on the BLM of reviewing that information at the application stage is not justified. The commenters requesting the requirement be reinstituted stated the rule removes the first layer of accountability for industry by not even requiring them to say they will comply with permitting, and the lack of certification removes a tool to hold operators accountable to follow the regulations. The BLM disagrees. The operators are required to comply with all applicable laws and regulations, regardless of when the information is submitted. A certification in the NOI does not add any value to the permit and lack of a certification in the notice does not restrain enforcement in the future. Therefore, no revisions to the
Several comments suggested that the BLM allow a “master chemical plan” to be submitted for wells that are proposed for hydraulic fracturing in the same field. According to the commenter, this plan could be used for routine hydraulic fracturing operations to help streamline the permitting process. However, the BLM is not requiring chemical disclosure prior to hydraulic fracturing, so a specific “master chemical plan” is unnecessary.
Numerous comments said that the rule should be modified to add a definition of “confining zone.” Additionally, the commenters indicated that the NOI required at 43 CFR 3162.3-3(d) should include the identification of an impermeable confining zone that would protect water sources from vertical migration of hydraulic fracturing fluids and associated brines. The BLM agrees with these comments. The final rule includes a definition of confining zone and a requirement that operators identify the measured and true vertical depths of the top and bottom of the confining zone in their permit application. In addition, in the final rule the operator must identify all known faults and fractures within one-half mile of the wellbore that transect the confining zone. These additions will allow the BLM to further ensure that the hydraulic fracturing fluid will not migrate outside of the intended zone in order to protect usable water.
Several comments asked that the BLM specify a minimum “vertical buffer” between the zone that is to be hydraulically fractured and the deepest aquifer. The BLM did not include this requirement in the final rule because the BLM must maintain the flexibility for field offices to review hydraulic fracturing applications on a case-by-case basis and apply site-specific conditions of approval. A minimum vertical distance that is appropriate in one area might be inadequate or overly restrictive in other areas based on the intervening geology. Furthermore, fracking technologies are likely to continue to improve an operator's control over the propagation of fissures.
Several commenters said that the rule should be modified to allow operators to submit a field-specific casing design and cementing plan and subsequently submit verification of a successful cement job. The BLM did not revise the rule as a result of these comments. This comment addresses the concept of a Master Development Plan (MDP) that is already described in and provided for by Onshore Order 1 for newly drilled wells. The MDP addresses the casing and cementing design of all of the wells within that MDP. Drilling operations and the associated MDP process is outside the scope of this rulemaking.
One commenter suggested that fracture modeling could be done for a group of wells instead of requiring a model for every well. The BLM did not revise the rule as a result of this comment for two reasons. First, neither the proposed rules nor the final rule require fracture modeling. Both allow for submittal of “estimated” fracture data. Second, fracture estimates for zones that are in substantially similar geologic regimes could be included in the MHFP under final section 3162.3-3(c).
One commenter expressed concern with the use of the term “estimate” in the supplemental proposed rule as it pertains to operator submissions under section 3162.3-3(d). The commenter stated that the BLM would be unable to ensure the protection of usable water zones if the operator is allowed to submit estimates. The BLM disagrees with this comment. This provision allows the operator to estimate some items, such as the depth of usable water and the pump pressure, in the APD and NOI. Allowing estimates in the APD and NOI instead of actual information does not compromise the safeguards for protection of usable water. At the time the APD and NOI is submitted, in many instances some of the required information cannot be known for certain, because the well has not yet been drilled. The estimates provide the BLM with sufficient information to evaluate the potential impacts of the planned operation and to ensure that usable water zones are adequately protected. No revisions to the rule are made as a result of this comment.
One commenter expressed concern that the changes made to the requirements in the NOI from the original proposed rule to the supplemental proposed rule do not seem designed to provide adequate safeguards for ecological and human resources. The BLM disagrees with this comment. The changes from the original proposed rule to the supplemental proposed rule were based on the comments received from individuals, Federal and state Governments, and agencies, interest groups, and industry representatives. The changes to each section and the rationale for the changes were discussed in the preamble of the supplemental proposed rule. One of the primary goals of the rule is to provide adequate safeguards for resources in and on the public lands and tribal lands, and thus for the persons who use those resources. The BLM believes the changes proposed in the supplemental proposed rule and the provisions of the final rule, along with existing processes for reviewing and approving oil and gas development proposals, accomplish that goal.
The supplemental proposed rule would have allowed an NOI to be submitted for a group of wells within the same geologic formation. One commenter suggested that the rule be required to specify the location of all wells where fracturing will take place. The commenter was concerned that if this is not specified, and notice is submitted in the form of a Sundry Notice for a group of wells, the location of each well will not be clear. The BLM disagrees with the commenter. Operators use Sundry Notices (Form 3160-5) to request approval to conduct operations and to subsequently report on operations after they are finished. Sundry Notices are used for all operations, not just hydraulic fracturing, and have been required for many years. The Sundry Notice form itself requires the operator to identify the lease number, the well number, and the location of the well. If a Sundry Notice is submitted for multiple wells, the Sundry Notice must contain a list of all of the wells including the lease number for each well and the legal land description of the location of each well. While this is not explicitly stated in the rule, the Sundry Notice form requires it. No revisions to the rule were made as a result of this comment.
Numerous commenters said that in states where there is already a regulatory process for hydraulic fracturing, an operator should be allowed to submit the same information to the BLM as it does to the state. Both the supplemental and final rules include provisions that address the commenters concern. The first (section 3162.3-3(d)) allows information submitted in accordance with state law to be submitted to the BLM if the information meets the standards of this rule. The second (section 3162.3-3(k)) allows the BLM to issue a statewide or regional variance to use particular state or tribal regulations and processes for permitting hydraulic fracturing
One commenter requested that the BLM clarify the following statement in section 3162.3-3(d): “If information submitted in accordance with state (on Federal lands) or tribal (on Indian lands) laws or regulations meets the standards prescribed by the BLM, such information may be submitted to the BLM as part of the Sundry Notice.” This language has been clarified in the final rule. Many of the comments received in response to the initial proposed rule and the supplemental proposed rule were critical of duplication between state or tribal regulations and the supplemental proposed rule. The statement in this section is meant to address those concerns and minimize any duplication. If the information submitted to states or tribes meets the standards in this section, the operator does not need to generate any new information. Operators may submit the information that was generated to meet the state or tribal requirements to the BLM. To better reflect the BLM's intent, the statement has been modified in the final rule for additional clarity, although no substantive change was made to the statement.
Some commenters recommended that sections 3162.3-3(d)(3) and 3162.3-3(d)(4) be restructured to add clarity to the requirements. Commenters said that the information required in section 3162.3-3(d)(3) of the supplemental proposed rule included the proposed measured depth of the perforations or the open-hole interval and included information concerning the source and location of the water to be used during hydraulic fracturing. While this information is still needed, the items are distinct, and therefore should be separate requirements. The BLM agrees with these comments and sections 3162.3-3(d)(3) and 3162.3-3(d)(4) are restructured in the final rule. Section 3162.3-3(d)(3) now requires information concerning the source and location of the water supply. In addition, the requirement for the measured depth of the proposed perforated or open-hole interval is moved to section 3162.3-3(d)(4)(v). The information regarding the proposed perforated interval is now a distinct requirement, and this information relates more closely with the other information required by section 3162.3-3(d)(4).
Some commenters expressed concern that the requirement to identify usable water zones placed an increased and substantial burden on operators. The commenters stated that the current practice is not for operators to identify “usable water” zones for protection and then submit the information to state oil and gas agencies or BLM offices for approval, but instead for these agencies to prescribe to operators which zones must be protected. The commenters' perception of existing requirements is incorrect. Section III.D.3.b. of Onshore Order 1 requires operators to provide the estimated depth and thickness of formations, members, or zones potentially containing usable water, and the operator's plans for protecting such resources. Section III.B. of Onshore Order 2 requires that the proposed casing and cementing programs be conducted as approved to protect and/or isolate all usable water zones. It goes on to require that determination of casing setting depth must be based on all relevant factors, including usable water zones. It also requires that all indications of usable water be reported. This final rule requires the operator to identify the measured or estimated depths (both top and bottom) of all occurrences of usable water. This requirement is consistent with the existing requirements in Onshore Orders 1 and 2 and does not place an increased burden on the operators. No revisions to the rule were made as a result of these comments. The BLM agrees, however, that in many instances state or tribal oil and gas regulators, or water regulators, will be able to identify for operators some or all of the usable water zones that will need to be isolated and protected.
One commenter recommended that the operator must inform the BLM of the locations, geologic formations, and depth of the usable water zones prior to initiating fracking operations. The commenter stated that this is of prime importance to people living in the vicinity of fracking and they need some certainty that the fracking operations will not impact their water resources. The BLM agrees. Some of this information is already required of the operators prior to drilling the well. Section III.D.3.b. of Onshore Order 1 requires operators to provide the estimated depth and thickness of formations, members, or zones potentially containing usable water, and the operator's plans for protecting such resources. The BLM uses this information in the evaluation of the well proposal to ensure that usable water zones are adequately protected by the proper placement of casing and cement. Since this information is already required to be submitted with the APD, it is not repeated in the rule. No revisions to the rule were made as a result of this comment. However, the information that would be required to be submitted as part of this rule will be made available to the public, consistent with the requirements of Federal law.
Some commenters recommended using a research agency such as the United States Geological Survey (USGS) to identify usable water. Other commenters recommended developing Federal and state partnerships to map water resources. The BLM agrees that those entities can be helpful in identifying usable water. However, the BLM cannot mandate their participation. We note that the use of information developed by the USGS or state agencies is acceptable information for operators to use to identify usable water. In many areas, the USGS, state agencies, or tribal agencies have developed water resource maps. Operators may use this information, along with any other available information, including logs from nearby wells, to identify usable water zones. No revisions to the rule were made as a result of these comments.
Section 3162.3-3(d) in the supplemental proposed rule required that the NOI include the measured or estimated depths (both top and bottom) of all occurrences of usable water by use of a drill log from the subject well or another well in the vicinity and within the same field.
Many commenters expressed concern that identification of usable water by drill log is very difficult and expensive. Other commenters stated that the BLM is incorrect to assume that drill logs can be used to identify usable water. The commenters stated that these logs do not directly measure water quality or TDS.
Operators often run resistivity logs for intermediate and production casing, and these logs might allow the qualitative identification of high salt content zones. These logs do not, however, directly measure TDS, and there are too many variables for the signature these logs record to be converted into accurate TDS data. Some commenters expressed concern that the term “drill log” is very broad and should be specifically defined. The BLM agrees with these comments. It was not the BLM's intent to mandate a prescriptive method of estimating the depths of usable water. Final section 3162.3-3(d) has been revised and the phrase “by use of a drill log from the subject well or another well in the vicinity and with the same field,”
Section III.D.3.b. of Onshore Order 1 requires operators to provide the estimated depth and thickness of formations, members, or zones potentially containing usable water, and the operator's plans for protecting usable water. It does not specify what information the operator must use to determine the estimated depth of usable water. The expectation is that the operator will use the best available information to estimate the depths of usable water. The expectation in this final rule is the same. Available information could include data and interpretation of resistivity logs run on nearby wells. In many areas, information can be obtained from state or tribal regulatory agencies. Many states have requirements that protect known water zones. For example, the North Dakota Industrial Commission requires that surface casing be set and cemented at a point not less than 50 feet below the base of the Fox Hills Formation (N.D. Admin Code 43-02-03-21 (2012)). The Wyoming Oil and Gas Conservation Commission uses regional water studies to identify known zones with potential to contain usable water such as the Fox Hills Formation in the Powder River Basin of Wyoming and bases its casing requirements on such information. Other information on usable water may be available from local BLM offices. For example, the BLM Pinedale Field Office Web site provides information regarding usable water. That Web site also provides typical casing and cementing designs for different areas under jurisdiction of the Field Office.
Some commenters stated the rule will impose additional casing and/or cementing costs on operators because, unlike Onshore Order 2, the proposed rule would require cement behind pipe across all usable water zones. The commenters state that even though the proposed rule uses the word “isolate,” it uses the word differently than Onshore Order 2. The commenters go on to say this is clear from the requirement to run a CEL for each casing string that protects usable water. The BLM disagrees with these comments. The requirements in the supplemental proposed rule are consistent with the requirements in Onshore Order 2. For many wells, the isolation of usable water will be accomplished by setting cement across the usable water zones. However, in some wells, cementing across the usable water zone may not be feasible. In these situations, isolation of the usable water zones from any hydrocarbon bearing formations is warranted. The BLM modified some of the requirements in the final rule to eliminate confusion over the requirement to isolate and protect usable water. In the final rule, a CEL is not required on each string of surface casing that isolates usable water if certain performance standards are met. A few examples of performance standards to be met include cement return to surface, a successful formation integrity test confirming good cement bonding, and no lost circulation or other cementing problems. For wells where a CEL is required, the operator must run a CEL to demonstrate that there is at least 200 feet of adequately bonded cement between the zone to be hydraulically fractured and the deepest usable water zone. Meeting this requirement would demonstrate isolation and protection of the usable water zone from the zone to be hydraulically fractured.
Another commenter recommended that all cementing requirements be eliminated from the rule. The commenter asserts that cementing operations are part of drilling operations and information is already submitted to state regulatory agencies for such operations. The commenter asserted that cementing operations have little to do with hydraulic fracturing. The BLM disagrees with this comment. While cementing information is already submitted to state regulatory agencies and the BLM, this rule expands on the requirements by including cement monitoring, cement remediation, and cement evaluation which are all related to protection of usable water from hydraulic fracturing operations. No revisions to the rule were made as a result of this comment.
Section 3162.3-3(d)(3) requires the operator to identify the anticipated access route for all water planned for use in fracturing the well. One commenter recommended that the BLM require the disclosure of all proposed and existing access routes, including those used to transport proppant (sand), equipment, and chemicals for use in the hydraulic fracturing fluids. The BLM disagrees with this comment. The BLM already requires the operator to submit its proposed access route to the well location in the APD (see Onshore Order 1, section III.D.4.a.). In this rule, the BLM requires the operator to specifically identify the access route for the water to be used in fracturing operations because the access route from the water source may be potentially different from the route approved in the APD. The BLM uses this information provided by the operator to determine potential environmental impacts under NEPA and if a right-of-way to cross public lands is needed, and to assure compliance with other statues such as the FLPMA. All other travel to and from the location should be on the route described in the approved APD. However, the BLM has no authority to require its approval for transportation not on public lands. No revisions to the rule were made as a result of this comment.
Some commenters disagreed with the requirement to provide information concerning the water source and location of water supply because they were unsure what the information would be used for, and others were concerned that the BLM would disapprove or condition the withdrawals, in violation of state authority over water use. Other comments stated that the water source could change and filing a Sundry Notice for the BLM to approve the change is burdensome. The BLM requires this information about the proposed source of the water in order to conduct and document an environmental effects analysis that takes a hard look at the impacts of its Federal action and meets the requirements of NEPA. The BLM has always required operators to file a Sundry Notice for changes to the approved permit—whether it is an APD or an NOI for hydraulic fracturing or for other operations requiring BLM approval. No changes to the final rule were made as a result of these comments.
Some commenters stated that information regarding the water source would have already been provided as part of the APD. The BLM agrees in part. Section III.D.4.e. of Onshore Order 1 requires the operator to identify the location and types of water supply to be used during the drilling operations in the APD. That water supply for such things as mixing drilling mud and cement may or may not be the same as the water supply for hydraulic fracturing operations, which often needs much greater quantities of water, but may be able to use water of different quality. Since the water supply may be different, this information must be included in the application for hydraulic fracturing. No revisions to the rule were made as a result of these comments.
One commenter expressed concern about identifying the source and
One commenter requested clarification of the term “water supply.” The commenter said it was unclear whether the requirement was requesting the source and location of the water to be used in the hydraulic fracturing operation or if the requirement was requesting the source for drinking water/agricultural water/industrial water in the area. The requirement is referring to the source water used as a base fluid in the hydraulic fracturing operations.
Another commenter recommended that the BLM strengthen the language regarding identification of the water supply to say “must” instead of “may.” The language in the rule requires the applicant to provide information on the source and location of the water supply, “which may be shown by quarter-quarter section on a map or plat, or which may be described in writing.” The BLM believes the rule is clear as written. The applicant must provide the information requested, but they have the option of either showing it on a map or plat, or by describing it in writing. No revisions to the rule were made as a result of these comments.
The BLM received one comment suggesting that the BLM should require the operator to provide the volumes of water to be used during hydraulic fracturing operations in its application. Another commenter asked if section 3162.3-3(d)(4)(i) refers to the volume of hydraulic fracturing fluid or the volume of water from the water supply. Section 3162.3-3(d)(4)(i) requires the submission of the estimated total volume of fluid to be used. This requirement does not specifically require the volume of water. However, since most all of the fracking fluid is water (assuming a water-based fracturing fluid), it is a good indicator of the estimated volume of water to be used. Some hydraulic fracturing operations, however, use other fluids such as nitrogen or carbon dioxide. For these operations, the estimated total volume of fluid would include all fluids, including the nitrogen or carbon dioxide.
Several comments suggested clarification of the pressures required in the permit application (supplemental proposed rule section 3162.3-3(d)). In the supplemental proposed rule, paragraph (d)(3) would have required “estimated pump pressures,” paragraph (d)(4)(ii) would have required the “anticipated surface treating pressure range,” and paragraph (d)(4)(iii) would have required the “maximum injection treating pressure.” The commenters expressed some confusion over the need for the three different pressures and also some confusion over the terminology. The BLM agrees with these comments and consolidated the requirements in proposed paragraph (d) to one requirement to provide the “maximum anticipated surface pressure that will be applied during the hydraulic fracturing process” (final section 3162.3-3(d)(4)(ii)). The primary reason for requesting this information was to ensure the pressures used during the hydraulic fracturing process were no greater than the pressures used in the MIT (see section 3162.2-2(f)) prior to hydraulic fracturing and to ensure that the wellbore is adequately designed to handle these pressures. Therefore, the requirement for “pressure ranges” in the supplemental proposed rule (paragraph (d)(4)(ii)) is not necessary—only the maximum pressure is required for the intended purpose. The phrase “treating pressure” is eliminated because the meaning of the word “treating” may not be universally understood.
Also in response to these comments, the BLM changed the wording in sections 3162.3-3(f)(1) and (i)(3) of the final rule to match the terminology used in section 3162.3-3(d)(4)(ii).
The BLM received several comments regarding the submittal of fracture design information. Some commenters fully supported the requirement. These commenters indicated the data is necessary for BLM evaluation. These commenters were in general agreement with the provisions of this section,
Some commenters objected to allowing fracture design estimates instead of actual fracturing data and other commenters requested that the data submitted include three dimensional reservoir and fracturing modeling. The primary objective of the additional requirements requested by the commenters was to give the BLM better information to ensure that the fractures would not extend into any usable water zones or intersect other wells (
The BLM also received numerous comments objecting to the requirement to specify the fracture length in the application for hydraulic fracturing. Several commenters stated that expensive modeling would be required to estimate fracture length. As discussed earlier, although it can be used, modeling is not required. The intent of this requirement is to provide the BLM with enough information about the proposed hydraulic fracturing operation that potential hazards, such as other wells and fracture propagation into usable water zones, can be identified and mitigated. Estimated fracture dimensions are sufficient to meet this intent. Because the rule already requires “estimated or calculated” fracture data, no changes to the rule were made as a result of the comments.
A few commenters expressed concern about confidentiality of the information
One commenter said that fracture data has nothing to do with wellbore integrity or protecting groundwater. The BLM disagrees. One of the purposes of submitting fracture estimates is to allow the BLM to analyze hydraulic fracturing proposals for potential interference with other wells. There is a potential for groundwater contamination if high-pressure hydraulic fracturing fluid intersects the drainage radius of another wellbore. The BLM did not revise the rule as a result of these comments.
In response to comments, the BLM determined that it should be made clear that the rule was not requiring only the locations of vertical segments of wells. The rule at paragraph (d)(4)(iii)(C) requires submission of a map showing the location of all wellbores within one-half mile horizontally of the wellbore to be hydraulically fractured. A wellbore is not merely the vertical component of a well. A wellbore is commonly understood to be “[t]he hole made by a well.” Williams & Myers Manual of Oil & Gas Terms, p.1173 (10th ed. 1997). It thus includes all vertical, directional, and horizontal legs of a well. Thus, any part of an existing well that comes within one-half mile horizontally of the trajectory of the well to be hydraulically fractured (regardless of any difference in depths) must be shown on the map submitted with the operator's application. The information will allow the authorized officer to work with the operator to prevent “frack hits.”
The BLM received a few comments regarding the vertical distance from the intended hydraulic fracture zone to the nearest aquifer. One commenter recommended that the rule be revised to require the operator to report the vertical distance from the intended hydraulic fracture zone to the nearest aquifer. The BLM did not revise the rule as a result of these comments since this is already required in final section 3162.3-3(d)(4)(iv) for all requests for approval of hydraulic fracturing.
Some commenters recommended that the rule be modified to clarify the requirement regarding the NOI estimated vertical distance to the nearest usable water aquifer above the fracture zone. The commenters indicated that the BLM should specify if this is the distance between the surface down to the aquifer or the distance between the aquifer to the fracture zone. The BLM agrees that the proposed language was unclear and has modified the rule as a result of these comments. The intent of this section is to estimate the vertical distance between the top of the fracture zone and the nearest usable water zone. The BLM believes that this information is necessary to properly evaluate the potential impacts of a hydraulic fracturing proposal and had revised the language accordingly.
Some commenters stated that requiring disclosure of proposed methods of handling the recovered fluids prior to drilling is an unreasonable administrative burden for operators when the requirement does nothing to further protect public health and welfare, the environment, nor facilitate efficient production. The BLM disagrees with these comments. The BLM requires the information about the handling of recovered fluids in order to conduct and document an environmental effects analysis that takes a hard look at the impacts of its Federal action and meets the requirements of NEPA and to assure that recovered fluids will not contaminate resources on or in public lands or Indian lands.
Other commenters requested that this section be expanded to include language that requests amounts, locations, facilities for storage, and options for recovering fluids for treatment. The rule requires reporting to the BLM of estimated volumes of recovered fluid along with the proposed methods of handling and disposal of those fluids. The BLM believes the information required in the final rule addresses the commenter's concern and is adequate to assess any potential impacts from the proposed methods of handling the produced fluids and to ensure protection of resources. No changes were made to the final rule based on this comment.
Commenters asked why the estimated chemical composition of the flowback fluid is required, and requested this requirement be struck from the rule. While the original proposed rule required the operator to submit the estimated chemical composition of the flowback fluid, the supplemental proposed rule did not. The rationale for deleting the requirement was discussed in the preamble of the supplemental proposed rule. This final rule does not require the estimated chemical composition of the flowback and therefore the BLM did not revise the rule as a result of these comments.
Some commenters recommended that section 3162.3-3(d)(7), which allows the authorized officer to request additional information prior to the approval of the NOI, be deleted. The commenters expressed concern that the provision creates too much uncertainty for operators and does not include any standards under which the BLM can request additional information. The BLM believes that the provision in the rule is necessary to provide the flexibility essential to regulating operations over a broad range of geologic and environmental conditions. Any new information that the BLM may request will be limited to information necessary for the BLM to ensure that operations are consistent with applicable laws and regulations, or that the operator is taking into account site-specific circumstances. Requests for information from the authorized officer are subject to administrative review if an operator believes the directive lacks a proper basis. The BLM did not revise the rule as a result of these comments.
Several commenters stated that many parts of the rule are duplicative of state requirements, and therefore were unnecessary and would increase the regulatory and permitting burdens on operators. Some of the comments were generic while others specifically identified states such as Colorado, New Mexico, and Wyoming. The BLM has determined that the collections of information in the rule are necessary to enable the BLM to meet its statutory obligations to regulate operations associated with Federal and Indian oil and gas leases; prevent unnecessary or undue degradation; and manage public lands using the principles of multiple use and sustained yield; and protect resources associated with Indian lands. The information that states, tribes, or other Federal agencies collect is neither uniform nor uniformly accessible to the BLM. For these reasons, the BLM has determined that the collections in the rule are necessary, and are not unnecessarily duplicative of existing Federal, tribal, or state collection requirements. If the data required by a state is the same as the data required by this rule, it is permissible for the operator to attach it to the APD or NOI required for Federal and Indian lands,
Some commenters were concerned over possible delays in BLM approval of their applications and requested that the BLM include processing timeframes in the rule. Specific timeframes suggested were from 10 to 30 days. Some commenters recommended that the permit be automatically approved after 30 days. Other commenters did not offer any specific suggestions on timeframes. The BLM did not revise the rule as a result of these comments because the imposition of a timeframe or “automatic” approvals could limit the BLM's ability to ensure protection of usable water and other resources. The BLM cannot abdicate its statutorily mandated responsibilities to prevent unnecessary or undue degradation of public lands and to protect Federal and Indian resources by establishing an arbitrary deadline. Furthermore, the BLM has obligations to assure compliance with relevant statutes and Executive Orders, which in some cases would require more than 30 days. As discussed in other sections, however, the rule would make several changes to the permitting process that could reduce the potential for processing delays.
One commenter suggested that the BLM allow the flowback data required in section 3162.3-3(d)(5) of the supplemental proposed rule to be submitted either in the Sundry Notice or through a database. The BLM did not revise the rule because there is no existing database suitable for that purpose and the BLM believes that submission under this final rule is adequate. However, the BLM is considering expanding the use of its Well Information System for electronic submittal of various types of Sundry Notices.
One commenter requested that the BLM require operators to have a water management plan for flowback fluid. No changes to the rule were made as a result of this comment because the BLM requires the equivalent of a water management plan in final section 3162.3-3(d)(5) of the rule.
Several commenters suggested that the BLM define clear standards for approving or denying an application for hydraulic fracturing. No changes to the rule were made as a result of this comment because the decision to approve or deny a particular application will be made by the authorized officer based on the site-specific conditions for that application and based on whether or not the application complies with this rule and applicable law.
This section requires operators to:
• Monitor and record their cementing operations—This is consistent with industry guidance stressing the importance of using data from reports, logs, and tests to evaluate the quality of a cement job, including drilling reports, drilling fluid reports, cement design and related laboratory reports, open-hole log information including caliper logs, and cement placement information including a centralizer program, placement simulations and job logs, etc.;
• Cement the surface casing to the surface—This is already required by Onshore Order 2 and most state regulations, and is consistent with industry practice;
• For both the intermediate and production casing strings where they serve to protect usable water, the operator must either cement to the surface or run a CEL to demonstrate that there is at least 200 feet of adequately bonded cement between the deepest usable water zone and the formation to be fractured. This is generally consistent with industry guidance and specified in some state regulations. The American Petroleum Institute's (API) guidance titled “Hydraulic Fracturing Operations-Well Construction and Integrity Guidelines, First Edition, October 2009,” commonly known as HF1, states that “if the intermediate casing is not cemented to the surface, at a minimum, the cement should extend above any exposed USDW or any hydrocarbon bearing zone” and that operators may run a CEL and/or other diagnostic tools to determine the adequacy of the cement integrity and that the cement reached the desired height.
If there is an indication of inadequate cement, the operator must notify the BLM within 24 hours, submit a plan to perform remedial action, verify that the remedial action was successful with a CEL or other approved method, and submit a subsequent report including a signed certification and results of the corrective action.
Section (e)(1) of the final rule is revised to require submission of the cement monitoring report to the BLM at least 48 hours prior to commencing hydraulic fracturing operations, instead of 30 days after the completion of hydraulic fracturing operations, as was proposed in the supplemental proposed rule. The BLM made this change to allow field office engineers time to review the cement monitoring report, consistent with ensuring wellbore integrity. The 48-hour period will allow the BLM sufficient time to review the report, while not creating an unreasonable burden on the operators. In most wells, any usable water is isolated with the surface casing that is set many days or even months before the well reaches total depth, so there is plenty of time for the operator to submit the report. For wells where usable water is isolated by intermediate or production casing, the operator would still have ample time to submit the cement monitoring report. Typically, after the operator completes drilling and cementing operations, the operator moves the drilling rig off the well and moves on a completion rig with hydraulic fracturing following. This transition period will allow the operators sufficient time to submit the cement operations monitoring report at least 48-hour prior to commencing hydraulic fracturing.
For any well completed pursuant to an APD that did not expressly authorize hydraulic fracturing operations, there is a new section 3162.3-3(e)(1)(ii) that requires the operator to submit documentation to demonstrate that adequate cementing was achieved for all casing strings designed to isolate or to protect usable water. The operator must submit the documentation with its request for approval of hydraulic fracturing operations, or no less than 48 hours prior to conducting hydraulic fracturing operations if no prior approval is required pursuant to paragraph 3162.3-3(a). The authorized officer may approve the hydraulic fracturing of the well only if the documentation provides assurance that the cementing was sufficient to isolate and to protect usable water, and may require such additional tests, verifications, cementing, or other protection or isolation operations, as the authorized officer may deem necessary.
This provision would apply to wells subject to the transition period as shown in the table in section 3162.3-3(a), and to other wells that might have been completed as conventional wells or fractured prior to this rule, but subsequently are proposed to be re-completed by hydraulic fracturing. Many if not most operators would have the information required in section 3162.3-3(e)(1)(i), and could readily provide it to the authorized officer. However, if the operator did not maintain all of those records, it could provide the available information to the authorized officer, who could approve the operator's request once there is assurance that the hydraulic fracturing
Sections 3162.3-3(e)(2) and (e)(3) of the supplemental proposed rule were deleted in the final rule and replaced by a new section 3162.3-3(e)(2). The supplemental proposed rule (section 3262.3-3(e)(2)) used a “type well” concept and would have required that a CEL be run on all casing strings that protect usable water unless the well was permitted with an NOI for a group of wells, was drilled with the same specifications and geologic characteristics as the type well, the cementing operations monitoring data paralleled the type well, and the type well CEL indicated successful cement bonding (section 3162.3-3(e)(3) of the supplemental proposed rule). The final rule no longer requires a CEL to be run on all casing strings that protect usable water and the type well provisions in the supplemental rule are deleted. Instead, section 3162.3-3(e)(2) of this rule sets performance standards for ensuring adequate cement bonding on all casing that protects usable water and applies to all wells, not just type wells. For casing strings that are cemented to the surface, which includes surface casing, the primary indicator of adequate cement bonding is cement monitoring. This includes such criteria as good returns to the surface, the absence of gas-cut mud, and properly functioning equipment throughout the cement job. The final rule also includes a criterion (10 percent of casing setting depth or 200 feet, whichever is less) for the amount of allowable fall-back. The BLM believes that these criteria will more effectively and less subjectively ensure the protection of usable water on all wells that will be hydraulically fractured than the CEL that would have been required in the supplemental proposed rule.
For intermediate and production casing designed to protect usable water and where cement is not brought to the surface, this final rule requires that a CEL demonstrate that there is at least 200 feet of adequately bonded cement between the zone to be hydraulically fractured and the deepest usable water zone. The supplemental proposed rule would have only required a CEL in this situation if the well was defined as a type well or if there were indications of an inadequate cement job. However, indications of an inadequate cement job are much more difficult to observe when cement is not brought to the surface. Therefore, the final rule requires a CEL on all intermediate or production casing strings designed to protect usable water when the cement is not circulated to the surface. This section also defines the amount of adequately bonded cement necessary to allow hydraulic fracturing, which was not defined in the supplemental proposed rule.
The BLM made several revisions to section 3162.3-3(e)(3) of the final rule (section 3162.3-3(e)(4) of the supplemental proposed rule), which address the course of action an operator must take if there are indications of an inadequate cement job. The final rule explicitly requires the operator to submit an NOI to the BLM for approval of remedial action to address inadequate cementing, where the supplemental proposed rule would have only required the operator to report the remedial action to the BLM. The BLM believes that the final rule's requirement that the operator receive BLM approval prior to remediating inadequate cementing will help to ensure protection of aquifers. The final rule also establishes a procedure for granting approval to take remedial action in emergency situations.
The supplemental proposed rule would have required the operator to submit a written report to the BLM within 48 hours of discovering an inadequate cement job. The final rule requires the submission of an NOI for BLM approval in lieu of the written report and also deletes the 48-hour timeframe. The BLM believes that in most cases prompt submission of an NOI would be in the operator's best interest because they cannot proceed with hydraulic fracturing until the NOI is approved and therefore the 48-hour timeframe is unnecessary. Both the supplemental proposed rule and the final rule require the operator to run a CEL verifying that the remedial action was successful.
Final section 3162.3-3(e)(3) contains revised requirements for what an operator must do if there are indications of an inadequate cement job. In the supplemental proposed rule (section 3162.3-3(e)(4)), prior to commencing hydraulic fracturing, the operator would have been required to notify the BLM within 24 hours, submit a written report within 48 hours, run a CEL showing the inadequate cement had been corrected, and at least 72 hours prior to commencing operations, submit a certification and documentation indicating the cement job had been corrected.
However, the supplemental proposed rule did not have a provision that would have allowed the BLM to review the documentation required or approve a plan for remedial action. The final rule requires the operator to notify the BLM within 24 hours and submit an NOI to the BLM for remedial action along with supporting documentation and logs. This gives the BLM the opportunity to review the documentation and logs submitted to ensure that the remedial action proposed by the operator is appropriate. The requirement to submit an NOI takes the place of the 48-hour written notification in the supplemental proposed rule, although the BLM determined that no timeframe is required because the operator will be required to submit the NOI and receive approval prior to commencing fracturing operations.
Very few commenters were supportive of the type well concept for cement evaluation. In the supplemental proposed rule, a type well CEL would have been required to demonstrate successful cement bonding; thereafter, other wells in an approved group would not have been required to have a CEL unless there were indications of inadequate cement. The subsequent wells would also have needed to have the same specifications and geologic characteristics as the type well, and the cementing operations monitoring data would have needed to parallel that of the type well. Many commenters stated that the definition of a type well was too vague. Some commenters wanted the BLM to limit the type well concept to a certain number of wells, to a certain distance between wells, or to a certain time between the hydraulic fracturing of wells. Other commenters recommended requiring a minimum number of successful wells rather than just a single type well. Other commenters wanted the type well concept to be greatly expanded to include all wells within a county or within a geologic basin. Many commenters stated that successful cementing operations on one well were not indicative of subsequent successful cementing of another well, regardless of the proximity. Some commenters wanted a clearer, more specific set of standards and procedures to guide the determination of what constitutes a type well for a given set of wells. Other commenters were critical that the rule did not elaborate upon the meaning of “substantially similar geological characteristics within the same geologic formation” (language used in the definition of type well) or the manner in which the BLM makes that determination. Still others expressed concern that the use of type wells assumes that geologic zones are compositionally, texturally, and mechanically homogeneous media, even though this is often not true. Other commenters stated the type well
After reviewing the comments on the use of type wells, type wells are eliminated from the final rule. The BLM agrees that successful cementing operations on one well are not necessarily indicative of subsequent successful cementing of another well regardless of the proximity or geologic characteristics, and that implementation of the type well concept would be difficult to achieve. Rather than restructure the definition, or develop a specific set of standards, the BLM instead made the decision to eliminate the type well concept and to establish cementing operations monitoring requirements and usable water isolation requirements that apply to every well.
Numerous commenters objected to the requirement to run a CEL on each casing string that protects usable water. Many of these commenters stated that the use of CELs on surface casing is unprecedented for onshore wells. The commenters pointed out that state regulations do not require CELs on surface casing and that API guidelines do not mention cement logs in the section specifically devoted to surface casing. Many commenters stated that where cement is circulated to the surface and pressure tests are satisfactory, CELs do not provide any additional assurance of protection. Many commenters were concerned about the costs associated with running a CEL on surface casing. Many other commenters said that CELs are not commonly run on surface and intermediate casing unless other indicators of an unsuccessful cement job are present. Many of the commenters were critical that the BLM was relying on the CEL as the “sole diagnostic tool” to evaluate cement integrity. Many commenters stated that CEL data can be difficult to interpret properly and often yields false positives. The BLM agrees with many of these comments and has revised the final rule as a result. The final rule does not require a CEL on the surface casing unless there are indications of inadequate cement. Final section 3162.3-3(e)(2)(i) requires that the operator determine that there is adequate cement for surface casing used to isolate usable water zones. The operator must observe cement returns to the surface and document any indications of inadequate cement (such as, but not limited to, lost returns, cement channeling, gas cut mud, failure of equipment, or fallback from the surface exceeding 10 percent of surface casing setting depth or 200 feet, whichever is less). If there are indications of inadequate cement, then under final section 3162.3-3(e)(2), the operator must determine the top of cement with a CEL, temperature log, or other method or device approved by the authorized officer.
Many other commenters recommended that a CEL be required on every string of casing in every well. Commenters expressed concern that anything less would greatly increase the risk of contamination. The commenters were opposed to allowing operators to run CELs on type wells only. The commenters expressed the view that CELs are the only way to ensure adequate cementing of the casing on each well.
Numerous other commenters stated that the best way to confirm the adequacy of a cement job is through proper monitoring of the cementing operations and direct observation of a variety of factors; the most important being cement returns to the surface. Many commenters expressed concern about the reliability of CELs, stating that CEL data can be difficult to interpret properly and often yield false positives. Commenters said that this can lead to unnecessary attempts at remediation, which will actually weaken the wellbore integrity.
Some commenters said that allowing operators to use CELs, rather than just CBLs, alleviates some, but not all of the interpretation concerns. Other commenters stated that CBLs are not effective until the cement has reached a certain compressive strength because CBLs work on the principle of acoustic attenuation. At low compressive strengths, commenters stated that the acoustic properties of cement and water are very similar and it is difficult to delineate between the two when interpreting logs. The commenters went on to state that the problem is also inherent in the CELs, which can sometimes provide a risky basis for evaluating the integrity of the cement. The commenters claim that the logs do not “see” the cement. The logs merely allow a competent professional to draw inferences about the evenness of the cementing around the pipe, based on readings of sonic or ultrasonic waves passing through the pipe into the cement and the rock beyond. The commenters quoted API Technical Report 10TR1, September 2008, which cautions that cement bond log interpretation “is not recommended as a best practice for cement evaluation.”
After further researching these concerns, the BLM agrees that the monitoring of data and direct observations of various factors, including cement return to the surface, are good indicators of an adequate cement job, and the BLM acknowledges the potential difficulties of running and interpreting CELs. As a result, the BLM has determined that requiring CELs on the surface casing of every well will not provide increased protection beyond cement operations monitoring and circulation of cement to the surface. Therefore, the final rule requires operators to monitor their cementing operations, including verification of cement returns to the surface, and to submit the cementing operations monitoring report to the BLM prior to commencing hydraulic fracturing operations.
Some commenters disagreed with the proposed regulation allowing the operator to wait to submit a cement monitoring operations report to the BLM until after completion of the hydraulic fracturing operations. These commenters said that the operator should submit the report to the BLM prior to the commencement of hydraulic fracturing operations. The BLM agrees and revised the rule as a result of these comments. Final section 3162.3-3(e)(1) requires that during cementing operations on any casing used to isolate usable water zones, the operator must monitor and record the flow rate, density, and pump pressure and submit a cement operation monitoring report, including that information, to the authorized officer at least 48 hours prior to commencing hydraulic fracturing operations, unless the authorized officer approves a shorter time. This would allow the BLM time to review the monitoring report to verify compliance with these regulations. If the monitoring report indicates problems with the cementing operations, the operator must correct the issue prior to hydraulically fracturing.
The final rule also has more specific criteria for the operator to follow to determine that there is adequate cement for all casing strings used to isolate usable water zones. Onshore Order 2 (section III.B.1.c.) requires surface casing in all wells to be cemented to the surface. For surface casing, this final rule requires the operator to observe cement returns to the surface and to document any indications of inadequate cement (such as, but not limited to, lost returns, cement channeling, gas cut mud, failure of equipment, or fallback from the surface exceeding 10 percent of
The BLM believes that the final rule's requirements described earlier, in conjunction with the casing and cementing requirements of Onshore Order 2, will sufficiently isolate and protect usable water. As discussed earlier, Onshore Order 2 (section III.B.1.c.) requires that the operator cement the surface casing to the surface. Onshore Order 2 (section III.B.1.f.) also requires that the surface casing shall have centralizers on the bottom three joints of casing in order to keep the casing in the center of the wellbore to help ensure efficient placement of cement around the casing string. Onshore Order 2 (section III.B.1.h.) requires the operator to pressure test all casing strings to ensure the integrity of the casing. Onshore Order 2 (section III.B.1.i.) also requires a pressure integrity test of each casing shoe on all exploratory wells and on that portion of any well approved for a 5M (5,000 pounds per square inch) BOPE (blowout preventer equipment). This test insures that a good, leak-tight cement job has been obtained.
Final section 3162.3-3(e) strengthens the requirements that operators must follow when there is an indication of inadequate cementing. The operator must notify the authorized officer within 24 hours of discovering the inadequate cement. For the surface casing, this will likely be immediately following the cementing operations. For intermediate or production casing that is not cemented to the surface, this may not be until after the operator has run the CEL. Early notification will ensure that the BLM is involved with the remediation of the cement. Under the final rule the operator must submit an NOI to the authorized officer requesting approval of a plan to perform remedial action to achieve adequate cement. The plan must include supporting documentation and logs. The BLM will review the plan, work with the operator to modify the plan if necessary, and attach any conditions of approval to the plan. Upon approval, the operator can commence the remedial actions. After completing the remediation process, the operator must verify that the remedial action was successful with a CEL or other method approved in advance by the authorized officer. The operator must submit a subsequent report for the remedial action, including a signed certification that the operator corrected the inadequate cement job in accordance with the approved plan, and the results from the CEL or other method approved by the authorized officer and documentation showing that there is adequate cement. As required by existing section 3160.0-9(c), the subsequent report is due 30 days after the operations are completed. This final rule, however, also requires the operator to submit the results from the CEL or other method approved by the authorized officer at least 72 hours before starting hydraulic fracturing operations. This will provide the BLM the opportunity to verify the remediation process was successful and that will help to ensure adequate protection of aquifers in advance of hydraulic fracturing operations.
Several commenters said that section 3162.3-3(e) should be modified to specify that a CEL requirement does not apply to conductor pipe. The BLM agrees with this comment and has modified the rule at sections 3162.3-3(e)(1) and 3162.3-3(e)(2) to clarify that CELs are only required on casing strings designed to protect usable water. Conductor pipe does not typically protect aquifers. Conductor pipe is a large diameter pipe set to relatively shallow depths which serves as a conduit for all other casings and well operations. The formations close to the surface are often unconsolidated and during the commencement of drilling operations these formations erode or wash out from the circulating drilling muds. The conductor pipe's purpose is to prevent this near-surface erosion from interfering with subsequent drilling and operating activities. Based on the surface formation's conditions, certain wells do not have conductor casing set, in other instances conductor pipe is mechanically driven into the surface formations without any cement, and in other instances the conductor pipe consists merely of corrugated pipe and is cemented with construction cement. One of the roles of the surface casing, the first casing string set, is to protect the near-surface usable-quality waters. Because conductor casing is not designed to protect usable water zones, the CEL requirement does not apply. In addition, the surface casing would be adequately cemented inside the conductor pipe, thus protecting near-surface zones.
Several commenters stated that section 3162.3-3(e)(2) (proposed section 3162.3-3(e)(4)) regarding indications of inadequate cement should be modified. Commenters indicated that the inadequate cement job criteria listed were not good indicators of an inadequate cement job. The commenters did not offer any suggestions of what would be good indicator(s). The BLM did not revise the rule as a result of this comment. The provision regarding indicators of inadequate cement, at final section 3162.3-3(e)(2)(i), expressly includes the language “such as, but not limited to” to indicate that the subsequent list is not an exhaustive list of possible indications of inadequate cement.
The BLM also received comments that this section should be revised to exempt cement fall back from being classified as an indication of inadequate cement. Commenters indicated that there should be a specific exception for those instances where the only remedy is to top-fill cement that has settled in the annulus after curing. The BLM agrees and has revised the rule as a result of these comments. Section 3162.3-3(e)(2) now addresses adequate cement for surface casing or intermediate and production casing separately. Additionally, the BLM believes that the fallback indicator for inadequate cement should incorporate a performance standard. Based on the BLM's experience, 10 percent of surface casing setting depth or 200 feet, whichever is less, is the limit that routine “top-jobs” are successfully performed; therefore, the rule has been revised to incorporate this exception as a fall back indicator for inadequate cement. Appropriate remedial operations are to be conducted in either event; however, determination of the cement top via a CEL would not be required under this exception.
Numerous commenters stated that the rule provisions dealing with self-certification should be modified. The supplemental proposed rule proposed self-certification statements for remedial cement jobs, wellbore integrity, fluids used, and compliance with laws and regulations.
Some commenters indicated that certifications are unnecessary and require the operator to certify the actions of third parties over whom they
Some commenters objected to the requirement that the operator certify proper execution of remedial cement jobs, the mechanical integrity of casing, and legal compliance related to hydraulic fracturing fluids, among other issues. They asserted that it is impossible for the operator to have one individual who can certify all of those matters and said that the possibility of criminal enforcement is an unreasonable imposition. The BLM disagrees. The operator has always been responsible for everything that occurs on the permitted well site. See existing section 3100.5(a). If an operator uses one or more service contractors for specific tasks, the operator remains fully responsible for those operations. See existing section 3162.3(b). If the operator's contractor, as its agent under existing section 3162.3(b), submits a certification, it is deemed to have come from the operator. Since 1948, the law has provided for criminal liability for certain false statements in public land matters, whether sworn or unsworn. 43 U.S.C. 1212. The certification requirement underscores the importance of operators taking responsibility for reporting accurate information necessary to assure that hydraulic fracturing operations were properly conducted and is intended to ensure that contractor activities on the lease are properly overseen by the operator. The final rule is not revised in response to these comments.
Other commenters were concerned that despite taking all prudent steps, implementing accepted industry standards, and complying with all regulatory requirements in the final rule, the operator could in good faith provide a certification that later in time is found invalid based on circumstances or facts unknown to the operator or that were out of his or her control. The BLM did not make any changes to the rule based on these comments. The BLM would take an operator's diligence and good faith into consideration in exercising enforcement discretion where a certification was later shown to have been in error.
Other commenters said that additional certifications should be required, including fracture propagation and the protection of usable water. The BLM did not make any changes to the rule as a result of these comments. The BLM believes that the subsequent report adequately details fracture design considerations, including fracture propagation. Additionally, usable water considerations are addressed at both the APD and hydraulic fracturing review stages.
Several commenters suggested that the rule require the cement monitoring report in paragraph section 3162.3-3(e)(1) to be submitted to the BLM prior to commencing hydraulic fracturing operations. This would give BLM field offices the opportunity to review the report to ensure the cement job was adequate. The proposed rule would have given operators 30 days from the completion of hydraulic fracturing operations to submit the cement monitoring report. The BLM agrees with this comment and revised final section 3162.3-3(e)(1) to require that the report be submitted at least 48 hours prior to commencing hydraulic fracturing operations.
One commenter suggested that the cement contractor's report should be acceptable to the BLM. The requirements of the cement report are detailed in section 3162.3-3(e)(1) of this rule. Any report meeting these requirements would be acceptable to the BLM, including a report submitted by the cement contractor as an agent of the operator. See 43 CFR 3162.3(b). No changes to the rule were made as a result of this comment.
One commenter suggested that the cement monitoring report in section 3162.3-3(e)(1) should be submitted to the BLM within 30 days of cementing, not within 30 days after completion of hydraulic fracturing operations as stated in the supplemental proposed rule. This, according to the commenter, would give the BLM adequate time to review the report prior to hydraulic fracturing. The rule is revised based on other comments to require the cement monitoring report at least 48 hours prior to hydraulic fracturing, which addresses the commenter's concern. In addition, the BLM does not believe that operators would proceed to fracture a well if the monitoring report showed a failure to ensure isolation and protection of usable water, knowing that if the BLM discovered the failure, the operator would be subject to enforcement action.
This section requires the operator to conduct a Mechanical Integrity Test (MIT). The MIT required by this rule is a pressure test of the casing through which the hydraulic fracturing will occur or through the fracturing string (if used). Industry guidance and many state regulations are consistent with this requirement. The API's guidance
Industry guidance on hydraulic fracturing states that the operator should pressure test the production casing. “Prior to perforating and hydraulic fracturing operations, the production casing should be pressure tested (commonly known as a casing pressure test). This test should be conducted at a pressure that will determine if the casing integrity is adequate to meet the well design and construction objectives.” (API Guidance Document HF1, First Edition, October 2009) This casing pressure test meets the intent of the MIT required by the rule.
Two changes were made to the MIT requirements in the final rule. The reference to refracturing in the supplemental proposed rule is deleted because the final rule no longer makes any distinction between refracturing and fracturing. The requirement to only perform an MIT on vertical sections of the wellbore in the supplemental proposed rule is also deleted in the final rule. This change ensures that the entire length of casing or fracturing string, not just the vertical section, prior to the perforations or open-hole section of the well, is able to withstand the applied pressure and contain the hydraulic fracturing fluids. In addition, it was unclear to what the term vertical section would apply in a directionally drilled well.
The BLM received numerous comments on performing a successful MIT prior to hydraulic fracturing. These comments ranged from concerns involving need, type wells, MIT reporting, well configurations,
Several commenters stated that the MIT requirement in general is unnecessary and costly. Other commenters indicated that because MITs are already completed as a matter of industry practice prior to any pumping procedure, regulating such procedure is merely bureaucratic and serves no environmental protection. The BLM realizes that many operators perform MITs; however the BLM believes that ensuring casing integrity prior to hydraulic fracturing is essential and that the only way to verify the integrity of the casing is to require a test to the anticipated hydraulic fracturing pressure. An MIT conducted immediately preceding the hydraulic fracturing operation to the specified test pressure would suffice. No change was made to the rule as a result of these comments.
Some commenters were concerned that an MIT would not be required on every well if the type well concept was adopted. As discussed, the proposed type well concept is not included in the final rule. Elimination of the type well concept clarifies any confusion regarding the requirement for an MIT for type wells. The final rule now requires that a successful MIT be performed on every well prior to hydraulic fracturing. The BLM believes that this is the only method that will ensure that each well to be hydraulically fractured demonstrates the appropriate structural capabilities to withstand the intended applied pressures.
Some commenters said that the rule requiring MITs for refracturing should be modified. The commenters stated that the requirement to perform an MIT before refracturing operations is unjustified. The commenter suggested that the BLM should put a timing restriction on when an MIT must be performed when refracturing a well. As previously discussed, the final rule has eliminated the term “refracturing” in its entirety. An MIT will be required prior to the first hydraulic fracturing operation in any well, and prior to all subsequent hydraulic fracturing operations in that well. To ensure proper wellbore integrity for protection and isolation of the usable water, an MIT will be required to ensure that an existing well is properly bonded and sheathed to sustain high pressures during a hydraulic fracturing operation. The BLM did not revise the rule as a result of these comments.
Other commenters recommended that the BLM require reporting the results of the MIT prior to hydraulic fracturing. The BLM does not believe that a requirement to report the results of the MIT prior to fracturing is necessary to ensure wellbore integrity. Final section 3162.3-3(f) requires a successful MIT prior to hydraulic fracturing; therefore, if the MIT failed and the operator proceeded with hydraulic fracturing operations, the operator would be in violation of the rule and would be subject to enforcement actions. No revisions to the rule were made as a result of this comment. In addition, final section 3162.3-3(i)(8)(i) requires a certification to be signed by the operator that it had performed a successful MIT under section 3162.3-3(f).
Some commenters recommended that the BLM clarify the requirement for conducting the MIT when the well configuration contains a pressure-actuated valve or sleeve at the end of a lateral completion. The commenters expressed concern that pressure testing this valve or sleeve to maximum anticipated pressure will possibly open the valve or sleeve, causing the pressure test to fail the proposed standard of 30 minutes with no more than a 10 percent pressure loss. The BLM also received comments urging modification to the MIT requirements for open-hole completions. The BLM appreciates the concerns expressed by the commenters. The BLM believes that ensuring casing integrity prior to hydraulic fracturing is essential and the best way to ensure the integrity of the casing is to test to the anticipated hydraulic fracturing pressure. No revisions to the rule were made as a result of these comments. Also, because this is a national rule, it cannot address all the possible wellbore configurations, and the BLM recognizes that certain wellbore configurations may require modifications to perform this test. Many wellbores will require the setting of packers, or other acceptable methods, to isolate existing, sensitive downhole components or open-hole completions. Operators are encouraged to anticipate these complications and provide details to the BLM's authorized officers in their hydraulic fracturing APDs and NOIs.
Several commenters requested clarification regarding at what point in the process should results of the MITs be submitted and for how long must the operator keep the results of the MIT. The final rule was not revised as a result of these comments; however, the rule was reorganized to better reflect the BLM's intent. As required by final section 3162.3-3(i)(9), the MIT results are required to be submitted to the BLM authorized officer, via a subsequent report, within 30 days after the completion of the last stage of the hydraulic fracturing for each well. Existing section 3162.4-1(d) requires that the operator maintain all required records and reports, including MITs, for 6 years from the date that it was generated.
Some commenters said that the rule should be modified to change the term “MIT” to “casing pressure test.” Other comments asked if the MIT was the same casing pressure test required by Onshore Order 2. The BLM did not make any changes to the rule as a result of these comments. The BLM believes that the term “Mechanical Integrity Test” is widely understood by industry, is used by many state regulatory agencies, and accurately describes the test. The MIT required by final section 3162.3-3(f) is not equivalent to either the casing pressure test required by Onshore Order 2, section III.B.1.h., or the casing shoe pressure test as currently required by Onshore Order 2, section III.B.1.i. The MIT is a specific test conducted on a wellbore in its hydraulic fracturing configuration and to the maximum anticipated pressure for the hydraulic fracturing operation being contemplated.
Some commenters suggested various alternative testing pressures or procedures to be used for the MIT. Commenters recommended lower pressures than the proposed rule provided or suggested that alternative methods, including ultrasonic imaging, could be utilized. Final section 3162.3-3(f) requires the operator to perform a successful MIT to not less than the maximum anticipated surface pressure that will be applied during the hydraulic fracturing process. This testing is necessary to help ensure the integrity of the wellbore during hydraulic fracturing operations. This test demonstrates that the casing provides sufficient structural strength to protect usable water and other subsurface resources during hydraulic fracturing operations. The BLM specifically chose the MIT over other alternative tools so that the test could be accomplished without requiring additional equipment, such as ultrasonic imaging tools. No revisions to the rule were made as a result of these comments. However, the BLM may consider a proposal by the operator to use alternative tools to an MIT. If such tools meet or exceed the objectives of performing an MIT, then the BLM may authorize an operator to use such tools as a variance to this requirement.
Commenters suggested alternative MIT failure indicator levels. Section 3162.3-3(f)(3) requires the well to hold the pressure for 30 minutes with no more than a 10 percent pressure loss. As previously pointed out, this test
This section requires the operator to continuously monitor and record the annulus pressure at the bradenhead during the hydraulic fracturing operation.
In the final rule, the BLM removed the term “refracturing” from the title of the section because the final rule no longer defines or uses the term “refracturing.” The final rule also clarifies that when pressures within the annulus increase by more than 500 psi, the operator must stop fracturing operations and determine the reasons for the increase. Prior to recommencing hydraulic fracturing operations, the operator must perform any remedial action required by the authorized officer and successfully perform an MIT required under paragraph (f) of the rule. The BLM believes that these actions are necessary in these cases to ensure that the integrity of a wellbore is confirmed through an MIT prior to recommencing hydraulic fracturing operations.
One commenter believed that the requirements for the operators in section 3162.3-3(g) of the supplemental proposed rule to continuously monitor and record annulus pressure at the bradenhead were too vague and wanted more specificity in the rule. The commenter also believed that the requirement was unnecessary. The commenter explained that operators already monitor pressures during hydraulic fracturing operations using sophisticated and expensive equipment. Another commenter said that the monitoring requirement could not be achieved because the bradenhead is not accessible. The BLM reviewed the language in the supplemental proposed rule and has determined that the language in this section is clear as written. In fact, the language in this section is very similar to the requirements in Colorado rule 341 (Colorado Oil and Gas Conservation Commission, February, 2014,
Other commenters recommended that the monitoring should continue on a daily basis for the first 30 days after hydraulic fracturing and then monthly for 5 years thereafter. The BLM disagrees with this comment. Upon completion of pumping the hydraulic fracturing fluids, the wellbore is no longer subject to the pump pressure. Therefore, continual monitoring for wellbore issues caused by the hydraulic fracturing operation is unnecessary. No revisions to the rule were made as a result of these comments.
Some commenters suggested that the reporting requirements of pressure increases by more than 500 psi during hydraulic fracturing operations in the annulus during hydraulic fracturing under section 3162.3-3(g)(2) of the supplemental proposed rule is unnecessary because it duplicates state requirements. Another commenter asserted the need for a more comprehensive regulatory approach for hydraulic fracturing operations in state and tribal lands. The BLM acknowledges that some states have similar requirements, but not all states have the same requirements. Since this rule applies to all Federal and Indian minerals, this requirement is necessary. Even in states that do have a similar requirement, the BLM needs to know about the pressure increase so that the BLM can work closely with the operator to correct the issue and take the appropriate action.
Another commenter recommended that in addition to the oral notification of a pressure increase, written notice should also be required. The BLM believes oral notification is sufficient in this situation. If warranted, the BLM may require additional documentation regarding the pressure increase and the corrective measures that were taken to abate the situation.
One commenter recommended that the BLM adopt the language in the original proposed rule which required the operator to file a subsequent report of the corrective actions taken within 15 days, instead of the language in the supplemental proposed rule which requires the submission of the subsequent report within 30 days of completion of the hydraulic fracturing operations. As stated earlier, the BLM will work closely with the operator following notification of the pressure increase. Since the BLM will be aware of the incident by the oral notification and will be involved with the corrective action from the start, the timing of submission of the subsequent report is not critical to the BLM. The 30-day requirement is consistent with all of the other documentation required to be included in the subsequent report. No revisions to the rule were made as a result of these comments.
One comment made numerous suggestions about additional monitoring that should take place on producing wells. The suggestions include:
• Submit monthly and annual production reports including volume of oil and gas to the BLM;
• Monitor pressure of each well daily for the first 30 days of operation;
• Maintain production and monitoring reports for 5 years;
• Conduct periodic well tests to determine flow rate and pressure;
• Maintain and test wellhead equipment over the life of the well;
• Annually report casing pressures to the BLM and notify the BLM if pressures approach the design limits of the casing;
• Install pressure relief valves, especially on high-pressure or high-volume wells; and
• Monitor all wells for corrosion and potential hazards.
The BLM did not revise the rule as a result of these comments because these comments apply to producing wells whether or not they are hydraulically fractured. The BLM believes that the existing monitoring, maintenance, and reporting requirements for producing wells are adequate. See 43 CFR part 3160, and
For example, operators of Federal and Indian wells already must report production to the Office of Natural Resource Revenue (ONRR). Furthermore, the supplemental notice of proposed rulemaking did not propose to amend the onshore orders or other operating regulations.
Several commenters suggested that the rule require operators to notify the BLM if the annular pressure exceeds 80 percent of the casing internal yield rating during hydraulic fracturing. Both the supplemental and the final rules require the operator to notify the BLM if the annular pressure exceeds 500 psi. The BLM determined that the standard for notifying the BLM should be an objective and easily measured parameter. The 500 psi limit can be detected by observing a pressure gauge. A standard based on casing yield ratings as the commenters suggested would be more difficult to detect and implement, especially if the person observing the gauge was not familiar with the weight, grade, and depth of the casing run, or the weight of the mud in the hole. In addition, as part of the BLM's review of hydraulic fracturing applications, the engineer will ensure that a 500 psi increase in annular pressure will not jeopardize the integrity of the casing. No revisions to the rule were made as a result of this comment.
This section requires operators to manage recovered fluids in rigid enclosed, covered, or netted and screened above-ground tanks. Those tanks may be vented, unless Federal, state or tribal law, as appropriate for the surface estate involved, require vapor recovery or closed-loop systems. The tanks must not exceed a 500 barrel (bbl) capacity unless approved in advance by the authorized officer. In certain very limited circumstances, the operator may apply for approval to use a lined pit.
Tanks that are not enclosed will need to be covered, netted, or screened to exclude wildlife. This is not a new requirement. In 2012, the BLM issued an instructional memorandum to its authorized officers to assure that pits, tanks, and similar structures are netted or screened to prevent entrapment and mortality of wildlife. (See
The supplemental proposed rule would have required that recovered fluids be stored in lined pits or tanks unless otherwise required by the BLM. The final rule incorporates two significant changes. First, the BLM decided not to distinguish flowback fluid from produced water. Instead, in the final rule the requirements for the storage of flowback fluid only apply to the interim period between the completion of hydraulic fracturing and the implementation of an approved plan for the disposal of produced water under Onshore Order 7. Fluids produced from the well during this period are referred to as “recovered fluid” in the final rule and the term “flowback” is deleted from the rule. Second, instead of allowing lined pits or tanks, as proposed in the supplemental proposed rule, the final rule requires that all recovered fluids to be stored in above-ground tanks unless otherwise approved by the BLM in advance of generating recovered fluids. In addition, a list of minimum criteria for the approval of storage in lined pits is included in the final rule.
In the supplemental proposed rule, the BLM asked for comments on whether flowback fluids should only be stored in closed tanks. The BLM received comments that both supported and objected to this proposal. Comments supporting a “tanks only” approach stated that the risk of impacts to air, water, and wildlife is too great, even if a pit is lined. Those commenters stated that lined pits are still subject to breaching, failure, and leaking. In addition, because pits are open to the atmosphere, fumes from the fluid in the pits can become airborne and cause health and environmental problems. The commenters also raised the possibility of wildlife getting into pits and dying or becoming ill from exposure to the chemical constituents in the fluids. Some of these comments suggested that flowback fluid should only be stored in “closed systems” that would not only use tanks, but the tanks would be vapor tight to eliminate the possibility of air contamination.
Many of the comments objecting to a “tanks only” approach raised the issue of increased cost if tanks or “closed systems” were required. Most of these comments preferred the flexibility of lined pits or tanks, depending on the location or the specific situation. For example, the extra cost of storing flowback fluid in tanks may have no benefits in remote areas where there are no water sources which could be contaminated and no human populations that could be affected by airborne contaminants. Some of the comments suggested that the rule could require geo-textile or composite liners or double-lined pits with leak detection systems in order to reduce the risks of leakage. Other commenters raised the concern of unintended consequences of requiring tanks, such as increased truck traffic.
After reviewing these comments and comments relating to the definition of “flowback,” the BLM decided to make a number of modifications to final section 3162.3-3(h). First, because the BLM is not differentiating “flow back” fluid from produced water, the requirements in paragraph (h) will only apply to the fluids recovered between the completion of hydraulic fracturing and the implementation of a plan for the disposal of produced water approved under BLM regulations, which currently are in Onshore Order 7. This will ensure that recovered fluids are stored and handled in a way that minimizes the risk of impacts to air, water, and wildlife during the interim period (up to 90 days) while the BLM is reviewing the operator's long-term plan for the disposal of produced water. When the information is available, the BLM highly encourages operators to submit their plans for long-term storage of recovered fluids with their APD or NOI for proposed hydraulic fracturing operations to allow the BLM to evaluate the various aspects of an operator's development proposal under one review process, rather than multiple processes.
Second, the BLM agrees with the comments stating that the storage of flowback, or recovered fluid in pits, poses a risk of impacts to air, water, and wildlife. Therefore, this rule requires storage of recovered fluids in rigid enclosed, covered, or netted and screened above-ground tanks during the interim period before the operator implements a BLM-approved plan for the disposal of produced water under its regulations (currently in Onshore Order 7). The BLM believes that above-ground tanks, when compared to pits, are less prone to leaking, are safer for wildlife, and will have less air emissions. The BLM generally considers tanks as being constructed from a rigid material such as steel or fiberglass. The BLM realizes
Third, the BLM agrees with the comments asking for the flexibility to allow lined pits based on site-specific conditions, but believes such exceptions should be limited and rarely granted. As a result, final section 3162.3-3(h)(1) allows the BLM to approve the storage of recovered fluids in lined pits on a case-by-case basis and only if the applicant demonstrates that the use of an above-ground tank is infeasible for environmental or public health or safety reasons only and all of the listed criteria are met. In circumstances where use of above-ground tanks has concomitant impacts to the environment, public health, and safety, the rule allows BLM to exercise its discretion to approve lined pits, but only if they meet all of the listed criteria. These criteria include minimum distances from water sources, public places, and residences, as well as potential floodplain impacts. If approved, the lined pit would be required to be constructed and maintained in accordance with final section 3162.3-3(h)(2), which requires the pit to be properly located, lined with a durable, leak-proof synthetic material and equipped with a leak detection system. Onshore Order 7 already establishes a standard for leak detection systems when disposing of produced water into lined pits. The minimum distances found in this section are similar to requirements found in Title 19, Chapter 15, Part 17 of the New Mexico Administrative Code. The BLM considers the criteria in this section as minimum requirements—if an operator proposes to store recovered fluid in a lined pit that does not meet one or more of these minimum requirements, the BLM would not approve the storage method. However, the BLM has the discretion to deny proposals to use lined pits that meet or exceed the minimum criteria, based on site-specific conditions. In no cases would the BLM allow the storage of recovered fluids in unlined pits.
Moreover, in the BLM's experience, the use of tanks in lieu of pits in high-volume operations limits potential environmental impacts, allows for quicker site preparation, reduces reclamation requirements, eliminates longer term environmental risk, reduces risks of spills or leaks, and increases safety. A tank can be removed in a day and there is no waiting required to recontour and seed the surface for reclamation purposes. The use of tanks for temporary storage of recovered fluids also provides the additional advantage of not requiring any long-term monitoring and mitigation. Pits also require periodic upkeep, monitoring, and fences. Several comments suggested that treatment and injection is the safest and most effective way to dispose of flowback fluids. The BLM did not revise the rule based on these comments because the ultimate disposal of recovered fluids is outside the scope of this rule, and, except for disposal on or in public lands, is outside of the BLM's regulatory authority.
In the BLM's experience, most operators use rigid, truck- or trailer-mounted tanks for temporary storage of recovered fluids, and those tanks are usually no larger than 500 bbl capacity. Large open-topped tanks, often called “semi-rigid,” can be susceptible to failures of seams or welds. Failure of a large-capacity tank containing recovered fluids would pose particular risks of harm to humans and wildlife because of the amount of fluid involved. Failures of large-capacity open-topped tanks have been documented. For example, between October 2011 and June 2013, there were five catastrophic failures of large-volume tanks reported to the Colorado Oil and Gas Conservation Commission (none of those tanks contained recovered fluids). Colorado has banned the storage of recovered fluids from such large-volume tanks.
In the supplemental proposed rule, the BLM asked for comments on whether or not the rule should differentiate flowback fluids from produced water and, if so, how the two should be distinguished. Flowback fluids generally refer to the fluids recovered from the well immediately after hydraulic fracturing, presumably containing a high percentage of the fluids injected during hydraulic fracturing. Produced water is generally considered to be water from the hydrocarbon zone that is produced along with oil and gas.
Onshore Order 7 establishes requirements for the handling and disposal of produced water. If this rule did not distinguish flowback fluid from produced water, then Onshore Order 7 could be applied to all water produced from the well, including that water recovered from the well immediately after hydraulic fracturing. If this rule did distinguish flowback fluid from produced water, then unique handling, disposal, and reporting requirements could be imposed for the flowback fluid.
The majority of comments received regarding this issue recommended that the rule not try to distinguish flowback fluid from produced water. The primary reasons given were: (1) There is no way to define the difference between the two; and (2) They are both potentially hazardous and should be treated in the same manner. A minority of comments recommended that the rule establish special handling, disposal, and reporting requirements for flowback fluid. However, no clear or enforceable means of making the distinction was given. Several comments suggested a time-based approach (
The BLM considered numerous different criteria on which to differentiate flowback fluid from produced water, including all the methods suggested in the comments. The BLM decided that any method of differentiation would be either arbitrary (
Ultimately, the BLM decided not to make a distinction between flowback fluid and produced water and all references to the term “flowback” were removed in the final rule (sections 3162.3-3(d)(5), (i)(6), and (i)(7)). Instead, the term “recovered fluid” is used in the final rule for all fluids coming from the well after a hydraulic fracturing operation is complete. Also Onshore Order 7 generally applies to all recovered fluids, including those fluids recovered immediately after hydraulic fracturing. However, under Onshore Order 7, section III.A., an operator has permission to temporarily dispose of produced water from newly completed wells for up to 90 days, until an application for the disposal of produced water is approved by the authorized officer. This 90-day interim period is typically when the highest percentage of hydraulic fracturing fluid is recovered. The BLM determined that special handling provisions are necessary for fluids recovered during this interim period after hydraulic fracturing and revised section 3162.3-3(h) of the final rule as a result (see the discussion of pits versus tanks under section 3162.3-3(h)).
The BLM also revised the provision for reporting the volume of fluid recovered during flowback, swabbing, or recovery from production vessels in final section 3162.3-3(i)(6). Instead of reporting volumes of “flowback” in the subsequent report for an undefined period of time, the BLM determined that the ultimate goal is to have a complete record of all volumes recovered from a well, regardless of how it is defined or when it is recovered. ONRR requires operators to report the monthly volume of all fluids (oil, gas, and water) produced from wells on the Oil and Gas Operations Report, Part A (OGOR A). However, some operators do not start reporting on OGOR A until royalty-bearing quantities of oil and gas are produced, thereby leaving a potential gap in the reporting of recovered fluids. To fill this gap, paragraph (i)(6) in the final rule requires operators to report the volume of fluid recovered between the completion of hydraulic fracturing and the start of reporting on OGOR A. Because the subsequent report is due 30 days after the completion of the last stage of hydraulic fracturing, there may be situations where the subsequent report is filed prior to the start of reporting on OGOR A. In these cases, the operator would have to file an amended subsequent report showing the total volume of fluid recovered prior to the start of reporting on OGOR A.
Refer to Figures A and B for an example of how the BLM will implement the provisions of this rule. Both figures show the flow rate of fluid recovered after hydraulic fracturing over some time period. Typically, the initial flow rate is high and declines over time as the excess pressure caused by hydraulic fracturing is relieved. The area under the flow-rate curve represents the volume of fluid recovered over a given time period. In Figure A, the operator begins reporting produced volumes on OGOR A 10 days after the completion of hydraulic fracturing and submits its subsequent report 20 days after the completion of hydraulic fracturing. Because reporting of recovered volumes on OGOR A precedes submittal of the subsequent report, only that volume recovered between the completion of hydraulic fracturing operations and the start of reporting produced fluids on OGOR A would be reported on the subsequent report—12,000 bbl in this example. The additional 5,000 bbl recovered before the submittal of the subsequent report will be captured by the volumes reported on OGOR A, thereby providing a continuous record of the volume of fluid recovered for the life of the well.
In Figure B, the subsequent report is submitted on its due date (30 days after the completion of hydraulic fracturing), but reporting of produced fluids on OGOR A does not occur until 40 days after the completion of hydraulic fracturing. In this example, the operator would have to submit a supplemental subsequent report showing the total volume of 24,000 bbl recovered between the completion of hydraulic fracturing and the start of reporting on OGOR A.
Several comments suggested that the BLM require that flowback fluid be tested prior to disposal. The BLM did not revise the rule as a result of this comment because disposal of recovered fluids is generally done off-site and under the authority of other agencies such as the EPA (for underground injection). Disposal on Federal or Indian land would be covered under Onshore Order 7.
One commenter suggested that the BLM create a manifest system to assure proper disposal of recovered fluids. While the commenter did not expound on what was meant by a “manifest system,” the BLM assumes it to mean a system of formal documented custody transfer ensuring that all flowback fluid removed from the site arrives at its destination (a disposal facility). Onshore Order 7 already requires the operator to submit a copy of the disposal facility's permit, and a right-of-way authorization if the wastewater would travel over Federal or Indian lands off of the lease. Other agencies regulate the transport and disposal of chemical wastes, and this rule does not interfere with those regulatory programs.
One comment suggested that the BLM should get rid of the Onshore Order 7 provision that allows the disposal of pit liquids through evaporation. No revisions to the rule were made as a result of this comment because it cannot be addressed at this final rule stage, but the BLM will evaluate and consider options for updating requirements under all of its existing Onshore Orders. This rule sets standards for the handling of recovered fluid until a disposal plan is approved by the BLM under Onshore Order 7. This rule does not amend Onshore Order 7.
Several commenters suggested that the rule should require the monitoring of constituents of flowback fluid. The BLM did not incorporate this suggestion because the goal of the rule is to contain the recovered fluids regardless of their chemical constituents. Disposal facilities often require an analysis of the fluid to be disposed; however, that is outside the scope of this rule.
This section lists information that the operator must submit to the BLM after the completion of a hydraulic fracturing operation and requires a disclosure of the chemicals used during the operation to FracFocus, the BLM, or another database that the BLM specifies.
The BLM strongly encourages operators to submit the chemical disclosure data through the FracFocus database. If data is submitted directly to the BLM, the BLM will upload it to Fracfocus.org. This will meet the goals and requirements of the rule most effectively by providing a direct public disclosure of the chemical additives used in the hydraulic fracturing operation. If the BLM finds that operators are avoiding use of FracFocus without a justification, such as temporary problems with the FracFocus site, the BLM will consider requiring a filing fee for chemical disclosure data submitted directly to the BLM.
Numerous changes are made to this section of the final rule. In the supplemental proposed rule, the 30-day time period for submitting the subsequent report would have begun when hydraulic fracturing operations were complete. In the final rule, the start of the time period begins after the last stage of hydraulic fracturing operations on each well is complete. This change is to clarify that in a multi-stage hydraulic fracturing operation, the operation is not complete until the last stage of hydraulic fracturing on each well is complete.
In section 3162.3-3(i)(1), the final rule clarifies that a description of the base fluid and each chemical added to the hydraulic fracturing fluid must be reported, instead of each chemical used. The BLM made this change to clarify that operators do not have to report chemicals that are found in the water used as a base fluid, whether taken from surface or groundwater, or reuse or recycled water. The word “description” is added for clarity.
The downhole information in section 3162.3-3(i)(2) of the supplemental proposed rule is moved to a new section (i)(5) of the final rule for clarity and to be consistent with the informational requirement of section (d)(3). Section (i)(2) of the final rule is now specific to water sources and section (i)(5) is specific to downhole information.
The pressure information in section 3162.3-3(i)(3) of the supplemental proposed rule is changed in the final rule to clarify that the maximum surface pressure at the end of each stage is required. The supplemental proposed rule would have required the “actual surface pressure,” which could be ambiguous. The maximum surface pressure is needed for the BLM to ensure that the pressure used in the MIT, as required in section 3162.3-3(f) of the final rule, was not exceeded.
Section 3162.3-3(i)(6) of the final rule redefines the period over which the volume of recovered fluids must be given in the subsequent report. In the supplemental proposed rule (section (i)(5)(i)) the volume of fluid to be included in the subsequent report was the amount recovered during flowback, swabbing, or recovery from production vessels. However, the supplemental proposed rule did not define the flowback period, or the period over which fluid recovery from swabbing or recovery from production vessels would have to be reported. The BLM determined that the goal of reporting recovered fluids is to have a complete history of everything that comes out of the well, regardless of how it is defined. Once an oil and gas well begins producing oil and gas, the monthly volumes of gas, oil, and water produced from each well must be reported on the OGOR A under 30 CFR 1210.102(a). Therefore, the only additional volumes that are needed to provide a complete history of fluids produced after hydraulic fracturing is the water produced immediately after hydraulic fracturing, but prior to the production of oil and gas that would trigger reporting on the OGOR A. If reporting on OGOR A does not start for more than 30 days after hydraulic fracturing—the timeframe in which the subsequent report is due—an amended subsequent report would have to be filed when OGOR A reporting started, showing the total volume of fluid produced since the completion of hydraulic fracturing.
Section 3162.3-3(i)(7) of the final rule (section 3162.3-3(i)(5) of the supplemental proposed rule) is revised to apply only to the handling and disposal of fluids recovered between the completion of hydraulic fracturing operations and the approval of a plan for the disposal of produced water under Onshore Order 7. The supplemental proposed rule would have required information on the handling and disposal of recovered fluids, but did not define what constituted “recovered fluids.” In addition, the examples of handling and disposal methods are revised to coincide with the information requirements in the hydraulic fracturing application in section (d)(5).
Section 3162.3-3(i)(7)(i) in the supplemental proposed rule would have required that the operator to certify that wellbore integrity was maintained under section (b) of the rule. Section 3162.3-3(i)(8)(i) of the final rule is reworded so that it is clear that the certification refers to compliance with paragraphs (b), (e), (f), (g), and (h) of this rule.
Section 3162.3-3(i)(9) of the final rule (section 3162.3-3(i)(8) of the supplemental proposed rule) is revised to eliminate the need to submit well logs and records of adequate cement (including CELs) under this section because the operator must already
Several commenters were concerned that the specific fracture dimensions data required by this section (fracture length, height, and direction) could only be obtained through fracture modeling and requested that the BLM allow the use of fracture data gathered and modeled for similar wells, as opposed to requiring new modeling for every well. The BLM did not make any changes as a result of these comments. As provided by this section, fracture length, height and direction data can be actual, estimated, or calculated. The BLM is anticipating only hydraulic fracturing design estimates, and that hydraulic fracturing modeling is not required to meet this requirement. These data are obtained by some operators during the fracturing operation using microseismic fracture mapping, a diagnostic technique that measures created hydraulic fracture dimensions and their azimuth. The purpose of fracture data is to avoid potential interconnectivity between fractured pathways and either existing wellbores,
Several comments suggested that the subsequent report compare the actual fracture dimensions with those estimated in the NOI. The BLM did not make any changes to the rule in response to these comments because the only method of verifying actual fracture dimensions is with a microseismic array, which the BLM is not requiring. The BLM believes that for the purpose of protecting ground water and identifying potential “frack hits,” estimated fracture dimensions are adequate. The estimated fracture dimensions are based on actual volume and pressure used during the hydraulic fracturing operation, and knowledge of the perforated string and the geology.
Several commenters stated that the BLM should allow 60 days after completion of hydraulic fracturing operations for submitting the completion reports required under section 3162.3-3(i). Some commenters added that it takes the operator some time after the completion of operations to gather the information from their service contractors and to then compile the report accurately prior to submission. One commenter also indicated that for consistency with existing chemical disclosure reporting requirements of a couple of states (Colorado and North Dakota), the timeframe for submittal should be modified to 60 days. Another commenter suggested that the information could be submitted in an annual report. The BLM requirement to submit completion reports within 30 days after completion is consistent with the BLM's existing requirements under Onshore Order 1, section IV.e. Given experience with industry submission of information to the BLM, 30 days has been demonstrated to be an acceptable timeframe for accurate submissions. The BLM did not make any changes as a result of these comments.
One commenter suggested that the word “fluid,” as it is used in the rule to provide an estimated volume of fluid in the initial submission of hydraulic fracturing proposal under section 3162.3-3(d)(4)(i) and for reporting the volume of fluid recovered under section 3162.3-3(i)(6), is ambiguous. The commenter recommended that the BLM require reporting of the total volume of “hydraulic fracturing fluid,” including gas, used or injected into the well, stated in gallons or other appropriate volumetric units of measurement. The BLM recognizes that a fluid includes both liquids and gases and any device employed to measure liquid volume would also measure any suspended or dissolved solids in the liquid. The BLM has defined the term “hydraulic fracturing fluid” in section 3160.0-5 in this rule. This should provide the needed clarity. Therefore, under this rule, the word “fluid” includes the liquid or gas, and any associated solids used in hydraulic fracturing, including constituents such as water, chemicals, and proppants. The BLM did not revise the rule based on this comment because the wording in the supplemental and final rules addresses the commenter's concern.
One commenter stated that the term “wellbore integrity,” as used in section 3162.3-3(i)(7)(i) of the supplemental proposed rule is vague and undefined. The BLM agrees with that comment and has deleted the separate reference to “wellbore integrity” in the final rule, which is now designated section 3162.3-3(i)(8)(i).
One commenter stated that the BLM should remove the requirement to certify wellbore integrity that cross-references to usable water zonal isolation. The commenter states that section 3162.3-3(i)(7)(i) of the supplemental proposed rule would require that operators certify that well integrity was maintained prior to and throughout the hydraulic fracturing operation, as required by section 3162.3-3(b). Section 3162.3-3(b) directly refers to the performance standard in section 3162.5-2(d) on isolation of all usable water. The commenter stated that isolation of useable water does not ensure wellbore integrity. The BLM agrees. This section of the final rule, which is now designated section 3162.3-3(i)(8)(i), has been rewritten to require the operator to certify that the operator complied with the requirements in paragraphs (b), (e), (f), (g), and (h) of the section.
Another commenter said that operators should not be required to certify that isolation of usable water and mineral zones was achieved, and should only be required to use best efforts to isolate those zones, because isolation cannot be measured directly, but only inferred. The final rule is not revised in response to that comment. Isolation of zones of usable water or minerals is shown or inferred by data indicating that hydraulic fracturing fluids, recovered fluids, or oil and gas have not been lost from the wellbore in or around those zones. It is appropriate to require operators to review the reasonably available data concerning their operations and to certify that the data indicate that zonal isolation was achieved.
A commenter was critical of the certification requirement, arguing that it added nothing because operators are required to comply with all applicable regulations, and that terms such as “treatment fluid” and “wellbore integrity” are ambiguous. The commenter stated that an operator could in good faith believe that its certification was valid, but later it could be proved that there was an undiscovered problem. Although the BLM agrees that operators must comply with all applicable regulations, the BLM disagrees with the commenter's conclusions. The term “treatment fluid” is not used in the regulations. The reference to wellbore integrity has been deleted. The function of the self-certification is to require operators to conduct a good-faith review of the construction and operational data for any indication of problems. Certification of compliance with the requirements in paragraphs (b), (e), (f), (g), and (h) of the section is appropriate.
A commenter said that the requirement for an operator to certify its compliance with applicable law for operations on an Indian reservation is unnecessary and could result in “serious litigation.” The BLM disagrees. An operator on an Indian reservation is
One commenter recommended that the rule model its reporting and certification requirements (final section 3162.3-3(i)(1) and (i)(8), respectively) on the Colorado Oil and Gas Conservation Commission (COGCC) Rule 205 and 205A because these rules strike a balance between reporting obligations of operators versus service companies. Rule 205A is specific to hydraulic fracturing and is most relevant to this rule. The BLM did not revise the rule as a result of these comments. The reporting requirements under 3162.3-3(i)(1) and Rule 205A, paragraph b, are very similar. Both require the disclosure of the hydraulic fracturing operations, including the well name, the total volume of water used, and the types and amounts of chemicals used in the operation (with exceptions for trade secrets). Both also require that the information be submitted by the operator (Rule 205A.b(2)). The Colorado rule requires vendors and service companies to provide water volume and chemical data to the operator; however, the operator is ultimately responsible for submitting the information to COGCC. In this respect, this rule is consistent with the Colorado rule. Section 3162.3-3(i)(8) in the final rule requires the operator to certify that it complied with paragraphs (b), (e), (f), (g), and (h) of the rule, and that the hydraulic fracturing fluid constituents comply with all applicable Federal, tribal, state, and local laws, rules, and regulations. There is no corollary requirement in the Colorado rule. The BLM primarily has authority over the parties who hold or operate the lease—the lease being the instrument through which the BLM exercises its authority over the lessee or operator. No changes to the rule were made as a result of this comment.
One commenter said that the rule should be revised to improve the readability of sections 3162.3-3(i)(8)(ii) and (iii), which contain the phrase “the hydraulic fracturing fluid used complied . . . .” The commenter indicated that this phrasing makes no sense linguistically since hydraulic fracturing fluid does not comply, the operator complies. The BLM did not revise the rule as a result of these comments. The lead-in section for this certification section of the rule, now designated as section 3162.3-3(i)(8), clearly indicates that the certification signed by the operator contains the information that the hydraulic fracturing fluids used complies with all applicable permitting and notice requirements.
Some of the commenters noted that reporting requirements of the rule would reduce duplication of effort for the operators. They supported the provision in the rule that allows operators in states that require disclosure on FracFocus to meet both the state and BLM requirements through a single submission to FracFocus. The BLM agrees with these comments and did not make any changes to the rule.
Other commenters were critical of FracFocus for not being user-friendly and for not allowing republication or linking with other databases. The BLM has been in discussions with the GWPC, which is responsible for the FracFocus database, to address some of these concerns. As of June 2013, the FracFocus database was upgraded to FracFocus 2.0. Their latest upgrades are explained on their Web site under “Frequently Asked Questions” at
Some commenters suggested that additional information, such as the APD, well status, compliance, volume of fluid recovered, and complaint process, should be reported through the FracFocus submission. While some of this information is available through the BLM, FracFocus only publishes information related to disclosure of chemicals used in hydraulic fracturing fluids. The BLM did not revise the rule as a result of this comment.
Some commenters were critical of FracFocus because of the unknown future condition and long-term reliability of this organization in hosting and retaining the data. A few commenters expressed concern about future funding, access, and data backup issues of FracFocus. Other commenters suggested that the disclosure registry should be searchable across forms and allow for meaningful cross-tabulation of search results. One of the commenters specified that each of the disclosure submissions should have a date stamp showing the actual date of submission to the database and validate/reject the correct/incorrect CAS Registry Numbers of the disclosed chemicals/ingredients when submitted. Another commenter suggested that the BLM should develop a new public disclosure platform tailored to the agency needs. The BLM considered these comments as valuable suggestions and will continue to work to improve any platform used for public disclosure. However, it did not make any changes in the rule because of these comments.
The BLM has reviewed the Secretary of Energy Advisory Board's FracFocus 2.0 Task Force Report, dated March 28, 2014, and its concerns and recommendations for FracFocus improvements as cited earlier in the preamble. Key issues raised include: The ability to search and generate information by chemical, well, company, and geography; quality control of data; and the capacity to handle large volumes of data. The BLM is committed to working with the DOE and FracFocus to ensure these issues are addressed so that public information gathered as a result of this rule is of high quality, accessible, and usable. As mentioned earlier, the GWPC and IOGCC, joint venture partners in the FracFocus initiative, announced the release of several improvements to FracFocus' system functionality. The new features are designed to reduce the number of human errors in disclosures, expand the public's ability to search records, provide public extraction of data in a “machine readable” format, update educational information on chemical use, environmental impacts from oil and gas production, and potential environmental impacts. The new self-checking features in the system will help companies detect and correct possible errors before disclosures are submitted. This feature will detect errors verifying that CAS numbers meet the proper format. These improvements to the system will address many of these concerns.
Many commenters addressed the use of the FracFocus database and Web site. Some commenters supported the BLM's proposal to allow submission of data through FracFocus. Other commenters, however, were critical of the proposal. Some commenters were concerned that the ownership of the data on FracFocus and the applicability of public disclosure laws, such as the Federal Freedom of Information Act (FOIA), are unknown. The Federal FOIA does not apply to FracFocus, because it is operated by the GWPC, which is not an
A commenter suggested that the BLM adopt a procedure used in Texas that requires operators to submit to the state commission a copy of the information that they upload to FracFocus. Under this final rule, submission of the required information through FracFocus is optional; an operator may instead submit it directly to the BLM, and the BLM will upload it to FracFocus. The BLM's intent, however, is to reduce the paperwork burden on operators by allowing them to submit information through FracFocus, if they so choose. Thus, in states that require submission on FracFocus, there would be no additional burden of complying with this requirement of the rule.
Some commenters said that using FracFocus would violate an Executive Order requiring new government information to be available to the public in open, machine-readable formats, and the implementing guidance from the Office of Management and Budget. See Executive Order 13642, 78 FR 93 (2013), and Memorandum for the Heads of Executive Departments and Agencies, M-13-13 (OMB 2013). That Executive Order provides, in pertinent part, that the policy of the Executive Branch is that new and modernized Government information resources must be open and machine readable. The order is subject to several conditions, including available appropriations.
That Executive Order does not prohibit the BLM from allowing operators to submit information through FracFocus. The BLM believes that FracFocus is the quickest, most cost-effective way to make the information public. Working with FracFocus to meet the policy goals of the Executive Order, including machine-readable formats, will be more prompt and will use taxpayer dollars more efficiently than would the BLM creating and managing its own database solely for chemical disclosures.
A commenter was concerned that using FracFocus could cause a conflict of interest because the GWPC is a trade association for the oil and gas industry. The BLM disagrees with this comment. The members of GWPC are the state agencies (
A commenter said that using FracFocus would fail to meet minimum standards for managing government records. The commenter misconstrues the role of FracFocus. FracFocus will not be the official repository of the chemical information required by the rule. Whether an operator submits information to BLM directly or through FracFocus, the BLM will keep the information in its records. The information will also be available on FracFocus for the benefit of the public and state and tribal agencies.
A commenter raised an issue of implementation and enforcement—that because FracFocus does not show the date that information is uploaded, it will be difficult for the BLM to know if the information was submitted within the time period required by the rule. The BLM will closely monitor FracFocus to ensure that operators submit information in a timely manner consistent with these regulations. The BLM will be working with the GWPC to improve the ability of FracFocus to meet the BLM's needs and of operators on Federal or tribal lands. The final rule is not revised in response to those comments.
One commenter expressed concern that operators may change their access route and transportation methods for water used in fracturing wells after the initial approval. The commenter suggested that operators be required to report any changes in approved access routes and transportation methods. Although not explicitly stated, operators are required to follow the approved plan along with any conditions of approval. This requirement includes using the approved access route and transportation method. Any change to the approved plan requires the BLM's approval. The Sundry Notice form itself addresses a change of plans. If the operator has a need to change the access route or transportation methods for water, they must file a change of plans. If the operator does not follow the approved plan along with any conditions of approval, the operator would be in noncompliance with the approval. The BLM would then take enforcement actions under 43 CFR part 3163. No revisions to the rule were made as a result of this comment.
Some commenters stated the information required to be submitted to the authorized officer within 30 days after the completion of the last stage of hydraulic fracturing operations under section 3162.3-3(i), is redundant, unnecessary, and burdensome. The commenters stated that much of the information is provided in the NOI and some of the information is already required with the completion report. The information in the application and the information in the subsequent report serve different purposes. The information in the application allows the BLM to analyze the proposed operations to ensure that there will not be any unnecessary or undue degradation of public lands or breach of trust on Indian lands, and to develop any necessary mitigation to protect resources. The purpose of the subsequent report is to provide information on what was done and how it was done, as compared to how it was planned. Some information, such as the results of the MIT and the cement operations monitoring report, are not included in the APD or NOI, and can only be submitted after the operations are complete. The information included with the subsequent report also differs from the information required with the well completion report. Examples include the results of the MIT and the operator certification that it complied with paragraphs (b), (e), (f), (g), and (h) of the rule prior to and throughout the hydraulic fracturing operation. However, final section 3162.3-3(i)(9) is revised in response to comments pointing out that the proposed requirement to submit well logs and records of adequate cement duplicates a requirement in the well completion report.
One commenter requested that the total volume of fluid injected during a hydraulic fracturing operation should be reported. Another commenter requested further subcategorization of water volumes, such as surface, subsurface, and recycled water. The BLM did not revise the rule as a result of these comments. During a water-based hydraulic fracturing operation, water and proppant generally make up approximately 98-99 percent of the fluid injected during a fracturing operation and other additives, such as friction reducers, surfactants, gelling agents, and scale inhibitors make up the remaining, usually about 1-2 percent. The difference between total fluid used and volume of water used is insignificant from a volumetric perspective. Other commenters were critical of the fact that the volumes of each chemical were not required to be reported in addition to the percentages of ingredients used. The maximum ingredient mass can be calculated from the percentages of ingredients reported. The BLM did not revise the rule because of these comments.
One commenter suggested that the BLM require operators to report their water usage to a public database to assure that water usage complies with state law and require operators to provide evidence of their water rights. The BLM does not need to see evidence of an operator's water right. Policing water rights is the duty of states and tribes, not the BLM. The rule already requires operators to report the total water volume used for each well. The BLM expects that most operators will report that information through FracFocus. This rule does not preempt any state or tribal law requiring operators to report water usage to another database.
One commenter stated that the post-fracking reporting requirements should clarify that the chemical disclosure is just for the chemicals added to the hydraulic fracturing fluids and do not include naturally occurring chemicals in the formation. The BLM concurs with this comment and section 3162.3-3(i)(1) is revised to clarify that the operator must submit a description of each additive in the hydraulic fracturing fluids. The chemical disclosure will include each additive in the hydraulic fracturing fluid used by the operator for conducting the hydraulic fracturing operation. Surface or ground water usually includes naturally occurring chemicals and may have pollutants from other sources. Re-used or recycled water will usually not be distilled, but rather have traces of chemicals from prior uses or by-products from processing. Those chemicals are not additives to the hydraulic fracturing fluids and will not be required to be reported as part of the disclosure. If the final rule required expensive chemical analysis of reused or recycled base fluids, it would discourage the use of reused or recycled water and put additional demands on surface or ground waters needed for drinking, agriculture, industry or ecosystems, and would increase the volume of recovered fluids needing permanent disposal. However, even if chemicals are naturally occurring in the formation, the same chemicals need to be disclosed if they are added to base fluid for hydraulic fracturing.
One comment stated that not all chemical compounds have CAS numbers and therefore could not be reported. CAS stands for Chemical Abstracts Service, a division of the American Chemical Society. The CAS number is a unique numerical identifier assigned to every chemical substance described in the open scientific literature. This registry is maintained by CAS and is internationally recognized. The BLM's review of disclosure reports on FracFocus indicates that the chemical substances added to base fluids are registered and have a CAS number. Therefore, the requirement for reporting a CAS number has not been changed. Multiple CAS numbers may be used if multiple chemical constituents are reported for one chemical compound.
Some of the commenters suggested that the BLM require both maximum and actual concentration of chemicals used. The BLM made no change to the rule because of this comment. Considering the objective of the chemical disclosure, the maximum concentration provides the worst case scenario, which is more important for environmental exposure, health, and safety of the operation. Percent by mass of each chemical is required in the hydraulic fracturing fluid to quickly evaluate potential exposure. Also, the actual concentration of chemicals may change as the operator fractures different stages of a single well. Thus, the maximum concentration provides the most useful information toward achieving the goal of protecting groundwater and developing potential response criteria.
A few commenters asserted that listing the maximum concentration of the non-MSDS-listed ingredients within an additive imparts no real value while increasing the risk that the disclosures could be used to reverse-engineer proprietary formulas for hydraulic fracturing additives. The BLM disagrees with this comment. The chemicals listed on Material Safety Data Sheets (MSDS) are believed to be hazardous to workers in an occupational setting as determined by the Occupational Safety and Health Administration (OSHA). Other chemicals which do not require MSDS, however, might be hazardous to humans in an environmental setting (such as in ground water used for drinking) or might be harmful to the environment. Therefore, disclosure of these chemicals, including the maximum concentration, is necessary. Section 3162.3-3(j)(1) of the final rule requires affidavits to validate the trade secret claims. This requirement will allow legitimate exemptions with proper documentation and attestations in compliance with the previously mentioned section. The BLM did not revise the rule as a result of this comment. Several commenters requested disclosure of the volume of proppant to be used along with the location where the proppant was mined or extracted. Final section 3162.3-3(i)(1) is revised to require a description of each additive in the hydraulic fracturing fluid, rather than just each chemical. While section 3162.3-3(i)(1) does not specifically require the volume of proppant to be reported, it does require that each additive to the hydraulic fracturing fluid be reported along with the maximum ingredient concentration in the hydraulic fracturing fluid. Because a proppant is an additive, it must be reported. The volume of proppant can be calculated from the percentages of ingredients reported. The BLM does not believe it to be appropriate to require the location where the proppant was mined or extracted because the BLM would have no authority over proppant extraction if it were not on public land. If it were on public land, it would require a separate authorization unrelated to these regulations. No changes to the rule were made as a result of this comment.
Some commenters asked that the BLM defer to states on matters of disclosure of information, including disclosure of chemicals used in hydraulic fracturing operations. These commenters said that states have the best knowledge of the geology, and have the experience and expertise to make the right decisions. The BLM agrees that state agencies are well-informed and have much experience and expertise, as does the BLM. However, chemical reporting requirements are not dependent on geological conditions. The final rule assures that the BLM, states, and the public will have access to information on the chemicals used in hydraulic fracturing operations on Federal and Indian land without imposing unreasonable burdens on operators.
Several commenters suggested clarifying the language in sections 3162.3-3(i)(7)(i) and (7)(ii) (paragraphs (5)(ii) and (5)(iii) in the proposed rule) to better differentiate handling methods from disposal methods. The commenters pointed out that hauling by truck and transporting by pipeline are not disposal methods. The BLM agrees and modified the requirement to differentiate handling methods (
Several comments objected to the requirement that operators report the volume of fluid recovered from production facility vessels. The BLM agrees with this comment and has reworded this requirement in final section 3162.3-3(i)(6). See the preamble discussion under flowback fluids for a further explanation.
One comment requested that the composition of the recovered fluid be required as in the original proposed rule (77 FR 27710). The BLM did not revise the rule as a result of this comment because this was not a requirement in the supplemental proposed rule and because the BLM believes providing such information would not be useful. This rule aims to treat all recovered fluid as potentially hazardous regardless of what the chemical constituents may be.
Numerous commenters stated that the rule should be modified to define what is meant by a “deviation from the approved plan” as required in the subsequent report after hydraulic fracturing operations have concluded. The commenters indicated that it is possible for numerous minor deviations to occur while conducting hydraulic fracturing operations, and that the BLM should identify any deviations it considers critical. Other commenters indicated that the BLM should request an explanation and additional information regarding issues believed to be potentially significant after the completion reports have been reviewed. The BLM agrees and has modified the rule as a result of these comments by deleting supplemental section 3162.3-3(i)(6). The BLM believes that due to the nature of hydraulic fracturing operations it is not practical to define, or list, all the myriad of outcomes and has deleted this specific requirement in the final rule. Anomalies or deviations are better handled through implementation, including both policy and training, and BLM engineers will identify and resolve deviations when reviewing completion reports as the BLM handles deviations involving approved APDs. This rule and the operating regulation provides for the authorized officer to request any additional information deemed necessary for review of the post-hydraulic fracturing operation on Federal or Indian leases.
Several commenters expressed concern about the requirement under the supplemental proposed rule (section 3162.3-3(i)(8)) requiring operators to submit well logs within 30 days of completion of hydraulic fracturing. A commenter stated this requirement is duplicative of the requirements of the BLM Well Completion or Recompletion Report and Log (Form 3160-4). The commenter stated that all logs are already provided with the completion report. The BLM agrees with this comment. As the commenter pointed out, operators are required to submit all logs with the BLM Well Completion or Recompletion Report and Log. Item 21 of the form requires the operator to specify the type of electric and other mechanical logs run and indicates operators are to submit a copy of each. Item 33 of the form requires the operator to indicate which items have been attached by placing a check in the appropriate boxes. The first box is for electrical/mechanical logs and in parentheses, the operator is reminded that “1 full set req'd.” Submission of the completion report and the logs is required by existing section 3162.4-1(b). Since the operators are already required to submit all logs, the requirement in supplemental section 3162.3-3(i)(8) has been deleted in the final rule.
Numerous commenters objected to the requirement in the supplemental proposed rule that the BLM can ask for additional information when reviewing an application for hydraulic fracturing. The commenters stated that this requirement is vague, unnecessary, and could lead to a broad interpretation by local BLM offices. The BLM did not revise the rule in response to this comment because the BLM must have the ability to ask for whatever information it needs to adequately review an application and fulfill our stewardship or trustee obligation. Because geology and operations vary widely, the BLM needs the flexibility to request information relevant to a specific or unique proposal and it would be unworkable for the BLM to list every possible piece of information that would cover all hydraulic fracturing applications.
Several comments expressed confusion over which pressure the BLM required in the subsequent report. Supplemental proposed rule section 3162.3-3(h)(2) asked for the actual pump pressure, and section 3162.3-3(h)(3) asked for the actual surface pressure. The BLM agrees that these requirements were confusing and revised the final rule to only require the maximum surface pressure that was applied during the hydraulic fracturing operations. The requirements in this section were also revised to make them consistent with the requirements of the NOI in section 3162.3-3(d).
This section sets out the circumstances and procedure under which operators may withhold information from public disclosure under the rule. An operator may withhold information as exempt from public disclosure only if it identifies a Federal statute or regulation that would prohibit the BLM from disclosing the information if it were in the BLM's possession. The BLM anticipates most if not all exemption assertions will be made under the Federal Trade Secrets Act, 18 U.S.C. 1905, a criminal statute which prohibits Federal employees from divulging trade secrets and other confidential information without authorization. The supplemental proposed rule would have allowed operators to withhold information otherwise required to be submitted by executing an affidavit affirming that the information was a trade secret. The final rule modifies the supplemental proposed rule at section 3162.3-3(j) in several respects. The list of items that the operator must affirm has been expanded to more completely address the factors that are needed to support a claim of exemption from public disclosure. The operator's affidavit must also identify any other entity, such as a contractor or supplier, which would be the owner of the withheld information. The operator must submit an affidavit from such entity that provides any information upon which the operator relies in executing the operator's affidavit. The operator must affirm that it has possession of the withheld information so that BLM would have access to it upon request. A corporate officer, managing partner, or sole proprietor must sign the operator's affidavit. Finally, the operator must maintain the withheld information for the later of the BLM's approval of the final abandonment notice for the well, or for Indian lands, 6 years, or for Federal lands, 7 years, as provided under existing applicable law discussed below. As in the supplemental proposed rule, the BLM may require the operator to provide the withheld information.
The BLM received numerous comments concerning trade secrets and confidential business information. Some commenters were critical of allowing operators to withhold any information from the public. Other commenters were critical of the role of the BLM in deciding whether information would be entitled to protection.
A commenter suggested that the BLM defer to states on the handling of trade secrets claims, asserting that they were state and tribal issues, and should be regulated by those authorities. Further, the commenter believed that states and tribes were better versed in hydraulic fracturing operations, and could be
Some commenters were critical of the supplemental proposed rule for not being the same as state rules on trade secrets. Many states have adopted the Uniform Trade Secrets Act, or have other laws governing protection of proprietary information. Those state statutes do not govern the BLM's compliance with the Federal Trade Secrets Act, and the Federal Trade Secrets Act does not apply to state governments. Thus, the BLM is not in a position to concur or to disagree with a state's “trade secret list,” as suggested by a commenter. The BLM understands concerns about duplication of efforts or the potential for inconsistent determinations. If a state agency has released information to the public without restrictions, that information would not qualify as a trade secret and the BLM would not withhold it from the public. Nothing in this rule preempts state or tribal laws requiring disclosure of information or protecting proprietary information.
Several commenters stated that if the BLM continues to allow exemptions from public disclosure for information on chemical identities in the final rule, it should at least require identification of the chemical family of the substance. The commenters stated this basic information does not implicate an operator's trade secrets, but provides at least some information about what types of chemicals were used by the operator in well stimulation. The commenters point out that such a rule is feasible because a number of states require that the chemical family be disclosed where a chemical's identity is withheld as a trade secret. Those states include Arkansas, Colorado, Louisiana, Montana, Oklahoma, Pennsylvania, and Texas. The BLM reviewed numerous hydraulic fracturing disclosure reports in FracFocus. The review revealed that many operators are providing the chemical family name or other similar descriptor for those chemicals that are protected as trade secrets. Those include reports from states that do not have a specific requirement to report on FracFocus, and thus were voluntarily disclosed.
A commenter recommended that the rule require disclosure of the generic chemical name as required under EPA's guidance implementing section 5 of the Toxic Substances Control Act (TSCA). See Instruction Manual for Reporting Under the TSCA § 5 New Chemicals Program, p.33 (EPA 2003). The BLM believes that the generic chemical name that was or should be provided to the EPA under TSCA or other statutes and published in the
The supplemental proposed rule at section 3162.3-3(j)(4) would have required operators to retain in their records the information they claimed to be exempt from disclosure for 6 years, by reference to the existing regulations at 43 CFR 3162.4-1(d). The rule expressly requested comments on whether another retention time would be more appropriate. The BLM received many comments on that topic. A few commenters favored the 6-year retention period, though more favored shorter periods. Many other commenters favored longer retention periods; several favored that records be retained for the life of the well, and a few advocated perpetual retention.
Final rule section 3162.3(j)(5) requires operators to retain information that is withheld from the BLM until the later of the approval of the notice of final abandonment of the well (
A 6-year minimum retention period on Indian lands is not burdensome because operators are already required under the Federal Oil and Gas Royalty Management Act (FOGRMA) and regulations to retain all records for a minimum of 6 years, including records and reports they submit to the BLM. See 30 U.S.C. 1713(b); 43 CFR 3162.4-1(d).
A 7-year minimum retention period is not burdensome because operators on Federal lands are already required under the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996 (FOGRSFA), 30 U.S.C. 1724(f), to retain all records for determining compliance with any regulation with respect to Federal oil and gas leases for 7 years. BLM's regulations at 43 CFR 3162.4-1(d) have not been updated to reflect that statutory obligation, but there is no impediment to this final rule requiring retention of data for a minimum of 7 years. Although FOGRSFA precludes the BLM from requiring longer retention of records pertaining to financial obligations (such as royalties), it does not preclude longer retention of records pertaining to other requirements for onshore oil and gas operations. FOGRSFA does not apply to Indian lands, and therefore the 6-year retention period in 30 U.S.C. 1713(b) applies to those lands.
Requiring trade secret records to be retained for the life of the well, if that life is longer than 6 or 7 years, is fair and reasonable because if an operator withholds the information under the rule (section 3162.3-3(j)(1)) the operator's records of the withheld information may be the only records of the chemicals injected into Federal or Indian minerals. Therefore, the BLM believes that it is necessary to have access to that information for the life of the well, and that the 6-year and 7-year retention periods in the pertinent statutes are minimum requirements with respect to records that do not pertain to financial obligations.
Some commenters said that the rule would fail to protect trade secrets, or that it mandated disclosure, putting the BLM and its employees at risk of lawsuits. The BLM disagrees. This rule, like the supplemental proposed rule, allows operators initially to withhold specific information by submitting an affidavit from the operator demonstrating that the information is protected from disclosure by law. The BLM retains authority to require operators to submit any of the initially withheld information. If the BLM decides that the information is not a trade secret, it would provide advance notice so that the operator or owner of the information could seek a court order
Some commenters expressed confusion about who would determine whether identities of chemicals were entitled to be withheld from the public as trade secrets. Under this final rule, in the first instance, the operator would either disclose the information or would withhold specific information and submit an affidavit. If the BLM requested the withheld information, the operator would be required to provide it. The BLM would determine if the information is a trade secret. As described earlier, if the BLM determines that the information is not a trade secret, the operator and owner of the information would have an opportunity to challenge the BLM's determination in Federal district court.
Some commenters were critical of the revised proposed rule for not defining trade secrets. The Federal Trade Secrets Act does not define trade secrets, and does not expressly authorize Federal agencies to define trade secrets. The BLM will make any decisions regarding trade secrets and other confidential information based on relevant Federal judicial opinions. See,
Other commenters asserted that 10 business days' notice before releasing information was insufficient, and one said that it would stifle development of more environmentally benign chemicals. The BLM disagrees. Similar to the Department's FOIA regulations, the final rule requires a minimum of 10 business days' notice prior to releasing information determined not to be exempt from disclosure. Cf. 43 CFR 2.33(c). That time is sufficient for the submitter to seek a temporary restraining order from a court. Also, the BLM would give due consideration to all relevant factors, including whether the information is the end product of innovation, in deciding whether the information is a trade secret.
Many commenters objected to the requirement that the operator certify that withheld chemical information is a trade secret. They said that the trade secrets are owned by the service contractors, and that the operator has no knowledge of them or ability to certify. Some said that the BLM should place the burden on the service contractors and not the operator. One commenter said that chemical manufacturers invest great sums in developing their products, and should not have to rely on oil and gas operators (or apparently, service providers) to assert and defend their trade secrets. The BLM disagrees in part. The BLM is aware that the common practice is for operators to engage service companies to conduct hydraulic fracturing services. The existing regulations are clear, however, that an operator cannot use a contract with a third party to escape responsibility for all operations on the permitted well site. See existing section 3162.3(b). Whether or not chemical suppliers or service contractors would “own” the information about the chemicals, it is the operator who has voluntarily taken responsibility for all operations in and on its wells, including hydraulic fracturing, and it is the operator who is responsible for submitting all required reports and information. Nonetheless, because the operator will not always be in the best position to declare why certain information should be withheld, the final rule allows the operator to submit an affidavit from the owner of the information attesting to the confidential status of the information in addition to the affidavit required from the operator. When the BLM is deciding whether alleged trade secret information it has received may be disclosed to the public, both the operator and the owner of the information may provide the BLM with any materials that would substantiate a claim of trade secret status, and both the operator and the owner of the information would receive advance notice of any BLM decision that the information is not a trade secret.
Some commenters asked that trade secret protection be extended to other required information, such as elements in the NOI. As with any submission of information to a Federal agency, the submitter may segregate the information it believes is a trade secret, and explain and justify its request that the information be withheld from the public.
Many commenters addressed other issues concerning trade secrets. Some commenters opposed allowing operators to withhold trade secrets from public disclosure. Other commenters asserted that the BLM was arbitrarily ignoring the recommendations of the Secretary of Energy's advisory task force that all chemicals should be disclosed to the public without exception. The BLM has no authority to require public disclosure of information that is entitled to protection under the Federal Trade Secrets Act. There is nothing arbitrary in assuring the compliance of BLM employees with a Federal criminal statute.
Some commenters said that the BLM's authority to promulgate regulations provides the BLM authority to require public disclosure by regulation, obviating protection under the Trade Secrets Act, citing,
Some commenters urged the BLM to require operators to submit trade secret information to the BLM, even if the BLM was required to maintain confidentiality, in order to encourage operators to make only good faith claims of trade secret protection. Some commenters said that the BLM should require operators to justify their trade secret claims. Some commenters said that the BLM should individually validate each claim of trade secret status. The BLM believes that the affidavit requirements are sufficient to assure that the vast majority of operators will assert only good faith claims for trade secret protection. But although the BLM will not be individually adjudicating each claim of trade secret status, the BLM agrees with those commenters in part. The BLM has revised the affidavit requirements to address all of the factors that the BLM would need to consider in deciding whether to release the information. The final rule requires the operator to affirm that it or any other owner of the information is in actual competition, identify competitors that would be interested in the withheld information, and affirm that release of the
A commenter suggested that, in addition to the affidavit, an operator should be required to provide independent verification that the information is a trade secret. The BLM will not require an operator to disclose proprietary information to an industry trade group as suggested by the commenter, in order to assert trade secret protection. Even if it were within the BLM's discretion, it would place industry trade groups in a role they have not requested.
Some commenters suggested that the BLM establish a procedure for citizens to challenge affidavits for withholding trade secret information. The BLM's resources will be better devoted to implementing this rule to assure protection of usable water from hydraulic fracturing fluids than in adjudicating uncontrollable numbers of challenges to affidavits. If the BLM has reason to believe that an affidavit is incomplete or inaccurate, or that it needs the information for any purpose, including a random inspection, it can demand the withheld information and make a determination if it is truly a trade secret. Additionally, the BLM encourages voluntary disclosure of fracturing fluids to the public, as some companies in the oil and gas industry have begun to do. Some commenters urged the BLM to require operators to disclose trade secret information in the event of a medical emergency. Other commenters stated that the material safety data sheets (MSDS) required by the OSHA are adequate for disclosure to medical personnel and first responders. The BLM understands the need for first responders and medical personnel to have complete information about potential chemical exposures in the event of an accident. However, unlike many state laws, the Federal Trade Secrets Act does not include an exception for medical or other emergencies. If the BLM requests the withheld information, and any Federal law required the BLM to provide it to another entity, the BLM would comply with that law. Note though, however, that nothing in this rule exempts operators or their contractors from complying with all applicable regulations of the OSHA, including requirements concerning MSDS. Furthermore, nothing in this rule preempts laws of states and localities (on Federal lands) or of tribes (on tribal land) requiring disclosure of information to first responders or to medical personnel.
Some commenters doubted the BLM's ability to make informed management decisions without complete information about the chemicals being used. The BLM disagrees. The BLM understands that hydraulic fracturing operations will use chemicals that are potentially hazardous. Compliance with this rule will assure that those chemicals are isolated from sources of usable water.
A commenter suggested deleting the “maximum ingredient concentration in additive (percent by mass)” requirement, arguing that it would have the effect of creating more trade secret exemptions, and that from an environmental perspective, what matters is the total concentration of a chemical. The BLM believes that the comment has merit, but there are costs and benefits to either approach. On balance, the rule is not revised in response. On the one hand, it is possible that if the rule does not require the percent by mass maximum ingredient concentration, more of the chemicals used in hydraulic fracturing operations would be disclosed because the risk of reverse-engineering would be reduced. On the other hand, the GWPC requests the percent by mass on its FracFocus data sheet and the industry has shown a willingness to furnish that information. As a result, the final rule requires disclosure of the percent by mass. The BLM notes that operators may seek to withhold the percent by mass as a trade secret, and to disclose the identity of the particular chemicals. That could be appropriate where the particular chemicals are not unusual, but the operator believes it has a valuable formula that optimizes the concentrations.
A commenter recommended that trade secret protection be denied unless there were a patent or a patent application pending for the chemicals. The Federal Trade Secrets Act does not have such a restriction and the BLM has no authority to impose one in this regulation. The final rule is not revised in response to that comment.
Some commenters recommended that operators should be able to obtain trade secret protection prior to conducting hydraulic fracturing operations, either in an NOI, or in a “master chemical plan.” The BLM disagrees. The BLM is not requiring submission of the identities of chemicals proposed to be used in hydraulic fracturing operations. Only the chemicals actually used in those operations would need to be either disclosed, or withheld by submitting an affidavit. The final rule is not revised in response to those comments.
Some commenters expressed uncertainty about what statute would prohibit disclosure of the identities of chemicals for purposes of final section 3162.3-3(j)(1)(ii). The BLM believes that most claims would be made under the Federal Trade Secrets Act, but the final rule leaves the category open in case any other statute might apply to certain information. The final rule is not revised in response to these comments.
A commenter recommended changing the affirmation required in the affidavit to “the best of the operator's knowledge at the time.” The final rule is not revised in response to that comment. Withholding the identities of chemicals injected into Federal or Indian minerals is a privilege, and to earn that privilege the operator must make informed declarations in the affidavit. If the operator is relying on information from a contractor or supplier, the rule requires that the operator provide an affidavit from that entity setting forth that information.
A commenter recommended deleting the affirmation as unnecessary. The BLM disagrees. The BLM believes that the affirmation is appropriate and has not revised the rule in response to that comment.
Some commenters urged that the records of the chemical identities withheld as trade secrets should be retained by the service contractors, not by the operators. As previously explained, operators are responsible for their contractors' actions on the well sites. Maintaining accurate and complete well records with respect to all lease operations is the operator's responsibility. See existing section 3162.4-1(a). Indeed, the admissions in comments that some operators are not currently retaining all information about hydraulic fracturing operations raise concerns. Note though, that nothing in the rule prevents an operator from maintaining the confidential information under a physical or an electronic seal that would notify the owner of the information when it was accessed, as long as the BLM will have access to it upon request.
Furthermore, in response to comments stating that owners of trade secret chemical information would not allow operators to possess it, the final rule provides that an operator will be deemed to be maintaining the required information if it can promptly provide it to the BLM upon request, even if the information is in the custody of its owner. Any successor operator will be responsible for maintaining that access for the retention period in this rule.
This section allows operators to request a variance from the requirements of this final rule. Variance language is common among BLM regulations. Under this provision, the BLM will consider alternatives if an operator can demonstrate that the objectives of the rule would be met using an alternate approach.
Three changes are made to this section. First, this section is reorganized for clarity, segregating requirements for individual variances and state or tribal variances. Second, this section has been revised to clarify that the authority to approve a variance that applies to all wells within a state or within Indian lands, lies with the State Director. Third, this section has been revised to make paragraph (k)(3) consistent with existing regulations in Onshore Order 1 by adding language stating that the decision on a variance request is not subject to administrative appeal either to the State Director or under 43 CFR part 4.
Numerous commenters said that the rule should be revised to prohibit blanket variances for operators. The BLM did not revise the rule as a result of these comments. No blanket variance provisions for hydraulic fracturing operations exist in the rule. As provided, variances may be granted on a case-by-case basis from a specific provision of the rule, within a state, or on a tribal basis. Individual variances could only be granted where the operator's proposal meets or exceeds the objectives of the rule, and state or tribal variances may only be granted if the state or tribal provisions meet or exceed the objectives of the rule. A variance granted pursuant to this rule would not be an exemption from the goals of this rule, and would not be an abdication of the Secretary's stewardship responsibilities on Federal lands or trust responsibilities on Indian lands.
Numerous commenters stated that the rule should be revised to disallow variances of any kind or that variances should be limited. The BLM did not make any changes as a result of these comments. The BLM believes that it is practical to include a variance provision since the rule cannot contemplate all possible hydraulic fracturing circumstances which may be encountered on a national basis and must include provisions to address those unique or local circumstances, or improved technologies. The BLM believes, however, that variances should only be granted when it is clear that the alternative requirement is equally or more protective than the BLM's rule.
Several commenters indicated that the variance definition is vague and could allow for waiving of hydraulic fracturing requirements. Other commenters requested further clarification or suggested alternative language for this section. The BLM did not revise the rule as a result of these comments. While the rule does not contain a specific variance definition, the variance provisions in the rule are substantially similar to existing provisions in 43 CFR 3162.7-5(b)(9) as well as in Onshore Orders 2 through 7 regarding variances. All hydraulic fracturing operations on Federal or Indian leases must still meet or exceed the objectives of the requirement for which a variance is being requested.
Several commenters said that the rule should be revised to include the procedure and criteria for requesting a variance. The commenters indicated that the rule should provide clarification on the variance-issuance process and expressed concern that the supplemental proposed rulemaking contained no mechanism to notify the public. The BLM did not revise the rule as a result of these comments. Throughout this rulemaking the BLM has been aware that members of the public are concerned about hydraulic fracturing. While specific processing details regarding hydraulic fracturing variances have yet to be developed, the notification process may be made available to the public for statewide and tribal variances. The BLM will post all variances on its Web site.
Several commenters said that the rule should be revised to address how variances will be implemented. Other commenters indicated that all variances should be written; that no oral variances should be allowed. The BLM did not revise the rule as a result of these comments. The final rule specifies the procedural steps for several different variance processes.
Additionally, final section 3162.3-3(k)(1) contains no provision for oral variances. The BLM envisions that the majority of case-by-case variances will be authorized in the same manner as existing variances are authorized and that is via Sundry Notices. Each variance request must contain specific information justifying why a variance is needed. For state or tribal variances, the provisions will depend on the formal agreement between the involved agency and the BLM. It is not possible to envision or regulate all the possibilities and therefore these rules provide flexibility and discretion to the local BLM manager.
Several commenters expressed concern regarding section 3162.3-3(k)(5) in the final rule (paragraph 3162.3-3(k)(4) in the supplemental proposed rule) which allows the BLM the right to rescind a variance. The commenters stated that this is extraordinarily broad language that does not provide any factual criteria that the BLM must meet before modifying or revoking a variance. In their view, the proposed variance process fails to provide operators with a reasonable assurance that regulatory requirements will not arbitrarily change. Commenters also stated that if the variance language remains in the rule, the BLM should be required to provide operators notice of its intent to rescind or modify a variance in writing, provide operators at least 30 days to respond, and provide that any final decision on variances not become effective until at least 30 days after receipt by the operator. The BLM agrees in part. The authorized officer will grant a variance only if the BLM determines that the proposed alternative meets or exceeds the objectives of the regulation for which the variance is being requested. The BLM understands that operators are likely to rely on a variance in planning and executing their operations. A decision to rescind a variance would only occur after a thorough internal process has been undertaken. But if the BLM later determines that a particular variance fails to meet the objectives of the regulation, the BLM must retain the right to rescind that variance. In addition, changes in Federal laws or changes in technology may dictate the need to rescind a variance. While the BLM appreciates the issues raised by the commenters, these concerns do not override the BLM's responsibility to manage the public lands to prevent unnecessary or undue degradation, and to assure proper resource protection on Federal and Indian lands. While no timeframe is described, the rule requires that the authorized officer provide a written justification if a variance is rescinded. The rule does not require prior notification, but it also does not prohibit the local BLM manager from providing prior notification of a rescission of a variance when
Numerous commenters said that the rule should be revised to establish the process for state-initiated variances. Commenters indicated that the rules lacked specificity in this regard and provided specific language for a “state equivalency determination” process which enumerated the steps a state agency would utilize as well as the process that binds the BLM in reviewing and approving such proposals. The BLM did not revise the rule as a result of these comments. State or tribal variances would be approved as a result of discussions among the BLM and the state or tribal agencies, which do not require a rigid process specified in regulations. A state or tribal variance is not a delegation of full or partial regulatory primacy, so a “state equivalency determination” process is neither necessary nor appropriate.
One commenter supported section 3162.3-3(k), which allows for the BLM to work in cooperation with a tribe and issue a variance that would apply to all wells within Indian lands or to specific fields or basins within Indian lands. The commenter, however, recommended that the rule be expanded to include the process that tribes would use to initiate a variance. The BLM does not believe the rule needs to be expanded to include the specific mechanism for approving variances with tribes since it may vary from tribe to tribe. The BLM will work cooperatively with any tribe or state to craft variances that would allow technologies, processes, or standards required or allowed by the state or tribe to be accepted as compliance with the rule. Such variances would allow the BLM and the states and tribes to improve efficiency and reduce costs for operators and for the agencies.
Numerous commenters stated that the rule should be revised to provide for statewide exemptions from the hydraulic fracturing rule. Other commenters suggested modifying the variance section so that the BLM's hydraulic fracturing rule should only apply in those states which do not have hydraulic fracturing rules. The BLM did not revise the rule as a result of these comments. The Secretary of the Interior has stewardship responsibilities on public lands and trust responsibilities on Indian land. Accordingly, the BLM is promulgating a rule that governs hydraulic fracturing operations on all Federal and Indian leases. While the BLM does not provide for statewide exemptions from the entire hydraulic fracturing rule, variances may be granted for individual provisions of the rule, if the variance proposal meets or exceeds the objectives of the rule. The BLM encourages formal agreements with state or tribal agencies to avoid overlap and promote cooperation amongst regulatory bodies and to reduce compliance burdens on operators.
Numerous commenters said that the rule should be revised to recognize existing state agency rules. The commenters indicated that under such a provision the need for any variance would then be redundant because all proposals would clear the “meets or exceeds” state threshold. The BLM did not revise the rule as a result of these comments. While numerous states have hydraulic fracturing rules in place or are currently contemplating hydraulic fracturing rules, the applicability and content of these rules are not consistent across all BLM-managed public lands in those states. Additionally, certain states do not have hydraulic fracturing rules at all. In addition, state rules may not apply to tribal lands. The BLM will work closely and cooperatively with state and tribal agencies to implement these rules to avoid overlap and duplication where possible. Formal agreements with state and tribal agencies are encouraged.
Numerous commenters said that the rule should be modified to allow for statewide or tribal variances. Commenters indicated that states should regulate hydraulic fracturing operations on all lands within that state by memorandum of understanding. The BLM agrees with those comments in part, and has modified the rule as a result of these comments. The rule has been edited to clarify that there are two types of variances: Individual (or operator-specific), and state or tribal (for wells on all or designated portions of state or tribal lands). As provided, variances may be granted to states and tribes, only if the state or tribal requirements meet or exceed the objectives of the rule. The rule also provides that state or tribal variances maybe initiated by the involved state, tribe, or the BLM.
The BLM may approve a variance under paragraph 3162.3-3(k) from one or more specific requirements of the rule, but not from the entire rule. The variance provision does not allow the BLM to delegate regulation of hydraulic fracturing operations on public or Indian lands to state agencies. Unlike several other environmental statutes, none of the BLM's statutory authorities authorize delegation of the BLM's regulatory duties to state or tribal agencies.
The changes to this section conforms the out-of-date language in this section with the Onshore Order 2 requirements. Onshore Order 2 superseded the existing regulations in 1988, because it was promulgated pursuant to notice-and-comment rulemaking. Since the final rule is consistent with Onshore Order 2, it does not represent a change in policy.
The BLM received numerous comments on the subject of usable water. Those comments are addressed under the section 3160.0-5 discussion in this preamble. This section is not revised in the final rule and remains as proposed.
Several commenters recommended that the BLM adopt American Petroleum Institute (API) Guidance Document HF1, First Edition (October 2009) (HF1) instead of developing its own standards. During the development of the rule, the BLM not only considered all comments received but also consulted numerous other sources including API HF-1, state regulations, and academic and professional papers such as King, George, SPE 152596, “Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor, and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells,” Society of Petroleum Engineers, Hydraulic Fracturing Technology Conference, (Feb. 2012). The BLM does not believe that the rule should incorporate any particular guidance. Although the BLM has carefully considered the API HF1 and HF2 guidance as we developed this rule, the BLM cannot fully incorporate the guidance documents because they do not meet all of the BLM's areas of concern for protection of resources on Federal and Indian lands. Moreover, nothing in this final rule precludes an operator from following recommended industry guidance. See the following table for a comparison of applicable components of API HF1 guidance and the final rule.
Several commenters stated that there is concern that the BLM is imposing new rules when the BLM does not have the staffing, budget, or the number of experts needed to implement the rule or requisite expertise to evaluate fracturing proposals, which would cause delays in approvals and decreased Federal and Indian oil and gas production. The BLM does not agree with the assertion regarding the lack of BLM staff expertise. The BLM employs qualified and experienced petroleum engineers and geologists. The BLM understands the time-sensitive nature of oil and gas drilling and well completion activities and does not anticipate that the review of additional information related to hydraulic fracturing with an APD will impact the timing of the approval of drilling permits. The BLM believes that the additional information that would be required by this rule would be reviewed in conjunction with the APD and within the normal APD processing timeframe. If an operator submits a request in an NOI, however, further processing time should be expected. The BLM understands that delays in approvals of operations can be costly to operators and the BLM intends to avoid delays whenever possible. Also, the revisions made from the supplemental rule to final rule would reduce the amount of staff time required to implement the rule and limit any permitting delays. The changes include eliminating the type well concept and the requirement for a CEL to be run and submitted for a type well prior to completing additional wells.
Several commenters said that the rule should be modified to provide enforcement provisions. The commenters stated that the BLM must monitor hydraulic fracturing operations on Federal and tribal lands to ensure compliance with the rules. The BLM did not make any changes as a result of these comments. Monitoring performed by the BLM is a matter of implementation and policy, not regulation, and therefore, revision of the rule for monitoring is not warranted.
Commenters also expressed concern that depending on self-reporting by the operators would be unreliable. The BLM, in line with its authority, has historically relied on self-reporting throughout the oil and gas program (
One commenter expressed concern over how the BLM will know if an operator fails to report a wellbore issue. The BLM has a number of mechanisms that would indicate if an operator failed to report a wellbore issue. The BLM routinely conducts inspections of ongoing operations. These inspections consist of witnessing operations, such as the cementing of casing, onsite review of the drillers log at the rig, or the review of documentation such as the third-party cementing ticket. Through witnessing the operation or the review of the documentation, the BLM inspectors can verify that operations were conducted in accordance with the approved plan and that no wellbore issues exist. Operators also must submit a subsequent report as required by final section 3162.3-3(i). BLM staff will review the information included in the subsequent report to identify any deviations from the approved plan, or any indications of wellbore issues. In addition, under final section 3162.3-3(i), the operator must certify that it complied with the paragraphs of the rule that assure wellbore integrity was maintained prior to and throughout the hydraulic fracturing operation. No revisions to the rule were made as a result of this comment.
One commenter recommended that each operator designate one or more individuals to be prosecuted criminally if criminal negligence, fraud, or conspiracy were found in any hydraulic fracturing operation. The commenter also recommended that an independent counsel be appointed to investigate death or disability caused by hydraulic fracturing operations, and a freezing of corporate stock pending such investigation. While criminal liability and criminal investigations are beyond the scope of this rulemaking, any information of potential criminal violations would be appropriately addressed by law enforcement authorities.
Some commenters wanted the BLM to add an appeal process for decisions to condition or to deny a hydraulic fracturing proposal, and wanted rules for the standing of third parties. The Department's regulations already provide procedures for administrative review of adverse decisions by the BLM. E.g., 43 CFR 3165.3(b). Issues of standing to participate in an administrative review or appeal of a BLM decision are beyond the scope of this rulemaking.
Several commenters suggested that the rule allow state oil and gas commissions to regulate hydraulic fracturing on Federal and tribal lands. Commenters believed that the BLM rule adds no value, and increases the layers of approval necessary to develop on Federal and tribal land. Other commenters stated that BLM rules duplicate state rules, and that because the states adequately protect and manage hydraulic fracturing, the BLM's rules are unnecessary, add costs and burdens for compliance, and present regulatory inconsistencies when enforced alongside state rules. Several commenters said that hydraulic fracturing should be regulated at the state level because implementing a national rule would be unworkable due to the widely varying geology and techniques used from region to region. Other commenters recommended that in those states which already have an established regulatory process for hydraulic fracturing, operators should automatically be exempt from this rule.
The BLM did not revise the rule as a result of these comments. The BLM recognizes that many states have made efforts to update their hydraulic fracturing regulations in recent years, but those regulations continue to be inconsistent across states. Further, those state rules may not apply to Indian lands. The rule will establish a consistent standard across Federal and Indian lands and fulfill BLM's stewardship and trust responsibilities. In addition, the BLM is not allowed to delegate its responsibilities to the states. The BLM has worked diligently to reduce the compliance burden on operators, and will continue to work with the states and tribes to develop cooperative agreements to help align hydraulic fracturing regulations at the state, Federal, and tribal levels. Although no changes to the rule were made as a result of these comments, final section 3162.3-3(k) establishes a process for state or tribal variances, if the BLM determines that certain state or tribal rules meet or exceed the objectives of this rule.
Several commenters objected to the use of state regulations. Commenters believed that state regulations were uneven and inconsistent, which could present problems for implementation and enforcement of the rule. The BLM did not revise the rule as a result of these comments. The rule applies on all Federal and Indian lands.
Some commenters urged the BLM to defer to state regulations that are more stringent in protecting resources than this rule. All state laws apply on Federal lands, except those that are preempted by Federal law. This rule does not preempt any more stringent state or tribal law. Operators on Federal leases must comply both with this rule and any applicable state requirements, just as they already must comply with both BLM rules and state rules on a variety of drilling and completion issues. For example, if a state law required recovered fluids to be held in above-ground tanks, the BLM would not approve an application to use a lined pit.
Some commenters objected to what they perceived as a suggestion that states do not have adequate regulatory authority. Those commenters are mistaken as to the BLM's intent. This rule is not about state regulatory programs. It is about the Secretary fulfilling her obligations under the statutes that assign to her stewardship over public lands and trusteeship over Indian lands.
Several commenters asked that the BLM regulate service companies. The commenters sought a list of “approved” service companies that would constitute the only eligible service companies who
Many commenters asked that the BLM ban hydraulic fracturing, unless the chemicals used in hydraulic fracturing can be contained. The BLM did not revise the rule as a result of these comments. The goals of the rule include groundwater protection, wellbore integrity, and chemical disclosure. Chemical management, containment, and public disclosure are core purposes behind the regulation, and the BLM fully intends to contain chemicals used in hydraulic fracturing through this rule.
Numerous commenters called for a moratorium or permanent ban on hydraulic fracturing on Federal and tribal lands. The BLM did not revise the rule as a result of these comments. The BLM has a responsibility under the FLPMA to act as a steward for the development, conservation, and protection of Federal lands, by implementing multiple use principles and recognizing, among other values, the Nation's need for domestic sources of minerals from the public lands. A ban or moratorium would not satisfy the BLM's multiple-use responsibilities under the FLPMA when regulations can adequately reduce the risks associated with hydraulic fracturing operations. Similarly, hydraulic fracturing operations on Indian lands result in substantial benefits to tribes and to individual Indians. By updating the requirements for hydraulic fracturing, this rule protects usable water on Indian lands without a ban or moratorium that could reduce royalty payments and employment. The BLM understands the risks and the environmental impacts of hydraulic fracturing operations, and the BLM believes that those risks and impacts can be managed by the rule. The rule will provide adequate assurance that hydraulic fracturing operations on Federal and Indian lands will continue to provide the Nation with domestically produced oil and gas and at the same time protect public lands and trust resources.
Many commenters asked that the rule require minimum setback distances for hydraulic fracturing operations. Some commenters requested setbacks from sensitive areas, including conservation areas, areas of critical environmental concern, wilderness and roadless areas, wild and scenic river corridors, surface waters, drinking water supplies, homes, schools, hospitals, other buildings, and recreation areas. Some commenters proposed setback distances ranging from 1,000 feet to half a mile. No revisions were made to the rule in response to these comments.
The BLM has processes in place to ensure protection of sensitive areas. For example, the BLM has rules at 43 CFR 3100.0-3(a)(2)(iii) that prohibit the leasing of Federal minerals beneath incorporated cities, towns, and villages, which is where the majority of homes, schools, hospitals, and other buildings are located. In addition, during development of a Resource Management Plan (RMP), the BLM identifies areas needing protection as areas closed to leasing or areas open to leasing, but with stipulations that limit or prohibit surface occupancy. Other sensitive areas are protected by seasonal and controlled surface use restrictions that are also developed during the land use planning process. When specific drilling proposals are received, the BLM conducts onsite inspections, which identify any sensitive areas and/or occupied dwellings. As part of the NEPA review for the specific proposal, the BLM then develops proper mitigation measures to protect these areas. Mitigation could include moving the well location and including site-specific conditions of approval (COAs). In addition, if unnecessary or undue degradation impacts are identified (for public lands), or unacceptable impacts (on Indian lands), which cannot be mitigated, the BLM may deny the proposal. Through existing regulations, the RMP process, and the subsequent site-specific analyses, the BLM has measures in place to ensure protection of sensitive areas, drinking water supplies, and occupied buildings.
Furthermore, state set-back requirements would normally apply on Federal lands, and tribal set-back requirements would apply on tribal lands (see also existing section 3162.3-1(b)). Minimum setbacks are more effective when they are determined and set at a site-specific level rather than in a nationwide rule because the unique circumstances of each drill site can be considered. Since setback requirements are already addressed in existing regulations and internal processes and policy, minimum setback distances are not necessary in this rule.
Several commenters asked that the BLM pursue cooperative agreements with states in order to establish more local control over hydraulic fracturing. Generally, the commenters believed that states have enhanced knowledge of the hydrological and geological conditions of their local oil and gas resources. The BLM did not make any rule changes based on these comments. The BLM intends to continue to pursue memoranda of understanding with states, and encourage further cooperation at the BLM State and field office level. The BLM cannot, however, delegate its stewardship responsibility to state or local officials, as some commenters suggested. The BLM must make the final decisions provided by statutes and regulations concerning operations on Federal lands and Indian lands. However, the BLM expects that by cooperatively working with states and through the variance process to appropriately consider state and tribal law and rules so as to reduce regulatory redundancies and compliance burdens.
Some commenters asserted that the rule should include a formal memorandum of understanding mechanism whereby state approval of hydraulic fracturing operations would constitute BLM approval. No statute authorizes the BLM to delegate its responsibilities to states. The rule provides for statewide variances that could result in aligning state and BLM requirements to reduce compliance burdens for operators while assuring that resources in and on public lands are protected.
One commenter asked that the BLM include a statement in this rule requiring operators to comply with other Federal laws and with state laws. Section 3162.3-3(i)(8)(i) of this rule already requires that the operator certify that the hydraulic fracturing fluid constituents complied with all Federal, state, and local laws, rules, and regulations, in addition to other certifications. In addition, the BLM's Federal oil and gas lease form requires the lessee to comply with all applicable laws, and that includes other Federal and state and local laws, rules, and regulations. That requirement is repeated in the existing regulations at sections 3162.1(a) and 3162.5-1(a). No revisions to this rule were made as a result of this comment because the commenters concern is already addressed in the rule and other BLM regulations.
A commenter suggested that the BLM require all chemicals used in hydraulic fracturing on Federal and Indian lands to be proven safe by an independent third party, or otherwise banned from use. The BLM did not revise the rule in response to this comment. The emphasis of this rule is to ensure that hydraulic fracturing fluid is confined to the intended zone and does not contaminate usable water zones, and that recovered fluids do not contaminate surface or ground water. Though this comment is beyond the scope of this rule, the BLM encourages the use of safer chemicals. Developing and using safer chemicals in all stages of hydraulic fracturing activities can help minimize potential environmental and health concerns while promoting greater public confidence.
Numerous commenters said that the rule disrupts the balance between environmental protection and energy development. The commenters stated that the rule would negatively affect jobs, revenue, and effective government. The BLM did not revise the rule as a result of these comments. The BLM evaluated these concerns as part of its economic analysis and found the impacts to be nominal in relation to current overall costs of drilling operations. The economic analysis is available upon request.
Several commenters stated that operators currently submit information regarding casing and cementing programs as part of the existing APD process under Onshore Order 1. The commenters stated that the existing regulatory program already ensures well integrity, thereby making the provisions in the supplemental proposed rule unnecessary. The BLM did not revise the rule as a result of these comments. While the APD process does include many similar components regarding casing and cementing specifics related to well construction, this rule addresses specific hydraulic fracturing operational aspects to verify the integrity of the casing that existing rules do not address.
Several commenters said that the rule is unnecessary and offers no change to the existing situation. The commenters indicated that the rule does not increase safety or transparency, and the supplemental proposed rule offered no solution. The BLM disagrees and did not make changes to the rule as a result of those comments. The BLM believes that compliance with these rules will increase transparency of the hydraulic fracturing approval process and provide a means for disclosure to the public of the fluids utilized in the hydraulic fracturing process.
Several commenters said that the BLM had no reason to promulgate the regulations because there was no evidence that hydraulic fracturing operations have caused contamination of groundwater. The BLM disagrees. The need to assure that hydraulic fracturing fluids are isolated from surface waters, usable groundwater, and other wells is clear. The BLM also notes that those commenters' arguments would apply equally to state regulations, which the same commenters champion. The final rule is not revised in response to those comments.
Several commenters stated that the rule is unnecessary because it codifies common industry practice which has been successful in preventing groundwater contamination. The BLM did not make any changes to this rule as a result of these comments because the BLM has the responsibility of ensuring for the public and tribes that specific minimum standards are adhered to, and does not depend upon voluntary compliance.
Several commenters requested that the BLM wait for EPA to complete its study of hydraulic fracturing and its potential impact on drinking water resources before promulgating a rule. The BLM does not believe it is necessary to wait for the EPA study to implement requirements that will help ensure the protection of water resources and the environment. Nothing prevents the BLM from updating its hydraulic fracturing regulations in light of a finalized EPA study. However, it is necessary to have adequate requirements in place without further delay. No revisions to the rule were made in response to this comment.
Many commenters asked whether the rule would apply to existing wells and requested that certain requirements be waived for those wells. The BLM agrees that the rule needs clarity on how it will address existing wells and added a table in section 3162.3-3(a) to specify which section of the rule would apply to which activity and when. Groundwater protection remains one of the principal reasons for applying the rule to all wells, existing or new. The BLM recognizes, however, that it may be impossible for an operator of an existing well to comply with all requirements of the rule. An example of this would be the requirements in section 3162.3-3(e)(1)(i) to monitor the casing and cementing operations, because the casing and cementing activities would have already occurred. Although most responsible operators retain that monitoring data and will be able to submit it to the BLM, not all of the data has been required by existing regulations. To comply with this section for existing wells, section 3162.3-3(e)(1)(ii) requires that the operator submit documentation demonstrating that an adequate cement job was achieved for all casing strings designed to isolate usable water, and provides that the BLM may require additional testing, verification, or other measures necessary to assure that the well will withstand hydraulic fracturing operations.
Several commenters suggested a phased or delayed implementation of the rule to give industry time to comply with the provisions of the new rule. One commenter requested a 180-day implementation period, instead of the 60-day implementation period required by statute and executive order (Congressional Review Act (5 U.S.C. 801-808) and Executive Order 12866). The BLM agrees that a longer implementation time is required given the complexity of the rule, the potential impacts of the rule on industry, the coordination needed with other entities, such as the GWPC for FracFocus, and for the development of internal training and policy. However, the public also expects new requirements for hydraulic fracturing to be implemented in a timely manner. Therefore, the final rule will be effective 90 days after publication in the
One commenter requested that the term “New Well” be added to the definitions section. The commenter recommended the following definition: “
Several commenters asked that the BLM completely ban the use of diesel fuel in hydraulic fracturing fluids. The BLM did not make changes as result of these comments. Congress has authorized regulation of the use of diesel fuels in hydraulic fracturing fluid by the Environmental Protection Agency (EPA), Underground Injection Control (UIC) Program. The EPA has provided technical guidance for protecting underground sources of drinking water (USDWs) from potential endangerment posed by hydraulic fracturing operations by requiring a permit under the UIC program where diesel fuels are used. See EPA Underground Injection Control Program Guidance # 84 for issues concerning diesel fuels during hydraulic fracturing operations (79 FR 8451). If, however, a state (on Federal lands) or a tribe (on tribal lands) prohibited the use of diesel, this rule would not ordinarily preempt such regulations.
Many commenters requested that the BLM increase liability bonds to account for the increased risk caused by hydraulic fracturing operations. The BLM did not revise the rule as a result of these comments. Existing section 3104.5(b) authorizes the BLM to adjust bond amounts to appropriately reflect the level of risk posed by an oil and gas operation. The BLM may increase the bond amount if there is a history of previous violations, if there are uncollected royalties due, or if the total cost of plugging existing wells and reclaiming lands exceeds the present bond amount based on the estimates determined by the authorized officer. The BLM believes that it has authority under existing regulations to adjust bond amounts to address any increased liability that may be present as a result of hydraulic fracturing operations. The BLM will make a liability determination for hydraulic fracturing on a case-by-case basis and increase the bond amount as necessary.
Many commenters stated that the rule should be modified to require prior approval for all significant changes to the proposed hydraulic fracturing plan. The commenter stated that the regulation only requires that the operator provide notice to the BLM after the hydraulic operations are complete. The BLM did not revise the rule as a result of these comments. The requirements that the commenter is referencing are specific to hydraulic fracturing operations that did not proceed as planned. Any change of plans from any approved permit must be submitted to the BLM for a new approval. This is the same requirement for changes to all authorizations for oil and gas operations, including APDs and Sundry Notices.
One commenter requested that the BLM establish criteria that would rise to the level of a “change in scope” that would necessitate the operator filing a subsequent Form 3160-5 Sundry Notice in the event of a change or deviation from the previously approved hydraulic fracturing operation. Too many possible scenarios exist to develop criteria that would address all issues that could arise. The BLM expects the operator to follow the approved plan along with any COAs. The BLM, however, recognizes that the operator may make minor changes in the design criteria prior to the hydraulic fracturing operations. This recognition is already acknowledged in the rule. Many of the items required in the permit application can be estimates (see final section 3162.3-3(d)). For example, the rule requires estimated pump pressures and the estimated total volume of fluid to be used. Slight deviations from these estimates would not trigger the need for a new Sundry Notice. Those items that cannot be estimated, however, such as the location of the water supply or the method of handling the recovered fluids, would have to be disclosed on an additional Sundry Notice requesting changes to the original approval. No revisions to the rule were made as a result of this comment.
Many commenters asked that the rule require a number of specific actions from the operator such as:
• The installation of air and water monitoring equipment on all hydraulic fracturing operations. The commenters stated that more comprehensive monitoring, including air and groundwater quality monitoring, could help build a knowledge base regarding hydraulic fracturing and its effects on the environment;
• Dust abatement on county roads;
• The power washing and inspection of all vehicles entering a well site to prevent non-native invasive plant species from becoming established;
• The installation of sound dampening devices;
• Prohibiting the use of jake (engine) brakes on trucks operating near residential areas;
• Provisions to control stormwater runoff;
• Capturing or controlling greenhouse gas emissions during hydraulic fracturing operations; and
• The prohibition of flaring in sensitive areas.
The BLM did not make any changes to the rule as a result of these comments. First, the requested changes are outside the scope of this rule, which is specific to hydraulic fracturing operations. With the exception of the installation of air and water monitoring equipment, all of the other requested changes would apply to oil and gas operations in general and are not unique or specific to hydraulic fracturing or appropriate to address in a hydraulic fracturing rule. Second, the BLM believes that it is not appropriate to require specific mitigation measures in a national rule of general applicability. Requiring specific actions such air monitoring, dust abatement, or power washing of vehicles is best left to the discretion of the local BLM offices, determined through NEPA analysis on a case-by-case basis and applied as lease stipulations, and conditions of approval in permits to drill, or through best management practices that operators may propose in their APDs. The rule must allow for some degree of flexibility to accommodate the wide range of geologic and environmental conditions encountered on Federal and Indian leases. If water quality or other impacts are anticipated due to hydraulic fracturing operations, the BLM would then develop mitigation measures, such as water quality monitoring, dust emission control, and any other relevant actions on a case-by-case basis. These requirements will be included as specific conditions of approval (COA) in the drilling permit to the extent consistent with the lease rights.
Several commenters expressed general concern over “frack hits” (
The BLM revised the rule as a result of these comments. As provided in this final rule, hydraulic fracture design, including estimated fracture length and direction data, are required to be submitted as part of the APD or NOI. In addition, the final rule requires the operator to provide a map showing the extent of the fractures along with all known wellbore trajectories within one-half mile of the well that is proposed to be fractured. One purpose of fracture design data is to avoid potential intersection between fractured pathways to existing nearby wellbores. These data will be reviewed during the review process for hydraulic fracturing approval. The provisions of Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-3A), March 1, 1979, (44 FR 2204) and other regulations already contain operator obligations for reporting, evaluation, and corrective actions in the event of an environmental release. Enforcement provisions for releases into the environment involving Federal or tribal leases already exist in the regulations and are outside the scope of this rulemaking.
Several commenters stated that the rule should be modified to establish an independent review of hydraulic fracturing proposals. The BLM did not revise the rule as a result of these comments. The BLM has the necessary expertise to properly review hydraulic fracturing proposals.
Several commenters stated that the rule should require notice to landowners, communities, and other stakeholders when hydraulic fracturing is proposed. Commenters said that the rule should require notice to parties located at various distances from 500 feet to 10 miles away from the hydraulic fracturing operation. The BLM did not revise the rule as a result of these comments. Public notice of Federal oil and gas operations is already provided to both the public and nearby landowners. By statute and regulations, notice of Federal APDs are publicly posted in BLM field office public rooms for a minimum of 30 days before the BLM issues a permit to drill (see existing section 3162.3-1(g)). Some field offices also make this information available on the field office Web site.
Furthermore, the BLM is working on improvements to make additional information available on a Web site for all Federal APDs in the near future. The information would include the operator name, well name and number, surface location legal land description, the date the BLM received the application, the date the BLM approved the application, the date the well was spudded, and the date the well was completed.
Additionally, surface owners of split estate lands are invited to attend the onsite inspection before an APD is approved, and other agencies and interested parties can request to attend the onsite well inspection. Also, the APD surface use plan of operations lists all wells and water wells within prescribed distances from the proposed wells, which provides additional information to the public about potential concerns. Although stakeholders could assume that any proposed well would be hydraulically fractured, the BLM will be exploring ways to provide additional public notice of proposed hydraulic fracturing operations. Information that would be required to be submitted as part of this rule will be made available to the public, consistent with the requirements of Federal law. Note, though, that the rule does not preempt notification requirements of states (on Federal lands) or tribes (on tribal lands).
Several commenters stated that the rule should be modified to provide for stakeholder participation in the permitting process for hydraulic fracturing operations. The BLM did not revise the rule as a result of these comments. The BLM already provides numerous opportunities for stakeholder participation during the Federal oil and gas leasing process as well as the APD process on Federal lands and stakeholders are specifically invited to participate during the NEPA process.
Several commenters stated that Onshore Order 2 is inadequate to ensure wellbore integrity during hydraulic fracturing operations. According to these commenters, the BLM needs more requirements specific to casing centralization, intermediate and production casing standards, cement types, cement compressive strength, ensuring proper wellbore condition prior to cementing, and ensuring a static wellbore during cementing operations. The BLM did not revise the rule as a result of these comments. Onshore Order 2 provides uniform national standards for the minimum levels of performance expected from operators when conducting drilling operations, including casing design, casing centralization, and cement compressive strength. The BLM reviews each drilling proposal to ensure that operations will meet these minimum standards. If the BLM's review determines that additional requirements regarding casing centralization, cement types, cement compressive strengths, etc., are necessary for wellbore integrity or isolation of usable water, the BLM can require the operator to modify its proposal or add COAs. The BLM believes that the requirements for well drilling, casing, or cementing in Onshore Order 2 along with the new requirements established by this rule are sufficient to assure that wellbores can withstand hydraulic fracturing operations.
Several comments stated that the rule should be modified to limit hydraulic fracturing activities in those areas with seismic zones. The BLM did not revise the rule as a result of these comments. The research on the phenomena of induced seismicity from hydraulic fracturing operations is still ongoing and inconclusive. For hydraulic fracturing operations proposed in seismically active areas or when the BLM determines through the internal and public scoping process that seismic impacts are an issue, risks of induced seismicity would be evaluated through the NEPA analysis, including analysis of the proposed drilling and fracturing operations. These final regulations also require submittal of additional geologic information prior to hydraulic fracturing to help further that review.
Several commenters stated that the rule should be revised to require tracer surveys in production and injection wells. The commenters indicated that if tracer efficacy could be validated, then the BLM should require its use. One commenter suggested that some of the constituents in flow back fluid could be used for tracers. The BLM did not revise the rule as a result of these comments. One of the rule's major emphases is the prevention of groundwater contamination from hydraulic fracturing operations through ensuring wellbore integrity and the isolation of usable water zones. Additionally, while the BLM believes that tracers may have value in certain situations, their overall effectiveness is questionable due to dilution and detection issues. These limitations render tracer surveys inappropriate for universal application
Numerous commenters asked that the BLM require baseline air and water monitoring prior to hydraulic fracturing. The commenters stated that without baseline air and water quality data, it would be impossible to prove (or disprove) that hydraulic fracturing caused changes in air or water quality. Several commenters noted that the API guidance document on hydraulic fracturing (HF-1) recommends baseline water quality monitoring of both surface and groundwater prior to hydraulic fracturing.
The BLM agrees that baseline air and water quality data and monitoring are good policies with benefits for land managers, the public, and the oil and gas industry, and fully endorses the API guidance with respect to baseline water monitoring. The BLM supports and encourages baseline testing and monitoring, and will require those activities on a case-by-case basis where appropriate, but is not requiring baseline monitoring in this nationwide rule for several reasons. First, there is such a wide variety of hydrogeological conditions that it would be unworkable to establish a single requirement for baseline water monitoring for all Federal and Indian lands. For example, some locations may not have surface or ground water resources, while other locations may have a mix of different types of water resources.
Second, there are many places where the BLM either does not manage the surface above the leased minerals, or the locations where baseline testing and monitoring would be necessary or most useful would be off of BLM-managed land. The BLM has no authority to require air or water quality monitoring on non-Federal lands, and limited authority on non-Federal surface estates (“split estates”). If the final rule were to require baseline testing and on-going monitoring, it would need to have so many exceptions that it would be confusing and of limited value.
Given the fact that the BLM cannot rationally and consistently implement baseline monitoring requirements, no revisions to the rule were made as a result of these comments. Nonetheless, analysis of potential impacts to both air and water quality are common elements of any NEPA review that the BLM prepares on proposals for drilling and hydraulic fracturing operations. If air or water quality impacts are anticipated, then, if not already part of the proposed operation, the BLM could require mitigation measures to address those impacts. These include baseline testing and monitoring that would be developed on a case-by-case basis taking into account local hydrogeologic or airshed factors, plans for field development, land ownership, and existing data and monitoring programs required or implemented by other agencies. These mitigation measures would be imposed as a condition of the BLM's approval for a given project. There are a number of cases where the BLM has required the baseline testing and monitoring of air and water resources as part of its decision to approve the development of oil and gas resources. For example, the Records of Decision (ROD) for the Pinedale Anticline Project Area Environmental Impact Statement (EIS) (see Appendix A-3 at
Some commenters said that BLM could require operators to obtain permission to test water on non-Federal lands. Although states' or tribal police powers may authorize such requirements, the BLM's statutory authority does not extend to non-federal, non-Indian lands, absent a threat to Federal resources. We therefore decline to revise the rule as suggested.
Other comments recommended that the BLM require baseline monitoring of soil, plants, human sickness, and environmental degradation before, during, and after hydraulic fracturing. Additionally, one commenter asked that the BLM provide landowners information on how to test their water to document baseline conditions. The BLM did not revise the rule as a result of those comments. Similar to the recommendation in the API Guidance
Several commenters requested that the rule address the potential stresses on local fresh water supplies. The commenters expressed concern that local fresh water supplies will be diminished by the demand for water for hydraulic fracturing. Some commenters suggested placing restrictions on the use of local fresh water and requiring the use of non-fresh water sources or recycled water to help reduce potential impacts to local fresh water. Other commenters requested the rule include restrictions on water usage. The BLM understands the concerns raised by the commenters. The BLM encourages operators to treat and recycle the water returned after performing hydraulic fracturing along with the water produced from the formation. In fact many operators on public lands are currently considering options of using produced water or recycled water for their hydraulic fracturing operations. The BLM, however, does not have regulatory authority over the use of local fresh water. State and tribal governments, through administration of water rights and permitting water wells, regulate water usage. Existing state and tribal laws require operators to obtain the proper permits and rights to use surface and groundwater. No revisions to rule were made as a result of these comments.
Some commenters expressed concern about the lack of groundwater use regulation in the rule. Commenters recommended that the rule include an assessment of water availability, provisions for reducing water use during droughts, and require that
One commenter recommended operators should pay for monitoring wells when there is suspected contamination. Other commenters recommended that the rule be strengthened by requiring the operator to physically replace any water supply that is contaminated. These recommendations are beyond the scope of this rule. The goal of the rule is to ensure proper wellbore construction and handling of produced fluids to prevent any contamination. If a situation arises where contamination from hydraulic fracturing operations is suspected, the BLM will work closely with states and tribes to determine the proper course of action. The proper course of action for any given situation will depend on the unique circumstances of that situation. No revisions to the rule were made as a result of this comment.
Some commenters asked that the rule include a requirement that some quantity of the water used in hydraulic fracturing operations must be recycled water. The commenters did not offer specific quantities. The BLM encourages operators to treat and recycle the water returned after performing hydraulic fracturing along with the water produced from the formation. Many operators are currently looking at options for using produced water and/or recycled water for their hydraulic fracturing operations. However, mandating the recycling of water is outside of the scope of this rule. No revisions to the rule were made as a result of these comments.
Some commenters asserted that the rules would make oil and gas operations uneconomic, and that would result in Federal liability for a breach of the lease. Federal oil and gas leases clearly provide that the lease rights are subject to all current and future regulations. The rule is an operational regulation and does not change any financial term of any Federal or Indian lease. The BLM does not expect the rule to dissuade operators from drilling in geologically promising areas. Lessees and operators routinely decide not to drill on leases found to be geologically unpromising or uneconomic, but the BLM is not required to waive drilling and completion regulations to improve profitability.
Some commenters asserted that the rule would be a breach of trust on Indian lands. The BLM disagrees. As all the other provisions of 43 CFR part 3160, the rule protects trust resources to the same extent that it protects resources in or on Federal lands. The commenters did not identify any provision of the Constitution, or a treaty, statute, or regulation that the rule violates. One tribe in its comments proposed 10 specific conditions of approval that it wanted to apply to hydraulic fracturing operations on its tribal lands. The BLM imposes conditions of approval on a case-by-case basis based on unique on-the-ground geologic, environmental, and operational circumstances. Specific conditions of approval are beyond the scope of this rulemaking and are inappropriate in a rule of general applicability. If hydraulic fracturing is proposed for specific tribal lands and the tribe proposes specific conditions for the BLM to apply, the BLM will consider the tribe's proposal for that development.
Some commenters said that the BLM has no authority under the FLPMA to promulgate regulations on Indian lands. The BLM agrees. The BLM's authority to regulate oil and gas operations on Indian lands does not come from the FLPMA. The Act of March 3, 1909 (25 U.S.C. 396), the Indian Mineral Leasing Act (IMLA) (25 U.S.C. 396d), and the Indian Mineral Development Act (25 U.S.C. 2107) assign regulatory authority to the Secretary over Indian oil and gas leases on trust lands (except those excluded from the IMLA,
Some commenters said that the FLPMA prohibits the BLM from exercising any part of the Secretary's trustee responsibilities over Indian lands. On the contrary, the FLPMA expressly provides that the Director of the BLM “shall perform such duties as the Secretary may prescribe with respect to the management of lands and resources under [her] jurisdiction according to the applicable provisions of [the FLPMA] and any other applicable law.” 43 U.S.C. 1731(a). Indian trust and restricted lands and minerals are resources under the Secretary's jurisdiction under applicable law. Therefore the delegation of operational oversight to the BLM of oil and gas development on Indian lands as exercised in this final rule is proper.
Several commenters said that the BLM's consultation process was not adequate. In light of statutory responsibilities and executive policies, including the Department's Tribal Consultation Policy (Secretarial Order 3317) and Executive Order 13175, the BLM attaches great importance to tribal consultation. During the proposed rule stage, the BLM initiated government-to-government consultation with tribes on the proposed rule and offered to hold follow-up consultation meetings with any tribe that desired to have an individual meeting. In January 2012, the BLM held four regional tribal consultation meetings, to which over 175 tribal entities were invited. Individual follow-up consultation meetings involved the local BLM authorized officers and management, including State Directors. After the publication of the initial proposed rule, tribal governments and tribal members were also invited to comment directly on the proposed rule.
In June 2012, the BLM held additional regional consultation meetings in Salt Lake City, Utah; Farmington, New Mexico; Tulsa, Oklahoma; and Billings, Montana. Eighty-one tribal members representing 27 tribes attended the meetings. In those sessions, the BLM and tribal representatives engaged in substantive discussions of the proposed hydraulic fracturing rule. A variety of issues were discussed, including, but
After publication of the supplemental proposed rule, the BLM again held regional meetings with tribes in Farmington, New Mexico, and Dickinson, North Dakota, in June 2013. Representatives from six tribes attended. The discussions included a variety of tribal-specific and general issues. One change resulting from those discussions is the re-drafting of paragraph 3162.3-3(k) to clarify that tribal and state variances are separate from variances for a specific operator. The BLM again offered to follow up with one-on-one consultations, and several such meetings were held with individual tribes. Several tribes, tribal members, and associations of tribes provided comments on the revised proposed rule.
In March 2014, the BLM invited tribes to participate in another meeting in Denver, Colorado. Twelve tribal representatives attended the meeting. There was significant discussion of issues raised in the comments on the revised proposed rule. The BLM believes its tribal consultation efforts were thorough.
Nonetheless, some commenters assert that the BLM failed to follow the stages of consultation set out in the Departmental consultation policy and Executive Order 13175. The BLM believes that it has complied with that Executive Order and with Secretarial Order 3317. The BLM understands the importance of tribal sovereignty and self-determination, and seeks to continuously improve its communications and government-to-government relations with tribes.
Some commenters said that the rule continued to apply the same requirements to operations on Indian lands as on Federal lands. They said that the BLM should promulgate different rules for Indian lands, citing as examples the authority of the BIA over cancellation of Indian leases, and ONRR's royalty valuation criteria for operations on Indian lands. The BLM does not assert that implementing its operational regulations on oil and gas operations on Indian lands is the only possible way to carry out the Secretary's trust responsibilities under the Indian mineral statutes cited earlier. Nonetheless, it is the means chosen by the Secretary and the BIA, and is more economic than creating a parallel set of regulations and regulatory personnel in the BIA. The BLM believes it is fulfilling its part of the Secretary's trust responsibilities by requiring operations on Indian lands to meet the same standards as those on Federal lands.
Some commenters urged the BLM to allow tribes to opt out of the final rule. A commenter also cited to BIA's regulations that provide for a tribal constitution or charter issued under the Indian Reorganization Act of 1934, or resolution authorized by such constitution to supersede the regulations in 25 CFR part 211 (which includes 25 CFR 211.4). See 25 CFR 211.29. That section, however, also includes a proviso that tribal law may not supersede the requirements of Federal statutes applicable to Indian mineral leases, and that the regulations in that part apply to tribal leases and permits that require the Secretary's approval. The commenters have not explained why, among all the other requirements of 43 CFR part 3160, an opt-out should be provided for this rule. Some commenters said that the final rule should be “inoperative” on tribal lands once the tribe has demonstrated that its regulatory program is “sufficient” to govern hydraulic fracturing operations. The Indian mineral leasing statutes previously cited do not authorize tribes to opt-out of the Secretary's regulations, and, unlike some environmental statutes, do not authorize tribal “primacy.” Furthermore, the BLM has no way of terminating the Secretary's trust responsibilities for hydraulic fracturing operations if a tribe were to opt out of having the BLM's regulations apply on that tribe's lands, or if the BLM failed to implement the final rule because a tribe was implementing its own program.
Several commenters addressed the variance provision approvingly. Some urged the BLM to recognize tribal regulations. The BLM recognizes that some tribes have been proactive in regulating hydraulic fracturing on their lands. It is not the BLM's intent to preempt tribal regulations. Commenters did not bring to the BLM's attention any tribal regulation or lease provision that the final rule would preempt. In the absence of preemption, tribal law would apply to leases of tribal and individually owned Indian land in addition to the final rule.
The variance provision of the rule allows the BLM, in cooperation with a tribe, to issue a variance that would apply to all wells within that tribe's lands, or to specific fields or basins within those lands, if the State Director determines that the proposal meets or exceeds the objectives of the provision for which a variance is requested. A variance would not necessarily adopt tribal regulations as the Federal rule. However, a variance would, for example, be a way of doing such common-sense things as aligning reporting requirements of the two sovereigns, addressing unique geological conditions, or facilitating technological innovation, while maintaining the performance standards and adequate margins of protection provided in the final rule.
Some commenters said that the variance provision does not comply with policies promoting tribal sovereignty, self-determination, and the Federal government's trust responsibility. The BLM believes that the rule is consistent with the Federal government's trust responsibility because it assures that Indian lands receive the same substantive protection as Federal lands, and that it promotes tribal sovereignty by facilitating coordination to achieve the goals of both sovereigns. By recognizing tribal regulations, it accords with tribal self-determination to the extent that could be expected from a rule governing hydraulic fracturing operations.
A commenter stated that tribal variances should not be subject to public comment. The rule does not provide for public notice and comment on tribal variances and the rule is not revised as a result of this comment.
Some commenters asked that the BLM provide more information about how to obtain contracts and funding under Public Law 93-638, the Indian Self-Determination and Education Assistance Act of 1975, 25 U.S.C. 450
Some commenters opposed the rule, or said that it should not apply on Indian lands, stating that it would increase operators' costs, and thereby make Indian lands less attractive to the oil and gas industry, potentially resulting in reductions of revenue to the tribes. The rule would not render Indian lands more or less attractive than Federal lands. In reviewing the comments and preparing the final rule, the BLM has looked for ways to reduce costs and burdens for operators, and to focus on requirements that promote the
Some commenters supported the rule and suggested that the rule include a cost recovery fee for hydraulic fracturing approval and inspection. The BLM did not propose a separate cost recovery fee for hydraulic fracturing approval and inspection in the initial and supplemental proposed rules. Section 365 of the Energy Policy Act of 2005 prohibits the Secretary from implementing a rulemaking that would enable an increase in fees to recover additional costs related to processing drilling-related permit applications and use authorizations until the end of fiscal year 2015. The BLM fully expects to process requests for hydraulic fracturing concurrently with the processing of drilling applications. The final rule does not include such fees, however, the BLM may address that in any future cost recovery adjustments.
Some commenters asserted that the rule is beyond the Secretary's jurisdiction because protection of surface waters and groundwaters are under the EPA's jurisdiction, not the BLM's jurisdiction. The BLM agrees that regulation of the quality of surface waters under the Clean Water Act, and the regulation of groundwater under the SDWA, are the duties of EPA and states and tribes. The requirements of this rule do not interfere with those programs. The rule does not address discharges to surface waters at all. The rule clarifies the existing definition of usable water to defer to state or tribal designations of aquifers as underground sources of drinking water or as exempted aquifers under the SDWA, so long as these designations are not inconsistent with the SDWA.
Some commenters challenged the Secretary's authority to regulate well construction and operation. Some claimed that the Secretary has no authority to disapprove or to require revisions to a hydraulic fracturing proposal. Some claim that the Secretary has no authority other than to lease lands and collect royalties. The BLM disagrees. The Secretary has authority to promulgate this rule, as the Secretary had for the other sections in 43 CFR part 3160 and the onshore oil and gas orders. That authority includes the FLPMA, the MLA, the Mineral Leasing Act for Acquired Lands, and the various Indian mineral statutes. Each lease is expressly subject to existing and future regulations. The BLM has authority to condition or to deny APDs, and this rule extends that authority to proposals for hydraulic fracturing operations.
Some commenters objected to the rule on the grounds that protection of water is a states' rights issue. The BLM agrees to a certain extent, and has revised the rule, as discussed elsewhere, to reduce potential conflicts with states' water allocation and water quality regulations. Other commenters said that the BLM lacks statutory authority to control water quality and usage because that authority is vested with the EPA and the states.
The BLM is not controlling water quality or usage under this rule. Operators are responsible for complying with state or tribal requirements for obtaining water for use in hydraulic fracturing operations and for discharges into surface or groundwater. The BLM will not be issuing or vetoing rights to use water or discharge permits. However, the BLM will need to know an operator's proposed source of water and planned disposal method in order to consider the potential environmental impacts and compliance with NEPA, but the BLM will not be adjudicating water rights.
Some commenters believed that the rule requires a Federalism assessment under Executive Order (EO) 13132. The BLM believes that there will be no financial impacts to the states as a result of this rule. Operators will have some increases in costs, but the BLM does not believe that production from Federal lands will be reduced as a result of this rule. Therefore, a Federalism assessment is not required.
Many commenters suggested that the annual costs of the rule would exceed $100 million per year and that the BLM failed to comply with E.O.12866 and E.O.13175. One commenter suggested that the costs would be $345 million per year, broken out as follows: $310 million for enhanced casing costs; $5.6 million for initial delay costs; $1.7 million for administrative costs; $2.6 million for cement logs; $5.9 million for log delays; and $19.6 million if the BLM were to require tanks to manage flowback. Other commenters referenced these cost figures. Another commenter suggested the costs of the rule could be as low as $30 million per year or as high as $2.7 billion per year. The range was due to uncertainty about the rule's effect on field operations. The areas of uncertainty in the comments are related to drilling delays and completion schedules, the number of impacted wells, additional requirements resulting from the usable water definition, and costs to conduct CELs on surface and intermediate casing. Another commenter suggested a range of possible costs of $0-$750 million per year.
The BLM has complied with E.O.12866 and E.O.13175. After reviewing and analyzing the submitted data, the BLM found that many of the assertions that the commenters made are based on flawed assumptions or confusion about the requirements in the rule. Commenters have also provided constructive feedback about rule provisions that would pose costs to operators that the BLM had not anticipated. Through the course of this rulemaking, the BLM adjusted requirements to better reflect the best management practices of operators conducting hydraulic fracturing operations and to resolve the unintended consequences that the proposed rules would have caused. The following discussion details comments by topic area.
Commenters suggested that usable water is not fully defined, that there are costs associated with identifying usable water zones, and that the costs are variable and uncertain. Various commenters suggested per-well costs of $4,000-$5,000, $8,000-$10,000, $60,000, and $400,000. Activities associated with identifying usable water include drill logs, water sampling, geologic characterization ($3,000-$8,000 or up to $408,000 per field development), and drill stem testing ($200,000 per test).
As explained in the discussion of section 3162.3-3(d), the final rule removes the requirement that an operator must identify the usable water zones with a drill log. Existing Onshore Order 1 already requires that an operator's drilling plan include the estimated depth and thickness of zones potentially containing usable water. In the final rule, the BLM expects operators to use all available information to identify usable water zones, consistent with Onshore Order 1. As such, and since this information will likely already be readily available to
Commenters suggested that the BLM's definition of usable water would pose additional costs, since the 10,000 ppm TDS standard in the proposed rule is higher than the 5,000 ppm TDS standard in the previous 43 CFR 3162.5-2(d). Our detailed response to these comments appears in the discussion of the definition of usable water and in section 3162.3-3(d) of this preamble. In short, the current requirements regarding usable water exist in Onshore Order 2, which was published after the requirements in the previous section 3162.5-2(d). Onshore Order 2 specifies a 10,000 ppm TDS standard that is consistent with our definition in the proposed and final rules. While the previous section 3162.5-2(d) specified a lower standard, it was superseded by Onshore Order 2 in 1988. This final rule clarifies any confusion between the regulations in the CFR and Onshore Order 2 standards. Since the 10,000 ppm TDS standard is not new, it does not result in additional costs.
Several commenters suggested that the rule would require operators to perform additional cementing that would pose costs to operators. A commenter's analysis suggests that the rule would require operators to run deeper surface casing, two-stage cementing on the production casing, or the addition of an intermediate string of casing, for a total cost of $310M (calculated as 2,350 feet per well of additional casing at $37 per foot for 3,566 wells). Another commenter suggested that, by requiring operators to run a CEL on all strings that protect usable water, operators would need to run cement for the entire lengths of these casings.
As explained in the discussion of the definitions section and section 3162.3-3(d) of this preamble, because the definition of usable water has not substantially changed in this rule, and because existing Onshore Order 2 already requires casing and cementing to protect and isolate all usable water zones, there will be no significant changes in costs of running casing and cement.
Commenters generally believe that the economic analysis underestimates the costs of running CELs, particularly for CELs on the surface casing. One commenter's analysis accepted the BLM's cost estimates for the CEL requirement. Another commenter suggested the CEL costs would be $24,000-$109,000 per well ($3,500-$5,700 for a CBL log, or $5,000-$6,500 for a CBL on the surface casing, $20,000 for a CBL on the intermediate casing, and rig delay costs up to $100,000). One commenter suggested the BLM neglected to include $50,000 per day in rig time from the analysis. One commenter suggested using delay costs of $1,833.33/hour ($1,000 for rig costs and $833.33 for ancillary costs). Commenters referenced EPA guidance that cement should harden for 72 hours for each casing.
As explained in the section 3162.3-3(c) discussion in this preamble, in the final rule the requirements for a CEL on the surface casing of a type well when cement returns to the surface with no indication of inadequate cementing are removed. The final rule instead requires well logging in a manner that is consistent with industry standards. The economic analysis is revised to account for this change.
A commenter identified a formatting error in calculating the costs of a CEL on the intermediate casing. The commenter was correct, and the formatting error is corrected.
Commenters suggested that MIT costs should be considered at a cost of $10,000 per test. The BLM disagrees that the costs of an MIT are attributable to the final rule. The requirements of the rule are consistent with industry guidance on hydraulic fracturing and with state regulations. Industry guidance states that the operator should pressure test the casing string through which the hydraulic fracturing will occur prior to commencing the hydraulic fracturing operation. API Guidance Document HF1 titled “Hydraulic Fracturing Operations—Well Construction and Integrity Guidelines” (First Edition, October 2009) states that “prior to perforating and hydraulic fracturing operations, the production casing should be pressure tested (commonly known as a casing pressure test). This test should be conducted at a pressure that will determine if the casing integrity is adequate to meet the well design and construction objectives” (p. 12). In addition, “prior to beginning the hydraulic fracture treatment, all equipment should be tested to make sure it is in good operating condition. All high-pressure lines leading from the pump trucks to the wellhead should be pressure tested to the maximum treating pressure” (p. 16). The BLM also reviewed state regulations in California, Colorado, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah, and Wyoming. From FY 2010 to FY 2013, the number of well completions on Federal and Indian lands in those states accounted for 99.3 percent of the total well completions on Federal and Indian lands nationwide. The state regulations in those states either require pressure tests on all casing strings or on the casing strings through which the completion operation will occur. Therefore, we believe that the MIT requirement will not pose an incremental cost to most responsible operators.
Several commenters suggested that in order to provide the actual length and height of the fractures (see section 3162.3-3(d)), an operator would have to conduct a “frack model” and that the associated costs are not accounted for in the analysis. They suggested that costs may range from $4,500-$200,000 per well depending on the sophistication of the modeling required. The BLM does not intend to require that operators undertake modeling. The BLM revised the requirement in section 3162.3-3(d) of the final rule to allow for greater operational flexibility, for example, by allowing operators to report the estimated length and height. Operators would not undertake the expense of hydraulically fracturing a well without an estimation or calculation of the propagation of the fissures. The final rule does not require additional modeling.
In the supplemental proposed rule, the BLM solicited comments concerning the incremental costs of a requirement to manage flowback with tanks instead of lined pits. One commenter suggested lined impoundments or semi-rigid atmospheric tanks are more cost effective than steel tanks. It estimated the 5-year net present value costs at: Impoundments $2.3 million, semi-rigid tanks $2.42 million, steel tanks $23 million). A commenter's analysis suggested a tank requirement would cost $19.6 million per year (or $11,500 per well). Another commenter suggested that an open pit costs $447,000 and a closed-loop system costs $267,000 (an $180,000 cost advantage). Section 3162.3-3(h) of the final rule requires that operators manage recovered fluids in enclosed above-ground tanks until approval of a produced water plan pursuant to Onshore Order 7. The economic analysis has been revised to address the costs associated with this revision.
One commenter suggested that hydraulic fracturing operations have additional ancillary costs that are borne by the public, including wider roads and more road maintenance. The economic analysis measures the incremental costs of implementing the rule, not all costs associated with
Several commenters suggested that the analysis should consider the cost of remedial cement squeezes. The practice of squeeze cementing is an operation in a well whereby a cement slurry is forced (squeezed) under pressure into a formation, or a channel behind the casing, or through holes purposely placed in the casing. One commenter suggested that costs for remedial cement squeezes may range between $0-$120,000, or $142,000 per well. Another commenter suggested that typical costs for cement remediation could include: Perforating casing—$12,000; squeeze cementing—$30,000; and post-squeeze CBLs—$6,000-$20,000. Further, the commenter believes that one cement squeeze would require 4 days and two squeezes would require 9 days to complete. The commenter estimated the minimum total cost to be $128,000 for a single cement squeeze and $284,000 for two squeezes, considering rig delay time and direct remediation costs only. Further, the commenter suggests that there is uncertainty in how many cement remediation jobs would be required after the hydraulic fracturing operation occurs.
The concerns about remedial cement squeezes were predicated on two arguments—that CELs are interpretive and that in implementing the rule, the BLM would require operators to perform remedial cement squeezes whenever the CEL detected a cement void. Final section 3162.3-3(e) does not require operators to run a CEL on the surface casing in every case. When there are indications of inadequate cement, the final rule specifies actions that an operator must take that are in line with current remedial procedures. Operators typically run CELs on the cement behind intermediate casings that protect usable water when they do not witness cement returns to surface. Therefore, the BLM believes that the CEL requirements in the final rule would not compel operators to take remedial action that they normally would not have taken otherwise. Thus, the revised requirements do not pose any incremental costs to operators.
Commenters suggested that the type well concept is unclear and undefined. Commenters presented a range of estimates for type well applicability. A commenter suggested 3 percent to over 50 percent per field depending on the maturity. A 5 percent increase in type well applicability is associated with a $34 million increase in industry costs. Another commenter suggests 14.29 percent of all wells because 6-8 wells can be drilled from the same platform. Another commenter suggested it could mean one type well per section (10 type wells per 640-acre section).
The final rule does not carry forward the type well concept or the CEL requirement for the surface casing. Thus, neither the costs of CELs for all surface casings, nor the cost savings from the type well are relevant for the final rule.
Commenters suggested that the economic analysis should consider legal challenges and delays to APDs. The BLM did not revise the final rule or alter the analysis to consider potential legal challenges or APD delays, because any potential delays that might arise as a result of legal challenges are speculative and not the result of the rule itself.
One commenter suggested that the analysis should account for the cost of labor required to implement the rule. In the economic analysis for both the initial proposed and the supplemental proposed rules, the BLM considered the additional BLM workload and cost required as a distributional cost. The BLM agrees with the comment and has revised the final analysis to include the labor costs as part of the total costs of the rule.
Some commenters agreed with the BLM's administrative cost estimate, while others thought that the estimate should be reevaluated. The administrative workload was based on the estimated agency review time. In the final rule's analysis, the BLM reevaluated the administrative costs given the changes to the rule. The results of the BLM reevaluation are discussed later in the Paperwork Reduction Act section of this rule.
Commenters suggested that the BLM failed to consider the effects on tribal governments, and that the rule will have a disproportionate effect on tribes. Commenters suggested that the compliance costs of the rule will discourage operators from developing resources on Federal and Indian lands, reduce royalties, and harm local economies. Some commenters suggest that there could be negative spillover effects on state and private lands as well.
The analysis for the proposed and supplemental proposed rules included impacts on tribal lands. The BLM revised the final rule's analysis to addresses these impacts. The BLM believes that the rule will not have a disproportionate effect on tribes, given the requirements are consistent with current industry best practices.
Many commenters suggested that the economic analysis failed to quantify or describe the benefits of the rule and that the benefits must support the BLM's proposed action. Commenters disagreed with the characterization of risk and of the incidence of problems. Commenters also acknowledged that the risk of hydraulic fracturing is largely unknown. One commenter suggests estimating the environmental risk or determining society's willingness to pay for risk reduction.
The BLM does not quantify the benefits of the rule, because it is unable to monetize the incremental reduction in risk that the rule confers. It further believes that determining society's willingness to pay for risk reduction would need to rely on a firm understanding of the incremental risk reduction. However, this does not mean that the rule is without benefits. The final rule includes requirements, many of which are already consistent with industry guidance, to ensure that operators conduct hydraulic fracturing in a manner that minimizes environmental and health risks associated with these activities. These requirements are also generally consistent with several state regulations governing hydraulic fracturing.
One commenter suggested that Federal Remediation Technologies Roundtable case studies referenced in the proposed rule's economic analyses are inappropriate because none of the studies are studies of hydraulic fracturing operations. One commenter referenced testimony that the remediation of groundwater contaminated by oil and gas wastes can range from $100,000 to $1 million. The BLM included these figures in the analysis to provide context about the cost of potential problems, but it does not use the figures to quantify a benefit.
Commenters suggested that the rule lacks economic justification and is unnecessary, that there have been no events of groundwater contamination, and the benefits must outweigh the costs. Elsewhere in this preamble we have discussed the need and purpose for the rule and it is prudent for the BLM to be proactive in the protection of resources on Federal and Indian lands. Throughout the rulemaking process, the BLM has been mindful of the potential compliance costs to the operator. The requirements in the final rule are consistent with industry best practices and the burden should be minimal. In addition to that, the rule is necessary given the overall scale of development and emergence of increasingly complex hydraulic fracturing operations that apply increased pressures and volumes of fluid within the subsurface. The BLM agrees that efforts to trace contaminants in groundwater to specific hydraulic
Commenters suggested that some of the requirements in the rule are duplicative of state rules, that the rule is duplicative and unnecessary, and that the analysis should reflect that. The economic analysis accounts for areas in which the rule's requirements are consistent with existing requirements (whether in current BLM onshore orders or in state regulations) or consistent with current industry best practice. For activities required by the rule that are already performed by operators, the economic analysis does not attribute the costs of those activities to the final rule.
Commenters suggested that wells that have been constructed prior to this rule should be grandfathered. Otherwise, operators would have to workover wells to comply with cement repair provisions. If not, those costs should be considered. As described in the discussion of final section 3162.3-3(a), the final rule clarifies which paragraphs of the final rule will apply to wells constructed prior to the effective date of the rule, and the economic analysis reflects the terms of the final rule.
Operators planning to conduct hydraulic fracturing on existing wells will need to submit documentation that demonstrates that adequate cementing was achieved for all casing strings designed to isolate and protect usable water. Monitoring reports of cement jobs are common in the industry and the operator should be able to provide such documentation to the BLM without any burden even for wells drilled prior to this rule. For older completed wells, to the extent that these reports are not available, the operator may provide any other information or perform any other measures deemed necessary by the authorized officer to assure that the cementing will isolate and protect usable water zones. Operators planning to conduct hydraulic fracturing on existing wells will also need to demonstrate that there is at least 200 feet of adequately bonded cement between the zone to be hydraulically fractured and the deepest usable water zone. Operators will be able to run a CEL on the production casing, as is consistent with prudent operating practice, without an additional cost burden.
Certain commenters expressed concern stating that the environmental assessment (EA) did not consider a reasonable range of alternatives to the proposed action. Commenters claimed that, other than the No Action alternative, all alternatives looked too similar to be considered different alternatives. Commenters further suggested that the BLM consider alternatives that: (1) Do not impose cement evaluation log (CEL) requirements; (2) Defer to states with hydraulic fracturing rules regardless of whether they meet or exceed the requirements of the BLM's rule; (3) Ban hydraulic fracturing entirely or in sensitive areas; (4) Regulate air emissions from hydraulic fracturing operations; (5) Ban the use of diesel in hydraulic fracturing fluid; or (6) Ban the use of harmful chemicals in hydraulic fracturing fluid.
To help inform the development of the hydraulic fracturing rule, the Secretary and the BLM hosted forums in Washington, DC and various parts of the country to receive input from the public regarding their concerns about hydraulic fracturing activities on onshore Federal and Indian lands. A majority of the concerns raised during the sessions relate to the risks hydraulic fracturing activities pose to surface and subsurface sources of water, the constituents of the fluids injected into the ground as part of the hydraulic fracturing process, and concerns over the management of the fluids used during and recovered after a well is fractured.
The information gathered from these sessions, coupled with the BLM's authority to regulate all oil and gas operations on Federal and Indian lands, helped guide the development of the BLM's
The
The BLM's obligation under NEPA is to analyze a reasonable range of alternatives (not every conceivable alternative) that would meet the bureau's purpose and need for Federal action and allow for a reasoned choice among alternatives to be made. The Council on Environmental Quality (CEQ) has determined that “Reasonable alternatives include those that are practical or feasible from the technical and economic standpoint and using common sense, rather than simply desirable from the standpoint of the applicant.”
The BLM analyzed six alternatives that respond to the BLM's purpose and need for Federal action. These alternatives consider a broad range of prescriptions for how hydraulic fracturing operations should be regulated, including the option of not promulgating a rule—the No Action alternative. Regarding the action alternatives, Alternative B seeks to regulate all forms of well stimulation, including hydraulic fracturing, and prescribes a particular way to confirm wellbore integrity and zonal isolation of usable water-bearing zones,
Alternative C evaluated the option of not requiring operators to line their pits to temporarily store recovered fluids. Alternative D evaluated the option of requiring operators to use only storage tanks to store recovered fluids. Under Alternative F, the BLM requires the use of rigid enclosed, covered, or netted and screened above-ground tanks with a 500 bbl capacity, but will consider the use of a lined pit so long as the risk of adversely affecting sensitive water resources, such as surface water and shallow groundwater, was low and use of storage tanks was infeasible for environmental, public health, or safety reasons. However, Alternative F does not include a requirement to perform a cement evaluation log on all casing strings. Rather, it requires operators to circulate cement to the surface for the surface casing and either circulate cement to the surface or run a CEL on the intermediate and production casing, in addition to performing specific well integrity tests, to confirm wellbore integrity and zonal isolation. These alternatives meet the BLM's purpose and need for Federal action and comply with CEQ's requirement to also consider the No Action alternative, which is Alternative A.
In addition to the six alternatives analyzed in the environmental assessment, the BLM also considered additional alternatives that were eliminated from detailed analysis. The BLM considered an alternative to defer to the states' and tribes' hydraulic fracturing rules regardless of whether those rules meet or exceed the agency's hydraulic fracturing requirement. However, those governments are regulating hydraulic fracturing operations in varying ways. For example, the state regulations range from not regulating the activity at all in some states to fairly comprehensive regulation in other states. The BLM administers oil and gas operations in many states and on various Indian reservations, and the agency needs a baseline set of standards that would apply to Federal and Indian oil and gas leases in all states. These standards must meet the agency's unique responsibilities under the FLPMA, the Indian mineral leasing acts, and other statutes to administer oil and gas operations in a manner that protects Federal and Indian lands. The BLM's regulations are necessary because the BLM is unable to delegate its responsibilities to the states and tribes. An alternative that would defer to state and tribal hydraulic fracturing rules, even in circumstances where those rules do not meet or exceed the requirements of the BLM's rule, would not meet the purpose and need for the BLM's action. Moreover, an alternative deferring only to more stringent regulations would be unnecessary. None of the alternatives considered by the BLM for this rulemaking would preempt a more stringent state or tribal law. Unless a specific variance is granted by the BLM, operators on Federal leases must comply both with this rule and any applicable state requirements, just as they already must comply with both BLM rules and state rules on a variety of drilling and completion issues. This alternative was therefore not carried forward for further analysis.
The BLM considered an alternative that would ban hydraulic fracturing activities in all areas. However, such an alternative may render most oil and gas development projects on Federal and Indian land infeasible, as indicated by the fact that the BLM estimates that 90 percent of the wells drilled on Federal and Indian land are hydraulically fractured. The BLM has a responsibility under the FLPMA to act as a steward for the development, conservation, and protection of Federal lands, by implementing multiple use principles and recognizing, among other values, the Nation's need for domestic sources of minerals from the public lands. The Secretary of the Interior has responsibilities under the Indian mineral leasing acts to assist tribes and individual Indians in obtaining the benefits of mineral development while protecting other resources. A ban or moratorium would not satisfy the BLM's development responsibility under the FLPMA, or the Secretary's responsibilities under other statutes, when regulations can adequately reduce the risks associated with hydraulic fracturing operations. In addition, a part of the BLM's purpose and need for this action is to administer oil and gas operations in a manner that protects Federal and Indian lands while providing for opportunities to develop oil and gas resources on those lands. An alternative that would ban or place a moratorium on hydraulic fracturing operations would not meet the purpose
Similarly, the BLM considered an alternative that would ban hydraulic fracturing activities in sensitive areas. However, the BLM has other tools and processes in place to ensure protection of sensitive areas. For example, the BLM has rules at 43 CFR 3100.0-3(a)(2)(iii) that prohibit the leasing of Federal minerals beneath incorporated cities, towns, and villages. Also, during development of a Resource Management Plan (RMP), the BLM identifies areas needing protection as areas closed to leasing or areas open to leasing, but with stipulations that limit or prohibit surface occupancy. Further, specific setbacks from sensitive areas are more effective when they are determined at a level where the information associated with a given sensitive area is available. That information is gathered and maintained at the field office level where specific drilling and hydraulic fracturing operations are permitted. At the permitting stage, the BLM conducts additional analysis as required by NEPA, when drilling/hydraulic fracturing proposals are received. The analysis includes onsite inspections, which identify any additional sensitive areas. Using that information, the BLM then develops proper mitigation to protect these areas. Mitigation could include moving the well location or including site-specific conditions of approval (COAs). In addition, if unnecessary or undue degradation impacts are identified on public land, or unacceptable impacts are identified on Indian land, which cannot be mitigated, the BLM may deny the proposal. Through existing regulations, the RMP process, and the subsequent site-specific analyses, the BLM has or can specify measures to ensure protection of sensitive areas. Furthermore, state set-back requirements would normally apply on Federal lands, and tribal set-back requirements would apply on tribal lands (see also existing section 3162.3-1(b)). Since setback requirements are already addressed in existing regulations, land use planning, and internal processes and policy, minimum setback distances are not necessary in this rule. For these reasons, an alternative that entails setbacks from sensitive areas would not be a reasonable alternative, and was not carried forward for further analysis.
The BLM considered an alternative that would regulate emissions associated with the hydraulic fracturing process. However, this alternative is not within the scope of this rulemaking. The purpose and need for the BLM's action is, among other things, to improve its regulatory framework to account for hydraulic fracturing activities and establish procedures that would provide adequate protection of water resources on Federal and Indian lands. Please note that the EPA issued final rules to reduce air pollution from the oil and natural gas industry. The final rules were issued in 2012 and include air standards for natural gas wells that are hydraulically fractured. For these reasons, the alternative was not carried forward for analysis.
The BLM considered an alternative that would ban the use of harmful chemicals in the fluids used to hydraulically fracture a well. Chemicals used during the hydraulic fracturing process are tailored to the downhole conditions of a given well. In this rule, to be conservative, the BLM treats all chemicals used in hydraulic fracturing as if they were hazardous. Thus, the rule is written to ensure that all hydraulic fracturing fluids are confined to the intended zone and do not contaminate usable water zones, and that recovered fluids do not contaminate surface or groundwater. For these reasons, an alternative to ban hazardous chemicals was not carried forward for analysis.
Similarly, the BLM considered an alternative that bans the use of diesel fuel in hydraulic fracturing fluids. Diesel fuel is used as a base fluid instead of water where the hydrocarbon-bearing formation would swell when coming into contact with water, limiting or preventing the flow of oil and gas into the wellbore. The regulation of diesel fuel in hydraulic fracturing fluids is committed to EPA under the SDWA and the Energy Policy Act of 2005. The action alternatives would prevent hydraulic fracturing fluids, recovered fluids, and hydrocarbons from contaminating usable water sources. Banning the use of diesel fuel on Federal and Indian lands could prevent some oil and gas resources from being developed, even though such operations would be allowed by the EPA's regulations and guidance. That would not serve the purpose and need for the regulation. Accordingly, an alternative to ban the use of diesel fuel was not carried forward for analysis.
Certain commenters recommended that the BLM not only analyze the impacts from the proposed rule, but rather all impacts associated with hydraulic fracturing operations in order to determine the effectiveness of the rule. Those commenters wanted an analysis of impacts to landscapes, air, wildlife, etc., as well as increased greenhouse gas emissions released as a result of increased production from unconventional sources made available only because of hydraulic fracturing technologies.
An expanded description of hydraulic fracturing operations is provided in the Environmental Impacts section of the EA, and in the discussion of the No Action Alternative. Analyzing impacts associated with actual site-specific hydraulic fracturing activities is outside the scope of the EA for this rule. The BLM's Preferred Alternative is not to consider the approval of a specific hydraulic fracturing operation, but rather to consider how its existing rules should be revised to respond to changes in technologies for hydraulic fracturing and the public's concern regarding the practice. Approvals to develop Federal and Indian oil and gas resources (including proposals to hydraulically fracture wells) are made at different levels of the agency's organization and during various decision-making processes—land use planning, oil and gas leasing, and permitting. It is at those decision points where the BLM would analyze, through the NEPA process, impacts to landscapes, air, wildlife, etc., as well as greenhouse gas emissions released from oil and gas development.
The BLM has analyzed the action alternatives in comparison to the No Action Alternative. The CEQ requires that a No Action Alternative be considered. The No Action Alternative would not amend the BLM's oil and gas regulations. Instead oil and gas activities on Federal and Indian lands would continue under existing regulations. The No Action Alternative provides a useful basis for comparison, enabling decision-makers to compare the magnitude of environmental effects of the action alternatives against the No Action Alternative. The No Action alternative also demonstrates the consequences of not meeting the need for the action.
The BLM has evaluated the effectiveness of the rule when evaluating the effects of the No Action Alternative in Chapter IV of the EA. The BLM determined that if none of the action alternatives were to be implemented, operators or their contractors would still perform hydraulic fracturing operations on Federal and Indian lands, usually without the BLM's prior approval, and without performance standards specific for wells to be fractured. The BLM and the public would not have an adequate assurance that hydraulic fracturing operations performed on Federal and Indian lands are conducted in a safe and environmentally sound manner, particularly because there would not be a regulation that provides: (1) For the disclosure of chemicals used in the stimulation process; (2) A means to
Some commenters believe that the scope of the rule requires the preparation of an EIS. The comments in favor of an EIS make one or more of three different positions. First, some commenters believe that an EIS is required because of the trade secrets provision within the rule. Although the rule contains requirements for disclosure, there are provisions that allow operators to withhold trade secrets. Those commenters said that the BLM cannot claim that the rule's chemical disclosure requirement will help the agency and other agencies make an accurate determination of whether hydraulically fractured fluids could be the source of any future reports of groundwater contamination. Without the information about trade secrets, the commenters said, future approvals of hydraulic fracturing operations could not accurately predict environmental impacts, and thus the BLM should prepare an EIS for the final rule.
Second, some commenters believe that an EIS is required because multiple significance factors are present under the regulations which would govern widespread hydraulic fracturing on public lands throughout the country. The alleged significance factors include adverse environmental effects, significant impacts to public health and safety, unique characteristics of the geographic area, controversial effects, uncertain risks, cumulatively significant impacts, adverse effects to threatened and endangered species, and potential violations of environmental laws. Commenters said that the significant impacts of widespread hydraulic fracturing on public lands that would take place under the regulations contradict BLM's ultimate conclusion in the EA that the proposed regulations would have no significant impacts on the environment.
Third, some commenters have expressed concern with the EA's analysis of socioeconomic impacts. Commenters said a nationwide rule that has economic and employment impacts is a major Federal action requiring the preparation of an EIS, therefore, the NEPA analysis performed for the proposed rule is inadequate. The commenter said that the BLM is in error in determining that an EA is sufficient to analyze the impacts associated with the rule. The commenter said that a nationwide rule of this magnitude and its coinciding economic and employment impacts certainly rise to the level of “Major Federal Action,” and therefore questioned the BLM's determination that an EA is sufficient.
The BLM has not prepared an EIS in response to those comments. First, the comments based on the trade secrets provisions miss the point that BLM's evaluation of the impacts associated with promulgation of the rule, and with the BLM's later evaluation of site specific impacts, does not require operators to disclose trade secrets. The BLM will make its decisions on proposals to conduct hydraulic fracturing operations on the assumption that the operations will use hazardous chemicals. The BLM will not approve proposals unless the operator demonstrates that the well was cased, cemented, and tested to show that it will isolate and protect usable water, and that recovered fluids will be isolated from surface and groundwater. The precise chemical constituents are not necessary for the BLM to assure that the operation will protect surface and groundwater. Exemptions from public disclosure for trade secrets or confidential business information will not prevent the BLM from assessing the environmental impacts of future hydraulic fracturing operations, and thus do not require an EIS for this rule.
Second, the comments that advocate an EIS because of multiple significance factors which would govern widespread hydraulic fracturing on public lands throughout the country misunderstand the effect and impact of this rule. Federal agencies are required to prepare an EIS when they will take a major Federal action that will potentially have a significant effect (direct, indirect, or cumulatively) on the human environment. The BLM's action is to update its existing regulations that pertain to hydraulic fracturing operations on Federal and Indian leases. Analyzing impacts associated with actual site-specific hydraulic fracturing activities is outside the scope of the EA for this rule. The BLM's proposed action is not to consider the approval of a specific hydraulic fracturing operation, but rather to consider how its existing rules should be revised to respond to changes in technologies for hydraulic fracturing and the public's concern regarding the practice. Approvals to develop Federal and Indian oil and gas resources (including proposals to hydraulically fracture wells) are made at different levels of the agency's organization and during various decision-making processes—land use planning, oil and gas leasing, and permitting. It is at those decision points where the BLM would conduct further analysis under NEPA to evaluate impacts to landscapes, air, wildlife, etc., as well as increased greenhouse gas emissions released from oil and gas development.
In the EA prepared for this rule, the BLM evaluated a range of reasonable alternatives, including the final rule, to determine whether its promulgation of the final rule would result in a significant effect on the human environment. In making its Finding of No Significant Impact (FONSI), the BLM considered the significance factors set out in 40 CFR 1508.27, which include the significance factors identified by commenters. For the reasons discussed in more detail in the EA and FONSI, the BLM concluded that the final rule would not have a significant impact on the environment and that no EIS was required.
Furthermore, the rule is not connected to other actions that may require an EIS because it does not automatically trigger land use planning decisions, oil and gas leasing, or hydraulic fracturing operations. The rule will be in effect regardless of any previous leasing or development. The rule is not an interdependent part of a larger action and it does not depend on any larger action for its justification.
The rule will govern future hydraulic fracturing operations, as will stipulations in oil and gas leases, and COAs in permits to drill. The lease stipulations and COAs can address local conditions and resources. Thus, the rule does not foreclose reasonable mitigation for site-specific direct, indirect, or cumulative impacts.
Under the CEQ's regulations, an EIS is required only if the issuance of a rule or regulation may significantly affect the quality of the human environment. 40 CFR 1508.18. The human environment includes the natural and physical environment and the relationship of people with that environment, but economic or social effects do not by themselves require preparation of an EIS. 40 CFR 1508.14. The EA refers to and analyzes the socioeconomic impacts of the rule that are provided in the separate economic analysis. The economic analysis shows that the rule will increase compliance costs of operators, but also discloses that those increased costs would be only a small percentage of the costs of drilling and hydraulically fracturing an oil and gas well. Thus, only marginally prospective lands could even theoretically become less attractive to the oil industry, and
Certain commenters stated that the BLM did not inform the public that it was preparing a NEPA analysis, nor did it circulate a draft EA. Other commenters expressed similar concern saying the BLM did not provide a public comment period and therefore, the public was not able to provide meaningful input at a time when the environmental analysis could have been altered and improved.
Unlike the procedures for issuing an EIS, which includes specific formal notification requirements through the
On May 11, 2012, the BLM issued the notice of proposed rulemaking and then issued a supplemental notice of proposed rulemaking on May 24, 2013. The 2012 proposal was available for public comment for 120 days and the 2013 notice was available for 90 days. Both rules put the public on notice that the EA was available for review and comment along with the other documents in the administrative record. The BLM, in fact, received several comments concerning the substance of the EA, and those comments have been considered. Thus, comments suggesting that the EA was unavailable, or not properly made available for comment, are incorrect.
To understand the context of the costs and benefits of this rule, the BLM includes background information concerning the BLM's leasing of Federal oil and gas, and management of Federal and Indian leases. This analysis explains the basis for the conclusions related to the procedural matters sections that follow. The BLM Oil and Gas Management program is one of the largest mineral leasing programs in the Federal Government. At the end of fiscal year (FY) 2013, there were 47,427 Federal oil and gas leases covering 36,092,482 acres, 93,598 producible and service drill holes, and 99,975 producible and service completions on Federal leases. Table 1 shows the sales volume, sales value, and royalty generated from Federal and Indian oil and gas production in 2013. For FY 2013, onshore Federal oil and gas leases produced about 133 million bbl of oil, 2.67 trillion cubic feet (Tcf) of natural gas, and 2.5 billion gallons (Gal) of natural gas liquids, with a sales value of almost $24 billion and generating royalties of almost $2.7 billion. Oil and gas production from Indian leases was almost 46 million bbl of oil, 238 billion cubic feet (Bcf) of natural gas, and 155 million gallons of natural gas liquids, with a sales value of over $5 billion and generating royalties of $860 million for the Indian mineral owners.
To summarize the need for policy action, the National Academy of Science has identified three potential pathways for hydraulic fracturing fluids or oil and gas from hydraulic fracturing operations to contaminate usable water resources. The BLM agrees that the most likely pathway would be a leak in the wellbore casing, and that assurances of the strength of the casing are appropriate. The BLM also believes that it is important to consider known faults or natural fissures that could serve as pathways between the fractured zone and usable water before approving a hydraulic fracturing operation. A related issue is prevention of “frack hits,” which are unplanned surges of pressurized fluids from one wellbore into another wellbore. Frack hits have resulted in surface spills on Federal and non-federal lands and have caused the loss of recoverable oil and gas, but they have not yet been shown to be a source of contamination of usable water. Furthermore, proper management of recovered fluids on the surface is necessary to prevent leaks and spills that could contaminate surface waters and shallow aquifers; the BLM needs to fill the existing regulatory gap between completion of a hydraulic fracturing operation and the implementation of an approved plan for permanent disposal of produced water. Finally, the BLM, the public, and tribes should have access to information about the chemicals injected into Federal or Indian lands, consistent with statutory protections for proprietary information. The following discusses those needs for policy action in more detail.
Much of the debate about hydraulic fracturing has centered on fluid or gas migration; that is, the potential that hydraulic fracturing fluids pumped into deep geologic formations, or oil or gas liberated by hydraulic fracturing will migrate into shallower drinking water sources with potential contamination made more likely if the wellbore integrity is compromised. Most reports suggesting that hydraulic fracturing operations contributed to contamination of water supplies involve instances of abnormally high concentrations of methane in water wells or monitoring wells in or near areas with active oil and gas drilling.
For example, the National Academy of Sciences issued reports in 2011
1. The movement of gas-rich solutions within the shale formations up into shallow drinking-water aquifers;
2. The movement of gas through inadequately constructed, or leaky gas-well casings; and
3. The creation of new or enlarging of existing fractures above the shale formation as a result of hydraulic fracturing, which increases the connectivity of the entire fracture system, thus allowing the gas to absolve out of solution and migrate through the fracture systems and into shallow aquifers.
These reports have indicated that the movement of gas-rich solutions within the shale formations up into shallow drinking-water aquifers is the least likely possibility. This is due primarily to the extensive distance between the shale formations and the shallow aquifers as well as high underground pressures exerted against the deep shale formations. The most likely possibility for gas contamination would be from leaky gas-well casings. These leaks could occur at hundreds of feet underground, with methane passing laterally through the well casing and vertically through fracture systems. There is also a possibility for gases to migrate through fractures above the shale formation that is created or enlarged as a result of hydraulic fracturing and thus expanding the overall underground fracture system. These new fractures could potentially relieve the pressures exerted against these gas-rich solutions, which would allow the gas to come out of solution and migrate through the fracture system and potentially into shallow aquifers or improperly plugged wells. However, these researchers have stated that the possibility of such occurrence is unlikely, but still unknown.
The focus on fluid or gas migration is only one aspect of potential damage. According to the EPA, there are other potential impacts, including stress on surface water and groundwater supplies from the withdrawal of large volumes of water used in drilling and hydraulic fracturing, contamination of underground sources of drinking water and surface waters resulting from spills, faulty well construction, or by other means, and adverse impacts from discharges into surface waters or from disposal into underground injection wells.
The BLM is aware that a small number of hydraulic fracturing operations on Federal lands have communicated with other wells in their vicinity. Those hydraulic fracturing operations created fractures that connected with existing fissures or fractures in the shale, allowing pressurized fluids to flow into nearby wellbores. During these instances of downhole inter-well communication, known as “frack hits,” the pumped-in hydraulic fracturing fluid may flow into and up through a nearby well, causing a blow out and spill.
At the President's direction, the Secretary of Energy's Advisory Board convened a Natural Gas Subcommittee to evaluate hydraulic fracturing issues. The subcommittee met with industry, service providers, state and Federal regulators, academics, environmental groups, and many other stakeholders. Initial recommendations were issued by the subcommittee on August 18, 2011. Among other things, the report recommended that more information be provided to the public, including disclosure of the chemicals used in fracturing fluids. The subcommittee also recommended the adoption of progressive standards for wellbore construction and testing.
The final report, issued on November 18, 2011, recommended, among other things, that operators and regulating agencies “adopt best practices in well development and construction, especially casing, cementing, and pressure management. Pressure testing of cemented casing and state-of-the-art cement bond logs should be used to confirm formation isolation. Regulations and inspections are needed to confirm that operators have taken prompt action to repair defective cementing jobs. The regulation of shale gas development should include inspections at safety-critical stages of well construction and hydraulic fracturing.”
The public and various groups have expressed strong concerns about the prevalence of hydraulic fracturing and the chemical content of the fluids used in the process. Some of the comments frequently heard during the public forums previously discussed included concerns about water quality, water consumption, and a desire for improved environmental safeguards for surface operations. Commenters also strongly encouraged the agency to require public disclosure of the chemicals used in hydraulic fracturing operations on Federal and tribal lands.
The BLM has existing regulations for hydraulic fracturing, found in 43 CFR 3162.3-2. Under that regulatory provision, an operator must seek approval from the BLM before performing “non-routine” fracturing operations. Conversely, an operator performing “routine” fracturing operations does not currently need the BLM's approval. The regulation makes a distinction between “routine” and “non-routine” fracturing operations, but it does not define them. This omission makes the distinction functionally difficult to apply and confusing for both the agency and the regulated public.
Also, hydraulic fracturing operations conducted now are vastly different than the operations conducted decades ago. For decades, hydraulic fracturing was a completion or re-completion technology that used relatively small quantities of fluid to improve the flow of hydrocarbons around the bottom of conventional wells. Due to advances in horizontal drilling, hydraulic fracturing operations are now conducted on wells with longer lateral legs (often 1 to 2 miles) and require far larger volumes of water. The chemical content of the hydraulic fracturing fluids is also a growing concern to the public, such that many state regulatory authorities now require the chemical disclosure of fracturing fluids. The information that the BLM currently requires before and after fracturing operations is inadequate and does not reflect the complex nature of the operations.
From a resource management perspective, the current regulation results in incomplete information being provided to the BLM. That lack of
Generally, there is greater potential for undesirable events or incidents to occur when operations are conducted in wells that are constructed improperly, where the plans are inadequate, or when the fluids are not properly managed. This potential extends to hydraulic fracturing operations, where the well may extend laterally and for longer distances, greater pressures are placed on the well, and larger volumes of fluids are used and recovered. As with all drilling and production activities, there is a potential that they may pose a negative externality to society, considering limitations in understanding the extent of potential damage or determining a causal relationship between the operation and the damage.
Relative to wells constructed with sufficient and demonstrated integrity, wells that are inadequately constructed may not sufficiently isolate formation gas or fluids from water resources or may be more likely to fail during fracturing operations. Although wellbore integrity provisions exist in current BLM regulations, this rule would enhance those provisions to account for advances in technology and hydraulic fracturing operations. In addition, the recovered fluid from hydraulic fracturing operations may pose additional risk to the surface and subsurface environments if not managed and disposed of properly.
After reviewing the requirements of the final rule, we have determined that it will not have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. Additionally, we have determined that it would not have a significant economic impact on a substantial number of small entities.
Many of the requirements are currently met by operators as a matter of standard industry practice or in compliance with existing state regulations or other BLM regulations (including Onshore Oil and Gas Orders No. 1 and No. 2). We measure the incremental burden to operators against that baseline. While some requirements do not pose an additional burden, other requirements will pose an additional burden.
We estimate that the rule will impact about 2,800 hydraulic fracturing operations per year, but that it could impact up to 3,800 operations per year based on previous levels of activity on Federal lands and growing activity on Indian lands. We estimate that the compliance cost could reach about $11,400 per operation or $32 million per year. The estimated per-operation compliance costs represent about 0.13 to 0.21 percent of the cost of drilling a well. Given the potential to impact 3,800 operations per year, the compliance costs might reach $45 million per year.
The BLM estimated or described the potential costs and benefits that would occur as a result of the rule. As such, it analyzes the impacts in relation to the current operating environment (or the baseline). In analyzing costs and benefits, it is important to differentiate between the activities that an operator conducts (either voluntarily or in compliance with state or Federal requirements) and those new activities that the rule would compel.
Office of Management and Budget (OMB) Circular A-4 recognizes that not all benefits and costs can be described in monetary or even in quantitative terms. In those cases, it directs agencies to present any relevant quantitative information along with a description of the unquantified effects.
We use a bottom-up approach to measure the incremental impacts rather than a top-down approach. In doing so, the BLM estimates the number of hydraulic fracturing operations per year for future years, determines the applicability of the requirements on the operations, determines the unit cost of compliance per requirement, and then calculates the total costs across all requirements and operations. Due to the uncertainty of the hydraulic fracturing activity in future years, the BLM presents a range of costs based on the range of potential activity. We chose to use a bottom-up approach because a requirement may not pose an incremental compliance cost, depending on the operators' voluntary compliance (generally determined as whether the requirement is consistent with industry guidance or best practice) or the regulatory requirements in the jurisdiction within which the operation will occur.
The BLM's approach to estimating the number of hydraulic fracturing operations is described in the Economic Analysis for this rule, which is available from the BLM at the address listed in the
For the annual estimate of completions using hydraulic fracturing, the BLM uses the 3-year average of the implementation years within each state and reservation. Recognizing the dip in well completions on Federal lands in FY 2013, and recognizing that previous levels of activity were higher, the BLM also calculated costs using the FY 2012 level of activity on Federal lands, prior to the FY 2013 decrease, and presents that estimate as an upper bound of potential costs.
The BLM expects that operators are already in compliance with many of the rule's requirements as a matter of company practice or standard industry practice (described in the Economic Analysis), or to meet state regulations (described in the Economic Analysis) or Federal regulations (described in the Economic Analysis). Where the rule's requirements are consistent with industry guidance, state regulations, or Federal regulations, the BLM considered the applicability of the requirement to be 0 percent and the incremental impact to be zero. We consider partial applicability in areas and in situations where the operator is expected to comply voluntarily, for example, when a requirement costs less than the alternative.
Application Requirement: The operator must submit an application to conduct a hydraulic fracturing operation with the APD or an NOI when it plans to hydraulically fracture a well for which it has:
• Not yet submitted an APD as of the effective date of this rule;
• Submitted an APD, but the APD has yet to be approved as of the effective date of this rule;
• An approved APD or APD extension on the effective date of this rule, drilling did not begin until after the effective date, and does not conduct
• Started (but does not complete) drilling before the effective date and does not conduct hydraulic fracturing within 90 days after the effective date;
• Completed drilling 180 days prior to the effective date, and does not conduct hydraulic fracturing within 90 days after the effective date; or
• Completed drilling 180 or more days prior to the effective date.
The operator may also submit an application for a group of wells as part of an MHFP, thus reducing the number of potential applications.
The BLM expects there to be fewer applications than there are hydraulic fracturing operations, because of the option to make one submission for a group of wells, a process which is designed to achieve additional efficiencies.
The BLM estimates the applicability of this requirement based on the number of well completions using hydraulic fracturing that we expect to occur. Since the BLM assumes that every hydraulic fracturing operation will require an application, our estimate is inclusive of all instances described in the first paragraph of this section (and particularly in bullets 3 through 6) where an operator would be required to submit an application to conduct hydraulic fracturing.
The data are as follows:
(a) Applicability of requirement = 100 percent of operations. Although the BLM allows for the operator to submit a single NOI covering a group of wells, it is uncertain whether the operator will prefer that method over submitting an application with the APD. For the purpose of this analysis, the BLM assumes that the operator will submit an application for a single well, especially in the near-term future.
(b) Cost per application = $643. The cost per application includes the operator burden and the BLM burden. For both burdens, the BLM estimates the compliance or review hours and the respective wage. The compliance cost for the operator is estimated to be about $496 per application (calculated as 8 hours at about $61.99 per hour). The review cost for the BLM is estimated to be about $147 per application (calculated as 4 hours at about $36.66 per hour).
Usable Water Requirement: The operator must isolate all usable water and other mineral-bearing formations and protect them from contamination. Usable water means generally those waters containing up to 10,000 ppm of TDS. Usable water includes, but is not limited to: (i) Underground water that meets the definition of “underground source of drinking water” as defined at 40 CFR 144.3; (ii) Underground sources of drinking water under the law of the state (for Federal lands) or tribe (for Indian lands); and (iii) Water in zones designated by the state (for Federal lands) or tribe (for Indian lands) as requiring isolation or protection from hydraulic fracturing operations.
The following geologic zones are deemed not to contain usable water:
(i) Zones from which an operator is authorized to produce hydrocarbons provided that the operator has obtained all other authorizations required by the EPA, the State (for Federal lands), or the tribe (for Indian lands) to conduct hydraulic fracturing operations in the specific zone;
(ii) Zones designated as exempted aquifers under 40 CFR 144.7; and
(iii) Zones that do not meet the definition of underground source of drinking water at 40 CFR 144.3 which the state (for Federal lands) or the tribe (for Indian lands) has designated as exempt from any requirement to be isolated or protected from hydraulic fracturing operations.
Cement Monitoring Requirement: During cementing operations on any casing used to isolate usable water zones, the operator must monitor and record the flow rate, density, and pump pressure and submit a cement operation monitoring report, including this information, to the authorized officer prior to commencing hydraulic fracturing operations. For wells drilled prior to the effective date of the rule, the operator is required to provide documentation that demonstrates that the well is adequately cemented.
Surface Casing Requirements: The operator must observe cement returns to the surface and document any indications of inadequate cement (such as, but not limited to, lost returns, cement channeling, gas cut mud, failure of equipment, or fallback from the surface exceeding 10 percent of surface casing setting depth, or 200 feet, whichever is less). If there are indications of inadequate cement, then
CEL on Intermediate Casing that Protects Usable Water: If the operator does not cement the intermediate casing string to surface and the intermediate casing is used to isolate usable water, then the operator must run a CEL to demonstrate that there is at least 200 feet of adequately bonded cement between the zone to be hydraulically fractured and the deepest usable water zone.
Generally, the BLM expects that the operator would log the intermediate casing to ensure that the well was constructed according to design. Logging the casing may also be warranted if the operator plans to hang a production liner off of the intermediate casing, if the proposed fracturing is through the intermediate casing, for hole stability, for isolation through salt zones, or for isolation through disposal zones.
Some states require logging of the intermediate casing through regulation in a manner that is consistent with this rule. North Dakota requires a CBL on the intermediate casing; Colorado requires a CBL if the operator uses a production liner; and Texas specifies that the operator must identify the top of cement (with a CBL or temperature log) if it does not cement to the surface. California and Wyoming may require it in certain circumstances. Additionally, the BLM and states may require operators to log the intermediate casing as a condition of approval if, for example, any of the conditions in the previous paragraph apply. Industry guidance states that operators may run a CBL and/or other diagnostic tools to determine the adequacy of the cement integrity and that the cement reached the desired height.
The rule requires that the operator demonstrate that there is at least 200 feet of adequately bonded cement between the zone to be hydraulically fractured and the deepest usable water zone. When the operator does not circulate cement to the surface, it will most often comply with this requirement by running a CEL on the production casing (when the operator is conducting hydraulic fracturing through the production string). That process is described later. However, if the operator plans to conduct the fracturing operation through a production liner that is hung from the intermediate casing, then it must either circulate the cement behind the intermediate string to surface or run a CEL on the intermediate casing string. Although we believe that this requirement is consistent with prudent operations, the intent of the industry guidance, other state regulations, and conditions of approval that the BLM generally places on APDs where the operator uses a production liner hung from the intermediate casing, we recognize that, in some cases, the rule would compel the operator to run a CEL when it would not have done so otherwise.
The BLM does not have credible data on the prevalence of voluntary compliance or the prevalence of CEL requirements as conditions of approval. The BLM assumes that the rule will compel new action for all operations in states without existing regulations requiring a CEL of the intermediate casing. The BLM also recognizes that, as a result of this assumption, the cost estimates will be overstated.
(a) Applicability of requirement = 0 percent of operations in ND and CO; 2.5 percent in TX ; and 5 percent in other states. Based on field experience, the BLM anticipates that only about 5 percent of wells have intermediate casing to protect usable water.
(b) Incremental cost per requirement = $111,200. After the operator cements the intermediate casing, it must wait a number of hours for the cement to harden before commencing drilling operations. After that time, the operator will pressure test the casing, drill out, and perform a leak-off test. The BLM received some comments indicating that a CEL test necessitates that the cement harden for 72 hours. These comments do not take into consideration the time that the operator must wait to perform other well tests. The BLM also notes that operators generally use additives to speed up the hardening of cement behind intermediate casing. For the purpose of our analysis, the BLM considers only the additional wait time required for the CEL, accounting for 48 hours of additional time at a cost of $1,900 per hour. The cost for a CEL on the intermediate casing includes the test ($20,000) and the cost of maintaining idle drilling equipment on-site ($91,200). The BLM believes that 48 hours is the upper bound of the potential cost. In addition, the operator could potentially avoid delays in part or entirely by running the CEL at some point while drilling the production casing.
CEL on Production Casing that Protects Usable Water: If the operator does not cement the production casing string to the surface, then the operator must run a cement evaluation log to demonstrate that there is at least 200 feet of adequately-bonded cement between the zone to be hydraulically fractured and the deepest usable water zone.
Corrective Action Requirement: On all casing strings where the operator cements to the surface, the operator must document any indications of inadequate cement (such as, but not limited to, lost returns, cement channeling, gas cut mud, failure of equipment, or fallback from the surface exceeding 10 percent of surface casing setting depth or 200 feet, whichever is less). If there are indications of inadequate cement, then the operator must:
• Notify the authorized officer within 24 hours of discovering the inadequate cement;
• Submit an NOI to the authorized officer requesting approval of a plan to perform remedial action to achieve adequate cement. In emergencies or in situations of an immediate nature that may result in unnecessary delays, the operator may request oral approval from the authorized officer for actions to be undertaken to remediate the cement and follow-up with a written notice afterwards;
• Verify that the remedial action was successful with a CEL or other method approved in advance by the authorized officer; and
• Submit a subsequent report for the remedial action including a signed certification that the operator corrected the inadequate cement job in accordance with the approved plan with the results from the CEL or other approved test.
(a) Applicability of requirement = 3 percent of operations. The number of wells where there is an indication that the initial cement jobs require repairs is generally believed to be between 1 percent and 5 percent.
(b) Cost per response = $643. Burden includes the operator burden and the BLM burden. The compliance cost for the operator is estimated to be about $496 per application (calculated as 8 hours at about $61.99 per hour). The review cost for the BLM is estimated to be about $147 per application (calculated as 4 hours at about $36.66 per hour).
Mechanical Integrity Test Requirement: If hydraulic fracturing through the casing is proposed, the operator must test the casing to not less than the maximum anticipated surface pressure that will be applied during the hydraulic fracturing process. If hydraulic fracturing through a fracturing string is proposed, then the operator must test the fracturing string to not less than the maximum anticipated surface pressure minus the annulus pressure applied between the fracturing string and the production or intermediate casing.
Monitor Annulus Pressures and Reporting Requirement: During the operation, the operator must continuously monitor and record the annulus pressures at the bradenhead and between any intermediate casings and the production casing. The operator must submit a continuous record of all annuli pressure during the fracturing operation in the subsequent report. If during any hydraulic fracturing operation any annulus pressure increases by more than 500 psi as compared to the pressure immediately preceding the stimulation, the operator must take immediate corrective action and orally notify the authorized officer as soon as practical, but no later than 24 hours following the incident. Within 30 days after the hydraulic fracturing operations are completed, the operator must submit a report containing all details pertaining to the incident, including corrective actions taken, as part of a subsequent report.
Storage Tank Requirement: The operator must manage recovered fluid in “rigid enclosed, covered or netted and screened above-ground tanks.” The tanks may be vented, unless Federal law, or state regulations (on Federal lands) or tribal regulations (on Indian lands) require vapor recovery or closed-loop systems. The tanks are also limited in size to 500 bbl of capacity or less. Under certain limited circumstances, the operator may seek approval to use a lined pit with a leak detection system.
The rule prohibits the use of other larger-volume above-ground semi-rigid tanks (with a capacity of up to 40,000 bbl) for managing recovered fluids. These tanks are “semi-rigid,” because they are constructed of steel sections and assembled on-site. These tanks are rarely used for managing flowback directly and are more often used for holding fresh water before the hydraulic fracturing operation and sometimes for holding water after it has been separated and treated after hydraulic fracturing operations.
The use of rigid steel tanks to manage recovered fluids tends to vary by operator and the regions in which they operate. These tanks are particularly prevalent in the Eastern U.S. and are being incorporated into model standards for shale development.
Our observations of field operations in the Western states lend evidence to the widespread use of steel rigid tanks to manage recovered fluids from hydraulic fracturing operations in those states. Further, by examining the expected volume of recovered fluids, and the relative costs of using storage tanks versus a pit for these volumes, the BLM believes that the use of storage tanks often will cost less than pits for operations on Federal and Indian lands as discussed in more detail below.
In the supplemental proposed rule, the BLM solicited comment concerning the incremental costs of a requirement to manage recovered fluids with tanks instead of lined pits.
One commenter supported the broad use of steel tanks, but recommended that the BLM not require closed-loop systems, citing concerns about costs, the pressurization of gas, and ability to make visual inspections of the fluid, the advantage of maintaining flexibility depending on the operations or conditions, and the EPA's regulations covering emissions from storage tanks. It also supported the option of potentially using larger volume atmospheric tanks and lined impoundments (or pits), both with secondary containment and leak detection systems, for large volume hydraulic fracturing operations.
The commenter estimated the costs of steel tanks, semi-rigid tanks, and pits over a 5-year period (using a present discounted value approach and a 10 percent discount rate) for multiple operations, with a cumulative total capacity of about 250,000 bbl. It estimated the costs of an engineered impoundment to be $2.3 million, semi-rigid tanks to be $2.42 million, and steel tanks to be $23 million, all over a 5-year period (see Table 5).
In reviewing these data, it would be inappropriate to conclude simply that using steel tanks would cost 10 times more than a pit. The commenter did not specify the number of hydraulic fracturing operations that a pit, or deployment of semi-rigid tanks or rigid steel tanks, might service over the 5-year period. The BLM expects that while each method could service the same number of hydraulic fracturing operations at the same general location, pits are limited to a single geographic location, but tanks are portable and can be deployed at different geographic locations over the 5-year period, thereby servicing a larger number of operations
We also note that the transportability and severability of 500 steel tanks allow an operator to service multiple operations in different locations at the same time. For example, 500 steel tanks could service 5 large operations (of 100 steel tanks each) concurrently in different geographic locations.
The BLM received other comments about the incremental costs of requiring storage tanks. A commenter's analysis suggested a tank requirement would pose an incremental cost of $5,500 per operation or $19.6 million for the industry per year. Another commenter suggested that an open pit costs $447,000 and a closed-loop system costs $267,000 (an $180,000 cost advantage).
The BLM did not receive comments on the prevalence of voluntary compliance among operations or across operations, though the first commenter supported the broad use of storage tanks and the potential option to use larger tanks or pits. The BLM would generally expect that an operator would choose to use steel tanks voluntarily (when otherwise not compelled to do so by regulation, condition of approval, environmental consideration, or company practice) in situations where tanks would cost the same as or less than pits, and this may be largely dependent on the volume of recovered fluids expected.
The amount of water used to hydraulically fracture a well and the amount of fluid recovered from the operations vary depending on the formation and the operation itself. The BLM examined data extracted from FracFocus
The data extracted from FracFocus do not show the amount of fluid recovered from the operations. The EPA indicates that this amount may range widely from 15 percent to 80 percent of the original amount injected, depending on the site.
Figure 3 also provides the range of volumes expected to be recovered from hydraulic fracturing operations, which is estimated to range from 3,658 bbl (10 percent) to 9,754 bbl (40 percent) on average based on the data.
The BLM contacted service providers of tanks used for the management of fluids from hydraulic fracturing operations to better examine the per-operation incremental costs of using rigid steel tanks instead of a pit. We estimated the baseline cost of
In Table 2, we provide the general engineering costs for rigid steel tanks provided by service companies and then we calculate per-operation job costs based on the capacity number of potential job capacities. In addition, for each job capacity, we estimate the cost of the tank deployment for that operation and the incremental cost per operation when employed instead of a pit. Other assumptions include that the transportation to and from the site for steel tanks will take 4 hours, and that the rental period is either 14 or 21 days.
According to the available information, rigid steel tanks are less costly than pits on smaller and medium volume jobs lasting 14 days (
Given the assumptions, and for a job lasting 14 days, the point at which the cost of using tanks and the cost of using a pit are roughly equal is when the job capacity is 32,368 bbl. This means that steel tanks would cost less for jobs where the volume of recovered fluids is less than 32,368 bbl and pits would cost less for jobs where the volume of recovered fluids is greater than 32,368 bbl. For a job lasting 21 days, the point at which the cost of using tanks and the cost of using a pit are roughly equal is when the job capacity is 27,333 bbl.
The BLM derived these thresholds using the following progression:
To estimate voluntary compliance, we looked at the percent of operations (in the data extracted from FracFocus) where the job capacity (measured as the 40 percent of the water used) was less than the thresholds of 32,368 bbl and 27,333 bbl.
Where the job capacity exceeded the threshold, the BLM assumed that the operators would not have voluntarily used storage tanks. We then calculated the average job capacity for operations above this threshold based on the distribution of operations on Federal and Indian lands. We estimate that the average job capacity for operations exceeding the threshold
Based on that average job capacity, we then calculated an average incremental cost of using tanks instead of a pit for only those operations where we do not estimate that the operator will
With respect to the applicability of the requirement, we estimate that the rule will have no impact in states with existing requirements for use of tanks. We also assume that the rule will have no impact where operators are expected to voluntarily comply with the use of tanks regardless of the rule (the rates of assumed voluntary compliance are in Table 5C). We assume that for all other states, the rule will compel action on 100 percent of the operations, even though we expect that operators are already in compliance with the rule as a matter of voluntary practice.
(a) Applicability of requirement = 0 percent of operations in NM and TX based on state regulations; 0 percent in AK, CA, SD, UT, based on estimated voluntary compliance; 97.1 percent in AR, 28.3 percent in CO, 4.4 percent in KS, 69.6 percent in LA, 33.3 percent in MS, 20.4 percent in MT, 24.9 percent in ND, 100 percent in OH, 38.1 percent in OK, 92.9 percent in PA, and 7.7 percent in WY, based on estimated voluntary compliance; 100 percent in AL and NV, based on lack of validating data. We attribute the appropriate percentages to each tribe based on geographic location.
(b) Incremental cost per operation = $74,400. This incremental cost is only for those operations where the use of storage tanks is not required by state regulations and where the operator is not expected to use storage tanks voluntarily. Operations that are most likely to incur this cost are in states where 0.8% of all oil and gas activity on public lands occurs. Incremental average costs across all operations on public and Indian lands are $5,544 (see Table 6A). Under the rule, the operator may request approval to use a lined pit that is equipped with a leak detection system. While Onshore Order 7 requires leak detection systems for produced water disposal pits, which may be used on a long-term basis, there has been no requirement for leak detection systems on temporary pits until now. According to BLM engineers citing analogous EPA data, the cost of equipping a pit with a leak detection system might range from $2 to $9 per square foot, depending on the sophistication of the system (EPA 2012, Field Demonstration of Innovative Condition Assessment Technologies for Water Mains: Leak Detection and Location). Assuming 2,000 feet of piping and that a centralized pit might service 5 operations, the per-operation cost of equipping a centralized pit with a leak detection system might be between $800 and $3,600. Additional cost information for leak detection systems is available in the EPA Notice of Proposed Rulemaking for Liners and Leak Detection for Hazardous Waste and Land Disposal Units. The notice suggests that costs of a leak detection system would be about $6,100 for a half-acre pit and $6,520 for an acre pit. Again, that cost could be spread across multiple hydraulic fracturing operations and, assuming a pit services 5 completions, the per-operation cost might be $1,200 to $1,300. However, according to the
The BLM examined an alternative approach to the final rule. That alternative would have required the operator to manage recovered fluids in a lined pit, at a minimum. The requirement to manage recovered fluids in lined pits or storage tanks is consistent with almost all existing state regulations in states where new oil and gas activity is occurring on BLM-managed lands. The BLM examined regulations in nine states where new drilling activity is most prevalent on Federal lands and found that those states either have existing minimum requirements for lined pits or storage tanks or that operators use lined pits or tanks to ensure the protection of groundwater. One exception, California, does not appear to have a statewide minimum requirement for lined pits, but such requirements may be contained within rules specific to particular fields within the state. Further, according to Resources for the Future (RFF), Alabama, Arkansas, Kansas, Louisiana, Mississippi, Pennsylvania, and South Dakota also have existing pit liner requirements.
(a) Applicability of requirement (alternative) = 0 percent of operations in AL, AR, CO, KS, LA, MS, MT, ND, NM, OK, PA, SD, TX, UT, WY; 20 percent in CA; 50 percent in AK, NV, OH, and Indian lands.
(b) Incremental cost per operation (alternative) = $6,000.
Post-Fracturing Reporting Requirement: The operator must submit information to the BLM after the hydraulic fracturing operation in a subsequent report. The operator must disclose the chemicals used to the BLM, and may use FracFocus for that disclosure. The operator may withhold formulations that are deemed to be a trade secret.
(a) Applicability of requirement = 100 percent of operations.
(b) Cost per requirement = $723. Burden includes the operator burden ($558 per Subsequent Report (SR) Sundry) and the BLM burden ($165 per SR Sundry). We estimate that the operator will require 9 hours at about $61.99 per hour to comply with the SR Sundry and that the BLM will require 4.5 hours at about $36.66 per hour to review the SR Sundry. The bases for these estimates are explained in the supporting statement for the Paperwork Reduction Act.
Variance Requests: The operator may submit a variance for BLM approval.
(a) Applicability of requirement = 10 percent of operations.
(b) Cost per request = $643. Burden includes the operator burden and the BLM burden. The compliance cost for the operator is estimated to be about $496 per application (calculated as 8 hours at about $61.99 per hour). The review cost for the BLM is estimated to be about $147 per application (calculated as 4 hours at about $36.66 per hour).
The potential benefits of the rule are significant, but are more challenging to monetize than the costs; however, the rule will significantly reduce the risks associated with hydraulic fracturing operations on Federal and Indian lands, particularly risks to surface waters and usable groundwater. The operational requirements of the final rule generally conform to industry guidance on hydraulic fracturing and state regulations. The operational requirements should ensure that hydraulic fracturing is conducted in a manner than minimizes any environmental and health risks.
The use of storage tanks in lieu of pits reduces the potential risk to surface and groundwater resources. The BLM expects that through this rule, since it incorporates many of the best practices currently used by companies to manage recovered fluid, will provide environmental benefit and provide the best possible avoidance of surface and groundwater spills and contamination. Pits require careful design, construction (including fencing and netting), monitoring and reclamation. Rigid steel tanks used for recovered fluids are typically mounted on truck trailers or are transportable by truck. They require space on a well pad. However, any leaks are readily detectable without special equipment. As compared with pits, tanks better isolate recovered fluids from contamination by surface sediments that might increase the costs of recycling the fluids.
The tank requirement also specifies that where an operator uses an “enclosed” tank, the tank may be vented unless another Federal, state, or tribal law or requirement requires a closed-loop system or vapor recovery. Tanks that are not enclosed will need to be covered, netted or screened to exclude wildlife. That is not a new requirement. BLM has issued an instructional memorandum for authorized officers to assure that pits, tanks, and similar structures are fully enclosed in netting or screens to exclude wildlife. This requirement helps prevent accidental
The primary challenge in monetizing benefits lies in the quantification of a baseline risk associated with specific operating practices and in the measurement of the change in that risk that the BLM can attribute to the rule's requirements. For example, the risk of spills associated with the use of pits versus the risk of spills associated with the use of storage tanks is unknown, though it is generally recognized that tanks carry less risk onsite. In an initial analysis for the proposed rule, we attempted to value the reduction in risk, but we do not believe that the available information represented modern hydraulic fracturing operations nor were we able to distinguish between the risks posed by wells that were hydraulically fractured and wells with conventional completion techniques.
Operators are required to notify the BLM when undesirable events occur, but there are limitations in using the BLM data on undesirable events for this analysis. Undesirable events may include accidents, or accidental spills or releases of hydrocarbon fluids, produced water, hydraulic fracturing flowback fluids, or other substances. Undesirable events also include “frack hits,” which are unplanned surges of pressurized fluids into other wells. These events have the potential to adversely affect public lands, Indian lands, and other important resources.
There are several limitations in using these data. First, the data do not specify whether the undesirable events occur in conjunction with or as a result of hydraulic fracturing operations. In addition, the available data cannot be readily matched with particular provisions in the rule. The data provide figures for the incidence of spills, accidents, injuries, and other impacts on a well, but the pit liner information is generally not specified in the incident reports for spills or leaks. As such, there is difficulty in quantifying the level of risk reduction that would be attributed to the regulations, even though the regulations would most certainly reduce risk.
Although operators are required to remediate damage when it occurs, there may be uncertainty about the true value or extent of any potential damage or limitations in connecting an incident to an operation. Even if the damage is internalized, and as long as the compliance costs are less than the damage costs, the net benefit to society would be less than if the incident was avoided, since resources would have been unnecessarily dedicated to the remediation.
Damage, in general, is unknown, particularly when attempting to generalize damage costs which may vary by expected magnitude and reversibility of effects. Also, the valuation of the damage may also take many and highly variable forms. For example, an undesirable incident occurring during hydraulic fracturing might require the remediation of surface or subsurface areas. The incident might also require that the operator shut-in temporarily or plug the well before it may produce all of the mineral resources. In this case, the operator would lose revenue and society would not benefit from the produced resources. Such would be the same for spills.
The following is an example of an event that occurred in 2012 when a hydraulic fracturing operation on one Federal well affected another Federal well. The incident occurred on November 20, 2012, in Lea County, New Mexico.
In order to control the event, the fracturing job had to be shut in. The active wells in the area were also shut in. The surface damage included less than 0.1 acre of pasture land, and the removal and disposal of the material inside the two firewalls. Vacuum trucks picked up all of the standing fluids. The impacted surface material was removed for sampling, site delineation, and remediation.
This “frack hit” incident illustrates the difficulty in estimating benefits. The environmental damage included potential surface contamination and subsequent remediation efforts, and most of the environmental damage appears to have been remediated by the operator. Aside from the environmental damage, there were several economic impacts, including the shutting-in of the impacted wells for a period of time, wellbore damage to the second wells, potentially lost fracturing stages, and unrecovered resources.
Since relative risk is unknown, the BLM provides a qualitative discussion of benefits. Field experience tells us that the remediation of a minor incident, such as the surface remediation after a minor spill, might cost about $15,000 and range upwards. Remediation efforts of larger spills are much more complicated and can reach the hundreds of thousands of dollars. The remediation of a major incident will likely be more complex. As with the example incident, there were surface, possible subsurface impacts to multiple wells, and potentially stranded resources (from lost fracturing stages of permanent plugging of wells). The Federal Remediation Technologies Roundtable makes a number of case studies available on its Web site (though none are hydraulic fracturing incidents) concerning contamination to aquifers where the remediation costs may be $1 million.
There is a time dimension to estimates of potential costs and benefits. While the incremental costs of the rule are likely to occur within a comparatively short period of time, the incremental benefits may continue into the future. The further in the future that the benefits and costs are expected to occur, the smaller the present value associated with the stream of costs and benefits.
For this analysis, we expect that the potential incremental costs posed to an operation will occur within a short timeframe, starting generally with the APD submission and ending with the subsequent report. As such, we generally use undiscounted costs for the requirements. However, in order to determine the incremental cost of the storage tank requirement, we adjusted the 5-year data provided by a commenter to annualize the costs of constructing and operating a pit based on the net present value of costs using a 7 percent discount rate.
The costs and benefits provided in this analysis are estimates and come with uncertainty. Generally, the primary sources of uncertainty are:
• Number of hydraulic fracturing operations on Federal and Indian lands occurring in the future. The economic analysis describes the method the BLM used to estimate operations that will occur in the future. The BLM also considers an upper bound estimate which should constrain the costs.
• Delays and costs associated with the CEL on the intermediate casing. Sources of uncertainty are: (1) The prevalence by which the operator will run a log on the intermediate casing as a matter of practice; and (2) The ways in which operators may run logs on the intermediate casing while avoiding delays.
• Storage tank costs. The BLM estimated voluntary compliance based on the average volume of recovered fluids and a number of cost assumptions, including the per-operation cost of a pit. In some areas, field observations indicate that the use of storage tanks is higher than the estimated voluntary compliance. As such, we believe the compliance costs of this requirement are still likely to be overestimated.
• Benefits of specific provisions. The BLM is unable to estimate the incremental benefits of the rule because the BLM is unable to ascribe incremental benefits to the particular provisions of the rule. Nonetheless, the rule's provisions are generally consistent with best management practices of the industry at large and of several firms within the industry.
The BLM estimates that the rule will impact 2,814 hydraulic fracturing operations per year in the near-term on Federal and Indian lands. The BLM estimates that the incremental cost of the rule on Federal and Indian lands will be about $26 million per year. These estimates are based on expectations about the future well completions on Federal and Indian lands. In order to meet a $100 million per year threshold, we estimate that the number of hydraulic fracturing operations on Federal and Indian lands would have to be about 3.83 times higher than we anticipate, or over 10,775 operations per year.
The estimated per-operation compliance costs of about $11,400 represent about 0.13 to 0.21 percent of the cost of drilling a well. The compliance costs, shown in Table 6A, were developed by dividing the total costs of the rule by the number of hydraulic fracturing operations expected to occur, per year. Because we believe that operators would have undertaken some of the rule's requirements voluntarily or as a result of state requirements, we expect that some of the compliance costs will be borne by a relatively small number of operations. This is particularly the case with respect to the requirement to use rigid above-ground tanks, which we estimate to be less costly than lined pits for operations with recovered fluids below a certain volume. In those cases where fluid volumes exceed a certain threshold, we estimate that the compliance with the storage tank requirement could cost an operator $74,400 (representing approximately 0.8 to 1.4 percent of the cost of drilling a well) Through our analysis we estimate that this is only a small subset of total operations. These operations are those where the volumes of recovered fluids are expected to be very high and typically occur in states (Arkansas, Louisiana, Mississippi, Ohio, Oklahoma, and Pennsylvania) which represent only about 0.8% of estimated hydraulic fracturing activities on Federal and Indian land (from FY 2010 to FY 2013).
The costs of drilling a well may vary by reservoir or formation, depth, and length, site-specific characteristics, as well as operator efficiencies. The Energy Information Administration suggests costs of about $5.4 million which we believe may be a lower bound estimate of the costs for drilling a well to be completed with hydraulic fracturing. The EIA figures were last updated in 2007, were not specific to horizontal wells or hydraulically fractured wells, and included costs of drilling exploratory or development wells. We adjusted the EIA figures to 2015 dollars. Meanwhile, horizontal wells drilled in the Bakken formation have been reported to cost $5.6 million (cited by Investopedia from Continental Resources in 2010) and, most recently, between $7-9 million per well (cited from various companies in industry trade journal Oil Patch Hotline 2015).
As discussed in the Economic Analysis, well completions decreased on Federal lands from FY 2012 to FY 2013, but increased steadily on Indian lands on an annual basis since FY 2010. If the FY 2012 level of activity on Federal lands is used as a basis for the estimate, the rule could potentially impact up to 3,775 hydraulic fracturing operations per year on Federal and Indian lands at an incremental cost of about $45 million per year.
Many of the rule's requirements are consistent with industry guidance and some are required by existing BLM regulations and state regulations. Accordingly, to the extent that industry is already in voluntary compliance, the cost of several provisions may be overestimated. Where the rule's requirements are consistent with industry practice or state regulations, there will not be an incremental cost. There are two requirements in particular that are likely to pose the bulk of the estimated costs.
First, the rule requires the operator to run a CEL on the intermediate casing if that casing string protects usable water and if the operator chooses not to cement the casing to the surface. Industry guidance suggests that an operator may run a cement bond log on the intermediate casing to show that the casing was cemented to the design. The BLM believes that operators will generally run logs on the intermediate casing, particularly if they plan to conduct hydraulic fracturing through a production liner that is hung from the intermediate casing, and that states or the BLM may specify this as a condition of approval, even if it is not in regulation. Since the BLM does not have validating data, the analysis assumes that the rule would compel CELs in all areas, except those states that require them in regulation. As such, the costs associated with this requirement are likely overstated.
Second, the rule requires the operator to manage recovered fluids in storage tanks. Industry guidance suggests that operators may use storage tanks or pits to manage recovered fluids. Some states require the use of tanks by regulation and some states have adopted the practice as a policy through guidance or as a standard condition of approval for drilling operations. Our observations of field operations indicate that operators almost always use storage tanks, which indicates that they may be doing so voluntarily. The BLM estimated the voluntary use of storage tanks in states that do not have regulations requiring their use. Still, in some areas, our field observations indicate that the use of storage tanks is higher than the estimated voluntary compliance. As such, the costs associated with this requirement are also likely overstated.
On Federal lands only, the BLM estimates that the final rule would impact 2,144 hydraulic fracturing operations per year in the near-term future and that the rule poses an incremental cost of about $22 million per year. The rule could potentially impact up to 3,105 operations per year on Federal lands at an incremental cost of about $35 million per year.
Tables 3A and 3B depict the annual incremental costs associated with the rule's requirements, attributed to operations on Federal lands within a state. It accounts for consistencies between a state's requirements and the rule's requirements.
On Indian lands, the BLM estimates that the final rule would impact 670 hydraulic fracturing operations per year in the near-term future and that the rule poses an incremental cost of about $10 million per year. The estimate accounts for the steady increase in activity on Indian lands over the past few years.
Table 4 depicts the annual incremental costs associated with the rule's requirements, attributed to operations on Indian lands within a reservation. The highest total costs are associated with operations in the Fort Berthold, Uintah and Ouray, and Jicarilla Apache reservations, due to the volume of activity within those reservations.
Tables 5A and 5B show the incremental costs by requirement for operations on Federal and Indian lands. The BLM estimates that the largest incremental costs are associated with the operational requirements for a CEL on certain intermediate casing and storage tanks to manage recovered fluids. As mentioned previously, the BLM does not have specific data about the prevalence of voluntary compliance with these requirements irrespective of the rule. Accordingly, these estimates are may be overstated. The BLM estimates that the CEL requirement will impact a fraction of the operations, but could cost operators $12.4 million annually (and potentially up to $16.3 million). The BLM also estimates that the incremental annual cost of requiring storage tanks (instead of allowing pits) could cost operators about $15.6 million (and potentially up to $23.7 million).
The rule would result in compliance costs of about $11,400 per hydraulic fracturing operation. Average compliance costs to meet the requirements for a CEL on certain intermediate casing and for storage tanks represent the bulk of the per-operation compliance costs. The results are in Tables 6A and 6B.
Of the estimated per-operation compliance costs, the administrative burden represents about $1,450. The BLM estimates that the operator will assume about $1,118 and the BLM will assume $331 of that amount. The administrative burden figures are in Tables 7A and 7B.
The review of information associated with the application, subsequent report, remedial action report (when applicable), and variance request (when applicable) will pose an additional workload to the BLM of about 25,400 hours per year. That additional burden represents about 12.20 full-time equivalent (FTE) of workload or, as a practical matter, about 13.80 staffed positions (takes into account leave and holidays).
Executive Order 13211 requires that agencies prepare and submit to the Administrator of the Office of Information and Regulatory Affairs (OIRA), OMB, a Statement of Energy Effects for certain actions identified as significant energy actions. Section 4(b) of Executive Order 13211 defines a “significant energy action” as “any action by an agency (normally published in the
A key consideration is the extent to which the costs of the requirements might impact investment, production, employment, and a number of other factors. That is, to what extent, if any, would an operator choose to invest in other areas, non-Federal and non-Indian lands, when faced with the cost requirements of the rule. Since the bulk of the costs of this rule would apply to hydraulic fracturing operations on wells that are yet to be drilled (and not on existing wells and to refracturing operations), operators will be able to account for any cost increases up front when making investment decisions.
The BLM believes that the additional cost per hydraulic fracturing operation is insignificant when compared with the drilling costs in recent years, the production gains from hydraulically fractured well operations, and the net incomes of entities within the oil and natural gas industries.
For the average hydraulic fracturing operation, the compliance costs represent about 0.13 to 0.21 percent of the cost of drilling a well. Since the estimated compliance costs are not substantial when compared with the total costs of drilling a well, the BLM believes that the rule is unlikely to have an effect on the investment decisions of firms, and the rule is unlikely to affect the supply, distribution, or use of energy.
Executive Order 13563 reaffirms the principles established in Executive Order 12866, but calls for additional consideration of the regulatory impact on employment. It states, “Our regulatory system must protect public health, welfare, safety, and our environment while promoting economic growth, innovation, competitiveness,
This final rule requires operators, who have not already done so, to conduct one-time tests on a well or make a one-time installation of a mitigation feature. In addition, operators are required to perform administrative tasks related to a one-time event.
Compliance with a few of the operational requirements is expected to pose an additional cost to the operator and is likely to shift resources from firms in the crude oil and natural gas extraction industries (NAICS codes: 211111—Crude Petroleum and Natural Gas Extraction, 211112—Natural Gas Liquid Extraction) to firms providing support services for drilling oil and gas wells (NAICS code: 213111—Drilling Oil and Gas Wells).
Of principal interest is the extent to which the financial burden is expected to change operators' investment decisions. If the financial burden is not significant and all other factors are equal, then one would expect operators to maintain existing levels of investment and employment. The BLM believes that the rule would result in an additional cost per well hydraulic fracturing operation that is small and will not alter the investment or employment decisions of firms.
The Regulatory Flexibility Act as amended by the Small Business Regulatory Enforcement Fairness Act (SBREFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act if a rule would have a significant economic impact, either detrimental or beneficial, on a substantial number of small entities. See 5 U.S.C. 601-612. Congress enacted the RFA to ensure that Government regulations do not unnecessarily or disproportionately burden small entities. Small entities include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.
The BLM reviewed the Small Business Administration (SBA) size standards for small businesses and the number of entities fitting those size standards as reported by the U.S. Census Bureau in the 2007 Economic Census. Using the Economic Census data, the BLM concludes that about 99 percent of the entities operating in the relevant sectors
Small entities represent the overwhelming majority of entities operating in the onshore crude oil and natural gas extraction industry. As such, the rule is likely to affect a significant number of small entities. To examine the economic impact of the rule on small entities, the BLM performed a screening analysis for impacts on a sample of expected affected small entities by comparing compliance costs to entity net incomes.
The firms most likely to be affected by the rule are those conducting hydraulic fracturing activities on Federal and Indian lands. More specifically, the firms most impacted are expected to be those drilling new wells for hydraulic fracture completions. The BLM compiled a list of firms that completed wells according to AFMSS. The BLM expects that these firms are most likely to be impacted by the rule. From that list, the BLM researched for company annual report filings with the Securities and Exchange Commission (SEC) to determine annual company net incomes and employment figures. From the original list, the BLM found 55 company filings. Of those, 33 were small businesses. For the purposes of this analysis, the BLM assumes that all entities (all lessees and operators) that may be affected by this rule are small entities, even though that is not actually the case.
Using the net income data for the small businesses that filed SEC Form 10-K, the BLM used the estimated compliance costs per hydraulic fracturing operation to calculate the percent of compliance costs as a portion of annual company net incomes for 2011. The BLM used the absolute values of the percentages in the average, so that the negative net incomes would not negate the positive net incomes, and vice versa. Averaging results for the small businesses that the BLM examined, the average costs of the rule are expected to represent about 0.15 percent of the company net incomes. The results of those findings are in Table 8.
The rule deals with hydraulic fracturing on all Federal and Indian lands (except those excluded by statute). Please see the discussion earlier in this preamble for the discussion of the need for, and objectives of the rule and a discussion of the impacts of the rule. The BLM received many comments on the economic impacts of the supplemental proposed rule, as discussed elsewhere in this preamble.
There would be some increased costs associated with the enhanced recordkeeping requirements and some new operational requirements. Specifically, there will be increased costs for operators to manage recovered
The BLM has taken steps to reduce costs on small entities by not promulgating a general requirement to run a CEL on surface casings, by allowing submission of chemical data through FracFocus, by providing for submission of a request for approval for hydraulic fracturing in a master hydraulic fracturing plan, by clarifying that isolating and protecting usable water means 200 feet of competent cement between the fractured zone and the usable water zone, by clarifying that modeling of fissure propagation is not required, and by allowing for both operation-specific and state or tribal variances. Therefore, the BLM has determined that the rule would not have a significant economic impact on a substantial number of small entities.
Also, based on the available information, the BLM estimates the annual effect on the economy of the regulatory changes will be less than $100 million. This rule will not create a major increase in costs or prices for consumers, individual industries, Federal, state, or local government agencies, or geographic regions. In addition, this regulation will not have any significant adverse effects on competition, employment, investment, productivity, innovation, or on the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and export markets.
In accordance with the criteria in Executive Order 12866, the Office of Management and Budget has determined that this rule is a significant regulatory action.
The rule will not have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities. However, the rule may raise novel policy issues because of the requirement that operators provide to the BLM information regarding hydraulic fracturing operations that they are not currently providing to the BLM.
This rule would not create inconsistencies or otherwise interfere with an action taken or planned by another agency. This rule would not change the relationships of oil and gas operations with other agencies. These relationships are included in agreements and memoranda of understanding that would not change with this rule. In addition, this rule would not materially affect the budgetary impact of entitlements, grants, loan programs, or the rights and obligations of their recipients. Please see the discussion of the impacts of the rule described earlier in this section of the preamble.
Under the Unfunded Mandates Act, agencies must prepare a written statement about benefits and costs prior to issuing a proposed or final rule that may result in aggregate expenditure by state, local, and tribal governments, or by the private sector, of $100 million or more in any one year.
This rule does not contain a Federal mandate that may result in expenditures of $100 million or more for state, local, and tribal governments, in the aggregate, or to the private sector in any one year. Thus, the rule is also not subject to the requirements of Sections 202 or 205 of the Unfunded Mandates Reform Act (UMRA).
This rule is also not subject to the requirements of Section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments; it contains no requirements that apply to such governments nor does it impose obligations upon them.
Under Executive Order 12630, the rule will not have significant takings implications. A takings implication assessment is not required. This rule establishes recordkeeping requirements for hydraulic fracturing operations and some additional operational requirements on Federal and Indian lands. All such operations are subject to lease terms which expressly require that subsequent lease activities be conducted in compliance with subsequently adopted Federal laws and regulations. The rule conforms to the terms of those Federal leases and applicable statutes and as such the rule is not a governmental action capable of interfering with constitutionally protected property rights. Therefore, the rule will not cause a taking of private property or require further discussion of takings implications under this Executive Order.
Under Executive Order 13352, the BLM has determined that this rule will not impede facilitating cooperative conservation and takes appropriate account of and consider the interests of persons with ownership or other legally recognized interests in land or other natural resources. The rulemaking process involved Federal, state, local, and tribal governments, private for-profit and nonprofit institutions, other nongovernmental entities and individuals in the decision-making. The process provides that the programs, projects, and activities are consistent with protecting public health and safety.
Under Executive Order 13132, this rule will not have significant Federalism effects. A Federalism assessment is not required because the rule will not have 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. The rule will not have any effect on any of the items listed. The rule affects the relationship between operators, lessees, and the BLM, but it does not impact states. Therefore, under Executive Order 13132, the BLM has determined that this rule will not have sufficient Federalism implications to warrant preparation of a Federalism Assessment.
Under Executive Order 13175, the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951), The Department of the Interior Policy on Consultation with Indian Tribes (Dec. 1, 2011), and 512 Departmental Manual 2, the BLM evaluated possible effects of the rule on federally recognized Indian tribes. The BLM approves proposed operations on all Indian onshore oil and gas leases (except those excluded by statute). Therefore, the rule has the potential to affect Indian tribes. In conformance with the Department's policy on tribal consultation, the Bureau of Land Management held four tribal consultation meetings to which over 175 tribal entities were invited. The consultations were held in four cities in January 2012.
The purpose of those meetings was to solicit initial feedback and preliminary comments from the tribes. To date, the tribes have expressed concerns about the BLM's Inspection and Enforcement program's ability to enforce the terms of this rule; previously plugged and abandoned wells being potential conduits for contamination of groundwater; and the operator having to provide documentation that the water used for the fracturing operation was legally acquired. The BLM considered these concerns during the drafting of the final rule.
After publication of the proposed rule, the BLM held another series of meetings to obtain comments and recommendations from tribes and tribal organizations. Those meetings were held in June 2012 in Utah, New Mexico, Oklahoma, and Montana. The BLM also engaged in one-on-one consultations as requested by several tribes. Some tribal representatives were concerned about risks to the quality of their vital water supplies. Others, though, were more concerned with the risk that increased compliance costs would drive the industry off of Indian lands, and deprive the tribes of much-needed revenues and economic development.
After publication of the supplemental proposed rule, the BLM again held regional meetings with tribes in Farmington, New Mexico, and Dickinson, North Dakota, in June 2013. Representatives from six tribes attended. The discussions included a variety of tribal-specific and general issues. The BLM again offered to follow up with one-on-one consultations, and several such meetings were held with individual tribes. Several tribes, tribal members, and associations of tribes provided comments on the supplemental proposed rule.
In March 2014, the BLM invited tribes to participate in another meeting in Denver, Colorado. Representatives from seven tribes attended. There was significant discussion of issues raised in the comments on the supplemental proposed rule. The BLM subsequently held several consultations with individual tribes.
The BLM understands the importance of tribal sovereignty and self-determination, and seeks to continuously improve its communications and government-to-government relations with tribes.
The BLM has considered and responded to the concerns expressed by the tribal representatives both orally and in written comments, as described previously. In particular, it has made changes that will reduce economic burdens of compliance for many operators.
Several tribes provided written and oral comments critical of the proposed rule. Other tribes said that the rules violated tribal sovereignty. The final rule, however, is not unique. Regulations promulgated by the Bureau of Indian Affairs render the BLM's operating regulations in 43 CFR part 3160 applicable to oil and gas leases of trust and restricted Indian lands, both tribal and individually owned. See 25 CFR 211.4, 212.4, and 225.4.
Some tribes insist that those BIA regulations are in violation of the FLPMA, which they said restricts the BLM's authority to Federal lands. Section 301 of the FLPMA, however, charges the Director of the BLM to carry out functions and duties as the Secretary may prescribe with respect to the lands and the resources under the Secretary's jurisdiction according to the applicable provisions of the FLPMA and any other applicable law. 43 U.S.C. 1731(a). See also 43 U.S.C. 1731(b). The Act of March 3,1909 (1909 Act) (at 25 U.S.C. 396), the Indian Minerals Leasing Act (IMLA) (at 25 U.S.C. 396d) and the Indian Mineral Development Act (IMDA) (at 25 U.S.C. 2107) provide the Secretary of the Interior with authority to promulgate regulations governing oil and gas operations and mineral agreements on certain Indian lands. As previously cited, the Secretary, through delegations in the Departmental Manual as reflected in the regulations promulgated by the BIA, has assigned to the BLM part of the Secretary's trust responsibilities to regulate oil and gas operations on those Indian lands. This rule concerning Indian lands is promulgated pursuant to the 1909 Act, the IMLA, and the IMDA, and will be implemented by the BLM under those authorities, consistent with Section 301 of the FLPMA.
Some tribes have asked that the final rule exempt Indian lands from its scope. Such an exemption would require the Secretary of the Interior to conclude, among other things, that usable waters in Indian lands, and the persons who use such waters, are less deserving of protection than waters and water users on Federal land. The Department of the Interior declines to reach that conclusion.
Some tribes have advocated that the rule should allow Indian tribes to decide individually whether the hydraulic fracturing regulations would apply on their lands. The BIA's regulations, however, apply to all of the BLM's oil and gas operating regulations on Indian lands, and do not allow the tribes to pick and select which of the BLM's regulations apply on their lands.
The tribes, however, report that industry representatives have threatened not to bid on Indian leases if the proposed rules were promulgated. The tribes are concerned that a major source of revenue and of economic development might leave Indian lands because of the costs of compliance with the rule. The BLM has carefully considered the tribes' comments, along with those of the oil and gas industry and of concerned citizens and governments. The final rule includes several changes from the initial proposed rules to reduce the costs and other burdens of compliance. Examples include not requiring a CEL on surface casings absent an indication of a cementing problem, allowing operators to use any one of a class of CELs to verify the adequacy of cement casings and not requiring the CEL to be approved before fracturing operations if there is no indication of problems with the cementing. The final rule also explicitly states that the BLM will require isolation of zones that the tribes designate for protection from oil and gas operations, and will not require isolation of zones that tribes have exempted from protection. (Note, though, that the final rule would not exempt an operator from the provisions of the SDWA.) Furthermore, the BLM could approve a variance from certain provisions of the rule applicable to all or parts of Indian lands, provided the relevant tribal rule meets or exceeds the effectiveness of BLM's rule. Such a variance could allow an operator's compliance with a tribe's standard or procedure to be accepted as compliance with the revised proposed rule, thus
The BLM is aware that the final rule could nonetheless result in some higher costs for operators on Federal and Indian lands, compared with compliance costs for hydraulic fracturing on non-Federal, non-Indian lands in some states with no regulations or less protective regulations. Regulatory compliance costs, however, are only one category in a long list of costs that operators compare to anticipated revenues when deciding whether and how much to bid on a Federal or Indian lease. The costs of this rule are estimated to be only 0.13 to 0.21 percent of the cost of drilling a well. It has not been the BLM's experience that regulatory compliance costs have caused the industry to avoid valuable oil and gas resources on Federal and Indian lands.
Under Executive Order 12988, the Office of the Solicitor has determined that this rule will not unduly burden the judicial system and meets the requirements of Sections 3(a) and 3(b)(2) of the Order. The Office of the Solicitor has reviewed the rule to eliminate drafting errors and ambiguity. It has been written to minimize litigation, to provide clear legal standards for affected conduct rather than general standards, and to promote simplification and avoid unnecessary burdens.
The Paperwork Reduction Act (44 U.S.C. 3501-3521) provides that an agency may not conduct or sponsor, and a person is not required to respond to, a “collection of information,” unless it displays a currently valid OMB control number. Collections of information include requests and requirements that an individual, partnership, or corporation obtain information, and report it to a Federal agency (44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
The BLM included a request for approval of a collection of information in both the proposed rule and the supplemental proposed rule. OMB approved the collection for the final rule under control number 1004-0203.
Compliance with this collection of information will be required to obtain or retain a benefit for the operators of Federal and Indian (except on the Osage Reservation, the Crow Reservation, and certain other areas) onshore oil and gas leases, units, or communitization agreements that include Federal leases. After the effective date of the final rule, the BLM plans to request that OMB merge control number 1004-0203 with control number 1004-0137, “Onshore Oil and Gas Operations,” (expiration date: January 31, 2018).
The following activities comprise the information collection for the final rule.
• The final rule removes the distinction in existing 43 CFR 3162.3-2 between “routine” and “non-routine” fracturing jobs, and requires in section 3162.3-3(a) that operators propose and seek prior BLM approval for all hydraulic fracturing jobs except for three instances in which a well is drilled shortly before or after the effective date of the rule, and is hydraulically fractured within 90 days after the effective date of the rule. However, all other applicable provisions of the rule must be adhered to, including 3162.3-3(e), relating to monitoring and verification of cementing operations prior to hydraulic fracturing.
Section 3162.3-3(c) provides that a request to commence hydraulic fracturing may be submitted either on Form 3160-5 as a “Notice of Intent (NOI) Sundry” or as part of Form 3160-3, Application for Permit to Drill (APD), both of which are authorized by control number 1004-0137. The BLM will use the following-described information to determine whether or not to grant prior approval for hydraulic fracturing jobs.
Section 3162.3-3(d)(6) lists two requirements that apply only if an operator requests prior approval for hydraulic fracturing in an NOI after drilling and completing a well. The first requirement (at paragraph (d)(6)(i)) is a surface use plan of operations if the hydraulic fracturing operation would include surface disturbance. The second requirement (at paragraph (d)(6)(ii)) is documentation that adequate cementing was achieved for all casing strings designed to isolate usable water zones. These requirements are included in the collection activity labeled “Request for Prior Approval of Hydraulic Fracturing Job Using a Notice of Intent Sundry Plus a Surface Use Plan of Operations Plus Documentation of Adequate Cementing.”
While the well completion report (Form 3160-4) that is approved under control number 1004-0137 requires some information about cementing, the second requirement in paragraph (d)(6)(ii) is not duplicative. The well-completion report requires the operator to disclose the number of sacks and type of cement, the slurry volume, the cement trop, and any cement squeeze information. The information we are requiring in paragraph (d)(6)(ii) is actual monitoring information from when the cementing operations took place, for example, pump pressures, cement density, and observations during the cement job. We anticipate that typically, an operator will comply with paragraph (d)(6)(ii) by providing us with information recorded on a service company's “job ticket.”
Section 3162.3-3(e)(1) lists two requirements that apply only if an operator requests prior approval for hydraulic fracturing in an Application for Permit to Drill before drilling and completing a well. This provision requires operators to submit a cement operation monitoring report to the BLM before commencing hydraulic fracturing operations. The required elements of a cement operation monitoring report are (1) The flow rate, density, and pump pressure during pre-fracturing cementing operations on any casing used to isolate usable water zones; and (2) A determination of adequate cement for all casing strings that are used to isolate usable water zones. These requirements are included in the collection activity labeled, “Request for Prior Approval of Hydraulic Fracturing Job Using an Application for Permit to Drill Plus a Cement Operation Monitoring Report.”
Unlike the supplemental proposed rule, the final rule does not require the operator to identify a “type well” as part of a request for prior approval for a group of wells. Instead, section 3162.3-3(c)(3) of the final rule provides for the submission of an MHFP. The differences between the “type well” requirement and the requirement for an MHFP are described in the preamble discussion of 43 CFR 3160.0-5 (“Definitions”). This discussion clarifies that the MHFP for a group of wells is only for initial planning purposes and that operators must submit all required information for each well and get approval for each well before drilling.
Section 3162.3-3(e)(3) requires an operator to notify the BLM within 24 hours of discovering inadequate cement on any casing used to isolate usable water and submit an NOI to the BLM requesting approval of a plan to perform remedial action. The BLM will use this collection activity to determine the adequacy of the proposed remedial action. At least 72 hours before starting hydraulic fracturing operations, operators must submit a subsequent report for the remedial action, which would include a signed certification that
Section 3162.3-3(i) lists information that must be provided to the BLM within 30 days after the completion of the last stage of hydraulic fracturing operations. We have revised the information that is required. The information is required for each well, even if the authorized officer approved fracturing of a group of wells.
The final rule lists the following requirements for a subsequent report:
(1) The true vertical depth of the well, total water volume used, and a description of the base fluid and each additive in the hydraulic fracturing fluid, including the trade name, supplier, purpose, ingredients, Chemical Abstract Service Number (CAS), maximum ingredient concentration in additive (percent by mass), and maximum ingredient concentration in hydraulic fracturing fluid (percent by mass). This information must be submitted to the authorized officer through FracFocus, another BLM-designated database, or in a subsequent report. If information is submitted through FracFocus or another BLM-designated database, the operator must specify that the information is for a Federal or an Indian well, certify that the information is correct, and certify compliance with applicable law;
(2) The actual source(s) and location(s) of the water used in the hydraulic fracturing fluid;
(3) The maximum surface pressure and rate at the end of each stage of the hydraulic fracturing operation and the actual flush volume;
(4) The actual, estimated, or calculated fracture length, height and direction;
(5) The actual measured depth of perforations or the open-hole interval;
(6) The total volume of fluid recovered between the completion of the last stage of hydraulic fracturing operations and when the operator starts to report water produced from the well to ONRR. If the operator has not begun to report produced water to ONRR when the subsequent report is submitted, the operator must submit a supplemental subsequent report to the authorized officer documenting the total volume of recovered fluid;
(7) The following information concerning the handling of fluids recovered covering the period between the commencement of hydraulic fracturing and the implementation of the approved plan for the disposal of produced water under BLM regulations (currently in Onshore Order 7):
(i) The methods of handling the recovered fluids, including, but not limited to, transfer pipes and tankers, holding pond use, re-use for other stimulation activities, or injection; and
(ii) The disposal method of the recovered fluids, including, but not limited to, the percent injected, the percent stored at an off-lease disposal facility, and the percent recycled;
(8) A certification signed by the operator that:
(i) The operator complied with the requirements in 43 CFR 3162.3-3(b), (e), (f), (g), and (h);
(ii) For Federal lands, the hydraulic fracturing fluid constituents, once they arrived on the lease, complied with all applicable permitting and notice requirements as well as all applicable Federal, state, and local laws, rules, and regulations; and
(iii) For Indian lands, the hydraulic fracturing fluid constituents, once they arrived on the lease, complied with all applicable permitting and notice requirements as well as all applicable Federal and tribal laws, rules, and regulations;
(9) The operator must submit the result of the mechanical integrity test as required by 43 CFR 3162.3-3(f); and
(10) The BLM may require the operator to provide documentation substantiating any of the information listed previously.
The information required in paragraphs (2) though (10), previously, must be submitted to the authorized officer in a subsequent report. This information will enable the BLM to have a complete record of the hydraulic fracturing job.
Section 3162.3-3(j) describes how an operator, or the operator and the owner of the information, may support a claim to be exempt from public disclosure of information otherwise required in the subsequent report. If required information is withheld, the regulation requires submission with the subsequent report of an affidavit that:
• Identifies the owner of the withheld information and provides the name, address and contact information for an authorized representative of the owner;
• Identifies the Federal statute or regulation that would prohibit the BLM from publicly disclosing the information if it were in the BLM's possession;
• Affirms that the operator has been provided the withheld information from the owner of the information and is maintaining records of the withheld information, or that the operator has access and will maintain access to the information held by the owner of the information;
• Affirms that the information is not publicly available;
• Affirms that the information is not required to be publicly disclosed under any applicable local, state, or Federal law (on Federal lands), or tribal or Federal law (on Indian lands);
• Affirms that the owner of the information is in actual competition and identifies competitors or others that could use the withheld information to cause the owner substantial competitive harm;
• Affirms that the release of the information would likely cause substantial competitive harm to the owner and provides the factual basis for that affirmation; and
• Affirms that the information is not readily apparent through reverse engineering with publicly available information.
In addition, if the operator relies upon information from third parties, such as the owner of the withheld information, to make the previous affirmations, the operator must provide a written affidavit from the third party that sets forth the relied-upon information. The BLM will use the information to determine whether to grant an exemption from public disclosure of information that otherwise would be required in a subsequent report.
Section 3162.3-3(j)(5) requires the operator to maintain records of any withheld information until the later of the BLM's approval of a final abandonment notice, or 6 years from the completion of hydraulic fracturing operations on Indian lands, or 7 years from the completion of hydraulic fracturing operations on Federal lands, consistent with applicable law. Any subsequent operator will be responsible for maintaining access to records of any withheld information during its operation of the well. The operator will be deemed to be maintaining the records if it can promptly provide the complete and accurate information to the BLM, even if the information is in the custody of its owner. This provision enables the BLM to have access to records of injected chemicals during the life of the well, while protecting trade secrets.
Section 3162.3-3(j)(6) provides that if any of the chemical identity information is withheld, the operator must provide the generic chemical name in the subsequent report.
Section 3162.3-3(k) provides that a decision on a variance request is not
The Paperwork Reduction Act requires each Federal agency to certify that its collections of information are necessary for the proper performance of agency functions, and are not unnecessarily duplicative of information otherwise reasonably accessible to the agency. 43 U.S.C. 3506(c)(3)(A) and (B). We received many comments on the proposed rule with respect to this standard, and we responded to them in the supplemental proposed rule. In addition, we received the following comments on the supplemental proposed rule with respect to this standard.
We did revise section 3162.3-3(i)(9) (paragraph (i)(8) of the supplemental proposed rule) in response to comments saying that the proposed requirement to submit well logs and records of adequate cement duplicates a requirement in the well completion report. However, we made no changes to section 3162.3-3(i) in response to other comments saying that the information required in the subsequent report duplicates information that is required in the well completion report. Examples of data that are required in the subsequent report, but not in the well completion report, include the cement operations monitoring report, the results of the MIT, and the operator certification that it complied with the paragraphs in the rule that assure wellbore integrity was maintained prior to and throughout the hydraulic fracturing operation.
The Paperwork Reduction Act requires that each Federal agency certify that each collection of information has practical utility. The term “practical utility” means the ability of an agency to use information, particularly the capability to process such information in a timely and useful fashion. 44 U.S.C 3502(11) and 3506(c)(3)(A).
The Paperwork Reduction Act requires each Federal agency to certify that each collection of information is written using plain, coherent, and unambiguous terminology and is understandable to those who are to respond. 44 U.S.C. 3506(c)(3)(D).
The Paperwork Reduction Act requires each Federal agency to certify that its collections of information are to be implemented in ways consistent and compatible, to the maximum extent practicable, with the existing reporting and recordkeeping practices of those who are to respond. 44 U.S.C. 3506(c)(3)(E). We received comments on the proposal to allow some of the information in a subsequent report to be submitted through FracFocus or another BLM-designated database.
Some commenters suggested that additional information, such as the APD, status, compliance, volume of fluid recovered, and complaint process, should be reported through the FracFocus submission.
Other commenters were critical of FracFocus as not being user-friendly and for not allowing re-publication or linking with other databases. Some commenters were critical of FracFocus because of the unknown future condition and long-term reliability of this organization in hosting and retaining the data. A few commenters expressed concern about future funding, access, and data backup issues of FracFocus. Other commenters suggested that the disclosure registry should be searchable across forms and allow for meaningful cross-tabulation of search results. One of the commenters specified that each of the disclosure submissions should have a date stamp showing the actual date of submission to the database and validate/reject the correct/incorrect CAS Registry Numbers of the disclosed chemicals/ingredients when submitted. Another commenter suggested that the BLM should develop a public disclosure platform tailored to the agency's needs.
Some commenters expressed concern that the ownership of the data on FracFocus and the applicability of public disclosure laws, such as FOIA are unknown. A commenter suggested that the BLM adopt a procedure used in Texas that requires operators to submit to the state commission a copy of the information that they upload to FracFocus.
Some commenters argued that using FracFocus would violate an executive order requiring government information to be available to the public in open, machine-readable formats, and the implementing guidance from the Office of Management and Budget. See Executive Order 13642, 78 FR 93 (2013), and Memorandum for the Heads of Executive Departments and Agencies, M-13-13 (OMB 2013). That order provides, in pertinent part that the policy of the Executive Branch is that modernized Government information resources must be open and machine readable. The order is subject to several conditions, including available appropriations.
A commenter was concerned that using FracFocus could cause a conflict of interest because the GWPC is a trade association for oil and gas.
A commenter argued that using FracFocus would fail to meet minimum standards for managing government records.
A commenter raised an issue of implementation and enforcement—that because FracFocus does not show the date that information is uploaded, it will be difficult for the BLM to know if the information was submitted within the time required by the rule.
Under this final rule, submission of the required information through FracFocus is optional; an operator may instead submit it directly to BLM. The BLM's intent, however, is to reduce the paperwork burden on operators by allowing them to submit information through FracFocus, if they so choose. Thus, in states that require submission on FracFocus, there would be no additional burden of complying with this requirement of the rule. If an operator submits the information directly to the BLM, the BLM will upload the information to FracFocus, and retain a copy in its files.
The BLM did not adopt suggestions to allow additional information to be reported through the FracFocus submission because FracFocus is limited to chemical disclosures.
The GWPC has upgraded the FracFocus database to enhance its functionality for the public, state regulatory agencies and industry users. As mentioned earlier under New Requirements, GWPC and IOGCC, joint venture partners in the FracFocus initiative, announced the release of several improvements to FracFocus' system functionality. The new features are designed to reduce the number of human errors in disclosures, expand the public's ability to search records, provide public extraction of data in a “machine readable” format, update educational information on chemical use, environmental impacts from oil and gas production, and potential environmental impacts. The new self-checking features in the system will help companies detect and correct possible errors before disclosures are submitted. This feature will detect errors verifying that CAS numbers meet the proper format. GWPC recently met with the BLM and confirmed the following updates to FracFocus:
(a) Validation of the CAS number;
(b) Reduction of errors by taking measures, such as a water volume alert if the operators input exceedingly high numbers (>15 million gallons) in error, multiple disclosures with the same API numbers, etc.;
(c) Validation checks of the maximum ingredient concentration, using two checks/alerts when the sum exceeds 3% and 10%;
(d) Improved public search capabilities with faster response times when filtering search results;
(e) Updated record retention and amendment aspects to keep a backup copy of every disclosure submitted to FracFocus;
(f) Adopted established record management standards to meet proper data quality objectives;
(g) Notify the BLM through a group email box when an operator uploads the chemical disclosure data for a well;
(h) Include a link to a downloadable file containing the data in a machine-readable format; and
(i) Provide a date stamp when chemical disclosure data is uploaded from the BLM operations.
These updates are addressed in the most recent iteration of FracFocus.
The agreement would also require GWPC to include the BLM as a member of the Full and Technical Committees to engage in updates and developments to FracFocus.
The BLM expects that these requirements will yield further progress and improvement of the FracFocus site to meet the requirements of the rule by providing an effective chemical disclosure registry for the hydraulic fracture fluids.
The Federal FOIA does not apply to FracFocus, because it is operated by the GWPC, which is not an agency of the Federal Government. However, information on FracFocus concerning Federal or tribal wells is public information because FracFocus is a public Web site and there would be no need for the costs of delays associated with awaiting a response to a FOIA request. The public can access that information for themselves.
Executive Order 13642 does not prohibit the BLM from allowing operators to submit information through FracFocus. We believe that FracFocus is the quickest, most cost-effective way to make the information public. Working with FracFocus to meet the policy goals of the Executive Order, including machine-readable formats, will be more prompt and will use taxpayer dollars more efficiently than would the BLM creating and managing its own database solely for chemical disclosures.
The use of FracFocus does not constitute a conflict of interest. The members of GWPC are the states agencies (
The use of FracFocus does not conflict with requirements for records management. FracFocus will not be the official repository of the chemical information required by the rule. Whether an operator submits information to the BLM directly or through FracFocus, the BLM will maintain access to all the relevant information. The information will also be available on FracFocus for the benefit of the public and state and tribal agencies.
The BLM will closely monitor FracFocus to ensure that operators submit information in a timely manner consistent with these regulations. Operators also have an incentive to assure that the BLM has received the required information within the deadlines. The BLM will be working with the GWPC to improve the ability of FracFocus to meet the BLM's needs and of operators on Federal or tribal lands.
The following table shows the estimated annual paperwork burdens associated with this rule.
No capital and start-up costs are involved with this information collection—respondents are not required to purchase additional computer hardware or software to comply with these information collection requirements. The Fiscal Year 2015 appropriations law (Pub. L. 113-203) directs the BLM to charge a $6,500 processing fee for Form 3160-3, Application for Permit to Drill or Re-Enter. We estimate that 5,000 of these applications are filed annually under control number 1004-0137, and another 2,614 will be filed under control number 1004-0203. The estimated non-hour cost burden is $32,500,000 under control number 1004-0137, and $16,991,000 under 1004-0203. The total estimated non-hour cost burden is $49,491,000.
The BLM has prepared an environmental assessment (EA) that concludes that this rule will not constitute a major Federal action that may result in a significant effect on the human environment under section 102(2)(C) of the National Environmental Policy Act (NEPA), 42 U.S.C. 4332(2)(C). The EA, the Finding of No Significant Impact, and the Decision Record are available for review and on file in the BLM Administrative Record at the address specified in the
In developing this rule, the BLM did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106-554).
Under Executive Order 13211, agencies are required to prepare and submit to OMB a Statement of Energy Effects for significant energy actions. This Statement is to include a detailed
Section 4(b) of Executive Order 13211 defines a “significant energy action” as “any action by an agency (normally published in the
The BLM believes that the additional cost per hydraulic fracturing operation is insignificant when compared with the drilling costs in recent years, the production gains from hydraulically fractured well operations, and the net incomes of entities within the oil and natural gas industries. For the average hydraulic fracturing operation, the compliance costs represent about 0.13 to 0.21 percent of the cost of drilling a well.
Since the estimated compliance costs are not substantial when compared with the total costs of drilling a well, the BLM believes that the rule is unlikely to have an effect on the investment decisions of firms, and the rule is unlikely to affect the supply, distribution, or use of energy. As such, the rule is not a “significant energy action” as defined in Executive Order 13211.
The principal authors of this rule are: Bryce Barlan, Program Analysis Officer, BLM Washington Office; James Tichenor, Economist, BLM Washington Office; Gerald Dickinson, Petroleum Engineer, BLM Rawlins Field Office; John Ajak, Petroleum Engineer, Washington Office; John Pecor, Petroleum Engineer, BLM Tre Rios Field Office; Rich Estabrook, Petroleum Engineer, BLM Washington Office; Rosemary Herrell, Senior Policy Analyst, BLM Washington Office; Steven Wells, Division Chief, Fluid Minerals, BLM Washington Office; Subijoy Dutta, Senior Petroleum Engineer, BLM Washington Office; Will Lambert, Petroleum Engineer, BLM Washington Office; Allen McKee, Petroleum Engineer, BLM Utah State Office; Don Judice, Field Manager, BLM Great Falls Field Office; Bev Winston, Public Affairs Specialist, BLM Washington Office; assisted by the BLM's Division of Regulatory Affairs and the Department of the Interior's Office of the Solicitor.
Administrative practice and procedure, Government contracts, Indians-lands, Mineral royalties, Oil and gas exploration, Penalties, Public lands-mineral resources, Reporting and recordkeeping requirements.
For the reasons stated in the preamble, and under the authorities stated below, the Bureau of Land Management amends 43 CFR part 3160 as follows:
25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
(1) Generally those waters containing up to 10,000 parts per million (ppm) of total dissolved solids. Usable water includes, but is not limited to:
(i) Underground water that meets the definition of “underground source of drinking water” as defined at 40 CFR 144.3;
(ii) Underground sources of drinking water under the law of the State (for Federal lands) or tribe (for Indian lands); and
(iii) Water in zones designated by the State (for Federal lands) or tribe (for Indian lands) as requiring isolation or protection from hydraulic fracturing operations.
(2) The following geologic zones are deemed not to contain usable water:
(i) Zones from which the BLM has authorized an operator to produce oil and gas, provided that the operator has obtained all other authorizations required by the Environmental Protection Agency, the State (for Federal lands), or the tribe (for Indian lands) to conduct hydraulic fracturing operations in the specific zone;
(ii) Zones designated as exempted aquifers pursuant to 40 CFR 144.7; and
(iii) Zones that do not meet the definition of underground source of drinking water at 40 CFR 144.3 which the State (for Federal lands) or the tribe (for Indian lands) has designated as exempt from any requirement to be isolated or protected from hydraulic fracturing operations.
(a) A proposal for further well operations must be submitted by the operator on a Sundry Notice and Report on Wells (Form 3160-5) as a Notice of Intent for approval by the authorized officer prior to commencing operations to redrill, deepen, perform casing repairs, plug-back, alter casing, recomplete in a different interval, perform water shut off, combine production between zones, and/or convert to injection. * * *
(b) Unless additional surface disturbance is involved and if the operations conform to the standard of prudent operating practice, prior approval is not required for acidizing jobs or recompletion in the same interval; however, a subsequent report on these operations must be filed using a Sundry Notice and Report on Wells (Form 3160-5).
(a)
(b)
(c)
(1) With an application for permit to drill; or
(2) With a Sundry Notice and Report on Wells (Form 3160-5) as a notice of intent (NOI).
(3) For approval of a group of wells submitted under either paragraph (c)(1) or (2) of this section, the operator may submit a master hydraulic fracturing plan. Submission of a master hydraulic fracturing plan does not obviate the need to obtain an approved APD from the BLM for each individual well.
(4) If an operator has received approval from the authorized officer for hydraulic fracturing operations, and the operator has significant new information about the geology of the area, the stimulation operation or technology to be used, or the anticipated impacts of the hydraulic fracturing operation to any resource, then the operator must submit a new NOI (Form 3160-5). Significant new information includes, but is not limited to, information that changes the proposed drilling or completion of the well, the hydraulic fracturing operation, or indicates increased risk of contamination of zones containing usable water or other minerals.
(d)
(1) The following information regarding wellbore geology:
(i) The geologic names, a geologic description, and the estimated depths (measured and true vertical) to the top and bottom of the formation into which hydraulic fracturing fluids are to be injected;
(ii) The estimated depths (measured and true vertical) to the top and bottom of the confining zone(s); and
(iii) The estimated depths (measured and true vertical) to the top and bottom of all occurrences of usable water based on the best available information.
(2) A map showing the location, orientation, and extent of any known or suspected faults or fractures within one-half mile (horizontal distance) of the wellbore trajectory that may transect the confining zone(s). The map must be of a scale no smaller than 1:24,000.
(3) Information concerning the source and location of water supply, such as reused or recycled water, rivers, creeks, springs, lakes, ponds, and water supply wells, which may be shown by quarter-quarter section on a map or plat, or which may be described in writing. It must also identify the anticipated access route and transportation method for all water planned for use in hydraulically fracturing the well;
(4) A plan for the proposed hydraulic fracturing design that includes, but is not limited to, the following:
(i) The estimated total volume of fluid to be used;
(ii) The maximum anticipated surface pressure that will be applied during the hydraulic fracturing process;
(iii) A map at a scale no smaller than 1:24,000 showing:
(A) The trajectory of the wellbore into which hydraulic fracturing fluids are to be injected;
(B) The estimated direction and length of the fractures that will be propagated and a notation indicating the true vertical depth of the top and bottom of the fractures; and
(C) All existing wellbore trajectories, regardless of type, within one-half mile (horizontal distance) of any portion of the wellbore into which hydraulic fracturing fluids are to be injected. The true vertical depth of each wellbore identified on the map must be indicated.
(iv) The estimated minimum vertical distance between the top of the fracture zone and the nearest usable water zone; and
(v) The measured depth of the proposed perforated or open-hole interval.
(5) The following information concerning the handling of fluids recovered between the commencement of hydraulic fracturing operations and the approval of a plan for the disposal of produced fluid under BLM requirements:
(i) The estimated volume of fluid to be recovered;
(ii) The proposed methods of handling the recovered fluids as required under paragraph (h) of this section; and
(iii) The proposed disposal method of the recovered fluids, including, but not limited to, injection, storage, and recycling.
(6) If the operator submits a request for approval of hydraulic fracturing with an NOI (Form 3160-5), the following information must also be submitted:
(i) A surface use plan of operations, if the hydraulic fracturing operation would cause additional surface disturbance; and
(ii) Documentation required in paragraph (e) or other documentation demonstrating to the authorized officer that the casing and cement have isolated usable water zones, if the proposal is to hydraulically fracture a well that was completed without hydraulic fracturing.
(7) The authorized officer may request additional information prior to the approval of the NOI (Form 3160-5) or APD.
(e)
(ii) For any well completed pursuant to an APD that did not authorize hydraulic fracturing operations, the operator must submit documentation to demonstrate that adequate cementing was achieved for all casing strings designed to isolate and protect usable water. The operator must submit the documentation with its request for approval of hydraulic fracturing operations, or no less than 48 hours prior to conducting hydraulic fracturing operations if no prior approval is required, pursuant to paragraph (a) of this section. The authorized officer may approve the hydraulic fracturing of the well only if the documentation provides assurance that the cementing was sufficient to isolate and to protect usable water, and may require such additional tests, verifications, cementing or other protection or isolation operations, as the authorized officer deems necessary.
(2) Prior to starting hydraulic fracturing operations, the operator must determine and document that there is adequate cement for all casing strings used to isolate and protect usable water zones as follows:
(i)
(ii)
(B) If the casing is cemented to surface, then the operator must follow the requirements of paragraph (e)(2)(i) of this section.
(3) For any well, if there is an indication of inadequate cement on any casing used to isolate usable water, then the operator must:
(i) Notify the authorized officer within 24 hours of discovering the inadequate cement;
(ii) Submit an NOI (Form 3160-5) to the authorized officer requesting approval of a plan to perform remedial action to achieve adequate cement. The plan must include the supporting documentation and logs required under paragraph (e)(2) of this section. In emergency situations, an operator may request oral approval from the authorized officer for actions to be undertaken to remediate the cement. However, such requests must be followed by a written notice filed not later than the fifth business day following oral approval;
(iii) Verify that the remedial action was successful with a CEL or other method approved in advance by the authorized officer;
(iv) Submit a Sundry Notice and Report on Wells (Form 3160-5) as a subsequent report for the remedial action including:
(A) A signed certification that the operator corrected the inadequate cement job in accordance with the approved plan; and
(B) The results from the CEL or other method approved by the authorized officer showing that there is adequate cement.
(v) The operator must submit the results from the CEL or other method approved by the authorized officer (see paragraph (e)(3)(iv)(B) of this section) at least 72 hours before starting hydraulic fracturing operations.
(f)
(1) If hydraulic fracturing through the casing is proposed, the casing must be tested to not less than the maximum anticipated surface pressure that will be applied during the hydraulic fracturing process.
(2) If hydraulic fracturing through a fracturing string is proposed, the fracturing string must be inserted into a liner or run on a packer-set not less than 100 feet below the cement top of the production or intermediate casing. The fracturing string must be tested to not less than the maximum anticipated surface pressure minus the annulus pressure applied between the fracturing string and the production or intermediate casing.
(3) The mechanical integrity test will be considered successful if the pressure applied holds for 30 minutes with no more than a 10 percent pressure loss.
(g)
(1) During any hydraulic fracturing operation, the operator must continuously monitor and record the annulus pressure at the bradenhead. The pressure in the annulus between any intermediate casings and the production casing must also be continuously monitored and recorded. A continuous record of all annuli pressure during the fracturing operation must be submitted with the required Subsequent Report Sundry Notice (Form 3160-5) identified in paragraph (i) of this section.
(2) If during any hydraulic fracturing operation any annulus pressure increases by more than 500 pounds per square inch as compared to the pressure immediately preceding the stimulation, the operator must stop the hydraulic fracturing operation, take immediate corrective action to control the situation, orally notify the authorized officer as soon as practicable, but no later than 24 hours following the incident, and determine the reasons for the pressure increase. Prior to recommencing hydraulic fracturing operations, the operator must perform any remedial action required by the authorized officer, and successfully perform a mechanical integrity test under paragraph (f) of this section. Within 30 days after the hydraulic fracturing operations are completed, the operator must submit a report containing all details pertaining to the incident, including corrective actions taken, as part of a Subsequent Report Sundry Notice (Form 3160-5).
(h)
(1) The authorized officer may approve an application to use lined pits only if the applicant demonstrates that use of a tank as described in this paragraph (h) is infeasible for environmental, public health or safety reasons and only if, at a minimum, all of the following conditions apply:
(i) The distance from the pit to intermittent or ephemeral streams or water sources would be at least 300 feet;
(ii) The distance from the pit to perennial streams, springs, fresh water sources, or wetlands would be at least 500 feet;
(iii) There is no usable groundwater within 50 feet of the surface in the area where the pit would be located;
(iv) The distance from the pit to any occupied residence, school, park, school bus stop, place of business, or other areas where the public could reasonably be expected to frequent would be greater than 300 feet;
(v) The pit would not be constructed in fill or unstable areas;
(vi) The construction of the pit would not adversely impact the hydrologic functions of a 100-year floodplain; and
(vii) Pit use and location complies with applicable local, State (on Federal lands), tribal (on Indian lands) and other Federal statutes and regulations including those that are more stringent than these regulations.
(2) Pits approved by the authorized officer must be:
(i) Lined with a durable, leak-proof synthetic material and equipped with a leak detection system; and
(ii) Routinely inspected and maintained, as required by the authorized officer, to ensure that there is no fluid leakage into the environment. The operator must document all inspections.
(i)
(1) The true vertical depth of the well, total water volume used, and a description of the base fluid and each additive in the hydraulic fracturing fluid, including the trade name, supplier, purpose, ingredients, Chemical Abstract Service Number (CAS), maximum ingredient concentration in additive (percent by mass), and maximum ingredient concentration in hydraulic fracturing fluid (percent by mass).
(2) The actual source(s) and location(s) of the water used in the hydraulic fracturing fluid;
(3) The maximum surface pressure and rate at the end of each stage of the hydraulic fracturing operation and the actual flush volume.
(4) The actual, estimated, or calculated fracture length, height and direction.
(5) The actual measured depth of perforations or the open-hole interval.
(6) The total volume of fluid recovered between the completion of the last stage of hydraulic fracturing operations and when the operator starts to report water produced from the well to the Office of Natural Resources Revenue. If the operator has not begun to report produced water to the Office of Natural Resources Revenue when the Subsequent Report Sundry Notice is submitted, the operator must submit a supplemental Subsequent Report Sundry Notice (Form 3160-5) to the authorized officer documenting the total volume of recovered fluid.
(7) The following information concerning the handling of fluids recovered, covering the period between the commencement of hydraulic fracturing and the implementation of the approved plan for the disposal of produced water under BLM requirements:
(i) The methods of handling the recovered fluids, including, but not limited to, transfer pipes and tankers, holding pond use, re-use for other stimulation activities, or injection; and
(ii) The disposal method of the recovered fluids, including, but not limited to, the percent injected, the percent stored at an off-lease disposal facility, and the percent recycled.
(8) A certification signed by the operator that:
(i) The operator complied with the requirements in paragraphs (b), (e), (f), (g), and (h) of this section;
(ii) For Federal lands, the hydraulic fracturing fluid constituents, once they
(iii) For Indian lands, the hydraulic fracturing fluid constituents, once they arrived on the lease, complied with all applicable permitting and notice requirements as well as all applicable Federal and tribal laws, rules, and regulations.
(9) The operator must submit the result of the mechanical integrity test as required by paragraph (f) of this section.
(10) The authorized officer may require the operator to provide documentation substantiating any information submitted under paragraph (i) of this section.
(j)
(1) For the information required in paragraph (i) of this section, the operator and the owner of the information will be deemed to have waived any right to protect from public disclosure information submitted with a Subsequent Report Sundry Notice (Form 3160-5) or through FracFocus or another BLM-designated database. For information required in paragraph (i) of this section that the owner of the information claims to be exempt from public disclosure and is withheld from the BLM, a corporate officer, managing partner, or sole proprietor of the operator must sign and the operator must submit to the authorized officer with the Subsequent Report Sundry Notice (Form 3160-5) required in paragraph (i) of this section an affidavit that:
(i) Identifies the owner of the withheld information and provides the name, address and contact information for a corporate officer, managing partner, or sole proprietor of the owner of the information;
(ii) Identifies the Federal statute or regulation that would prohibit the BLM from publicly disclosing the information if it were in the BLM's possession;
(iii) Affirms that the operator has been provided the withheld information from the owner of the information and is maintaining records of the withheld information, or that the operator has access and will maintain access to the withheld information held by the owner of the information;
(iv) Affirms that the information is not publicly available;
(v) Affirms that the information is not required to be publicly disclosed under any applicable local, State or Federal law (on Federal lands), or tribal or Federal law (on Indian lands);
(vi) Affirms that the owner of the information is in actual competition and identifies competitors or others that could use the withheld information to cause the owner of the information substantial competitive harm;
(vii) Affirms that the release of the information would likely cause substantial competitive harm to the owner of the information and provides the factual basis for that affirmation; and
(viii) Affirms that the information is not readily apparent through reverse engineering with publicly available information.
(2) If the operator relies upon information from third parties, such as the owner of the withheld information, to make the affirmations in paragraphs (j)(1)(vi) through (viii) of this section, the operator must provide a written affidavit from the third party that sets forth the relied-upon information.
(3) The BLM may require any operator to submit to the BLM any withheld information, and any information relevant to a claim that withheld information is exempt from public disclosure.
(4) If the BLM determines that the information submitted under paragraph (j)(3) of this section is not exempt from disclosure, the BLM will make the information available to the public after providing the operator and owner of the information with no fewer than 10 business days' notice of the BLM's determination.
(5) The operator must maintain records of the withheld information until the later of the BLM's approval of a final abandonment notice, or 6 years after completion of hydraulic fracturing operations on Indian lands, or 7 years after completion of hydraulic fracturing operations on Federal lands. Any subsequent operator will be responsible for maintaining access to records required by this paragraph during its operation of the well. The operator will be deemed to be maintaining the records if it can promptly provide the complete and accurate information to BLM, even if the information is in the custody of its owner.
(6) If any of the chemical identity information required in paragraph (i)(1) of this section is withheld, the operator must provide the generic chemical name in the submission required by paragraph (i)(1) of this section. The generic chemical name must be only as nonspecific as is necessary to protect the confidential chemical identity, and should be the same as or no less descriptive than the generic chemical name provided to the Environmental Protection Agency.
(k)
(1) Individual variance: The operator may make a written request to the authorized officer for a variance from the requirements under this section. A request for an individual variance must specifically identify the regulatory provision of this section for which the variance is being requested, explain the reason the variance is needed, and demonstrate how the operator will satisfy the objectives of the regulation for which the variance is being requested.
(2) State or tribal variance: In cooperation with a State (for Federal lands) or a tribe (for Indian lands), the appropriate BLM State Director may issue a variance that would apply to all wells within a State or within Indian lands, or to specific fields or basins within the State or the Indian lands, if the BLM finds that the variance meets the criteria in paragraph (k)(3) of this section. A State or tribal variance request or decision must specifically identify the regulatory provision(s) of this section for which the variance is being requested, explain the reason the variance is needed, and demonstrate how the operator will satisfy the objectives of the regulation for which the variance is being requested. A State or tribal variance may be initiated by the State, tribe, or the BLM.
(3) The authorized officer (for an individual variance), or the State Director (for a State or tribal variance), after considering all relevant factors, may approve the variance, or approve it with one or more conditions of approval, only if the BLM determines that the proposed alternative meets or exceeds the objectives of the regulation for which the variance is being requested. The decision whether to grant or deny the variance request must be in writing and is entirely within the BLM's discretion. The decision on a variance request is not subject to administrative appeals either to the State Director (for an individual variance) or under 43 CFR part 4.
(4) A variance under this section does not constitute a variance to provisions of other regulations, laws, or orders.
(5) Due to changes in Federal law, technology, regulation, BLM policy, field operations, noncompliance, or other reasons, the BLM reserves the right to rescind a variance or modify any conditions of approval. The authorized officer must provide a written justification before a variance is rescinded or a condition of approval is modified.
(d)
Office of National Marine Sanctuaries (ONMS), National Ocean Service (NOS), National Oceanic and Atmospheric Administration (NOAA), Department of Commerce (DOC).
Proposed rule.
The National Oceanic and Atmospheric Administration (NOAA) is proposing to expand the boundaries and scope of Hawaiian Islands Humpback Whale National Marine Sanctuary (HIHWNMS or sanctuary), amend the regulations for HIHWNMS, change the name of the sanctuary, and revise the sanctuary's terms of designation and management plan. The purpose of this action is to transition the sanctuary from a single-species management approach to an ecosystem-based management approach. A draft environmental impact statement and draft revised management plan have been prepared for this proposed action. NOAA is soliciting public comment on the proposed rule, draft environmental impact statement, and draft revised management plan.
Comments on this proposed rule will be considered if received by June 19, 2015.
You may submit comments on this document, identified by NOAA-NOS-2015-0028, by any of the following methods:
•
•
Malia Chow, Superintendent, Hawaiian Islands Humpback Whale National Marine Sanctuary at 808-725-5901 or
Copies of the draft environmental impact statement and proposed rule can be downloaded or viewed on the Internet at
Public hearings will be held in the following locations at the locales and times indicated:
* Please note that due to limited access to the island this is not a public meeting. This meeting is for people residing on and landowners of Ni‘ihau Island.
The Hawaiian Islands Humpback Whale National Marine Sanctuary (HIHWNMS or sanctuary) covers approximately 1,031.4 square nautical miles (1,366 square miles) of federal and state waters in the Hawaiian Islands. The sanctuary lies within the shallow warm waters surrounding the main Hawaiian Islands which are a nationally significant marine environment. The area is a diverse and unique ecosystem with marine resources including coral reefs, highly endangered Hawaiian monk seals, three species of sea turtles, marine species endemic to this area such as monk seals, corals, and seagrasses, and 25 species of cetaceans including humpback whales. This area constitutes one of the world's most important humpback whale habitats. The warm, calm waters in this area are used by humpback whales for breeding, calving, and nursing. The waters in this area also contain a number of cultural
The sanctuary is co-managed by NOAA and the State of Hawai`i (State) through a compact agreement that was signed in 1998 which clarifies the relative jurisdiction, authority, and conditions of the NOAA-State partnership for managing the sanctuary. The Hawaii Department of Land and Natural Resources (DLNR) serves as the lead agency for the State's co-management of the sanctuary.
When Congress designated the HIHWNMS in 1992, it mandated NOAA to provide for the identification of marine resources and ecosystems of national significance for possible inclusion in the sanctuary. The current management plan review process seeks to carry out this mandate. Started in 2010, the sanctuary management plan review provided an opportunity to: Consider the value of marine ecosystems, assess existing threats and protections to these valuable resources; and determine where NOAA can provide added value to the resource management efforts provided by the state and other federal agencies.
NOAA believes that an ecosystem-based, rather than single-species based, management approach for HIHWNMS would provide sanctuary management with the platform to begin to evaluate and potentially address the full suite of resource management issues currently faced by marine resources in the main Hawaiian Islands. By focusing on the biological, physical, and human components of a healthy marine environment, an ecosystem-based management approach in the sanctuary would be more comprehensive and inclusive of all aspects of the marine ecosystem than the current single species approach. Humpback whales and their habitat are an essential component of the marine ecosystem in Hawai`i and the sanctuary would continue to support current humpback whale management programs, but would also engage in research, resource protection, education, community engagement, and education for other areas and issues of the sanctuary environment.
This management approach is also consistent with Native Hawaiians' management practices, which have traditionally used a holistic approach to conserve both land and marine resources. Native Hawaiians also view natural and cultural resources as being interrelated and, that all biological resources are culturally significant. NOAA recognizes the importance of including Native Hawaiian knowledge and practices in the management framework of the sanctuary and intends to incorporate the sustainable use of natural and cultural resources into its management planning. In addition, the sanctuary management plan and regulations will strive to accommodate traditional uses and achieve sustainable cultural practices.
During the 2002 management plan review (MPR), NOAA received comments from the general public requesting that HIHWNMS, consistent with section 2304(b) of the HINMSA, consider the conservation and management of marine resources in addition to humpback whales and their habitat. In response, NOAA included a goal in the HIHWNMS 2002 management plan to “identify and evaluate resources and ecosystems for possible inclusion in the sanctuary”. NOAA followed up by conducting an assessment of living marine resources and maritime heritage resources within the sanctuary, including human population trends, past and current threats, existing management authorities, and conservation needs. The assessment report was shared with then Governor Linda Lingle in 2007 who publicly expressed her support for NOAA to consider protecting additional marine species within the sanctuary.
Between April 2009 and July 2010, NOAA conducted a series of meetings and workshops to solicit public input on the inclusion of additional marine resources into sanctuary management and raise awareness about the management plan review process. These events were conducted formally and informally across the State of Hawai`i on all the main islands.
NOAA formally initiated the public scoping process on July 14, 2010, by publishing a notice of intent in the
Many people commended HIHWNMS for their active role in promoting the conservation of humpback whales and their habitat, but suggested that NOAA consider expanding the scope of sanctuary management to conserve additional marine species and habitats. Other comments identified the need to address anthropogenic threats to the marine environment including pollution, offshore development, and climate change. The public also identified opportunities and recommendations for HIHWNMS to:
• Improve and expand upon enforcement, management effectiveness, and marine animal assessment and response;
• better integrate Native Hawaiian cultural resources and maritime heritage resources into sanctuary management and planning;
• emphasize ocean literacy programs; and
• update research programs, regulations, and sanctuary boundaries.
Comments were submitted by agencies, organizations, elected officials and community members from throughout Hawai`i, the U.S. mainland and elsewhere. NOAA documented all comments received during the public comment period as part of the administrative record; the comments are available online at
In response to many of these comments, this proposed rule proposes several changes to the HIHWNMS regulations and boundaries as described below in the “Summary of the Regulatory Amendments.” The environmental effects of these proposed changes are analyzed in a DEIS published concurrently with this proposed rule. NOAA has also developed an associated draft management plan describing sanctuary management activities in research,
NOAA is proposing to amend § 922.180(a)-(b) to reflect the inclusion of other marine resources in the resource protection mission of the proposed ecosystem-based sanctuary. Similarly, NOAA is proposing to remove the current species-based definition of “sanctuary resource” and “habitat” in § 922.182, which currently only includes humpback whales and their habitat in the definition of sanctuary resource. The definition that would then apply to the sanctuary would be the existing definition presented in the regulations for all national marine sanctuaries at § 922.3.
This national definition for sanctuary resource is: “any living or non-living resource of a National Marine Sanctuary that contributes to the conservation, recreational, ecological, historical, research, educational, or aesthetic value of the Sanctuary, including, but not limited to, the substratum of the area of the Sanctuary, other submerged features and the surrounding seabed, carbonate rock, corals and other bottom formations, coralline algae and other marine plants and algae, marine invertebrates, brine-seep biota, phytoplankton, zooplankton, fish, seabirds, sea turtles and other marine reptiles, marine mammals and historical resources (15 CFR 922.3).” In a separate rulemaking NOAA has proposed to update this national definition to add cultural resources to the definition of sanctuary resources (78 FR 5998). Upon completion of that separate national rulemaking the updated definition of sanctuary resources would then apply to all national marine sanctuaries.
NOAA is proposing to expand the current boundaries to include five additional areas in the sanctuary, adding 192.6 total square nautical miles (255 square miles) to the sanctuary bringing the total area to 1,224 square nautical miles (1,621 square miles). Under this action, NOAA is proposing to: (1) Extend the sanctuary boundary on the north shore of O`ahu west to include waters adjacent to the Ali`i Beach Park; (2) extend the sanctuary boundaries on the north shore of Kaua`i east to include waters adjacent to the Pīla`a ahupua`a; (3) extend the sanctuary boundaries on the north shore of Kaua`i west to include waters adjacent to the Hā`ena ahupua`a; (4) include the waters around the island of Ni`ihau, southwest of Kaua`i; and (5) modify the southern boundary of Penguin Bank and Maui Nui to simplify the convolutions of the current boundary where the approximation of the 100-fathom (182.8 meter) isobaths is too intricate for enforcement and to include additional important habitat. Ahupua`a are a system of traditional Hawaiian land division extending from the upland to the sea or watershed boundary. NOAA is also proposing a technical correction to the seaward boundary of the full sanctuary to include latitude/longitude coordinates approximating the 100-fathom (182.8 meter) isobaths and where needed the three nautical mile line to define the boundary, which would result in minor modification to the overall area estimate of the sanctuary.
The proposed boundary changes were selected through a public process to identify and assess marine areas that could more effectively complement current management authorities or enhance natural and cultural resource value. Collectively, these new areas capture a greater diversity of habitats and biological resources than currently protected by HIHWNMS. Inclusion of these areas within the sanctuary system would provide additional regulatory protection, resources for management, and improved public awareness of their natural and cultural resource value. The technical correction addresses the current seaward boundary of the sanctuary which is defined as following the historic 100-fathom (182.8 meter) isobaths. NOAA proposes to modernize the boundary by employing a textual description coupled with a table of latitude/longitude coordinates that approximates the 100-fathom (182.9 meter) isobath. The correction is being made to clarify the boundary for paper and electronic nautical charts, to provide a more accurately defined boundary for use by ships using GPS technology, and to improve enforceability. The technical change is not intended to add any additional area to the sanctuary and is distinct from the five new areas being proposed for addition to the sanctuary. The harbors currently excluded from the sanctuary boundaries continue to be excluded. Those harbors are Kawaihae Boat Harbor & Small Boat Basin on Hawai`i; Kaumalapau Harbor and Manele Harbor on Lāna`i; Lahaina Boat Harbor and Mā`alaea Boat Harbor on Maui; Hale o Lono Harbor and Kaunakakai Harbor on Moloka`i; and Kuapa Pond (Hawai`I Kai) and Hale`iwa Harbor on O`ahu. The proposed boundary changes for the five new areas are described in more detail below.
NOAA is proposing to incorporate the waters around the island of Ni`ihau into the sanctuary, including the waters surrounding Lehua Island. The boundary for this area would extend around the islands seaward from the shoreline three nautical miles. The total area of the proposed boundary expansion would be 163.9 square nautical miles (217 square miles). Ni`ihau is the seventh largest island in the Hawaiian Archipelago and is the westernmost island of the populated Hawaiian Islands. The island has an area of approximately 69.5 square miles (180 square km) and is located approximately 18 miles (29 km) west of the island of Kaua`i across the Kaulakahi Channel. Uninhabited Lehua Islet lies 0.7 miles (1.1 km) directly north of Ni`ihau.
Ni`ihau is the closest of the populated Hawaiian Islands to the Northwestern Hawaiian Islands and is at the interface between the two bioregions, serving as a functional transition zone in the archipelago. The specific biophysical and cultural connectivity dynamics at this interface are of special interest. The coral at Ni`ihau and Lehua have significantly lower prevalence of coral disease than elsewhere in the populated Hawaiian Islands. The waters around Ni‘ihau and Lehua also have a higher level of fish biomass and a higher number of endemic species than the other populated Hawaiian Islands.
Ni`ihau is also an important habitat for dolphins, monk seals and humpback whales. The endangered Hawaiian monk seals have a significant presence in Ni`ihau and Lehua. Lehua Islet is an important monk seal feeding and resting site. Aerial surveys conducted in 2000, 2001, and 2008 documented approximately three times more monk seals on the coastal areas of Ni`ihau and Lehua than on other islands in the populated Hawaiian Islands. Island-wide surveys of Ni`ihau have observed between 17 and 69 monk seals at a particular time, higher than any other reported sightings on the populated Hawaiian Islands. Recent research
The current sanctuary boundary on the north shore of Kaua`i extends along the shoreline from Kailiu Point eastward to Mokolea Point and seaward to approximately the 100-fathom (182.8 m) isobath. NOAA is proposing to extend the sanctuary boundary in two areas to more closely include the waters of the adjacent ahupua‘a.
On the north shore of the island of Kaua`i, west of the town of Hanalei, NOAA is proposing to extend the western boundary of the sanctuary to Ke`e Beach and include the waters of the Hā`ena ahupua`a seaward to approximately the 100-fathom (182.8 meter) isobath. The boundary extension would also include the Hā`ena community-based subsistence fishing area (CBSFA) which is currently managed by the State of Hawai`i. The total area of the proposed boundary expansion would be approximately 6 square nautical miles (8 square miles).
NOAA is also proposing to extend the eastern-boundary of the sanctuary on the north shore of Kaua`i to include the waters from Mokolea Point to Kepuhi Point including those of the Pīla`a ahupua`a seaward to approximately the 100-fathom (182.8 meter) isobath. The total area of the proposed boundary expansion would be approximately 3.8 square nautical miles (5 square miles). The proposed sanctuary area would be used to pilot traditional Hawaiian marine resource management approaches along with science-informed management to restore the degraded coral reef ecosystem.
The current sanctuary boundary on the north shore of O`ahu extends from Pua`ena Point eastward to Māhie Point and seaward to approximately the 100-fathom (182.8 meter) isobath. With this action, NOAA is proposing to extend the western boundary of the sanctuary from Pua`ena Point to approximately Ali`i Beach Park and seaward to approximately the 100-fathom (182.8 meter) isobath to include the North Shore Surfing Reserve. The designation of the Surfing Reserve in 2010 was part of a state-led effort to acknowledge the cultural and historic significance of important surf sites in Hawai`i. The proposed sanctuary boundary extension would exclude Hale`iwa Harbor. The total area of the proposed boundary expansion would be approximately 3 square nautical miles (4 square miles).
The current sanctuary boundary in the area around Penguin Bank off the southwest shore of Moloka`i and in Maui Nui between the islands of Lāna`i and Kaho`olawe closely approximates the 100-fathom (182.8 meter) isobath. The current boundary in these areas meanders significantly due to the complexity of the seafloor bathymetry, currently making enforcement of sanctuary regulations difficult. As part of a sanctuary-wide effort to modernize the sanctuary boundary by employing a textual description coupled with a table of latitude/longitude coordinates that approximates the 100-fathom (182.8 meter) isobath, NOAA proposes to improve the boundary in these areas by simplifying the convolutions of the current boundary, thus eliminating any potential confusion regarding the location of the boundary due to the complexity of the bathymetry. The new, less intricate boundary will make enforcement less difficult and for Penguin Bank the area is also defined to be inclusive of precious corals, mesophotic corals and monk seal foraging areas. The net result is an addition of approximately 15.9 square nautical miles (21 square miles) to the sanctuary in federal waters.
In recognition of the proposed change to an ecosystem-based approach to management, NOAA is proposing that the sanctuary be renamed “Hawaiian Islands National Marine Sanctuary—Nā Kai `Ewalu”. The phrase “Nā Kai `Ewalu” means “the eight seas” in Native Hawaiian and refers to the ocean channels between the populated Hawaiian Islands and a Native Hawaiian poetic reference to the Hawaiian Islands themselves. It illustrates the interconnectedness between the ocean, the people of Hawai`i and their communities. Since the current name no longer fits NOAA is proposing a change that communicates both the management approach and a sense of community throughout Hawai'i, recognizing humans as part of the ecosystem.
The current sanctuary regulation prohibits approaching, or causing a vessel or other object to approach, within the sanctuary, by any means, within 100 yards of any humpback whale except as authorized under the MMPA and the ESA. NOAA is proposing to add interception (
These proposed changes to the existing humpback whale approach regulation would help to minimize incidences of humpback whale harassment or injury within the sanctuary, reduce adverse behavioral responses, and limit vessel strikes within the sanctuary. NOAA is proposing to apply these changes to the exiting regulation to the entire sanctuary including the proposed new areas of the sanctuary.
NOAA is proposing to apply the current overflight prohibition on operating an aircraft within 1,000 feet of humpback whales, to the new proposed areas for the sanctuary.
NOAA is proposing to combine the existing prohibitions on take and possession of humpback whales within the sanctuary into one regulation to be consistent with humpback whale take and approach regulations under the Marine Mammal Protection Act (MMPA) and the State of Hawai`i Administrative Rules 13-124 and apply the new proposed regulation to the entire sanctuary including the proposed new areas of the sanctuary.
NOAA proposing to apply the current prohibition on interfering with enforcement to the new proposed areas in the sanctuary.
NOAA is proposing to prohibit damaging, removing or displacing any signs, notices, placards, stakes, posts, or other boundary markers related to the sanctuary. NOAA is proposing to apply this to the entire sanctuary including the proposed new areas of the sanctuary.
NOAA is proposing to prohibit removing, damaging, or tampering with any historical or cultural resources within the sanctuary. Cultural heritage
This proposed prohibition would provide additional protection for maritime heritage resources within the sanctuary and complement existing state and Federal statutes, such as the National Historical Preservation Act and Sunken Military Craft Act. NOAA is proposing to apply these changes to the entire sanctuary including the proposed new areas of the sanctuary.
NOAA is proposing to create three Special Sanctuary Management Areas. NOAA is proposing a number of regulations specific to the Special Sanctuary Management Areas at Penguin Bank and the Maui Nui area (both in federal waters outside of 3 nautical miles) and Maunalua Bay (state waters within 3 nautical miles). For a map of these three areas, see the HIHWNMS Web page (
As a complement to existing protections, NOAA is proposing to prohibit taking or possessing any marine mammal, sea turtle, seabird, ESA-listed species or Hawai`i Revised Statutes chapter 195D listed species, within or above sanctuary waters in the three SSMAs, with an exception for species authorized by the Marine Mammal Protection Act, the Endangered Species Act, the Migratory Bird Treaty Act (MBTA), the Magnuson Stevens Fishery Conservation and Management Act, or Hawai`i State Law.
NOAA is proposing to modify the current prohibition on discharging or altering any submerged lands by separating the regulation into two parts, and refining the language for clarity and enforceability. Due to the proposed expanded scope of the sanctuary, NOAA understands that the scope of the application of the prohibition has also expanded. Therefore NOAA is seeking to assess value of the regulation in the SSMAs only instead of applying them sanctuary-wide at this time. With respect to the prohibition on discharging, NOAA is proposing to prohibit discharging or depositing any material or matter into the three SSMAs, except:
• Fish, fish parts, chumming materials or bait used in or resulting from fishing in the sanctuary;
• treated biodegradable effluents incidental to vessel use;
• water generated by routine vessel operations, such as engine exhaust, deck wash down; engine cooling water, clean bilge water or anchor wash; and
• biodegradable materials for traditional ceremonies associated with culturally important customs and usage (
This prohibition, and its associated exceptions, would also apply to discharge adjacent to these areas, should that discharge subsequently enter and injure a sanctuary resource within the SSMAs. This prohibition will likely enhance water quality in the Penguin Bank and Maui Nui SSMAs, and reduce impacts from pollutants and debris to the biological and physical environment in the Maunalua Bay SSMA. NOAA could use the authorization authority proposed in this rulemaking to evaluate whether to authorize activities that receive a permit from the U.S. Army Corps of Engineers or the State of Hawai'i and include additional conditions for those activities to protect sanctuary resources from activities.
NOAA is proposing to modify the current prohibition on discharging or altering any submerged lands by separating the regulation into two parts, and refining the language for clarity and enforceability. Due to the proposed expanded scope of the sanctuary, NOAA understands that the scope of the application of the prohibition has also expanded. Therefore, NOAA is seeking to assess the value of the regulation in the SSMAs only, instead of applying them sanctuary-wide at this time. With respect to the prohibition on altering any submerged lands, NOAA is proposing to refine the current regulations to prohibit dredging, drilling into, or otherwise altering in any way submerged lands in the three SSMAs, except:
• Anchoring a vessel on sandy bottom or substrate;
• routine maintenance of docks, seawalls, breakwaters, piers authorized by federal, state or local authorities with jurisdiction;
• the installation and maintenance of navigational aids authorized by federal, state or local authorities with jurisdiction; and
• aquaculture or fishing activities authorized under a permit issued by the State of Hawai`i Department of Land and Natural Resources, State of Hawai`i Department of Health, the U.S. Army Corps of Engineers, or NOAA's National Marine Fisheries Service.
Submerged lands include bottom formations, live rock and coral. There are currently no regulations for any non-precious stony corals, including mesophotic corals, in federal waters of Penguin Bank and the Maui Nui area. The proposed regulation supports and enhances efforts to protect previous corals in the Maui Nui area that have been designated Essential Fish Habitat (EFH) under the Magnuson-Stevens Act. Similarly, the proposed regulation would reduce direct physical and biological damage to coral and other marine habitats in Maunalua Bay.
Under the proposed regulations, NOAA would have the authority to authorize federal, state, or local permits for construction and dredging activities that would otherwise violate the proposed regulations in Maunalua Bay. Under the proposed regulation, any permittee with a pre-existing (at the time of final rule) federal, state, or local permit would need to notify NOAA of the permitted activity. Then the permittee would need to come into compliance with the sanctuary regulations by getting an authorization from NOAA within 1 year of the effective date of the final regulations. See Section 11 below for more information on authorization authority.
NOAA is proposing to prohibit possessing or using explosives within the SSMAs, with exceptions for explosives used for valid law enforcement purposes.
This proposed prohibition is consistent with the current State of Hawai`i regulations. Currently, the state prohibits the possession and use of explosives in or around fishing areas in state waters within three nautical miles (HAR § 13-75, HRS § 188-23).
NOAA is proposing to prohibit introducing or otherwise releasing an introduced species into the SSMAs, with an exception for species cultivated by aquaculture activities in state waters pursuant to a valid lease, permit, license or other authorization issued by DLNR or NMFS on the effective date of this final regulation. Introduced species can pose a major economic and environmental threat to the living resources and habitats of a sanctuary as well as the commercial and recreational uses that depend on these resources. NOAA understands that not all introduced species will become invasive species; however, national marine sanctuaries are mandated by law to preserve the natural character of national marine sanctuary ecosystems and any proposed alteration of the natural biological community (
NOAA is proposing to add to HIHWNMS regulations the authority to consider permits for the following four activities otherwise prohibited:
• Discharges of material or matter in the Special Sanctuary Management Areas (SSMAs);
• discharges of material or matter outside SSMAs that may enter and injure;
• disturbance of submerged lands of the SSMAs; and
• damaging cultural and maritime resources.
As proposed, NOAA's permitting authority would apply sanctuary-wide only to activities prohibited by the proposed damaging cultural and maritime resources regulation. NOAA would only consider permits for activities prohibited by the proposed regulations for discharge and disturbance of the submerged lands in the SSMAs (and are therefore limited to the SSMAs).
Similar to other national marine sanctuaries, NOAA is proposing to consider these permits only for the purposes of sanctuary education, research, and management (see the Summary of Regulations below for a specific description of these categories). NOAA is also proposing to add a fourth permit category for actions involving “installation of submarine cables.” This permit category would only apply to submarine cable activities otherwise prohibited in the SSMAs (and, therefore, apply only to the SSMAs).
To address the above additions to the ONMS general permit authority for HIHWNMS, NOAA would amend regulatory text in the program-wide regulations in sections 922.48 and 922.50 to add references to Subpart Q, as appropriate. NOAA would also add a new section 922.188 in Subpart Q titled “Permit procedures and review criteria.” Further, NOAA would add a subparagraph to 922.184 that would specify which general permit categories apply to which prohibited activities.
NOAA also proposes to provide HIHWNMS with the authority to consider allowing an otherwise prohibited activity if such activity is specifically authorized by any valid Federal, State, or local lease, permit, license, approval, or other authorization. Authorization authority is intended to streamline regulatory requirements by reducing the need for multiple permits and would apply to all proposed prohibitions at 922.49 Subpart Q. As such, NOAA proposes to amend the regulatory text at 922.49 to add reference to Subpart Q and at 922.184 (HIHWNMS regulations).
NOAA proposes to allow the ONMS Director to issue special use permits (SUPs) at HIHWNMS as established by Section 310 of the NMSA. Although SUP authority is established statutorily, NOAA has not exercised this authority at HIHWNMS. In the proposed regulatory changes, NOAA intends to make it clear that the ONMS Director may issue SUPs at HIHWNMS.
SUPs can be used to authorize the conduct of specific activities in a sanctuary if such authorization is necessary (1) to establish conditions of access to and use of any sanctuary resource; or (2) to promote public use and understanding of a sanctuary resource. The activities that qualify for a SUP are set forth in the
1. The placement and recovery of objects associated with public or private events on non-living substrate of the submerged lands of any national marine sanctuary.
2. The placement and recovery of objects related to commercial filming.
3. The continued presence of commercial submarine cables on or within the submerged lands of any national marine sanctuary.
4. The disposal of cremated human remains within or into any national marine sanctuary.
5. Recreational diving near the USS Monitor.
6. Fireworks displays.
7. The operation of aircraft below the minimum altitude in restricted zones of national marine sanctuaries.
The NMSA places certain requirements on any issuance of a SUP by the ONMS Director. Specifically, it states that the Director:
Shall authorize the conduct of an activity only if that activity is compatible with the purposes for which the sanctuary is designated and with protection of sanctuary resources;
Shall not authorize the conduct of any activity for a period of more than 5 years unless renewed by the Secretary;
Shall require that activities carried out under the permit be conducted in a manner that does not destroy, cause the loss of, or injure Sanctuary resources; and
Shall require the permittee to purchase and maintain comprehensive general liability insurance, or post an equivalent bond, against claims arising out of activities conducted under the permit and to agree to hold the United States harmless against such claims.
The NMSA allows the assessment and collection of fees for the conduct of any activity under a SUP. The fees collected could be used to recover the administrative costs of issuing the permit, the cost of implementing the permit, and the fair market value of the use of sanctuary resources.
Section 304(a)(4) of the National Marine Sanctuaries Act (NMSA) requires that the terms of designation include the geographic area included within the sanctuary; the characteristics of the area that give it conservation, recreational, ecological, historical, research, educational, or aesthetic value; and the types of activities that will be subject to regulation by the Secretary of Commerce to protect these characteristics.
Pursuant to the NMSA and the HINMSA, the terms of designation of the sanctuary shall be modified pursuant to Sections 303 and 304 of the NMSA and Sections 2305 and 2306 of the HINMSA.
With this proposed rule, NOAA is proposing changes to the HIHWNMS terms of designation, which were previously published in the
1. Modify the introduction to change the name of the sanctuary to the Hawaiian Islands National Marine Sanctuary—Nā Kai `Ewalu, and re-characterize the purpose of the sanctuary as ecosystem-based (rather than single species).
2. Modify Article I. Effect of Designation to change the name of the sanctuary to the Hawaiian Islands National Marine Sanctuary—Nā Kai `Ewalu.
3. Modify Article II. Description of the Area to update the boundary description with the new areas NOAA proposes adding to the sanctuary and remove the outdated text pertaining to Kahoolawe Island.
4. Modify Article III. Characteristics of the Area to update information on the abundance of humpback whales found near the Hawaiian Islands.
5. Modify Article IV. Scope of Regulations to update the activities regulated to include the activities covered by the proposed regulations.
6. Modify Article V to update the reference to the NMSA.
The revised terms of designation are proposed to read as follows (new text in bold and deleted text in brackets and
On November 4, 1992, President Bush signed into law the Hawaiian Islands National Marine Sanctuary Act (HINMSA or Act; Subtitle C of the Oceans Act of 1992, Pub. L. 102-587) which designated the Hawaiian Islands Humpback Whale National Marine Sanctuary [
(1) protect
(2) educate and interpret for the public the
(3) manage human uses of the Sanctuary consistent with the designation and Title III of the Marine Protection, Research and Sanctuaries Act, as amended (MPRSA; also cited as the National Marine Sanctuaries Act or NMSA), 16 U.S.C. 1431
Section 2306 of the HINMSA requires the Secretary to develop and issue a comprehensive management plan and implementing regulations to achieve the policy and purposes of the Act, consistent with the procedures of sections 303 and 304 of the NMSA. Section 304 of the NMSA authorizes the issuance of such regulations as are necessary and reasonable to implement the designation, including managing and protecting the conservation, recreational, ecological, historical, research, educational and aesthetic resources and qualities of the Hawaiian Islands Humpback Whale National Marine Sanctuary
The HINMSA identified a Sanctuary boundary but authorized the Secretary to modify the boundary as necessary to fulfill the purposes of the designation. The Sanctuary boundary was modified by the Secretary to encompass the submerged lands and waters off the coast of the Hawaiian Islands extending seaward from the shoreline, cutting across the mouths of rivers and streams,—
[
The Hawaiian Islands comprise an archipelago which consist of eight major islands and 124 minor islands, with a total land area of
Section 1. Activities Subject to Regulation.
In order to implement the Sanctuary designation, the following activities
[
b. [
[
Section 2. Emergencies.
Where necessary to prevent or minimize the destruction of, loss of, or injury to a Sanctuary resource or quality; or minimize the imminent risk of such destruction, loss or injury, any activity, including those not listed in Section 1 of this Article, is subject to immediate temporary regulation, including prohibition. If such a situation arises, the Director of NOAA's Office of
Pursuant to section 304(c)(1) of the NMSA, 16 U.S.C. 1434(c)(1), no valid lease, permit, license, approval or other authorization issued by any Federal, State, or local authority of competent jurisdiction, or any right of subsistence use or access, may be terminated by the Secretary of Commerce, or his or her designee, as a result of this designation, or as a result of any Sanctuary regulation, if such authorization or right was in existence on the effective date of Sanctuary designation (November 4, 1992).
The terms of designation, as defined under section 304
Appendix A to subpart Q, part 922, 15 CFR sets forth the precise boundary coordinates for the Sanctuary.
NOAA has prepared a draft environmental impact statement to evaluate the environmental effects of the proposed rulemaking. Copies are available at the address and Web site listed in the
Section 307 of the Coastal Zone Management Act (CZMA; 16 U.S.C. 1456) requires Federal agencies to consult with a state's coastal program on potential Federal regulations having an effect on state waters. Because the Hawaiian Islands Humpback Whale National Marine Sanctuary encompasses a portion of the Hawai`i State waters, NOAA intends to submit a copy of this proposed rule and supporting documents to the State of Hawai`i Coastal Zone Management Program for evaluation of Federal consistency under the CZMA.
This proposed rule has been determined to be not significant for purposes of Executive Order 12866.
NOAA has concluded that this regulatory action does not have federalism implications sufficient to warrant preparation of a federalism assessment under Executive Order 13132.
The National Historic Preservation Act (NHPA; 16 U.S.C. 470
The Chief Counsel for Regulation of the Department of Commerce certified to the Chief Counsel for Advocacy of the Small Business Administration (SBA) that this proposed rule, if adopted, would not have a significant economic impact on a substantial number of small entities. The factual basis for this certification is as follows:
The SBA has established thresholds on the designation of businesses as “small entities”. A fish-harvesting business is considered a small business if it has annual receipts not in excess of $3.5 million (13 CFR 121.201). Sports and recreation businesses and scenic and sightseeing transportation businesses are considered small businesses if they have annual receipts not in excess of $6 million (13 CFR 121.201). According to these limits, each of the businesses potentially affected by the proposed rule, except those in the commercial marine transportation and submarine cable installation businesses would most likely be small businesses. The analysis presented here is based on limited quantitative information on how much activity occurs within the boundaries of the proposed expansion areas for HIHWNMS, except for commercial fishing operations.
Methodology. Due to the lack of quantitative data on the number of businesses directly affected by the proposed regulations and their levels of revenues, costs and profits from their activities in the HIHWNMS expansion area, the assessment here is qualitative.
NOAA analyzed four regulatory alternatives (identified as Alternatives 1-4 in the Draft Environmental Impact Statement). User groups that entail small businesses included commercial fishing operation and recreation-tourism related businesses. Other user groups included in the full regulatory impact review in the DEIS and not included here are research and education, people who receive passive economic use value
NOAA assessed two types of regulations included in the proposed action (discharges and submerged lands—seabed alterations), which are only proposed to apply to three areas called Special Sanctuary Management Areas (SSMAs) within the HIHWNMS. NOAA also analyzed the impact of all regulations combined. Submarine cable regulations addressed in the full regulatory impact review are not discussed here since that industry is judged not to involve small businesses.
Discharge Regulations. Under the proposed rule, NOAA would prohibit discharging or depositing any material or matter into the three SSMAs, with an exception for treated biodegradable effluents incidental to vessel use. Many commercial vessels affected by the proposed regulations are expected to belong to commercial fishing operations and businesses involved in providing guide services in the recreation tourism industry (
Of the three proposed Special Sanctuary Management Areas, Penguin Bank and Maui Nui are active commercial fishing grounds. According to Vessel Management System (VMS) data, only 68 commercial fishing vessels entered the Special Sanctuary Management Areas in the last year. There are 42 permitted commercial boats operating out of Lahaina and all of these boats are using the federal waters of Maui Nui. This information is generally consistent with the information compiled during the Ocean Etiquette trainings and the USCG Marine Safety Office inventory for Maui.
Based on a 2012 survey conducted by the Pacific Islands Fisheries Science Center, there were roughly 170 active charter boat operations in the main Hawai`i Islands, with roughly 100 of these operating out of the big island of Hawai`i. Roughly 55 boats were based in Maui and O`ahu, the islands adjacent to the Special Sanctuary Management Areas. The average charter boat length in Maui and O`ahu was 40 feet and 39 feet, respectively.
Additionally, 99 active tour vessels operate out of Maui County, of which 55 are whale-watching operations. These larger vessels carry dozens of passengers and are typically equipped with a Coast Guard certified Marine Sanitation Device (MSD) that, if properly used, is compliant with the proposed treatment requirement in the Special Sanctuary Management Areas. At a minimum, most of the commercial operators have holding tanks.
There are pump out stations in the major harbors of the Maui Nui area (Lahaina and Mā`alaea), which ensures ease of compliance for boats that only have a holding tank. Furthermore, some tour operators have retrofitted their boats to increase the holding capacity and eliminate the need for discharging at sea.
Taking into account all of the above information, including the relatively modest total number of vessels operating in the Special Sanctuary Management Areas and the high proportion of vessels already equipped with compliant marine sanitation devices, NOAA expects there to be negligible costs from these new regulations.
NOAA expects both the commercial fishing industry and the recreation-tourism industry to receive moderate net benefits from these regulations in the form of improved habitat qualities, which would likely result in increased fish stocks for commercial and recreational fishing. In addition, NOAA expects that the resulting improved habitat qualities would benefit the recreation-tourism industry, which depends upon a healthy and thriving sanctuary ecosystem to support its business. Thus, NOAA expects that the commercial fishing and recreation-tourism industries would experience a net benefit from the discharge regulations. NOAA expects the proposed action to generate a mid-range level of costs with a mid-range level of net benefits compared with all other regulatory alternatives. Land use and development businesses would not be directly affected by the discharge regulations.
NOAA invites public comments from small business owners and members of the public potentially affected by the new discharge regulations to better understand and assess any impact of these proposed regulations.
Submerged lands — Seabed Alteration Regulations. Regulations prohibiting disturbances of the seabed in Special Sanctuary Management Areas would impact the commercial fishing industry and the recreation tourism industry. NOAA expects these industries to receive moderate net benefits from these regulations because of the improvement or maintenance of habitat qualities that these industries depend upon. NOAA also expects businesses in these industries to experience negligible increases in costs of operations because there is no significant anchoring activity in the Special Sanctuary Management Areas. Because of the exceptions, permit, and authorization processes in the proposed action, which may allow for some activities that disturb the seabed, including a proposed submarine cable installation, costs would be expected to be in the mid-range of costs across all alternatives.
All other regulatory amendments to the HIHWNMS regulations proposed in this rulemaking are either technical changes or are not expected to have any measurable impact, economic or otherwise, on the resources and businesses operating in and near the Special Sanctuary Management Areas. Because this action would not have a significant economic impact on a substantial number of small entities, no initial regulatory flexibility analysis was prepared.
Because the impacts of this proposed rule on commercial fishing, recreational tourism, and land use and development businesses are minimal, the Chief Counsel for Regulation certified to the Chief Counsel for Advocacy at SBA that this rulemaking would not have a significant economic impact on a substantial number of small entities.
ONMS has a valid Office of Management and Budget (OMB) control number (0648-0141) for the collection of public information related to the processing of ONMS permits across the National Marine Sanctuary System. NOAA's proposal to expand HIHWNMS would likely result in an increase in the number of requests for ONMS general permits, special use permits, and authorizations since this action proposes to add general permits and special use permits, certifications, appeals, and the authority to authorize other valid federal, state, or local leases, permits, licenses, approvals, or other authorizations. An increase in the number of ONMS permit requests would require a change to the reporting burden certified for OMB control number 0648-0141. An update to this control number for the processing of ONMS permits would be requested as part of the final rule for sanctuary expansion.
Nationwide, NOAA issues approximately 200 national marine sanctuary permits each year. Of this amount, HIWHNMS is expected to add
Send comments regarding the burden estimate for this data collection requirement, or any other aspect of this data collection, including suggestions for reducing the burden, to NOAA (see ADDRESSES) and by email to
NOAA requests comments on this proposed rule for by June 19, 2015.
A complete list of all references cited herein is available upon request (see
Administrative practice and procedure, Coastal zone, Historic preservation, Intergovernmental relations, Marine resources, Natural resources, Penalties, Recreation and recreation areas, Reporting and recordkeeping requirements, Wildlife.
Accordingly, for the reasons discussed in the preamble, the National Oceanic and Atmospheric Administration proposes to amend 15 CFR part 922 as follows:
16 U.S.C. 1431
(a) The purpose of the regulations in this subpart is to implement the designation of the Hawaiian Islands National Marine Sanctuary—Nā Kai `Ewalu by regulating activities affecting the resources of the Sanctuary or any of the qualities, values, or purposes, for which the Sanctuary was designated, in order to protect, preserve, and manage the conservation, ecological, recreational, research, educational, historical, cultural, and aesthetic resources and qualities of the area. The regulations are intended to supplement and complement existing regulatory authorities; and to facilitate all public and private uses of the Sanctuary, to the extent compatible with the primary objective of an ecosystem-based management approach that is inclusive of all aspects of the marine ecosystem emphasizing the biological, physical, and human components of a healthy marine environment, including protecting the humpback whale and its habitat, that are essential components of the marine ecosystem. Public and private uses of the Sanctuary include, but are not limited to, uses of Hawaiian natives customarily and traditionally exercised for subsistence, cultural, and religious purposes; as well as education, research, recreation, commercial and military activities; to reduce conflicts between compatible uses; to maintain, restore, and enhance the humpback whale and other protected species and their habitat; to contribute to the maintenance of natural assemblages of humpback whales and other protected species for future generations; more specifically to provide a place for humpback whales that are dependent on their Hawaiian Islands wintering habitat for reproductive activities, including breeding, calving, and nursing, and for the long-term survival of their species; and to achieve the other purposes and policies of the HINMSA and NMSA.
(b) These regulations may be modified to fulfill the Secretary's responsibilities for the Sanctuary, including the provision for additional protections of the Sanctuary ecosystem resources including for humpback whales and their habitat, as reasonably necessary, and the conservation and management of other marine resources, qualities and ecosystems of the Sanctuary determined to be of national significance. The Secretary shall consult with the Governor of the State of Hawai`i on any modifications to the regulations contained in this part that pertain to State of Hawai`i waters. For any modification of the regulations contained in this part that would contribute a change in a term of designation, as contained in the Designation Document for the Sanctuary, the Secretary shall follow the applicable requirements of section 303 and 304 of the NMSA, and sections 2305 and 2306 of the HINMSA.
(c) Section 304(e) of the NMSA requires the Secretary to review management plans and regulations every five years, and make necessary revisions. Upon completion of the five year review of the Sanctuary management plan and regulations, the Secretary will repropose the Sanctuary management plan and regulations in their entirety with any proposed changes thereto. The Governor of the State of Hawai`i will have the opportunity to review the re-proposed management plan and regulations before they take effect and if the Governor certifies any term or terms of such management plan or regulations as unacceptable, the unacceptable term or terms will not take effect in State waters of the Sanctuary.
(a) The Hawaiian Islands National Marine Sanctuary—Nā Kai `Ewalu (sanctuary) encompasses an area of approximately 1,224 square nautical miles (1,621 square miles) of coastal and ocean waters, and submerged lands thereunder, cutting across the mouths of rivers and streams, surrounding the populated Hawaii Islands as described below. The precise boundary coordinates are listed in Appendix A to this subpart.
(1) O`ahu: The sanctuary boundary on the southern shore of O`ahu is defined by the coordinates provided in table A1 and the following textual description. The boundary begins ENE of Makapu`u Point roughly 3.2 nautical miles offshore at Point 1. It approximates the 100-fathom (182.8 meter) isobath line extending first clockwise to the SE., then to the SW., and finally to the west to Point 68 in numerical order. From Point 68 the boundary extends NE
(2) Hawai`i: The sanctuary boundary of Hawai`i Island is defined by the coordinates provided in table A3 and the following textual description. The boundary begins offshore roughly 0.5 nautical miles west of Keāhole Point at Point 1, and approximates the 100-fathom (182.8 meter) isobath line as it extends northward to Point 102 in numerical order. The northeastern edge of the sanctuary boundary extends from Point 102 south towards Point 103 on the northern tip of `Upolu point until it intersects the shoreline. From this intersection, the boundary extends west and then south along the shoreline until it intersects the line segment between Point 104 and Point 105 to the north of Kawaihae Harbor. Kawaihae Harbor is excluded from the sanctuary so the boundary extends across the mouth of the harbor from this intersection towards Point 105 on the outer breakwater of Kawaihae Harbor until it intersects the shoreline. From this intersection the boundary continues south along the shoreline until it intersects the line segment between Point 106 and Point 107 at the westernmost tip of Hawai`i Island (Keāhole Point), west of the southern end of Kona Airport. From this intersection, the boundary extends seaward approximately 0.5 nautical miles west to Point 107.
(3) Ni`ihau: The sanctuary boundary around the island of Ni`ihau (including Lehua Island) is defined by the coordinates provided in table A4 and the following textual description. The landward boundary of Ni`ihau and Lehua is the shoreline. The seaward boundary of Ni`ihau and Lehua is approximately three nautical miles from the shoreline and extends around the islands from Points 1 to 60 in numerical order.
(4) Kaua`i: The sanctuary boundary off the north coast of Kaua`i is defined by the coordinates in table A5 and the following textual description. The boundary begins offshore nearly 3.3 nautical miles WNW of Ka`īlio Point at Point 1 and approximates the 100-fathom (182.8 meters) isobath line as it extends eastward in numerical order to Point 59, approximately 1.5 nautical miles NE of Kepuhi point at roughly the Pila`a/Waipake ahupua`a boundary. The eastern edge of the sanctuary boundary then extends SW from Point 59 towards Point 60 on Kepuhi Point until it intersects the shoreline. From this intersection the sanctuary boundary extends westward along the shoreline of the north coast of Kaua`i, and then continues to follow the shoreline as it extends southward along the eastern shore of Hanalei Bay until it intersects the line segment between Point 61 and Point 62 at approximately the mouth of the Hanalei River. From this intersection the boundary extends towards Point 62 until it intersects the shoreline again. From this intersection the boundary continues to follow the shoreline south around Hanalei Bay and then westward around Ka`ilio Point until it intersects the line between Point 63 and Point 64 at approximately the boundary of the Ha`ena/Hanakāpi`ai ahupua`a NE of Hanakāpi`ai beach. From this intersection, the boundary extends seaward to the WNW to Point 64.
(5) Maui Nui: The sanctuary boundary of Maui Nui between the islands of Moloka`i, Lana'i, and Maui is defined by the coordinates in table A6 and the following textual description. The boundary begins roughly 3.5 nautical miles west of `Īlio Point off the northwest tip of Moloka`i at Point 1. The boundary approximates the 100-fathom (182.8 meter) isobath line to the west and south around Penguin Bank and then back to the north and east following the coordinates in numerical order across Kalohi Channel to Point 196 to the NE of Kaena on Lana`i. The boundary then continues to approximate the 100-fathom (182.8 meter) isobath line south around Lana'i and then east crossing the Kealaikahiki Channel and continuing between Kaho`olawe and Molokini to the SE to Point 341 in numerical order roughly 2.2 nautical miles WSW of Hanamanioa Light on the southern shore of Maui. The boundary then continues ENE towards Point 342 until it intersects the shoreline near the Hanamanioa Light. At this intersection the boundary follows the shoreline northward to Mā`alaea Bay until it intersects the line segment between Point 343 and Point 344 at the eastern breakwater of the entrance to Mā`alaea Harbor. From this intersection the boundary continues toward Point 344 until it intersects the shoreline at the western breakwater of Mā`alaea Harbor. From this intersection the boundary continues to follow the shoreline SW around McGregor and Papawai Points and then to the NW until it reaches Lahaina Small Boat Harbor. The boundary continues along the shoreline of the outer breakwater of Lahaina Small Boat Harbor until it reaches the northern tip at the intersection of the shoreline and a line between points 345 and 346. From this intersection the boundary extends offshore to the NNW for approximately 25 meters to point 346. The boundary then heads WNW towards point 347 until it intersects the shoreline again. From this intersection the boundary then continues to follow the shoreline northward until it intersects the line
Other terms appearing in this subpart are defined at 15 CFR 922.3, and/or in the Marine Protection, Research, and Sanctuaries Act, as amended, 33 U.S.C. 1401
(a) All activities except those prohibited by § 922.184 may be undertaken in the Sanctuary subject to any emergency regulations promulgated pursuant to § 922.185, subject to the interagency cooperation provisions of section 304(d) of the NMSA [16 U.S.C. 1434(d)] and § 922.187 of this subpart, and subject to the liability established by section 312 of the NMSA and § 922.46 of this part. All activities are also subject to all prohibitions, restrictions, and conditions validly imposed by any other Federal, State, or county authority of competent jurisdiction.
(b) Included as activities allowed under the first sentence of paragraph (a) of this section are all classes of military activities, internal or external to the Sanctuary, that are being or have been conducted before the effective date of these regulations, as identified in the Final Environmental Impact Statement/Management Plan. Paragraphs (a)(1) through (a)(11) of § 922.184 do not apply to these classes of activities, nor are these activities subject to further consultation under section 304(d) of the NMSA.
(c) Military activities proposed after the effective date of these regulations are also included as allowed activities under the first sentence of paragraph (a) of this § 922.183. Paragraphs (a)(1) through (a)(11) of § 922.184 apply to these classes of activities unless—
(1) They are not subject to consultation under section 304(d) of the NMSA and § 922.187 of this subpart, or
(2) Upon consultation under section 304(d) of the NMSA and § 922.187 of this subpart, NOAA's findings and recommendations include a statement that paragraphs (a)(1) through (a)(11) of § 922.184 do not apply to the military activity.
(d) If a military activity described in paragraphs (b) or (c)(2) of this section is modified such that it is likely to destroy, cause the loss of, or injure a Sanctuary resource in a manner significantly greater than was considered in a previous consultation under section 304(d) of the NMSA and § 922.187 of this subpart, or if the modified activity is likely to destroy, cause the loss of, or injure any Sanctuary resource not considered in a previous consultation under section 304(d) of the NMSA and § 922.187 of this subpart, the modified activity will be treated as a new military activity under paragraph (c) of this section.
(e) If a proposed military activity subject to section 304(d) of the NMSA and § 922.187 of this subpart is necessary to respond to an emergency situation and the Secretary of Defense determines in writing that failure to undertake the proposed activity during the period of consultation would impair the national defense, the Secretary of the military department concerned may request the Director that the activity proceed during consultation. If the Director denies such a request, the Secretary of the military department concerned may decide to proceed with the activity. In such case, the Secretary of the military department concerned shall provide the Director with a written statement describing the effects of the activity on Sanctuary resources once the activity is completed.
(a) The following activities are prohibited and thus unlawful for any person to conduct or cause to be conducted.
(1)(i) Approaching in the Sanctuary, by any means, including by interception (
(ii) Causing a vessel or other object to approach within 100 yards (91.4 m) of a humpback whale;
(iii) Disrupting the normal behavior or prior activity of a whale by any other act or omission. A disruption of normal behavior may be manifested by, among other actions on the part of the whale, a rapid change in direction or speed; escape tactics such as prolonged diving, underwater course changes, underwater exhalation, or evasive swimming patterns; interruptions of breeding, nursing, or resting activities, attempts by a whale to shield a calf from a vessel or human observer by tail swishing or by other protective movement; or the abandonment of a previously frequented area;
(iv) Exceptions:
This paragraph (a)(1) does not apply to any approach is authorized by the National Marine Fisheries Service through a permit issued under 50 CFR part 222, subpart C, General Permit Procedures or through a similar authorization;
(2) Operating any aircraft above the Sanctuary within 1,000 feet of any humpback whale except as necessary for takeoff or landing from an airport or runway, or as authorized under the MMPA and the ESA;
(3)(i) Taking or possessing any humpback whales within the Sanctuary except as authorized by the Marine Mammal Protection Act (MMPA), or the Endangered Species Act (ESA;
(ii) Taking or possessing any marine mammal, sea turtle, seabird, Endangered Species Act-listed species or Hawai`i Revised Statutes chapter 195D listed species, within or above the Special Sanctuary Management Areas, except as authorized by the Marine Mammal Protection Act (MMPA); the Endangered Species Act (ESA); the Migratory Bird Treaty Act (MBTA); the Magnuson Stevens Fishery Conservation and Management Act; or Hawai`i State Law.
(4) Discharging or depositing any material or other matter in the Special Sanctuary Management Areas, except:
(i) Fish, fish parts, chumming materials or bait used in or resulting from lawful fishing activities within the Sanctuary, provided that such discharge or deposit is during the conduct of lawful fishing activities within the Sanctuary;
(ii) Biodegradable effluents incidental to vessel use and generated by Type I and II marine sanitation devices approved in accordance with section 312 of the Federal Water Pollution Control Act33 U.S.C. 1322;
(iii) Water generated by routine vessel operations (
(iv) Engine exhaust; or
(v) Discharge of biodegradable materials for traditional ceremonies associated with culturally important customs and usage (
(5) Discharging or depositing any material or other matter outside of the Special Sanctuary Management Areas if the discharge or deposit subsequently enters and injures a sanctuary resource within the Special Sanctuary Management Areas.
(6) Dredging, drilling into, or otherwise altering in any way the submerged lands (including natural bottom formations, live rock and coral) within the Special Sanctuary Management Areas, except:
(i) To anchor a vessel on sandy bottom or substrate other than live rock or coral;
(ii) Routine maintenance of docks, seawalls, breakwaters, jetties, or piers authorized by any valid lease, permit, license, approval, or other authorization issued by any Federal, State, or local authority of competent jurisdiction;
(iii) Installation and maintenance of navigational aids by, or pursuant to valid authorization by, any Federal, State, or local authority of competent jurisdiction;
(iv) Activities associated with conducting harbor maintenance in accordance with a federal or state permit issued prior to [EFFECTIVE DATE OF FINAL RULE], including dredging of entrance channels during the time period of one year from the [final rule effective date];
(v) Aquaculture activities authorized under a permit issued by the State of Hawai`i Department of Land and Natural Resources, the State of Hawai`i Department of Health, the U.S. Army Corps of Engineers, or the National Marine Fisheries Service pursuant to applicable regulations under the appropriate fisheries management plan.
(vi) Lawful fishing activities authorized under a permit issued by the State of Hawai`i or the National Marine Fisheries Service pursuant to applicable regulations under the appropriate fisheries management plan.
(7) Possessing or using explosives within the Special Sanctuary Management Areas, except for valid law enforcement purposes.
(8) Introducing or otherwise releasing from within or into the Special Sanctuary Management Areas an introduced species, except species cultivated by aquaculture activities in state or federal waters pursuant to a valid lease, permit, license or other authorization issued by the State of Hawai`i Department of Natural Resources, or the National Marine Fisheries Service in effect on the effective date of the final regulation.
(9) Removing, damaging, or tampering with any historical or cultural resource within the sanctuary.
(10) Marking, defacing, or damaging in any way, or displacing or removing or tampering with any signs, notices, or placards, whether temporary or permanent, or with any monuments, stakes, posts, or other boundary markers related to the Sanctuary including boundary markers related to the Special Sanctuary Management Areas.
(11) Interfering with, obstructing, delaying or preventing an investigation, search, seizure or disposition of seized property in connection with enforcement of either of the Acts or any regulations issued under either of the Acts.
(b) The prohibitions in paragraph (a) of this section do not apply to activities necessary to respond to emergencies threatening life, property or the environment; or to activities necessary for valid law enforcement purposes. However, while such activities are not subject to paragraphs (a)(1) through (11) of this section, this paragraph (b) does not exempt the activity from the underlying prohibition or restriction under other applicable laws and regulations (
(c)(1) The prohibitions in this section do not apply to any activity authorized by any lease, permit, license, approval, or other authorization issued after the effective date of regulatory amendments to this section and issued by any Federal, State, or local authority of competent jurisdiction, provided that the applicant complies with 15 CFR 922.49, the Director notifies the applicant and authorizing agency that he or she does not object to issuance of the authorization, and the applicant complies with any terms and conditions the Director deems necessary to protect Sanctuary resources and qualities.
(2) The prohibitions in this section do not apply to activities associated with harbor maintenance including dredging of entrance channels, provided the applicant requests an authorization of a valid federal or state permit from the Director.
(d) The prohibitions in this section do not apply to any activity conducted in accordance with a general permit issued pursuant to § 922.188.
Where necessary to prevent or minimize the destruction of, loss of, or injury to a Sanctuary resource, or to minimize the imminent risk of such destruction, loss, or injury, any and all activities are subject to immediate temporary regulation, including prohibition. Before issuance of such regulations the Director shall consult to the extent practicable with any relevant Federal agency and the Governor of the State of Hawai`i. Emergency regulations shall not take effect in State waters of the Sanctuary until approved by the Governor of Hawai`i.
(a) Pursuant to section 307 of the NMSA, each violation of either of the Acts, or any regulation in this subpart is subject to a civil penalty of not more than $100,000. Each such violation is subject to forfeiture of property or Sanctuary resources seized in accordance with section 307 of the NMSA. Each day of a continuing violation constitutes a separate violation.
(b) Regulations setting forth the procedures governing the administrative proceedings for assessment of civil penalties for enforcement reasons, issuance and use of written warnings, and release or forfeiture of seized property appear at 15 CFR part 904.
(c) A person subject to an action taken for enforcement reasons for violation of these regulations or either of the Acts may appeal pursuant to the applicable procedures in 15 CFR part 904.
Under section 304(d) of the NMSA, Federal agency actions internal or external to a national marine sanctuary, including private activities authorized by licenses, leases, or permits, that are likely to destroy, cause the loss of, or injure any sanctuary resource are subject to consultation with the Director. The Federal agency proposing an action shall determine whether the activity is likely to destroy, cause the loss of, or injure a Sanctuary resource. To the extent practicable, consultation procedures under section 304(d) of the NMSA may be consolidated with interagency cooperation procedures required by other statutes, such as the ESA. The Director will attempt to provide coordinated review and analysis of all environmental requirements.
(a)
(1) The provisions of subpart E; and
(2) The relevant site specific regulations appearing in this subpart.
(b)
(1) Research—activities that constitute scientific research on or scientific monitoring of national marine sanctuary resources or qualities;
(2) Education—activities that enhance public awareness, understanding, or appreciation of a national marine sanctuary or national marine sanctuary resources or qualities;
(3) Management—activities that assist in managing a national marine sanctuary; or
(4) Installation of submarine cables—activities that involve the installation of a submarine cable
(c)
(1) The proposed activity will be conducted in a manner compatible with the primary objective of protection of national marine sanctuary resources and qualities, taking into account the following factors:
(i) The extent to which the conduct of the activity may diminish or enhance national marine sanctuary resources and qualities; and
(ii) Any indirect, secondary or cumulative effects of the activity.
(2) It is necessary to conduct the proposed activity within the national marine sanctuary to achieve its stated purpose;
(3) The methods and procedures proposed by the applicant are appropriate to achieve the proposed activity's stated purpose and eliminate, minimize, or mitigate adverse effects on sanctuary resources and qualities as much as possible;
(4) The duration of the proposed activity and its effects are no longer than necessary to achieve the activity's stated purpose;
(5) The expected end value of the activity to the furtherance of national marine sanctuary goals and purposes outweighs any potential adverse impacts on sanctuary resources and qualities from the conduct of the activity;
(6) The applicant is professionally qualified to conduct and complete the proposed activity;
(7) The applicant has adequate financial resources available to conduct and complete the proposed activity and terms and conditions of the permit;
(8) There are no other factors that would make the issuance of a permit for the activity inappropriate; and
(9) For the installation of submarine cables, the activity is not required to
Coordinates listed in this appendix are unprojected (Geographic) and based on the North American Datum of 1983.
Coordinates listed in this appendix are unprojected (Geographic) and based on the North American Datum of 1983.
The Maunalua SSMA extends throughout the sanctuary waters in Maunalua Bay south of Oahu and is defined by the coordinates in table B1 and the following textual description. Point 1 of the SSMA boundary is located roughly 1.3 nautical miles SE of Kūpikipiki`ō Point (Black Point) on the sanctuary boundary. From Point 1 the SSMA boundary extends along the sanctuary boundary to the east to Point 21 roughly 0.5 nautical miles south of Kawaihoa Point, Koko Head. From Point 21 the SSMA boundary extends towards Point 22 until it intersects the shoreline. From this intersection the boundary follows the shoreline to the west around Kawaihoa Point and north around Maunalua Bay until it intersects the line segment between Point 23 and Point 24 at the eastern entrance to Hawaii Kai Marina. From this intersection the boundary moves towards Point 24 across the entrance to the marina until it intersects the shoreline again. The boundary then follows the shoreline westward until it intersects the line segment between Point 25 and Point 26 at the western entrance to the Hawaii Kai Marina. From this intersection the boundary moves towards Point 26 across the entrance to the marina until it intersects the shoreline again. The
The Penguin Bank SSMA extends throughout the federal waters of the Penguin Bank area southwest of Moloka`i and is defined by the coordinates in table B2 and the following textual description. The SSMA boundary begins roughly 3.3 nautical miles west of `Īlio Point off the northwest tip of Moloka`i at Point 1 at the intersection of the sanctuary boundary and the three nautical mile line. From Point 1 the SSMA boundary follows the sanctuary boundary to the SW and then back around Penguin Bank to the NE to Point 158 located at the intersection of the sanctuary boundary and the three nautical mile line to the SSW of Lono Harbor on Moloka`i. From Point 158 the SSMA boundary approximates the three nautical mile line extending west and then north to Point 185 west of northwest tip of Moloka'i.
The Maui Nui Special Sanctuary Management Area (SSMA) extends throughout the federal waters of the Maui Nui area between Maui, Moloka`i and Lana`i and is defined by the coordinates in table B3 and the following textual description. Point 1 of the SSMA boundary is located at approximately the intersection of the Moloka`i three nautical mile line and the sanctuary boundary south of Kaunakakai on Moloka'i near the Kalohi Channel. From Point 1, the SSMA boundary extends eastward approximating the three nautical mile line south of the Moloka`i coastline to Point 29 in numerical order at approximately the intersection of the Moloka`i three nautical mile line and the sanctuary boundary line that extends across Pailolo Channel from Cape Halawa on Moloka`i to Lipoa Pt. on Maui. From Point 29, the SSMA boundary extends southeast to Point 30 at approximately the intersection of the Maui three nautical mile line and the sanctuary boundary line NW of Lipoa Point on Maui. From Point 30, the SSMA boundary curves southwest and then southeast approximating the three nautical mile line west and south of the Maui coastline until it intersects the Kaho`olawe three nautical mile line and the sanctuary boundary WNW of Molokini between Maui and Kaho`olawe at Point 87. From Point 87 the SSMA boundary briefly approximates the Kaho`'olawe three mile line extending west to Point 90 at the intersection of the three nautical mile line north of the coastline of Kaho`olawe and the sanctuary boundary. From Point 90, the SSMA boundary extends west along the sanctuary boundary across the Kealaikahiki Channel until it intersects the Lana`i three nautical mile line SE of Kamaiki Point at Point 133. From Point 133 the SSMA boundary extends north and then NW to the east of Lana`i to Point 161 at the intersection of the Lana`i three nautical mile line and the sanctuary boundary NW of Pohakuloa Point on Lana`i. From Point 161 the SSMA boundary then follows the sanctuary boundary north across the Kalohi Channel until it intersects with the Moloka'i three nautical mile line at Point 175 south of Kaunakakai on Moloka'i.
(a) A person may conduct an activity prohibited by subparts F through O, and Q, if conducted in accordance with the scope, purpose, terms and conditions of a permit issued under this section and subparts F through O, and Q, as appropriate. For the Florida Keys National Marine Sanctuary, a person may conduct an activity prohibited by subpart P if conducted in accordance with the scope, purpose, terms and conditions of a permit issued under § 922.166. For the Thunder Bay National Marine Sanctuary and Underwater Preserve, a person may conduct an activity prohibited by subpart R in accordance with the scope, purpose, terms and conditions of a permit issued under § 922.195.
(b) Applications for permits to conduct activities otherwise prohibited by subparts F through O, and Q, should be addressed to the Director and sent to the address specified in subparts F through O, and Q, or subpart R, as appropriate. An application must include:
(1) A detailed description of the proposed activity including a timetable for completion;
(2) The equipment, personnel and methodology to be employed;
(3) The qualifications and experience of all personnel;
(4) The potential effects of the activity, if any, on Sanctuary resources and qualities; and
(5) Copies of all other required licenses, permits, approvals or other authorizations.
(c) Upon receipt of an application, the Director may request such additional information from the applicant as he or she deems necessary to act on the application and may seek the views of any persons or entity, within or outside the Federal government, and may hold a public hearing, as deemed appropriate.
(d) The Director, at his or her discretion, may issue a permit, subject to such terms and conditions as he or she deems appropriate, to conduct a prohibited activity, in accordance with the criteria found in subparts F through O, and Q, or subpart R, as appropriate. The Director shall further impose, at a minimum, the conditions set forth in the relevant subpart.
(e) A permit granted pursuant to this section is nontransferable.
(f) The Director may amend, suspend, or revoke a permit issued pursuant to this section for good cause. The Director may deny a permit application pursuant to this section, in whole or in part, if it is determined that the permittee or applicant has acted in violation of the terms and conditions of a permit or of the regulations set forth in this section or subparts F through O, and Q, subpart R or for other good cause. Any such action shall be communicated in writing to the permittee or applicant by certified mail and shall set forth the reason(s) for the action taken. Procedures governing permit sanctions and denials for enforcement reasons are set forth in subpart D of 15 CFR part 904.
(a) A person may conduct an activity prohibited by subparts L through R of the part, if such activity is specifically authorized by any valid Federal, State, or local lease, permit, license, approval, or other authorization issued after the effective date of Sanctuary designation, or in the case of the Florida Keys National Marine Sanctuary after the effective date of the regulations in subpart P, provided that:
(1) The applicant notifies the Director, in writing, of the application for such authorization (and of any application for an amendment, renewal, or extension of such authorization) within fifteen (15) days of the date of filing of the application or the effective date of Sanctuary designation, or in the case of the Florida Keys National Marine Sanctuary the effective date of the regulations in subpart P, whichever is later;
(2) The applicant complies with the other provisions of this section;
(3) The Director notifies the applicant and authorizing agency that he or she does not object to issuance of the authorization (or amendment, renewal, or extension); and
(4) The applicant complies with any terms and conditions the Director deems reasonably necessary to protect Sanctuary resources and qualities.
(b) Any potential applicant for an authorization described in paragraph (a) of this section may request the Director to issue a finding as to whether the activity for which an application is intended to be made is prohibited by subparts L through R, as appropriate.
(c) Notification of filings of applications should be sent to the Director, Office of Ocean and Coastal Resource Management at the address specified in subparts L through R of this part, as appropriate. A copy of the application must accompany the notification.
(d) The Director may request additional information from the
(e) The Director shall notify, in writing, the agency to which application has been made of his or her pending review of the application and possible objection to issuance. Upon completion of review of the application and information received with respect thereto, the Director shall notify both the agency and applicant, in writing, whether he or she has an objection to issuance and what terms and conditions he or she deems reasonably necessary to protect Sanctuary resources and qualities, and reasons therefor.
(f) The Director may amend the terms and conditions deemed reasonably necessary to protect Sanctuary resources and qualities whenever additional information becomes available justifying such an amendment.
(g) Any time limit prescribed in or established under this § 922.49 may be extended by the Director for good cause.
(h) The applicant may appeal any objection by, or terms or conditions imposed by, the Director to the Assistant Administrator or designee in accordance with the provisions of § 922.50.
Except for permit actions taken for enforcement reasons (see subpart D of 15 CFR part 904 for applicable procedures), an applicant for, or a holder of, a National Marine Sanctuary permit; an applicant for, or a holder of, a Special Use permit issued pursuant to section 310 of the Act; a person requesting certification of an existing lease, permit, license or right of subsistence use or access under § 922.47; or, for those Sanctuaries described in subparts L through R, an applicant for a lease, permit, license or other authorization issued by any Federal, State, or local authority of competent jurisdiction (hereinafter appellant) may appeal to the Assistant Administrator:
(a) The granting, denial, conditioning, amendment, suspension or revocation by the Director of a National Marine Sanctuary or Special Use permit;
(b) The conditioning, amendment, suspension or revocation of a certification under § 922.47; or
(c) For those Sanctuaries described in subparts L through R, the objection to issuance of or the imposition of terms and conditions on a lease, permit, license or other authorization issued by any Federal, State, or local authority of competent jurisdiction.
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration |