| Page Range | 61273-61715 | |
| FR Document |
| Page and Subject | |
|---|---|
| 80 FR 61474 - Sunshine Act: Notice of Agency Meeting | |
| 80 FR 61275 - Delegation of Authority Under Sections 506(a)(1) and 552(c)(2) of the Foreign Assistance Act of 1961 | |
| 80 FR 61273 - Delegation of Authority Under the National Defense HEADAuthorization Act for Fiscal Year 2015 | |
| 80 FR 61424 - Proposed Data Collection Submitted for Public Comment and Recommendations | |
| 80 FR 61495 - In the Matter of Energy Northwest; Columbia Generating Station | |
| 80 FR 61500 - Virginia Electric and Power Company; North Anna Power Station; Independent Spent Fuel Storage Installation | |
| 80 FR 61333 - Defense Federal Acquisition Regulation Supplement: Evaluating Reasonableness of Price for Commercial Items (DFARS Case 2013-D034) | |
| 80 FR 61454 - United States v. Cox Enterprises, Inc. et al.; Proposed Final Judgment and Competitive Impact Statement | |
| 80 FR 61503 - Sunshine Act Meeting | |
| 80 FR 61406 - Notice of Opportunity To Comment on an Analysis of the Greenhouse Gas Emissions Attributable to Production and Transport of Jatropha Curcas Oil for Use in Biofuel Production | |
| 80 FR 61419 - Proposed Information Collection Request; Comment Request; Information Collection Request for Reporting Requirements for BEACH Act Grants (Renewal) | |
| 80 FR 61443 - Albuquerque Indian School District-Liquor Control Ordinance | |
| 80 FR 61566 - Senior Executive Service; Legal Division Performance Review Board | |
| 80 FR 61441 - Notice of Certain Operating Cost Adjustment Factors for 2016 | |
| 80 FR 61317 - Interpretation of Notification Requirements To Exclude Model Aircraft; Correction | |
| 80 FR 61373 - Water Infrastructure Business Development Mission to Singapore, Vietnam, and the Philippines | |
| 80 FR 61562 - Twentieth Meeting: RTCA Special Committee (225) Rechargeable Lithium Battery and Battery Systems | |
| 80 FR 61362 - Welded Line Pipe From the Republic of Turkey: Final Determination of Sales at Less Than Fair Value | |
| 80 FR 61361 - Circular Welded Carbon Steel Pipes and Tubes From Turkey: Final Results of Countervailing Duty Administrative Review; Calendar Year 2013 and Rescission of Countervailing Duty Administrative Review, in Part | |
| 80 FR 61369 - Brass Sheet and Strip From Germany: Final Results of Antidumping Duty Administrative Review and Final Determination of No Shipments; 2013-2014 | |
| 80 FR 61447 - Renewal of Approved Information Collection; Control Number 1004-0058 | |
| 80 FR 61318 - Magnuson-Stevens Act Provisions; Fisheries Off West Coast States; Pacific Coast Groundfish Fishery; 2015-2016 Biennial Specifications and Management Measures; Inseason Adjustments | |
| 80 FR 61371 - Welded Line Pipe From the Republic of Turkey: Final Affirmative Countervailing Duty Determination | |
| 80 FR 61402 - Environmental Management Site-Specific Advisory Board, Hanford | |
| 80 FR 61358 - Proposed Foreign-Trade Zone-Hitchcock, Texas; Under Alternative Site Framework | |
| 80 FR 61366 - Welded Line Pipe From the Republic of Korea: Final Determination of Sales at Less Than Fair Value | |
| 80 FR 61403 - Environmental Management Site-Specific Advisory Board, Portsmouth | |
| 80 FR 61372 - Prestressed Concrete Steel Wire Strand From the People's Republic of China: Continuation of the Antidumping and Countervailing Duty Orders | |
| 80 FR 61443 - Endangered and Threatened Wildlife and Plants; Initiation of a 5-Year Review of the Polar Bear | |
| 80 FR 61336 - Announcement of Grant Application Deadlines and Funding Levels for the Assistance to High Energy Cost Rural Communities Grant Program | |
| 80 FR 61425 - Issuance of Final Guidance Publications | |
| 80 FR 61448 - BLM Director's Responses to the Appeals by the Governors of Idaho, Nevada, North Dakota, South Dakota, and Utah Governors of the BLM State Directors' Governor's Consistency Review Determination | |
| 80 FR 61384 - Privacy Act of 1974; System of Records | |
| 80 FR 61365 - Welded Line Pipe From the Republic of Korea: Final Negative Countervailing Duty Determination | |
| 80 FR 61368 - Certain Stilbenic Optical Brightening Agents From Taiwan: Final Results of Antidumping Duty Administrative Review; 2013-2014 | |
| 80 FR 61561 - 30-Day Notice of Proposed Information Collection: Six DDTC Information Collections | |
| 80 FR 61552 - Bureau of Consular Affairs; Registration for the Diversity Immigrant (DV-2017) Visa Program | |
| 80 FR 61376 - North Pacific Fishery Management Council; Public Meeting | |
| 80 FR 61383 - Proposed Collection; Comment Request | |
| 80 FR 61293 - Infant Formula: The Addition of Minimum and Maximum Levels of Selenium to Infant Formula and Related Labeling Requirements; Confirmation of Effective Date | |
| 80 FR 61436 - National Advisory Council on the National Health Service Corps; Notice of Meeting | |
| 80 FR 61433 - Agency Information Collection Activities; Proposed Collection; Comment Request; Quantitative Information in Direct-to-Consumer Television Advertisements | |
| 80 FR 61430 - Agency Information Collection Activities; Proposed Collection; Comment Request; Recommended Recordkeeping for Cosmetic Good Manufacturing Practices | |
| 80 FR 61382 - Proposed Collection; Comment Request | |
| 80 FR 61388 - Proposed Collection; Comment Request | |
| 80 FR 61423 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
| 80 FR 61422 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
| 80 FR 61392 - Proposed Collection; Comment Request | |
| 80 FR 61400 - Proposed Collection; Comment Request | |
| 80 FR 61332 - Request for Comment on the Effectiveness of Financial Disclosures About Entities Other Than the Registrant | |
| 80 FR 61564 - Additional Designations, Foreign Narcotics Kingpin Designation Act | |
| 80 FR 61386 - Proposed Collection; Comment Request | |
| 80 FR 61359 - Order Denying Export Privileges | |
| 80 FR 61564 - Michael R. Bennett and Workplace Compliance; Removal from the Public Interest Exclusion List | |
| 80 FR 61376 - Takes of Marine Mammals Incidental to Specified Activities; Seabird Research Activities in Central California, 2015-2016 | |
| 80 FR 61439 - Submission for OMB Review; 30-Day Comment Request: National Institute of Mental Health (NIMH) Recruitment Milestone Reporting System | |
| 80 FR 61332 - Disguised Payments for Services; Extension of Comment Period | |
| 80 FR 61389 - Defense Business Board; Notice of Federal Advisory Committee Meeting | |
| 80 FR 61387 - Proposed Collection; Comment Request | |
| 80 FR 61358 - In the Matter of Rex Gene Maralit, Inmate Number-80731-053, FCI Ashland, Federal Correctional Institution, P.O. Box 6001, Ashland, KY 41105: Order Denying Export Privileges | |
| 80 FR 61440 - Submission for OMB Review; 30-Day Comment Request: International HIV/AIDS Research Fellowship Award Program (NIDA) | |
| 80 FR 61302 - Design Standards for Highways | |
| 80 FR 61563 - Federal Transit Administration Notice To Rescind the Record of Decision (ROD) for the Baltimore Red Line Project Baltimore County and City, Maryland | |
| 80 FR 61395 - Proposed Collection; Comment Request | |
| 80 FR 61401 - Agency Information Collection Activities; Comment Request; William D. Ford Federal Direct Loan Program General Forbearance Request | |
| 80 FR 61402 - Agency Information Collection Activities; Submission to the Office of Management and Budget for Review and Approval; Comment Request; Student Assistance General Provisions-Student Right-to-Know (SRK) | |
| 80 FR 61564 - Notifications of Trails Act Agreement and Substitute Sponsorship | |
| 80 FR 61419 - Agency Information Collection Activities: Comment Request | |
| 80 FR 61425 - Submission for OMB Review; Comment Request | |
| 80 FR 61298 - Physical Medicine Devices; Reclassification of Shortwave Diathermy for All Other Uses, Henceforth To Be Known as Nonthermal Shortwave Therapy | |
| 80 FR 61426 - Organon USA Inc. et al.; Withdrawal of Approval of 67 New Drug Applications and 128 Abbreviated New Drug Applications | |
| 80 FR 61308 - Notional Principal Contracts; Swaps With Nonperiodic Payments | |
| 80 FR 61423 - Agency Forms Undergoing Paperwork Reduction Act Review | |
| 80 FR 61298 - New Animal Drugs for Use in Animal Feed; Withdrawal of Approval of a New Animal Drug Application; Penicillin G Procaine | |
| 80 FR 61293 - New Animal Drugs; Approval of New Animal Drug Applications; Withdrawal of Approval of a New Animal Drug Application; Change of Sponsor; Change of Sponsor's Address | |
| 80 FR 61384 - Global Positioning System Directorate (GPSD) Meeting Notice | |
| 80 FR 61403 - Combined Notice of Filings #2 | |
| 80 FR 61511 - New Postal Product | |
| 80 FR 61404 - Combined Notice of Filings #1 | |
| 80 FR 61405 - Combined Notice Of Filings | |
| 80 FR 61405 - Combined Notice of Filings #1 | |
| 80 FR 61390 - Proposed Collection; Comment Request | |
| 80 FR 61494 - Information Collection: NRC Form 748, National Source Tracking Transaction Report | |
| 80 FR 61396 - Proposed Collection; Comment Request | |
| 80 FR 61381 - Proposed Collection; Comment Request | |
| 80 FR 61439 - National Institute of Neurological Disorders and Stroke; Notice of Closed Meetings | |
| 80 FR 61436 - National Cancer Institute; Notice of Closed Meetings | |
| 80 FR 61437 - Center for Scientific Review; Notice of Closed Meetings | |
| 80 FR 61438 - National Institute of Environmental Health Sciences; Notice of Closed Meetings | |
| 80 FR 61393 - Proposed Collection; Comment Request | |
| 80 FR 61471 - Renewal of the Native American Employment and Training Council (NAETC) Charter | |
| 80 FR 61389 - Proposed Collection; Comment Request | |
| 80 FR 61504 - Excepted Service | |
| 80 FR 61507 - Excepted Service | |
| 80 FR 61277 - Prevailing Rate Systems; Special Wage Schedules for U.S. Army Corps of Engineers Flood Control Employees of the Vicksburg District in Mississippi | |
| 80 FR 61436 - Meeting of the National Advisory Committee on Children and Disasters | |
| 80 FR 61492 - In the Matter of Nuclear Innovation North America LLC, Combined Licenses for South Texas Project, Units 3 and 4; Notice of Hearing | |
| 80 FR 61356 - Notice of Public Meeting of the Illinois Advisory Committee for a Meeting To Discuss Civil Rights Issues in the State, and Potential Next Project Topics for the Committee's Investigation | |
| 80 FR 61357 - Notice of Public Meeting of the Nebraska Advisory Committee To Discuss Findings and Recommendations Resulting From Its Inquiry Into the Civil Rights Impact of Nebraska's 2009 Legislative Bill 403 | |
| 80 FR 61357 - Notice of Public Meeting of the Missouri Advisory Committee to Discuss Themes and Findings Resulting From Testimony Received Regarding Civil Rights and Police/Community Interactions in the State | |
| 80 FR 61422 - Notice of Termination; 10404, Piedmont Community Bank, Gray, Georgia | |
| 80 FR 61540 - Self-Regulatory Organizations; Chicago Stock Exchange, Inc.; Order Granting Accelerated Approval of a Proposed Rule Change, as Modified by Amendment No. 1 Thereto, To Adopt and Implement CHX SNAP SM | |
| 80 FR 61421 - Consumer Advisory Committee Meeting | |
| 80 FR 61503 - Advisory Committee on Reactor Safeguards (ACRS) Meeting of the Acrs Subcommittee on Reliability and PRA; Notice of Meeting | |
| 80 FR 61499 - Advisory Committee on Reactor Safeguards (ACRS); Meeting of the ACRS Subcommittee on Structural Analysis; Notice of Meeting | |
| 80 FR 61469 - Bulk Manufacturer of Controlled Substances Application: American Radiolabeled Chemicals, Inc. | |
| 80 FR 61469 - Importer of Controlled Substances Registration: Unither Manufacturing, LLC | |
| 80 FR 61470 - Bulk Manufacturer of Controlled Substances Application: Apertus Pharmaceuticals | |
| 80 FR 61470 - Bulk Manufacturer of Controlled Substances Application: Cambridge Isotope Lab | |
| 80 FR 61495 - Advisory Committee on Reactor Safeguards (ACRS), Meeting of the ACRS Subcommittee on AP1000 | |
| 80 FR 61397 - Submission for OMB Review; Comment Request | |
| 80 FR 61475 - Advisory Committee on Reactor Safeguards (ACRS) Meeting of the Acrs Subcommittee on Thermal-Hydraulic Phenomena; Notice of Meeting | |
| 80 FR 61471 - Agency Information Collection Activities; Proposed Collection; Comments Requested; Revision of a Currently Approved Collection: Office for Victims of Crime Training and Technical Assistance Center (OVC TTAC) Feedback Form Package | |
| 80 FR 61309 - Safety Zone, Great Egg Harbor Bay; Somers Point, NJ | |
| 80 FR 61535 - Submission for OMB Review; Comment Request | |
| 80 FR 61539 - Submission for OMB Review; Comment Request | |
| 80 FR 61536 - Submission for OMB Review; Comment Request | |
| 80 FR 61512 - Submission for OMB Review; Comment Request | |
| 80 FR 61551 - Submission for OMB Review; Comment Request | |
| 80 FR 61379 - Endangered and Threatened Species; Recovery Plans | |
| 80 FR 61527 - Self-Regulatory Organizations; BOX Options Exchange LLC; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend Rule 7270 (Block Trades) | |
| 80 FR 61513 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Filing of Proposed Rule Change for New Equity Trading Rules Relating to Auctions for Pillar, the Exchange's New Trading Technology Platform | |
| 80 FR 61529 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Amending the NYSE Arca Equities Schedule of Fees and Charges for Exchange Services | |
| 80 FR 61537 - Self-Regulatory Organizations; NASDAQ OMX PHLX LLC; Notice of Filing of Proposed Rule Change Relating to Active Specialized Quote Feed Port Fee | |
| 80 FR 61545 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing of a Proposed Rule Change To Merge FINRA Dispute Resolution, Inc. Into and With FINRA Regulation, Inc. | |
| 80 FR 61476 - Biweekly Notice: Applications and Amendments to Facility Operating Licenses and Combined Licenses Involving No Significant Hazards Considerations | |
| 80 FR 61502 - Expanded River Reconnaissance Paleoliquefaction Study Area | |
| 80 FR 61475 - Southern California Edison; San Onofre Nuclear Generating Station, Units 2 and 3 | |
| 80 FR 61563 - Sixty-Fourth Meeting: Special Committee (186) Automatic Dependent Surveillance-Broadcast (ADS-B) | |
| 80 FR 61335 - Submission for OMB Review; Comment Request | |
| 80 FR 61472 - SGS North America, Inc.: Application for Expansion of Recognition | |
| 80 FR 61398 - Proposed Collection; Comment Request | |
| 80 FR 61378 - Proposed Information Collection; Comment Request; Groundfish Tagging Program | |
| 80 FR 61399 - Proposed Collection; Comment Request | |
| 80 FR 61394 - Proposed Collection; Comment Request | |
| 80 FR 61422 - Update to Notice of Financial Institutions for Which the Federal Deposit Insurance Corporation has Been Appointed Either Receiver, Liquidator, or Manager | |
| 80 FR 61420 - Information Collection Being Reviewed by the Federal Communications Commission Under Delegated Authority | |
| 80 FR 61311 - Air Plan Approval; MI; Infrastructure SIP Requirements for the 2008 Ozone, 2010 NO2 | |
| 80 FR 61391 - Proposed Collection; Comment Request | |
| 80 FR 61420 - Agency Information Collection Activities: Comment Request | |
| 80 FR 61424 - Statement of Organization, Functions, and Delegations of Authority | |
| 80 FR 61327 - Airworthiness Directives; Airbus Airplanes | |
| 80 FR 61278 - Automated Commercial Environment (ACE) Filings for Electronic Entry/Entry Summary (Cargo Release and Related Entry) | |
| 80 FR 61475 - Membership of National Science Foundation's Senior Executive Service Performance Review Board | |
| 80 FR 61375 - Administration National Sea Grant Advisory Board | |
| 80 FR 61330 - Airworthiness Directives; Dowty Propellers Constant Speed Propellers | |
| 80 FR 61646 - Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas | |
| 80 FR 61610 - Pipeline Safety: Safety of Hazardous Liquid Pipelines | |
| 80 FR 61402 - Agency Information Collection Activities; Comment Request; Application for Grants Under the Talent Search Program | |
| 80 FR 61568 - Endangered and Threatened Wildlife and Plants; Proposed Endangered Status for Five Species From American Samoa | |
| 80 FR 61334 - Agency Information Collection Activities: Request for Comments; Renewal of a Currently Approved Collection: Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants and Awardees |
National Agricultural Statistics Service
Rural Utilities Service
Foreign-Trade Zones Board
Industry and Security Bureau
International Trade Administration
National Oceanic and Atmospheric Administration
Air Force Department
Army Department
Defense Acquisition Regulations System
Navy Department
Federal Energy Regulatory Commission
Agency for Toxic Substances and Disease Registry
Centers for Disease Control and Prevention
Children and Families Administration
Food and Drug Administration
Health Resources and Services Administration
National Institutes of Health
Coast Guard
U.S. Customs and Border Protection
Fish and Wildlife Service
Indian Affairs Bureau
Land Management Bureau
Antitrust Division
Drug Enforcement Administration
Employment and Training Administration
Occupational Safety and Health Administration
Federal Aviation Administration
Federal Highway Administration
Federal Transit Administration
Pipeline and Hazardous Materials Safety Administration
Surface Transportation Board
Foreign Assets Control Office
Internal Revenue Service
Consult the Reader Aids section at the end of this issue for phone numbers, online resources, finding aids, and notice of recently enacted public laws.
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.
U.S. Office of Personnel Management.
Final rule.
The U.S. Office of Personnel Management (OPM) is issuing a final rule to establish special wage schedules specific to nonsupervisory, leader, and supervisory wage employees of the U.S. Army Corps of Engineers (USACE) who work at flood control dams (also known as reservoir projects) at the Vicksburg District of the Mississippi Valley Division. This final rule assigns lead agency responsibility for establishing and issuing these special wage schedules to the Department of Defense (DOD). The special wage schedules established will have rates of pay identical to the Memphis, TN, appropriated fund Federal Wage System (FWS) wage schedules and will be adjusted at the same times as those scheduled in the future.
Madeline Gonzalez, by telephone at (202) 606-2858 or by email at
On June 5, 2015, OPM issued a proposed rule (80 FR 32042) to establish special wage schedules specific to nonsupervisory, leader, and supervisory wage employees of the U.S. Army Corps of Engineers (USACE) who work at flood control dams (also known as reservoir projects) at the Vicksburg District of the Mississippi Valley Division.
The four lakes of the District are currently in two separate wage areas. The Vicksburg District of the Mississippi Valley Division is comprised of the following four lakes:
Because a unique situation exists in the Vicksburg District in that all four lakes are managed as one installation, the Federal Prevailing Rate Advisory Committee (FPRAC), the national labor-management committee responsible for advising OPM on matters concerning the pay of FWS employees, recommended by majority vote that DOD establish and issue special wage schedules for USACE employees whose duty station is located in one of the lakes that comprise the Vicksburg District of the Mississippi Valley Division. This final rule will create a special wage schedule practice in this unique circumstance as recommended by FPRAC. The special wage schedules will be established using rates identical to the Memphis, TN, appropriated fund FWS wage schedule.
The 30-day comment period ended on July 6, 2015. OPM received one comment from local agency management supporting this change. These special wage schedules will apply on the first day of the first applicable pay period beginning on or after 60 days following publication of the final regulations. USACE employees with duty stations at one of the lakes of the Vicksburg District will transfer to the new special wage schedules on a step-by-step basis. No current employee will have his or her pay rate reduced as a result of implementing these new special wage schedules.
I certify that these regulations will not have a significant economic impact on a substantial number of small entities because they will affect only Federal agencies and employees.
Administrative practice and procedure, Freedom of information, Government employees, Reporting and recordkeeping requirements, Wages.
Accordingly, the U.S. Office of Personnel Management amends 5 CFR part 532 as follows:
5 U.S.C. 5343, 5346; § 532.707 also issued under 5 U.S.C. 552.
(a)(1) The Department of Defense will establish special wage schedules for wage employees of the U.S. Army Corps of Engineers who work at flood control dams (also known as reservoir projects) and whose duty station is located in one of the lakes that comprise the Vicksburg District of the Mississippi Valley Division.
(2) These special wage schedules will provide rates of pay for nonsupervisory, leader, and supervisory employees. These special schedule positions will be identified by pay plan codes XR
(b) The Vicksburg District of the Mississippi Valley Division is comprised of the following four lakes:
(c) Special wage schedules shall be established at the same time and with rates identical to the Memphis, TN, appropriated fund wage schedule.
U.S. Customs and Border Protection, Department of Homeland Security; Department of the Treasury.
Interim final rule.
This document amends the U.S. Customs and Border Protection (CBP) regulations to reflect that on November 1, 2015, the Automated Commercial Environment (ACE) will be a CBP-authorized Electronic Data Interchange (EDI) System. This regulatory document informs the public that the Automated Commercial System (ACS) is being phased out as a CBP-authorized EDI System for the processing electronic entry and entry summary filings (also known as entry filings). ACE will replace the Automated Commercial System (ACS) as the CBP-authorized EDI system for processing commercial trade data. This document also announces the conclusion of the ACE
You may submit comments, identified by docket number USCBP-2015-0045, by
•
•
For policy questions related to ACE, contact Josephine Baiamonte, Director, Business Transformation, ACE Business Office, Office of International Trade, at
Interested persons are invited to participate in this rulemaking by submitting written data, views, or arguments on all aspects of the interim rule. U.S. Customs and Border Protection (CBP) also invites comments that relate to the economic, environmental, or federalism effects that might result from this interim rule. Comments that will provide the most assistance to CBP in finalizing these regulations will reference a specific portion of the interim rule, explain the reason for any recommended change, and include data, information, or authority that support such recommended change.
Section 484 of the Tariff Act of 1930, as amended (19 U.S.C. 1484), establishes the requirement for importers of record to make entry for merchandise to be imported into the customs territory of the United States. Customs entry information is used by CBP and partner government agencies to determine whether merchandise may be released from CBP custody.
The customs entry requirements were amended by Title VI of the North American Free Trade Agreement Implementation Act (Pub. L. 103-182, 107 Stat. 2057, December 8, 1993), commonly known as the Customs Modernization Act, or Mod Act. In particular, section 637 of the Mod Act amended section 484(a)(1)(A) of the Tariff Act (19 U.S.C. 1484(a)(1)(A)) by revising the requirement to make and complete customs entry by submitting documentation to CBP, to also allow in the alternative, the transmission of entry information electronically pursuant to a CBP-authorized electronic data interchange system. Further, section 634 of the Mod Act amended section 401 of the Tariff Act (19 U.S.C. 1401) to add definitions related to the electronic filing of the entry and entry summary. The term “electronic entry” is defined as the electronic transmission to CBP of entry information required for the entry of merchandise, and entry summary information required for the classification and appraisement of the merchandise, the verification of statistical information, and the determination of compliance with applicable law. The term “electronic transmission” is defined as the transfer of data or information through an authorized electronic data interchange system consisting of, but not limited to, computer modems and computer networks. The term “electronic data interchange system” is defined as any established mechanism approved by the CBP Commissioner through which information can be transferred electronically.
To implement the Mod Act, CBP has been modernizing the business processes essential to securing U.S. borders, facilitating the flow of legitimate shipments, and targeting illicit goods. The key automated system behind these initiatives is the Automated Commercial Environment (ACE). ACE is the backbone of CBP trade data processing and risk management activities and provides a single, centralized access point to connect CBP, other International Trade Data System (ITDS) agencies, and the trade community.
On February 19, 2014, President Obama issued Executive Order (EO) 13659,
CBP will complete the development of core trade processing capabilities in ACE and decommission corresponding capabilities in legacy systems by the end of 2016. At that time, ACE will provide a Single Window for processing trade data, and become the primary system through which the international trade community will submit import and export data and the Government will determine admissibility.
CBP established the specific requirements and procedures for the electronic filing of entry and entry summary data for imported merchandise through the Automated Broker Interface (ABI), originally a module of the Automated Commercial System (ACS), in a final rule (T.D. 90-92) published in the
CBP has been developing and testing ACE over the last several years as the successor EDI system to ACS. CBP has provided significant public outreach through events and on-line information to help ensure that the international trade community is fully engaged in the transition from ACS to ACE as the system authorized by the Commissioner for processing entry and entry summary information. CBP has conducted numerous tests of the filing of entries and entry summaries through ACE.
During the transition from ACS to ACE, filers have continued to use the ABI functionality to transmit entry and entry summary information both to the ACS and ACE EDI systems. In this document, CBP is announcing, consistent with 19 U.S.C. 1401, that, with the conclusion of National Customs Automation Program (NCAP) tests discussed below, ACE will be an authorized electronic data interchange system authorized by the Commissioner to which entry and entry summary filings (also known as entry filings) can be transmitted electronically. It should be noted that Reconciliation entries are not affected by this change.
As part of the transition from ACS to ACE, CBP has been conducting tests of ACE under the NCAP. The NCAP was established by Subtitle B of the Mod Act.
On November 9, 2011, CBP published a general notice in the
CBP has published several notices announcing ACE tests related to the
The Cargo Release and ESAR Tests will terminate only with regard to requirements directly related to automated entry and entry summary that do not involve data from other ITDS agencies upon the effective date of this rule. Test participants may continue to participate in the test until that date.
As a result of the two tests discussed above having been successful, CBP is amending its regulations to provide that ACE is a CBP-authorized electronic data interchange (EDI) system for processing electronic entry and entry summary filings with CBP. As of the end of February 2016, CBP anticipates that ACE will be fully functional for filing entry and entry summary so that ACS will no longer be available for entry filings. CBP encourages filers to adjust their business practices by filing in ACE as of the effective date of this rule.
This rule amends sections 12.140, 24.23, 128.11, 128.23, 141.57, 141.58, 143.1, 143.31, 143.32, and 174.12 to replace references to the Automated Commercial System, or ACS, each place it appears in these sections with the phrase “ACE or any other CBP-authorized electronic data interchange system.” In section 24.23(a)(4)(i), regarding the Merchandise Processing Fee (MPF), we are retaining the reference to ACS, because that system will continue to be used to process payments, including MPF. We are adding the words “or any other CBP-authorized electronic data interchange system” to enable CBP to transition the payment processing functions to ACE at a later date.
This rule further amends certain definitions concerning the entry of merchandise in 19 CFR 141.0a to reflect that ACE is the CBP-authorized EDI system for processing trade data. In particular, the definitions for the following terms are revised to indicate filers may also submit required entry information electronically to ACE, as well as by paper, to CBP: “entry,” “entry summary,” “submission,” “filing,” “entered for consumption,” “entered for warehouse,” and “entered temporarily under bond.” Similarly, this rule amends the definitions related to the special entry procedures in 19 CFR 143.32 to replace reference to ACS with reference to ACE. Specifically, this rule also revises in 19 CFR 143.32 the definitions of the terms “ABI,” “electronic immediate delivery,” and “statement processing,” and adds a definition of the term “authorized electronic data interchange system,” to indicate that ACS is will no longer be the only CBP-authorized EDI system.
As the Automated Broker Interface, or ABI, continues to be the functionality that allows entry filers to transmit immediate delivery, entry and entry summary data to CBP, and to receive transmissions from CBP, there is no need to amend references to that term. However, this rule amends 19 CFR 143.32 to correct the definition of ABI which currently defines ABI as a module of ACS. This definition is inaccurate because ABI is a functionality that operates separately from ACS.
This rule further amends the document filing procedures within 19 CFR parts 4, 7, 10, 12, 18-19, 24, 54, 102, 113, 123, 125, 128, 132, 134, 141-146, 148, 151-152, 158, 163, 174, 181, and 191 by providing filers with the option of transmitting electronic data to CBP. Specifically, this rule amends these parts to allow filers, in the alternative, to submit the electronic equivalent of CBP Forms (including CBP Forms 28, 29, 247, 434, 3229, 3289, 3299, 3311, 3461, 4315, 4455, 4457, 4647, 7501, 7533, and 7552) and other documents that may be required by CBP or other government agencies at the time of entry. These documents include the records and information required for the entry of merchandise listed in the Appendix to part 163 (commonly referred to as the “(a)(1)(A)” list). This amendment does not mean that an electronic equivalent exists, but merely that an electronic equivalent may be used when such an equivalent exists. Lastly, this rule makes technical corrections to the nomenclature of “Customs” or “Customs Service” to “CBP” in some existing regulatory text, and updates some text to comply with the Plain English initiative in regulatory drafting.
In consideration of the business process changes that may be necessary to achieve full compliance and to provide members of the trade community with sufficient time to transition from ACS to ACE, filers are encouraged to adjust their business practices at the current time so that they can file in ACE before the end of February of 2016 when it is anticipated that ACS will no longer be supported for entry and entry summary. Filers who have technical questions should contact their assigned client representative. Filers without an assigned client representative should contact Steven Zaccaro, Client Representative Branch, ACE Business Office, Office of International Trade, at
Filers interested in participating in these tests should review the notices published in the
This document announces the conclusion of the
Importers currently can file required forms electronically to a CBP-authorized electronic data interchange system, by paper, or a combination of both (hybrid filing). When importers file a paper or hybrid entry, they fill out the required documents on their computer, print the documents, and then send the documents to their broker or to the port of entry by either mail or a courier. CBP is considering proposing a rule to require importers to choose between submitting the required entry and entry summary documentation (including ITDS Agency documents) entirely electronically or entirely by paper. CBP would no longer accept any hybrid filings, except in limited circumstances. This would mean that if an importer files one paper document not covered by the limited exceptions, the entire filing, including the report to CBP, must be on paper.
While CBP is considering this proposal, comments are invited on all aspects of a policy to eliminate hybrid filings, including economic, operational, and feasibility of implementation. In particular, CBP is interested in data and views on the following:
1. Assessments of costs of implementing the proposal, including IT, training, and compliance. Comments should include a discussion about how the requirement to file all on paper or all in electronic form, if adopted, would affect business operations, cost to government of processing paper, and impact on health, safety, and the environment when enforcement and compliance agencies may see electronic data reduced.
2. Assessment of net benefits that may include processing enhancements, savings in processing time, and other perceived quantitative and qualitative benefits.
3. Estimates of time needed to comply with the proposal, if adopted.
4. Suggestions for including regulatory flexibilities such as phased-in compliance dates, exceptions, and safe harbors that will ease compliance for filers, especially those filers that are small entities.
5. Suggestions as to documentation and data that should be excepted from the proposed policy and supporting information to explain the appropriateness of the exception.
Pursuant to 5 U.S.C. 553(b)(3), public notice is inapplicable to these interim regulations because they concern matters relating to agency procedure and practice inasmuch as the changes involve updates to the format of the electronic submission of data to CBP's proprietary electronic data interchange (EDI) system from ACS to ACE for persons filing required information related to the importation of merchandise pursuant to 19 U.S.C. 1401 and 1484. Further, good cause exists pursuant to 5 U.S.C. 553(d) and 808(2), to issue these regulations without a delay in effective date. The transition from ACS to ACE does not substantively alter the underlying rights or interests of importers or filers, only the manner in which they present required information to the agency. By shifting to a modified electronic format for the submission of required data, CBP will be able to more efficiently determine whether merchandise presented for importation is admissible into the United States. In addition, although this interim rule will be codified on November 1, 2015, CBP anticipates that filers can continue to file in ACS or ACE until February 2016, when ACE will be fully functional for filing entry and entry summary. Accordingly, CBP and Treasury have determined that the requirements for prior notice and a delay in effective date are inapplicable, however the agencies are soliciting comments in this interim rule and will consider all comments received before issuing a final rule.
Executive Orders 13563 and 12866 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (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. OMB believes that this rule is an “economically significant regulatory action,” under section 3(f) of Executive Order 12866.
When importing to the United States, importers may file the required entry and entry summary documents to CBP in two ways: By paper or electronically through the Automated Broker Interface (ABI). The technical requirements to file in ABI are spelled out in the CBP and Trade Automated Interface Requirements (the CATAIR), which is available to the public on CBP's Web page.
If the importer chooses to file electronically, it submits the required data in ABI and the data then gets transmitted from ABI to a CBP system for processing. Originally, ABI transmitted the data to only the Automated Commercial System (ACS). Currently, the data can be transmitted to either ACS or the Automated Commercial Environment (ACE), depending on whether the importer has met the relevant CATAIR requirements.
The existing regulations set forth the requirements for how filers interact with CBP through ABI. In doing so, the regulations make reference to ACS several times. This rule replaces the ACS references in the regulations with “ACE or any other CBP-authorized EDI system.” This regulation also corrects the definition of ABI, which is currently defined as a module of ACS. This is an erroneous definition since ABI exists separately from ACS and is simply a functionality by which importers can file entries with CBP. With this rule, importers will continue to be able to file their entries electronically via ABI, which will now transmit all the entry data to ACE.
CBP acknowledges that importers and software developers who have not already made the changes required to transmit their entry information from ABI to ACE rather than to ACS will need to make these changes to comply with the ABI CATAIR specifications. The change in technical specifications for ABI filing is independent from this regulatory change. (Technical specifications change frequently and are done independently of any regulatory action.) What follows is a short analysis of the costs of the systems changes, some portion of which may be attributable to this rule.
Based on conversations with members of the trade community on CBP's Technical Advisory Group,
The cost of making software compatible with ACE will fall on the software developers and the 5 percent of importers who do not purchase a software product, because they develop their own software. CBP's ACE Business Office estimates that 150 businesses will need to make software modifications, including 112 importers who self-file and 38 software developers. According to the Technical Advisory Group, the cost of making these changes is covered by the existing fees software developers charge to their users. Many of these parties have already made the changes to take advantage of the added functionality available in ACE. According to CBP's ACE Business Office, of the 38 software developers that provide software to facilitate the filing of entries, 36 have already modified their systems to allow for filing in ACE. CBP does not know how many of the 112 self-filers have already modified their systems, but it is likely that many of these self-filers have already made the necessary changes. According to CBP data, as of April 2015, 53 percent of entries were filed in ABI in an ACE-compatible format. According to an estimate from a member of the Technical Advisory Group, it can cost from $25,000 to $90,000 to make the change to ACE formatting, including systems costs and training. This estimate also includes all the costs of converting to ACE, not just the cost of making the changes necessary to file entries in ACE format, so the actual costs necessary to file entries in ACE format is likely to be lower. Based on the range of costs to convert to ACE formatting, we estimate that it will cost our estimated 112 software vendors and 38 self-filers between $3.75 million and $13.5 million to file in ACE format. These estimates assume that all 150 software vendors and self-filers will incur costs to convert to ACE, which we previously noted is unlikely given that many of these parties have already made the change to take advantage of ACE's additional functionality. We invite comments on these estimates of system costs and on other transition costs.
This rule benefits the public by clarifying the information presented in the regulations regarding how importers interact with CBP via ABI. The broader regulatory and non-regulatory shift from ACS to ACE has substantial benefits to federal agencies and the public. Transitioning to ACE will expedite cargo processing; improve compliance with CBP and other government agency regulations; provide greater efficiency in receiving, processing, and sharing import data which will increase the effectiveness of federal agencies; and reduce redundant information requirements for the importing community. We note that these benefits of the transition to ACE are characterized by the same analytic difficulty as the costs; it is not clear what portion is attributable to this rule as opposed to other regulatory and non-regulatory actions. We invite comments that would allow for reasonable attribution of effects across these various actions.
The Regulatory Flexibility Act (5 U.S.C. 601
As there is no collection of information proposed in this document, the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. 3507) are inapplicable.
This document is being issued in accordance with § 0.1(a)(1) of the CBP Regulations (19 CFR 0.1(a)(1)) pertaining to the authority of the Secretary of the Treasury (or his/her delegate) to approve regulations related to certain customs revenue functions.
Customs duties and inspection, Entry, Exports, Freight, Harbors, Imports, Maritime carriers, Pollution, Reporting and recordkeeping requirements, Vessels.
American Samoa, Coffee, Customs duties and inspection, Guam, Guantanamo Bay, Imports, Insular possessions, Johnston Islands, Kingman Reef, Liquor, Midway Islands, Puerto Rico, Reporting and recordkeeping requirements, Wake Island, Wine.
Caribbean Basin initiative, Customs duties and inspection, Entry of merchandise, Exports, Imports, Reporting and recordkeeping requirements, Trade agreements.
Customs duties and inspection, Reporting and recordkeeping requirements.
Baggage, Bonds, Common carriers, Customs duties and inspection, Exports, Explosives, Foreign trade statistics, Freight, Imports, Merchandise in transit, Penalties, Prohibited merchandise, Railroad, Reporting and recordkeeping requirements, Restricted merchandise, Surety bonds, Transportation in bond, Vehicles, Vessels.
Customs duties and inspection, Exports, Freight, Imports, Reporting and recordkeeping requirements, Surety bonds, Warehouses, Wheat.
Accounting, Claims, Customs duties and inspection, Harbors, Imports, Reporting and recordkeeping requirements, Taxes.
Customs duties and inspection, Reporting and recordkeeping requirements.
Canada, Customs duties and inspection, Exports, Imports, Mexico, Reporting and recordkeeping requirements, Trade agreements.
Common carriers, Customs duties and inspection, Exports, Freight, Laboratories, Reporting and recordkeeping requirements, Surety bonds.
Administrative practice and procedure, Aircraft, Aliens, Baggage, Canada, Common carriers, Customs duties and inspection, Entry of merchandise, Fees, Forms (Written agreement), Freight, Immigration,
Customs duties and inspection, Freight, Government contracts, Harbors, Reporting and recordkeeping requirements.
Administrative practice and procedure, Customs duties and inspection, Entry, Express consignments, Freight, Imports, Reporting and recordkeeping requirements.
Agriculture and agricultural products, Customs duties and inspection, Quotas, Reporting and recordkeeping requirements.
Canada, Country of origin, Customs duties and inspection, Imports, Labeling, Marking, Mexico, Packaging and containers, Reporting and recordkeeping requirements, Trade agreements.
Customs duties and inspection, Entry of merchandise, Reporting and recordkeeping requirements.
Canada, Customs duties and inspection, Mexico, Reporting and recordkeeping requirements.
Customs duties and inspection, Entry of merchandise, Reporting and recordkeeping requirements.
Customs duties and inspection, Reporting and recordkeeping requirements, Warehouses.
Customs duties and inspection, Exports, Lotteries, Reporting and recordkeeping requirements.
Administrative practice and procedure, Customs duties and inspection, Exports, Foreign trade zones, Imports, Penalties, Petroleum, Reporting and recordkeeping requirements.
Airmen, Aliens, Baggage, Crewmembers, Customs duties and inspection, Declarations, Foreign officials, Government employees, International organizations, Privileges and immunities, Reporting and recordkeeping requirements, Seamen, Taxes, Trade agreements (U.S.-Canada Free-Trade Agreement).
Cigars and cigarettes, Cotton, Customs duties and inspection, Fruit juices, Laboratories, Metals, Imports, Reporting and recordkeeping requirements, Sugar, Wool.
Appraisement, Classification, Customs duties and inspection, Valuation.
Computer technology, Customs duties and inspection, Exports, Freight, Merchandise (lost, damaged, abandoned, exported), Reporting and recordkeeping requirements.
Administrative practice and procedure, Customs duties and inspection, Exports, Imports, Penalties, Reporting and recordkeeping requirements.
Administrative practice and procedure, Customs duties and inspection, Protests, Reporting and recordkeeping requirements, Trade agreements.
Administrative practice and procedure, Canada, Customs duties and inspection, Exports, Imports, Mexico, Reporting and recordkeeping requirements, Trade agreements.
Alcohol and alcoholic beverages, Claims, Customs duties and inspection, Exports, Foreign trade zones, Guantanamo Bay Naval Station, Cuba, Packaging and containers, Reporting and recordkeeping requirements, Trade agreements.
For the reasons stated above in the preamble, CBP amends parts 4, 7, 10, 12, 18, 19, 24, 54, 102, 113, 123, 125, 128, 132, 134, 141, 142, 143, 144, 145, 146, 148, 151, 152, 158, 163, 174, 181, and 191 of title 19 of the Code of Federal Regulations (19 CFR parts 4, 7, 10, 12, 18, 19, 24, 54, 102, 113, 123, 125, 128, 132, 134, 141, 142, 143, 144, 145, 146, 148, 151, 152, 158, 163, 174, 181, and 191) to read as follows:
5 U.S.C. 301; 19 U.S.C. 66, 1431, 1433, 1434, 1624, 2071 note; 46 U.S.C. 501, 60105.
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1623, 1624; 48 U.S.C. 1406i.
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States (HTSUS)), 1321, 1481, 1484, 1498, 1508, 1623, 1624, 3314.
5 U.S.C. 301; 19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States (HTSUS)), 1624.
Section 12.140 also issued under 19 U.S.C. 1484, 2416(a), 2171;
5 U.S.C. 301; 19 U.S.C. 66, 1202 (general Note 3(i), Harmonized Tariff Schedule of the United States), 1551, 1552, 1553, 1623, 1624.
5 U.S.C. 301; 19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1624.
5 U.S.C. 301; 19 U.S.C. 58a-58c, 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1505, 1520, 1624; 26 U.S.C. 4461, 4462; 31 U.S.C. 3717, 9701; Public Law 107-296, 116 Stat. 2135 (6 U.S.C. 1
Section 24.23 also issued under 19 U.S.C. 3332;
19 U.S.C. 66, 1202 (General Note 3(i); Section XV, Note 5, Harmonized Tariff Schedule of the United States), 1623, 1624.
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1624, 3314, 3592.
19 U.S.C. 66, 1623, 1624.
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1431, 1433, 1436, 1448,1624, 2071 note.
19 U.S.C. 66, 1565, and 1624.
19 U.S.C. 58c, 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1321, 1484, 1498, 1551, 1555, 1556, 1565, 1624.
(b)
(2)
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States (HTSUS)), 1623, 1624.
5 U.S.C. 301; 19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States (HTSUS)), 1304, 1624.
19 U.S.C. 66, 1448, 1484, 1498, 1624.
Section 141.66 also issued under 19 U.S.C. 1490, 1623.
Unless the context requires otherwise or a different definition is prescribed, the following terms will have the meanings indicated when used in connection with the entry of merchandise:
(a)
(b)
(c)
(d)
(1) The delivery to CBP, including electronic submission to the Automated Commercial Environment (ACE) or any other CBP-authorized electronic data interchange system, of the entry documentation or data required by section 484(a), Tariff Act of 1930, as amended (19 U.S.C. 1484(a)), to obtain the release of merchandise, or
(2) The delivery to CBP, including electronic submission to the Automated Commercial Environment (ACE) or any other CBP-authorized electronic data interchange system, together with the deposit of estimated duties, of the entry summary documentation or data required to assess duties, collect statistics, and determine whether other requirements of law and regulation are met, or
(3) The delivery to CBP, including electronic submission to the Automated Commercial Environment (ACE) or any other CBP-authorized electronic data interchange system, together with the deposit of estimated duties, of the entry summary documentation or data, which will serve as both the entry and the entry summary.
(e)
(f)
(g)
(h)
(i)
19 U.S.C. 66, 1448, 1484, 1624.
(a)
(b)
(a)
(b)
19 U.S.C. 66, 1321, 1414, 1481, 1484, 1498, 1624, 1641.
The Automated Broker Interface (ABI) allows participants to transmit data electronically to CBP through ABI and to receive transmissions from Automated Commercial Environment (ACE) or any other CBP-authorized electronic data interchange system. Its purposes are to improve administrative efficiency, enhance enforcement of customs and related laws, lower costs and expedite the release of cargo.
(a)
(b)
(j)
(p)
19 U.S.C. 66, 1484, 1557, 1559, 1624.
19 U.S.C. 66, 1202 General Note 3(i), Harmonized Tariff Schedule of the United States, 1624.
19 U.S.C. 66, 81a-81u, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1623, 1624.
19 U.S.C. 66, 1496, 1498, 1624. The provisions of this part, except for subpart C, are also issued under 19 U.S.C. 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States).
19 U.S.C. 66, 1202 (General Note 3(i) and (j), Harmonized Tariff Schedule of the United States (HTSUS), 1624.
19 U.S.C. 66, 1401a, 1500, 1502, 1624,
19 U.S.C. 66, 1624, unless otherwise noted. Subpart C is also issued under 19 U.S.C. 1563.
5 U.S.C. 301; 19 U.S.C. 66, 1484, 1508; 1509, 1510, 1624.
19 U.S.C. 66, 1514, 1515, 1624.
19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1624, 3314;
5 U.S.C. 301; 19 U.S.C. 66, 1202 (General Note 3(i), Harmonized Tariff Schedule of the United States), 1313, 1624;
Food and Drug Administration, HHS.
Final rule; confirmation of effective date.
The Food and Drug Administration (FDA or we) is confirming the effective date of June 22, 2016, for the final rule that appeared in the
Effective date of final rule published in the
Carrie Assar, Center for Food Safety and Applied Nutrition (HFS-850), Food and Drug Administration, 5100 Paint Branch Pkwy., College Park, MD 20740-3835, 240-402-1451.
In the
We gave interested persons until July 23, 2015, to file objections or requests for a hearing. We received no objections or requests for a hearing on the final rule. Therefore, we find that the effective date of the final rule that published in the
Food labeling, Infants and children, Nutrition, Reporting and recordkeeping requirements, Signs and symbols.
Food and Drug Administration, HHS.
Final rule; technical amendment.
The Food and Drug Administration (FDA) is amending the animal drug regulations to reflect application-related actions for new animal drug applications (NADAs) and abbreviated new animal drug applications (ANADAs) during July and August 2015. FDA is also informing the public of the availability of summaries of the basis of approval and of environmental review documents, where applicable. The animal drug regulations are also being amended to reflect a change of sponsor, a change of sponsor's address, a revised food safety warning, the voluntary withdrawal of approval of an NADA, and a technical amendment. This technical amendment is being made to improve the accuracy of the regulations.
This rule is effective October 13, 2015, except for the amendment to 21 CFR 558.460, which is effective October 23, 2015.
George K. Haibel, Center for Veterinary Medicine (HFV-6), Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855, 240-402-5689,
FDA is amending the animal drug regulations to reflect approval actions for NADAs and ANADAs during July and August 2015, as listed in table 1. In addition, FDA is informing the public of the availability, where applicable, of documentation of environmental review required under the National Environmental Policy Act (NEPA) and, for actions requiring review of safety or effectiveness data, summaries of the basis of approval (FOI Summaries) under the Freedom of Information Act (FOIA). These public documents may be seen in the Division of Dockets Management (HFA-305), Food and Drug Administration, 5630 Fishers Lane, rm. 1061, Rockville, MD 20852, between 9 a.m. and 4 p.m., Monday through Friday. Persons with access to the Internet may obtain these documents at the CVM FOIA Electronic Reading Room:
In addition, IMPAX Laboratories, Inc., 30831 Huntwood Ave., Hayward, CA 94544 has informed FDA that it has transferred ownership of, and all rights and interest in, ANADA 200-366 for NOVOCOX (carprofen sodium) Caplets to Putney, Inc., One Monument Square, suite 400, Portland, ME 04101.
Also, Pharmgate LLC, 161 North Franklin Turnpike, suite 2C, Ramsey, NJ 07446, has informed FDA that it has changed its address to 1015 Ashes Dr., suite 102, Wilmington, NC 28405. Accordingly, 21 CFR 510.600 is being amended to reflect this change.
In addition, FDA is revising a human food safety warning for use of sulfamethazine soluble powder in pre-ruminating calves. FDA is also changing the drug labeler code for a generic dinoprost injection product in 21 CFR 522.690, which in error was omitted from a final rule changing sponsorship of an application (78 FR 17595, March 22, 2013). Also, the strength of lufenuron injectable suspension is also being amended to conform to the approved application. These technical amendments are being made to improve the accuracy of the regulations.
In addition, Zoetis Inc., 333 Portage St., Kalamazoo, MI 49007 has requested that FDA withdraw approval of NADA 046-666 that provides for use of Type A medicated articles containing penicillin G procaine to manufacture medicated feeds administered to poultry and swine. This action is being taken at the sponsor's request because this product is no longer manufactured or marketed. Note this NADA was identified as being affected by Guidance for Industry (GFI) #213, “New Animal Drugs and New Animal Drug Combination Products Administered in or on Medicated Feed or Drinking Water of Food-Producing Animals: Recommendations for Drug Sponsors for Voluntarily Aligning Product Use Conditions with GFI #209,” December 2013. Elsewhere in this issue of the
This rule does not meet the definition of “rule” in 5 U.S.C. 804(3)(A) because it is a rule of “particular applicability.” Therefore, it is not subject to the congressional review requirements in 5 U.S.C. 801-808.
Administrative practice and procedure, Animal drugs, Labeling, Reporting and recordkeeping requirements.
Animal drugs.
Animal drugs, Foods.
Animal drugs, Animal feeds.
Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs and redelegated to the Center for Veterinary Medicine, 21 CFR parts 510, 520, 522, 524, 556, and 558 are amended as follows:
21 U.S.C. 321, 331, 351, 352, 353, 360b, 371, 379e.
(c) * * *
(1) * * *
(2) * * *
21 U.S.C. 360b.
(d) * * *
(1)
(ii)
(iii)
(2)
(ii)
(iii)
(3)
(ii)
(iii)
(d) * * *
(4) * * *
(iii) * * * Do not use in calves under one (1) month of age or calves being fed an all-milk diet. Use in these classes of calves may cause violative residues to remain beyond the withdrawal time.
21 U.S.C. 360b.
The revisions and addition read as follows:
(a)
(b)
(1) No. 054771 for use of the 12.5 mg/mL product as in paragraph (d)(1) of this section.
(2) Nos. 000859 and 054771 for use of the 5 mg/mL product as in paragraphs (d)(2), (d)(3), and (d)(4) of this section.
(c)
(d) * * *
(1)
(i)
(ii)
(A) For estrus synchronization in beef cows, beef heifers and replacement dairy heifers.
(B) For unobserved (silent) estrus in lactating dairy cows with a corpus luteum.
(C) For treatment of pyometra (chronic endometritis) in cattle.
(D) For abortion in beef cows, beef heifers and replacement dairy heifers.
(E) For use with gonadorelin injection as in § 522.1077 of this chapter to synchronize estrous cycles to allow fixed-time artificial insemination (FTAI) in lactating dairy cows.
(F) For use with progesterone intravaginal inserts as in § 529.1940 of this chapter for synchronization of estrus in lactating dairy cows.
(G) For use with progesterone intravaginal inserts as in § 529.1940 of this chapter for synchronization of estrus in suckled beef cows and replacement beef and dairy heifers, advancement of first postpartum estrus in suckled beef cows, and advancement of first pubertal estrus in beef heifers.
(4)
(b) * * *
(2) No. 055529 for use of product described in paragraph (a)(1) of this section as in paragraph (e)(1) of this section, and use of product described in paragraph (a)(2) in this section as in paragraphs (e)(2), (e)(3)(i)(B), and (e)(3)(ii) of this section.
(a)
(1) 300 milligrams (mg) florfenicol in the inactive vehicles 2-pyrrolidone and triacetin.
(2) 300 mg florfenicol in the inactive vehicles n-methyl-2-pyrrolidone, propylene glycol, and polyethylene glycol.
(3) 300 mg florfenicol in the inactive vehicles 2-pyrrolidone and glycerol formal.
(b)
(1) No. 000061 for use of product described in paragraph (a)(1) as in paragraph (d)(1)(i); and
(2) Nos. 000061 and 086050 for use of product described in paragraph (a)(2) as in paragraph (d)(1)(ii).
(3) No. 055529 for use of product described in paragraph (a)(3) as in paragraph (d)(1)(ii).
(d) * * *
(1)
(C)
(ii) 300 mg/mL florfenicol in the inactive vehicles n-methyl-2- pyrrolidone, propylene glycol, and polyethylene glycol, or in 2-pyrrolidone and glycerol formal:
(C)
(a)
(b)
(c)
(2)
(3)
21 U.S.C. 360b.
(a) * * *
(1) 500 units bacitracin, 3.5 milligrams (mg) neomycin sulfate (equivalent to 3.5 mg neomycin base), and 10,000 units polymyxin B sulfate; or
(2) 400 units bacitracin zinc, 5 mg neomycin sulfate (equivalent to 3.5 mg neomycin base), and 10,000 units polymyxin B sulfate.
(b) * * *
(2) Nos. 000061, 043264, and 059399 for use of product described in paragraph (a)(2) as in paragraph (c) of this section.
(a)
(b)
21 U.S.C. 342, 360b, 371.
(a)
(b)
(c)
21 U.S.C. 354, 360b, 360ccc, 360ccc-1, 371.
(d) * * *
(a)
(b)
(c)
(2) The expiration date of VFDs for avilamycin medicated feeds must not exceed 90 days from the date of issuance. VFDs for avilamycin shall not be refilled.
(d)
(e)
(2)
(3)
(a)
(b)
Food and Drug Administration, HHS.
Notification of withdrawal.
The Food and Drug Administration (FDA) is withdrawing approval of a new animal drug application (NADA) providing for the use of penicillin G procaine in medicated feed of poultry and swine. This action is being taken at the sponsor's request because this product is no longer manufactured or marketed.
Withdrawal of approval is effective October 23, 2015.
Sujaya Dessai, Center for Veterinary Medicine (HFV-212), Food and Drug Administration, 7519 Standish Pl., Rockville, MD 20855, 240-402-5761,
Zoetis Inc., 333 Portage St., Kalamazoo, MI 49007 has requested that FDA withdraw approval of NADA 046-666 that provides for use of Type A medicated articles containing penicillin G procaine to manufacture medicated feeds administered to poultry and swine. This action is being taken at the sponsor's request because this product is no longer manufactured or marketed. Note this NADA was identified as being affected by guidance for industry #213, “New Animal Drugs and New Animal Drug Combination Products Administered in or on Medicated Feed or Drinking Water of Food-Producing Animals: Recommendations for Drug Sponsors for Voluntarily Aligning Product Use Conditions with GFI #209,” December 2013.
Therefore, under authority delegated to the Commissioner of Food and Drugs and redelegated to the Center for Veterinary Medicine, and in accordance with 21 CFR 514.116
Elsewhere in this issue of the
Food and Drug Administration, HHS.
Final order; technical correction.
The Food and Drug Administration (FDA) is issuing a final order to reclassify shortwave diathermy (SWD) for all other uses, a preamendments class III device, into class II (special controls), and to rename the device “nonthermal shortwave therapy” (SWT). FDA is also making a technical correction in the regulation for the carrier frequency for SWD and SWT devices.
This order is effective on October 13, 2015. See further discussion in Section IV, “Implementation Strategy.”
Michael J. Ryan, Center for Devices and Radiological Health, 10903 New Hampshire Ave., Bldg. 66, Rm. 1615, Silver Spring, MD 20993, 301-796-6283,
The Federal Food, Drug, and Cosmetic Act (the FD&C Act), as amended by the Medical Device Amendments of 1976 (the 1976 amendments) (Pub. L. 94-295), the Safe Medical Devices Act of 1990 (Pub. L. 101-629), the Food and
Under section 513(d) of the FD&C Act, devices that were in commercial distribution before the enactment of the 1976 amendments, May 28, 1976 (generally referred to as preamendments devices), are classified after FDA has: (1) Received a recommendation from a device classification panel (an FDA advisory committee); (2) published the panel's recommendation for comment, along with a proposed regulation classifying the device; and (3) published a final regulation classifying the device. FDA has classified most preamendments devices under these procedures.
Devices that were not in commercial distribution prior to May 28, 1976 (generally referred to as “postamendments devices”), are automatically classified by section 513(f) of the FD&C Act into class III without any FDA rulemaking process. Those devices remain in class III and require premarket approval unless, and until, the device is reclassified into class I or II or FDA issues an order finding the device to be substantially equivalent, in accordance with section 513(i) of the FD&C Act, to a predicate device that does not require premarket approval. The Agency determines whether new devices are substantially equivalent to predicate devices by means of premarket notification procedures in section 510(k) of the FD&C Act (21 U.S.C. 360(k)) and 21 CFR part 807.
A preamendments device that has been classified into class III and devices found substantially equivalent by means of premarket notification (510(k)) procedures to such a preamendments device or to a device within that type (both the preamendments and substantially equivalent devices are referred to as preamendments class III devices) may be marketed without submission of a premarket approval application (PMA) until FDA issues a final order under section 515(b) of the FD&C Act (21 U.S.C. 360e(b)) requiring premarket approval.
On July 9, 2012, FDASIA was enacted. Section 608(a) of FDASIA amended section 513(e) of the FD&C Act, changing the mechanism for reclassifying a device from rulemaking to an administrative order.
Section 513(e) of the FD&C Act provides that FDA may, by administrative order, reclassify a device based upon “new information.” FDA can initiate a reclassification under section 513(e) or an interested person may petition FDA to reclassify a preamendments device. The term “new information,” as used in section 513(e), includes information developed as a result of a reevaluation of the data before the Agency when the device was originally classified, as well as information not presented, not available, or not developed at that time. (See,
Reevaluation of the data previously before the Agency is an appropriate basis for subsequent action where the reevaluation is made in light of newly available authority (see
FDA relies upon “valid scientific evidence” in the classification process to determine the level of regulation for devices. To be considered in the reclassification process, the “valid scientific evidence” upon which the Agency relies must be publicly available. Publicly available information excludes trade secret and/or confidential commercial information,
Section 513(e)(1) of the FD&C Act sets forth the process for issuing a final reclassification order. Specifically, prior to the issuance of a final order reclassifying a device, the following must occur: (1) Publication of a proposed order in the
In response to the February 20, 2014, proposed order to reclassify shortwave diathermy for all other uses and to rename the device “nonthermal shortwave therapy,” FDA received 40 comments from industry, a patient advocacy group, and consumers of SWT devices. Of those, 35 comments were received from users of specific devices who support the use and availability of those devices in the United States. Several of these comments also supported reclassification into class II. This final order reclassifies into class II SWT devices intended for adjunctive use in the palliative treatment of postoperative pain and edema of soft tissue by means other than the generation of deep heat within body tissues and establishes special controls that are intended to mitigate risks to health of SWT devices in order to provide a reasonable assurance of their safety and effectiveness. These special controls are meant to protect patients from unsafe or ineffective SWT devices.
Six of the comments from users also requested that the prescription use restriction be removed from the proposed regulation so that SWT devices could be available over-the-counter (OTC). This final order applies only to SWT devices for the indications and uses that have been previously cleared for marketing. To date, FDA has not cleared an SWT device for OTC use and, as a result, has limited the reclassification in this final order to prescription use devices. However, if FDA receives a marketing application in the future for an SWT device indicated
One public comment FDA received requested that SWT devices remain classified in class III, and that FDA call for PMAs. FDA disagrees that SWT devices should remain in class III and require PMA approval. On May 21, 2013, FDA held a meeting of the Orthopedic and Rehabilitation Devices Panel (the 2013 Panel), to discuss the classification of SWT devices (Ref. 1). The 2013 Panel reached consensus that SWT devices did not fit the statutory definition of a class III device. Section 513(a)(1)(C) of the FD&C Act provides that a device is class III if (a) the device is life supporting or life sustaining, of substantial importance in preventing impairment to human health, or presents a potential unreasonable risk of illness or injury, and (b) the device cannot be classified in class I or II because insufficient information exists to determine that general controls or general and special controls would provide reasonable assurance of the safety and effectiveness of the device. The 2013 Panel agreed that SWT devices are not life supporting or life sustaining, or of substantial importance to preventing impairment to human health. The 2013 Panel was concerned about the potential unreasonable risk of illness or injury resulting from the use of SWT devices in certain instances, such as treatments around the eye. Moreover, the 2013 Panel concluded that the information presented to the panel was sufficient to establish special controls that are necessary to provide reasonable assurance of safety and effectiveness of SWT. Thus, the consensus of the 2013 Panel was to recommend that SWT be reclassified into class II (special controls).
FDA agrees with the 2013 Panel's recommendation for reclassification. The Agency believes, as stated in the proposed order, that the risks of SWT devices are sufficiently understood based on valid scientific evidence, and a review of the clinical literature indicates that few relevant adverse events have been reported for these devices. FDA further believes that the risks of SWT devices with the special controls identified in this final order will be nominal.
One of the public comments, received from industry, requested removal of the special control requiring clinical data, stating that it was unnecessary and there was already sufficient evidence of effectiveness. This comment did not cite new data, but requested that FDA reconsider the data that was previously presented to the 2013 Panel. The available scientific evidence on the effectiveness of SWT was presented to the 2013 Panel by both FDA and industry, and there was panel consensus that the existing data was very limited and that clinical data should be required as a special control. When asked to consider the benefits of SWT based on the information presented to it by FDA and industry, the 2013 Panel consensus was that there may be a certain subset of patients who may benefit from SWT; however, the 2013 Panel had “very serious concerns involving both the veracity and the scientific methodology of the data presented.” Thus, although the limited data reviewed by the Agency and by the 2013 Panel suggest that SWT could potentially be effective, particularly for management of postoperative pain, the 2013 Panel members indicated a need for clinical data demonstrating effectiveness from statistically powered, well-controlled studies with quantified outcomes. The 2013 Panel agreed with FDA that clinical studies should consider the following attributes: Randomization, utilization of sham controls, blinding, well-defined cohorts, well-defined treatment parameters, clinically relevant and validated measures, adequate power, appropriate and defined methods of statistics, predefined hypotheses, and systematic collection of adverse events. The 2013 Panel believed that clinical studies incorporating these basic design elements should be feasible to conduct, and are important in demonstrating an appropriate level of effectiveness for specific devices. FDA agrees with the 2013 Panel's assessment and has determined that the special controls identified in this final order, including clinical performance data, are necessary to provide a reasonable assurance of safety and effectiveness of SWT.
Two comments from sponsors of currently marketed SWT devices supported reclassification, but requested 2 years from the effective date of the final order to submit a 510(k), rather than the 60 days FDA proposed in the proposed order. The comments suggested that if clinical data are necessary, it will be difficult to plan and conduct a clinical trial and submit the data within 60 days of the effective date of the final order. One comment suggested that it will be beneficial to interact with the Agency prior to a clinical trial and submission of the data to FDA, and that 60 days may not be adequate to accomplish such. FDA would like to encourage interaction with the Agency prior to a clinical study and submission of the data to FDA, and therefore grants these requests to provide more time for currently legally marketed SWT devices to comply with the special controls identified in this order. The special controls will be effective on the date of publication of this final order. However, FDA does not intend to enforce compliance with the special controls with respect to currently legally marketed SWT devices until 1 year after the date of publication of this final order. Please see Section IV, “Implementation Strategy.” The Agency also notes that when indicated for adjunctive use in the palliative treatment of postoperative pain and edema, SWT devices may not be considered significant risk devices, per 21 CFR 812.3(m), and therefore clinical studies conducted in the United States involving SWT devices with those indications for use may not require an application for Investigational Device Exemption (U.S. studies involving such devices would, however, require approval by an institutional review board; see 21 CFR 812.2(b)(1)). Alternatively, SWT devices with indications for use different from adjunctive use in the palliative treatment of postoperative pain and edema of soft tissue, or that specify the types of postoperative pain or edema, may be considered significant risk devices. We encourage interaction with FDA through the presubmission process to address any questions regarding whether such a device is significant risk.
One industry comment challenged FDA's authority to require new 510(k)s for SWT devices that have already been legally marketed to demonstrate that the SWT devices meet the special controls. FDA has considered this comment, and will not require manufacturers of currently legally marketed SWT devices to submit a new 510(k) notification. However, manufacturers must comply with the special controls implemented by this order; if the special controls are not met then the device may be considered adulterated under section 501(f)(1)(B) of the FD&C Act (21 U.S.C. 351(f)(1)(B). In order to ensure compliance with these special controls, FDA is requiring that manufacturers of currently marketed SWT devices submit an amendment to their previously cleared 510(k) demonstrating compliance with the special controls. Such amendment will be added to the 510(k) file but will not serve as a basis for a new substantial equivalence review. An amendment to a 510(k) in this context will be used solely to submit information demonstrating to
As discussed above, the special controls will be effective on the date of publication of this final order. However, FDA does not intend to enforce compliance with the special controls with respect to currently legally marketed SWT devices until 1 year after the date of publication. Please see Section IV, “Implementation Strategy.” If an amendment to a 510(k) that demonstrates compliance with the special controls for the device is not submitted as required in Section IV or if FDA determines after review of the amendment that the device is not in compliance with the special controls, the device may be considered adulterated and sale of the device would have to cease.
In reviewing the proposed order, the comments received, and the 2013 Panel's recommendations, FDA is also making a few modifications to the identification and special controls for SWT devices. The identification has been revised from “intended for the treatment of medical conditions except for the treatment of malignancies” to “intended for adjunctive use in the palliative treatment of postoperative pain and edema of soft tissue,” as the latter statement more closely captures the current intended uses of existing SWT devices. The special control that specifies saline gel test loads has been revised to allow for testing in saline gel test load or other appropriate models to allow for flexible characterization approaches. The special control “Documented clinical performance testing must demonstrate safe and effective use of the device” has been revised to “A detailed summary of the clinical testing pertinent to use of the device to demonstrate the effectiveness of the device in its intended use.” This revision clarifies the information that FDA would expect to see under this special control. Finally, labeling for SWT devices must include output characteristics of the device and recommended treatment regimes, including duration of use, in addition to a detailed summary of the clinical testing pertinent to the use of the device and a summary of the adverse events and complications. This revision clarifies the type of information that FDA would expect to see in labeling for SWT devices. FDA believes these revisions provide additional clarification and flexibility for SWT device manufacturers.
Under section 513(e) of the FD&C Act, FDA is adopting its findings as published in the preamble to the proposed order with the modifications discussed in Section II of this final order. FDA is issuing this final order to reclassify shortwave diathermy (SWD) for adjunctive use in the palliative treatment of postoperative pain and edema in superficial soft tissue by means other than the generation of deep heat within body tissues from class III to class II, rename the device “nonthermal shortwave therapy” (SWT), and establish special controls by revising part 890 (21 CFR part 890). As described in the proposed order, FDA is also making a technical correction in the regulation for the carrier frequency for SWD and SWT devices from “13 megahertz (MHz) to 27.12 MHz” to “13.56 MHz or 27.12 MHz.” The identification for § 890.5290 has been revised to provide the name change of the device under paragraph (b) and a more accurate description of the devices in this classification section. SWT devices must comply with the special controls identified in this order (see Section IV, “Implementation Strategy”).
Section 510(m) of the FD&C Act provides that FDA may exempt a class II device from the premarket notification requirements under section 510(k) of the FD&C Act if FDA determines that premarket notification is not necessary to provide reasonable assurance of the safety and effectiveness of the devices. FDA has determined that premarket notification is necessary to provide reasonable assurance of safety and effectiveness of SWT and, therefore, this device type is not exempt from premarket notification requirements.
Following the effective date of this final order, firms marketing SWT devices must comply with the special controls set forth in this order (see Section IV, “Implementation Strategy”).
The special controls identified in this final order are effective October 13, 2015. For models of SWT devices that have not been legally marketed prior to October 13, 2015, or models that have been legally marketed but are required to submit a new 510(k) under § 807.81(a)(3) because the device is about to be significantly changed or modified, manufacturers must obtain 510(k) clearance, among other relevant requirements, and demonstrate compliance with the special controls included in this final order, before marketing the new or changed device.
FDA does not intend to enforce compliance with the special controls for currently legally marketed SWT devices until October 13, 2016. For those manufacturers who wish to continue to offer currently legally marketed devices for sale, FDA expects them to submit a 510(k) amendment for those devices by October 13, 2016 demonstrating compliance with the special controls included in this final order. If a 510(k) amendment is not submitted by this date for the device or if FDA determines that the amendment does not demonstrate compliance with the special controls, the device may be considered adulterated under section 501(f)(1)(B) of the FD&C Act as of the date of FDA's determination of noncompliance or October 13, 2016, whichever is sooner, and sale of the device would have to cease.
The Agency has determined under 21 CFR 25.34(b) that this action is of a type that does not individually or cumulatively have a significant effect on the human environment. Therefore, neither an environmental assessment nor an environmental impact statement is required.
This final order refers to previously approved collections of information found in FDA regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520). The collections of information in 21 CFR part 812 have been approved under OMB control number 0910-0078; the collections of information in 21 CFR part 807, subpart E, have been approved under OMB control number 0910-0120; the collections of information in 21 CFR part 814, subpart B, have been approved under OMB control number 0910-0231; and the collections of information under 21 CFR part 801 have been approved under OMB control number 0910-0485.
Prior to the amendments by FDASIA, section 513(e) of the FD&C Act provided for FDA to issue regulations to reclassify devices. Although section 513(e) of the FD&C Act as amended requires FDA to issue final orders rather than regulations, FDASIA also provides for FDA to revoke previously issued regulations by order. FDA will continue to codify classifications and reclassifications in the Code of Federal Regulations (CFR). Changes resulting from final orders will appear in the CFR as changes to codified classification determinations or as newly codified orders. Therefore, under section 513(e)(1)(A)(i) of the FD&C Act, as amended by FDASIA, in this final order
FDA has placed the following reference on display in the Division of Dockets Management (HFA-305) Food and Drug Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852. Interested persons may see it between 9 a.m. and 4 p.m., Monday through Friday, and online at
1. FDA's Orthopedic and Rehabilitation Devices Panel transcript and other meeting materials are available on FDA's Web site at
Medical devices, Physical medicine devices.
Therefore, under the Federal Food, Drug, and Cosmetic Act and under authority delegated to the Commissioner of Food and Drugs, 21 CFR part 890 is amended as follows:
21 U.S.C. 351, 360, 360c, 360e, 360j, 371.
The revisions read as follows:
(a)
(b)
(2)
(i) Components of the device that come into human contact must be demonstrated to be biocompatible.
(ii) Appropriate analysis/testing must demonstrate that the device is electrically safe and electromagnetically compatible in its intended use environment.
(iii) Non-clinical performance testing must demonstrate that the device performs as intended under anticipated conditions of use. Non-clinical performance testing must characterize the output waveform of the device and demonstrate that the device meets appropriate output performance specifications. The output characteristics and the methods used to determine these characteristics, including the following, must be determined:
(A) Peak output power;
(B) Pulse width;
(C) Pulse frequency;
(D) Duty cycle;
(E) Characteristics of other types of modulation that may be used;
(F) Average measured output powered into the RF antenna/applicator;
(G) Specific absorption rates in saline gel test load or other appropriate model;
(H) Characterization of the electrical and magnetic fields in saline gel test load or other appropriate model for each RF antenna and prescribed RF antenna orientation/position; and
(I) Characterization of the deposited energy density in saline gel test load or other appropriate model.
(iv) A detailed summary of the clinical testing pertinent to use of the device to demonstrate the effectiveness of the device in its intended use.
(v) Labeling must include the following:
(A) Output characteristics of the device;
(B) Recommended treatment regimes, including duration of use; and
(C) A detailed summary of the clinical testing pertinent to the use of the device and a summary of the adverse events and complications.
(vi) Nonthermal shortwave therapy devices marketed prior to the effective date of this reclassification must submit an amendment to their previously cleared premarket notification (510(k)) demonstrating compliance with these special controls.
Federal Highway Administration (FHWA), Department of Transportation (DOT).
Final rule.
This rule updates the regulations governing the required design standards to be utilized on Federal-aid highway program (FAHP) projects. In issuing the final rule, FHWA incorporates by reference the latest versions of design standards and standard specifications previously adopted and incorporated by reference, and removes the corresponding outdated or superseded versions of these standards and specifications. This rule also makes technical changes to the regulatory text consistent with updated
This final rule is effective November 12, 2015. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of November 12, 2015.
Mr. Michael Matzke, Office of Program Administration (HIPA-20), (202) 366-4658, or via email at
This document, the notice of proposed rulemaking (NPRM), and all comments received may be viewed online through the Federal eRulemaking portal at:
This rulemaking updates existing regulations governing new construction, reconstruction, resurfacing (except for maintenance resurfacing), restoration, and rehabilitation projects on the National Highway System (NHS), including the Interstate System, by incorporating by reference the current versions of design standards and standard specifications previously adopted and incorporated by reference under 23 CFR 625.4, and removing the outdated or superseded versions of these standards and specifications. Several of these design standards and standard specifications were established by the American Association of State Highway and Transportation Officials (AASHTO) and the American Welding Society (AWS) and were previously adopted by FHWA through rulemaking. The updated standards or specifications replace previous versions of these documents and represent the most recent refinements that professional organizations have formally accepted. The FHWA formally adopts them for NHS projects.
The revisions include referencing the 2011 edition of the AASHTO
The AASHTO is an organization that represents 52 State transportation agencies (STA) (including the District of Columbia and Puerto Rico). Its members consist of the duly constituted heads and other chief officials of those agencies. The Secretary of Transportation is an ex-officio member, and DOT staff participates in various AASHTO activities as nonvoting representatives. Among other functions, AASHTO develops and issues standards, specifications, policies, guides, and related materials for use by the States for highway projects. Many of the standards, policies, and standard specifications that were approved by FHWA and incorporated into 23 CFR part 625 were developed and issued by AASHTO.
The revisions also include updated versions of welding codes published by AWS. The AWS is a nonprofit organization known for its code and certification procedures, providing industry standards for welding, including in the transportation field. The AWS reports about 66,000 members worldwide and develops updated materials for welding professionals and other interested parties, including those related to bridge welding and structural welding.
While these adopted standards and specifications apply to all projects on the NHS (including the Interstate System), FHWA encourages the use of flexibility and a context-sensitive approach to consider a full range of project and user needs and the impacts to the community and natural and human environment. The STA and local agencies may consider using design exceptions to achieve a design that balances project and user needs, performance, cost, environmental implications, and community values. These adopted design standards provide a range of acceptable values for highway features, and FHWA encourages the use of this flexibility to achieve a design that best suits the desires of the community while satisfying the purpose for the project and needs of its users.
At a minimum, STAs and local agencies should select design values based on an evaluation of the context of the facility, needs of all the various project users, safety, mobility, human and natural environmental impacts, and project costs. For most situations, there is sufficient flexibility within the range of acceptable values to achieve a balanced design. However, when this is not possible, STAs and local agencies may consider designs that deviate from the design standards when warranted based on the project's impact on the environment (natural and built), historical and recreational facilities, and other factors. In instances where design standards for a particular element cannot be attained, a design exception, subject to approval by FHWA, or on behalf of FHWA if an STA has assumed the responsibility through a Stewardship and Oversight agreement, is required for projects on the NHS. Additional information on FHWA's adopted design standards and design exceptions is available electronically at
In addition, FHWA supports using design guides that national organizations develop from peer-reviewed research, or equivalent guides developed in cooperation with State or local officials, when such guides are not in conflict with Federal laws and regulations.
The rule also makes technical changes to the regulatory text consistent with updated
The documents FHWA is incorporating by reference are reasonably available to interested parties, primarily STAs and local agencies carrying out Federal-aid highway projects. These documents represent the most recent refinements that professional organizations have formally accepted and are currently in use by the transportation industry. The documents are also available for review at the U.S. Department of Transportation's National Transportation Library, the National Archives and Records Administration, or may be obtained from AASHTO or AWS.
The documents incorporated by reference in this final rule are:
(1) A Policy on Geometric Design of Highways and Streets, 6th Edition, AASHTO 2011. The AASHTO, 2011 edition incorporates the latest research and current industry practices, with the basic criteria identified for geometric design standards remaining essentially the same. This Policy is a comprehensive manual to assist STAs and local agencies in administrative, planning, and educational efforts pertaining to design formulation. The Policy includes design guidelines for freeways, arterials, collectors, and local roads in both urban and rural locations.
(2) A Policy on Design Standards Interstate System, AASHTO, January 2005. This Policy complements
(3) Standard Specifications for Highway Bridges, 17th Edition, AASHTO, 2002. This document details
(4) AASHTO LRFD Bridge Construction Specifications, 3rd Edition, AASHTO 2010, with 2010, 2011, 2012, and 2014 Interim Revisions. This new edition has been revised to be consistent with its companion, the recently updated
(5) AASHTO LRFD Bridge Design Specifications, 7th Edition, AASHTO, 2014, with 2015 Interim Revisions. The
(6) AASHTO LRFD Moveable Highway Bridge Design Specifications, 2nd Edition, AASHTO, 2007, including 2008, 2010, 2011, 2012, 2014, and 2015 Interim Revisions. This guide includes information on design of bridge spans, mechanical systems (motors, hydraulics, etc.), electrical systems, and bridge protection systems. The guidelines also cover seismic analysis and vessel impact analysis. Several types of movable bridges as discussed, including Bascule span, Swing span, and Vertical Lift bridges.
(7) AASHTO/AWS D1.5M/D1.5: 2010 Bridge Welding Code, 6th Edition, AASHTO, 2010, with 2011 and 2012 Interim Revisions. This document covers AASHTO welding requirements for welded highway bridges made from carbon and low-alloy construction steels. Chapters cover design of welded connections, workmanship, technique, procedure and performance qualification, inspection, and stud welding. This document features the latest AASHTO revisions and nondestructive examination requirements, as well as a section providing a “Fracture Control Plan for Nonredundant Bridge Members.”
(8) Standards for Structural Supports for Highway Signs, Luminaires and Traffic Signals, 6th Edition, AASHTO, 2013. These Standards are applicable to the structural design of supports for highway signs, luminaires, and traffic signals. The Standards are intended to serve as a standard and guide for the design, fabrication, and erection of these types of supports.
(9) D1.4/D1.4M: 2011 Structural Welding Code—Reinforcing Steel, 7th Edition, American Welding Society, 2011. This manual covers welding of reinforcing steel in most reinforced concrete applications. It includes sections on allowable stresses, structural details, workmanship requirements, technique, procedure and performance qualification, and inspection.
On June 2, 2015, FHWA published an NPRM in the
The Pennsylvania DOT was concerned that the NPRM lacked implementation timeframes for the updated standards. As an example, they stated that STAs will need to update standard designs for structural support for overhead signs and traffic signals and estimated that it may take 3 years to accomplish this. Pennsylvania DOT went on to suggest implementation timeframes of 1-2 years for standards 23 CFR 625.4(b)(1), (2), (3), (4), (5), and (6); and 3-4 years for standard 23 CFR 625.4(b)(7).
The FHWA believes that the standards and manuals incorporated by reference under this rulemaking, where not in conflict with standards and manuals under the previous regulation, have been used by STAs for projects on the NHS. This final rule is effective for all NHS projects authorized to proceed with design activities on or after the effective date of this rule. While FHWA will not establish any extended implementation timeframes within the regulation, STAs should work closely with their FHWA division office in implementing the final rule.
Both Oklahoma DOT and California DOT expressed support for the update of the standards, specifications, and text.
The Oklahoma DOT and California DOT support was noted. No change was made to the regulation.
An individual commenter advised that the address shown in the NPRM 23 CFR 625.4(d)(2) was incorrect and should be: American Welding Society, 8869 NW 36 Street, #130, Miami, FL 33166-6672.
The FHWA agrees and the final rule was revised accordingly.
The individual also noted that in July 2015, the AASHTO Standard in 23 CFR 625.4(c)(2) (Standard Specifications for Transportation Materials and Methods of Sampling and Testing, parts I and II, AASHTO 1995), was superseded by the latest edition of the manual (Standard Specifications for Transportation Materials and Methods of Sampling and Testing, 35th Edition and AASHTO Provisional Standards, 2015 Edition). Furthermore, the Standard Specifications for Structural Supports for Highway Signs, Luminaires and Traffic Signals, 6th Edition, AASHTO 2013 was superseded by LRFD Specifications for Structural Supports for Highway Signs, Luminaires and Traffic Signals, 1st Edition, AASHTO 2015 in August of 2015.
The timing of the updates for the AASHTO materials and structural support publications did not allow for FHWA to propose the adoption of them in the NPRM. The FHWA will consider adopting these two manuals in a future update to the regulations. No change was made to the final rule.
The individual also recommend several other documents for incorporation by reference including a specification for bridge and parking garage deck overlays and several roadway lighting guides and specifications. Generally, the guides and specifications suggested by the commenter refer to specific roadway materials and appurtenances and are left up to STAs to reference as necessary for projects. No changes were made to the final rule to adopt the additional documents suggested by the commenter.
Another individual commenter suggested that the time period for adopting newer versions of the Green Book can be shortened or eliminated by not including specific edition information in the regulation, and that by doing so, FHWA could avoid a formal rulemaking process and adopt newer editions of the Green Book by only issuing a memo or policy paper.
Procedures and requirements for incorporation by reference are covered in 1 CFR part 51. This regulation requires that the language incorporating
An individual expressed support for the update as long as it eliminates outdated options for road and road-related infrastructure. A review of the list of outdated options provided by the commenter showed that they mainly related to signing and striping issues and therefore fall under the purview of the Manual on Uniform Traffic Control Devices, or are based on specific design decisions that are made on a project-by-project basis by STAs and local agencies. No change was made to the final rule.
An individual commented that the regulation needs to contain timeline limits for highway projects and that it must require that more time is spent on drainage design since rework after completion of construction can be costly. In addition, the individual suggested that all cloverleaf on and off ramps be replaced to provide for smoother operations on the highway system.
Establishing design and construction schedules and timelines for highway projects is left to STAs and/or local agencies and will depend on many factors such as project complexity, engineering and environmental issues, and agency staffing and resources, to name a few. Similarly, as the owners of the highway system, STAs and/or local agencies are responsible for setting highway improvement priorities according to local needs. As such, it is outside the scope of this rulemaking to set or otherwise require timelines for design and construction of projects. The standards adopted by this regulation address the need for proper drainage design and interchange geometrics, including cloverleaf on and off ramps. No change was made to the final rule.
The National Association of City Transportation Officials (NACTO), Smart Growth America, and People For Bikes all recommended amending 23 CFR 625 to include the NACTO Urban Street Design Guide
Part 625, Design Standards for Highways, contains a listing of documents that define specific criteria and controls for the design of NHS projects. Such documents are referred to as standards. The FHWA and other organizations produce many other documents that serve to complement the design standards. These documents are often referred to as guides, references, or best practices. Non-regulatory information, such as guides and references that serve to complement or supplement design standards need not be included within the Code of Federal Regulations. Instead, FHWA typically recognizes guidance through policy memoranda or development of separate FHWA publications.
As an example, on August 20, 2013, FHWA issued a memorandum
While adopted standards and specifications apply to all projects on the NHS, the AASHTO Green Book encourages the use of flexibility and a context-sensitive approach to consider the full range of project and user needs and the impacts to the community and natural and human environment. The 2011 edition, adopted under this rulemaking, strengthens such language and incorporates many of the principles contained in the materials referenced in 23 U.S.C. 109(c)(2). For most situations, there is sufficient flexibility within the range of acceptable values contained in the standards to achieve a balanced design for a variety of roadway classification types. However, when this is not possible, a design exception may be appropriate.
The FHWA does not intend to adopt the guides as standards for the NHS but will continue to recommend the use of a wide array of design resources to achieve context-sensitive urban street designs. Instead, language has been added to the rule to recognize that FHWA supports the use of guides that national organizations develop from peer-reviewed research, or equivalent guides developed in cooperation with State or local officials, when such guides are not in conflict with other Federal laws or regulations.
In addition, FHWA will consider including a similar statement about FHWA support of other guides that serve as supplements to the regulatory standards in future updates to 23 CFR part 652.
The Public Resource.org asserted that the documents to be incorporated by reference into the rule are not reasonably available to the public.
As stated earlier, when proposing to incorporate a document by reference in the regulations, FHWA follows the policies and procedures under 1 CFR part 51 to ensure that the materials proposed to be incorporated are reasonably available to interested parties and usable by the class of persons affected. The NPRM describes where the materials can be obtained by members of the public, including in-person at the Department of Transportation headquarters office. The materials have been formally adopted by professional organizations and have been in use by the community for some time. The FHWA believes these documents to be in use by the STAs and local agencies affected by this rulemaking and thus are reasonably available.
The FHWA determined that this action does not constitute a significant regulatory action within the meaning of Executive Order 12866 or within the meaning of DOT regulatory policies and procedures. The amendments update several industry design standards and standard specifications adopted and incorporated by reference under 23 CFR part 625 and remove the corresponding outdated or superseded versions of these standards and specifications. This rule makes technical changes to the regulatory text consistent with updated
In addition, this action complies with the principles of Executive Order 13563. After evaluating the costs and benefits of these amendments, FHWA determined that the economic impact of this rulemaking would be minimal. These changes are not anticipated to adversely affect, in any material way, any sector of the economy. In addition, these changes will not create a serious inconsistency with any other agency's action or materially alter the budgetary impact of any entitlements, grants, user fees, or loan programs. These updated standards and specifications represent the most recent refinements that professional organizations have formally accepted, and are currently in use by the transportation industry. The FHWA anticipates that the economic impact of this rulemaking will be minimal; therefore, a full regulatory evaluation is not necessary.
In compliance with the Regulatory Flexibility Act (Pub. L. 96-354, 5 U.S.C. 601-612), FHWA evaluated the effects of this rule on small entities, such as local governments and businesses. The FHWA determined that this action would not have a significant economic impact on a substantial number of small entities. The amendments would update several industry design standards and standard specifications adopted and incorporated by reference under 23 CFR part 625. The FHWA believes the projected impact upon small entities that utilize Federal-aid highway program funding for the development of highway improvement projects on the NHS would be negligible. Therefore, FHWA certifies that the rule would not have a significant economic impact on a substantial number of small entities.
This final rule does not impose unfunded mandates as defined by the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4, March 22, 1995, 109 Stat. 48). Furthermore, in compliance with the Unfunded Mandates Reform Act of 1995, FHWA evaluated this rule to assess the effects on State, local, and tribal governments and the private sector. This rule does not result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $143.1 million or more in any one year (2 U.S.C. 1532). In addition, the definition of “Federal Mandate” in the Unfunded Mandates Reform Act excludes financial assistance of the type in which State, local, or tribal governments have authority to adjust their participation in the program in accordance with changes made in the program by the Federal Government. The Federal-aid highway program permits this type of flexibility.
This rule was analyzed in accordance with the principles and criteria contained in Executive Order 13132, dated August 4, 1999, and it was determined that this rule does not have a substantial direct effect or sufficient federalism implications on States that would limit the policymaking discretion of the States. Nothing in this rule directly preempts any State law or regulation or affects the States' ability to discharge traditional State governmental functions.
The regulations implementing Executive Order 12372 regarding intergovernmental consultation on Federal programs and activities apply to this program. This Executive Order applies because State and local governments would be directly affected by the proposed regulation, which is a condition on Federal highway funding. Local entities should refer to the Catalog of Federal Domestic Assistance Program Number 20.205, Highway Planning and Construction, for further information.
Federal agencies must obtain approval from the Office of Management and Budget for each collection of information they conduct, sponsor, or require through regulations. This rule does not contain a collection of information requirement for the purpose of the Paperwork Reduction Act of 1995 (44 U.S.C. 3501,
The FHWA analyzed this rule for the purposes of the National Environmental Policy Act (NEPA) (42 U.S.C. 4321
The FHWA analyzed this rule under Executive Order 13175, dated November 6, 2000, and believes that this action would not have substantial direct effects on one or more Indian tribes, would not impose substantial direct compliance costs on Indian tribal governments, and would not preempt tribal law. This rule establishes the requirements for the procurement, management, and administration of engineering and design related services using FAHP funding and directly related to a construction project. As such, this rule would not impose any direct compliance requirements on Indian tribal governments nor would it have any economic or other impacts on the viability of Indian tribes. Therefore, a tribal summary impact statement is not required.
The FHWA analyzed this rule under Executive Order 13211, Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use. We determined that this action would not be a significant energy action under that order because any action contemplated would not be likely to have a significant adverse effect on the supply, distribution, or use of energy. Therefore, FHWA certifies that a Statement of Energy Effects under Executive Order 13211 is not required.
The FHWA analyzed this rule and determined that this action would not affect a taking of private property or otherwise have taking implications under Executive Order 12630, Governmental Actions and Interference with Constitutionally Protected Property Rights.
This action meets applicable standards in sections 3(a) and 3(b)(2) of Executive Order 12988, Civil Justice Reform, to minimize litigation, eliminate ambiguity, and reduce burden.
The FHWA analyzed this action under Executive Order 13045, Protection of Children from Environmental Health Risks and Safety Risks, and certifies that this proposed action would not cause an environmental risk to health or safety that may disproportionately affect children.
The Executive Order 12898 requires that each Federal agency make achieving environmental justice part of its mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of its programs, policies, and activities on minorities and low-income populations. The FHWA determined that this rule does not raise any environmental justice issues.
A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN number contained in the heading of this document can be used to cross-reference this action with the Unified Agenda.
Design standards, Grant programs-transportation, Highways and roads, Incorporation by reference.
In consideration of the foregoing, the FHWA amends 23 CFR part 625 as follows:
23 U.S.C. 109, 215, and 402; Sec. 1073 of Pub. L. 102-240, 105 Stat. 1914, 2012; 49 CFR 1.48(b) and (n).
(a)
(2) A Policy on Design Standards Interstate System, AASHTO, January 2005 (incorporated by reference; see § 625.4(d)).
(3) The geometric design standards for resurfacing, restoration, and rehabilitation (RRR) projects on NHS highways other than freeways shall be the procedures and the design or design criteria established for individual projects, groups of projects, or all non-freeway RRR projects in a State, and as approved by the FHWA. The other geometric design standards in this section do not apply to RRR projects on NHS highways other than freeways, except as adopted on an individual State basis. The RRR design standards shall reflect the consideration of the traffic, safety, economic, physical, community, and environmental needs of the projects.
(4) Location and Hydraulic Design of Encroachments on Flood Plains, refer to 23 CFR part 650, subpart A.
(5) Procedures for Abatement of Highway Traffic Noise and Construction Noise, refer to 23 CFR part 772.
(6) Accommodation of Utilities, refer to 23 CFR part 645, subpart B.
(7) Pavement Design, refer to 23 CFR part 626.
(b)
(2) AASHTO LRFD Bridge Construction Specifications, 3rd Edition, AASHTO, 2010, with 2010, 2011, 2012, and 2014 Interim Revisions (incorporated by reference; see § 625.4(d)).
(3) AASHTO LRFD Bridge Design Specifications, 7th Edition, AASHTO, 2014, with 2015 Interim Revisions (incorporated by reference; see § 625.4(d)).
(4) AASHTO LRFD Movable Highway Bridge Design Specifications, 2nd Edition, AASHTO, 2007, including 2008, 2010, 2011, 2012, 2014, and 2015 Interim Revisions (incorporated by reference; see § 625.4(d)).
(5) AASHTO/AWS D1.5M/D1.5: 2010 Bridge Welding Code, 6th Edition, AASHTO, 2011, with 2011 and 2012 Interim Revisions (incorporated by reference; see § 625.4(d)).
(6) D1.4/D1.4M: 2011Structural Welding Code-Reinforcing Steel, American Welding Society, 2011 (incorporated by reference; see § 625.4(d)).
(7) Standard Specifications for Structural Supports for Highway Signs, Luminaires and Traffic Signals, 6th Edition, AASHTO, 2013 (incorporated by reference; see § 625.4(d)).
(8) Navigational Clearances for Bridges, refer to 23 CFR part 650, subpart H.
(d)
(1) American Association of State Highway and Transportation Officials (AASHTO), Suite 249, 444 North Capitol Street NW., Washington, DC 20001;
(i) A Policy on Geometric Design of Highways and Streets, 6th Edition, 2011.
(ii) A Policy on Design Standards Interstate System, January 2005.
(iii) Standard Specifications for Highway Bridges, 17th Edition, 2002
(iv) AASHTO LRFD Bridge Construction Specifications, 3rd Edition, 2010; with:
(A) Interim Revisions, 2010,
(B) Interim Revisions, 2011,
(C) Interim Revisions, 2012, and
(D) Interim Revisions, 2014.
(v) AASHTO LRFD Bridge Design Specifications, 7th Edition, 2014, with:
(A) 2015 Interim Revisions.
(B) [Reserved].
(vi) AASHTO LRFD Movable Highway Bridge Design Specifications, 2nd Edition, 2007, with:
(A) Interim Revisions, 2008,
(B) Interim Revisions, 2010,
(C) Interim Revisions, 2011,
(D) Interim Revisions, 2012,
(E) Interim Revisions, 2014, and
(F) Interim Revisions, 2015
(vii) AASHTO/AWS D1.5M/D1.5: 2010 Bridge Welding Code, 6th Edition, 2010, with:
(A) Interim Revisions, 2011, and
(B) Interim Revisions, 2012
(viii) Standard Specifications for Structural Supports for Highway Signs, Luminaires and Traffic Signals, 6th Edition, AASHTO 2013.
(2) American Welding Society (AWS), 8869 NW 36 Street, #130 Miami, FL 33166-6672;
(i) D1.4/D1.4M: 2011 Structural Welding Code—Reinforcing Steel, 2011.
(ii) [Reserved].
(e) The FHWA supports using, as design resources to achieve context sensitive designs, guides that national organizations develop from peer-reviewed research, or equivalent guides that are developed in cooperation with State or local officials, when such guides are not in conflict with Federal laws and regulations.
Internal Revenue Service (IRS), Treasury.
Temporary regulations; correcting amendments.
This document contains amendments to temporary regulations relating to guidance for the treatment of nonperiodic payments made or received pursuant to certain notional principal contracts. These amendments change the applicability date of the embedded loan rule for the treatment of nonperiodic payments from November 4, 2015, to the later of January 1, 2017, or six months after the date of publication of the Treasury decision adopting these rules as final regulations in the
Alexa Dubert at (202) 317-6945 (not a toll-free number).
The temporary regulations that are the subject of these amendments are under section 446(b) of the Internal Revenue Code (Code). The temporary regulations (TD 9719) were published in the
Section 1.446-3T(g)(4)(i) of the temporary regulations provides that, subject to certain exceptions set forth in § 1.446-3T(g)(4)(ii), a notional principal contract with one or more nonperiodic payments is treated as two separate transactions consisting of an on-market, level payment swap and one or more loans (the embedded loan rule). Section 1.446-3T(g)(4)(i) eliminated the exception to the embedded loan rule for non-significant, nonperiodic payments set forth in the final regulations (TD 8491) published in the
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is corrected by making the following correcting amendments:
26 U.S.C. 7805 * * *
(j) * * *
(2)
Coast Guard, DHS.
Temporary final rule.
The Coast Guard is establishing a temporary safety zone on the waters of Great Egg Harbor Bay in the vicinity of the Garden State Parkway Bridge in Somers Point, NJ. The safety zone will restrict vessel traffic on a portion of the Great Egg Harbor Bay while critical girder erection work is being conducted in response to the rehabilitation project of the main navigational channel section of the bridge. This temporary safety zone is necessary to protect the surrounding public and vessels from the hazards associated with the bridge construction operations.
This rule is effective without actual notice from October 13, 2015 through December 5, 2015. For purposes of enforcement, actual notice will be used from October 5, 2015 through October 13, 2015.
To view documents mentioned in this preamble as being available in the docket, go to
If you have questions on this rule, call or email Lieutenant Brennan Dougherty, U.S. Coast Guard, Sector Delaware Bay, Chief Waterways Management Division, Coast Guard; telephone (215) 271-4851, email
The Coast Guard is issuing this temporary rule without prior notice and opportunity to comment pursuant to authority under section 4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This provision authorizes an agency to issue a rule without prior notice and opportunity to comment when the agency for good cause finds that those procedures are “impracticable, unnecessary, or contrary to the public interest.” Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good cause exists for not publishing a notice of proposed rulemaking (NPRM) with respect to this rule because this critical phase of the rehabilitation work to the Garden State Parkway Bridge, main channel section, poses a safety threat to maritime traffic and a safety zone is needed. Furthermore, notification of the proposed work was not received until September 18, 2015. Due to the need for an immediate response and the late notification of the work, providing a notice and comment period would be impractical.
We are issuing this rule, and, under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause exists for making it effective less than 30 days after publication in the
The Coast Guard is issuing this rule under authority in 33 U.S.C. 1231; 33 CFR 1.05-1 and 160.5; and Department of Homeland Security Delegation No. 0170.1. The Captain of the Port, Delaware Bay, has determined that potential hazards associated with bridge construction operations starting October 5, 2015, will be a safety concern for anyone within a 200-yard radius of bridge work, vessels, and machinery. This rule is needed to protect personnel, vessels, and the marine environment in the navigable waters within the safety zone while the bridge work is being conducted.
This rule establishes a safety zone from October 5, 2015, through December 5, 2015, and the zone will be enforced from 7 a.m. to 6 p.m. daily, excluding Sundays. The safety zone will cover all navigable waters within 200 yards of vessels and machinery, at approximate position, 39°17′32″ N., 074°37′32″ W., being used by personnel for construction and repair of the Garden State Parkway Bridge over the Great Egg Harbor Bay in Somers Point, NJ. The duration of the zone is intended to protect personnel, vessels, and the marine environment in these navigable waters while bridge construction operations are being conducted. Entry into, transiting, or anchoring within the safety zone is prohibited unless vessels obtain permission from the Captain of the Port (COTP) or make satisfactory passing arrangements with the construction vessel per this rule and the Rules of the Road (33 CFR Subchapter E). During portions of this project the main navigation channel will be closed each day for vessel traffic from 7 a.m. to 6 p.m., excluding Sundays. These closures are necessary for safety due to hazards associated with bridge maintenance. Bridge work will stop and the channel will be clear for vessels to pass under the bridge between 6 p.m. to 7 a.m. Monday through Saturday; during these hours when bridge work is stopped, mariners may transit the main channel without restrictions. In addition, the channel will be fully available on Sundays and vessels may transit freely. At all times, secondary bridge spans will be clear to pass; vessels able to pass under secondary channel spans may do so at any time. There will be number of working days that the navigation channel will not be obstructed; however, mariners wishing to transit Monday through Saturday between 7 a.m. and 6 p.m. must make passing arrangements with the on scene construction vessel or obtain permission from the COTP or his representative.
We developed this rule after considering numerous statutes and executive orders (E.O.s) related to rulemaking. Below we summarize our analyses based on a number of these statutes and E.O.s, and we discuss First Amendment rights of protestors.
E.O.s 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. E.O. 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has not been designated a “significant regulatory action,” under E.O. 12866. Accordingly, it has not been reviewed by the Office of Management and Budget.
This regulatory action determination is based on the size, location, and duration of the safety zone. Vessel traffic will be able to safely transit from the hours of 6 p.m. to 7 a.m., daily, excluding Sundays. At other times,
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.
While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section V.A above, this rule will not have a significant economic impact on any vessel owner or operator.
Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the
Small businesses may send comments on the actions of Federal employees who enforce, or otherwise determine compliance with, Federal regulations to the Small Business and Agriculture Regulatory Enforcement Ombudsman and the Regional Small Business Regulatory Fairness Boards. The Ombudsman evaluates these actions annually and rates each agency's responsiveness to small business. If you wish to comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR (1-888-734-3247). The Coast Guard will not retaliate against small entities that question or complain about this rule or any policy or action of the Coast Guard.
This rule will not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).
A rule has implications for federalism under E.O. 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in E.O. 13132.
Also, this rule does not have tribal implications under E.O. 13175, Consultation and Coordination with Indian Tribal Governments, because it does not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this rule has implications for federalism or Indian tribes, please contact the person listed in the
The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this rule will not result in such an expenditure, we do discuss the effects of this rule elsewhere in this preamble.
We have analyzed this rule under Department of Homeland Security Management Directive 023-01 and Commandant Instruction M16475.lD, which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This rule involves a safety zone in force for no more than 11 hours each day, from October 1, 2015, to December 5, 2015, that prohibits entry within 200 yards of vessels and machinery being used by personnel conducting bridge work on the Garden State Parkway Bridge over the Great Egg Harbor Bay, in Somers Point, NJ. It is categorically excluded from further review under paragraph 34(g) of Figure 2-1 of the Commandant Instruction. An environmental analysis checklist supporting this determination and a Categorical Exclusion Determination are available in the docket where indicated under
The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to contact the person listed in the
Harbors, Marine safety, Navigation (water), Reporting and recordkeeping requirements, Security measures, Waterways.
For the reasons discussed in the preamble, the Coast Guard amends 33 CFR part 165 as follows:
33 U.S.C. 1231; 50 U.S.C. 191; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Department of Homeland Security Delegation No. 0170.1.
(a)
(b)
(1)
(2)
(c)
(1) During periods of full channel closures, the main navigational channel will be obstructed and vessels will be unable to pass. Secondary bridge spans will be clear to pass; vessels able to pass under secondary channel spans may do so.
(2) Vessels wishing to transit the safety zone in the main navigational channel may do so if they can make satisfactory passing arrangements with the on-scene construction vessel in accordance with the Navigational Rules in 33 CFR Subchapter E. If vessels are unable to make satisfactory passing arrangements with the on-scene construction vessel, they may request permission from the COTP or his designated representative on VHF channel 16.
(3) There will be number of working days that the navigation channel will not be obstructed; however, mariners wishing to transit during the enforcement period must still comply with the procedures in paragraph (c)(2) of this section.
(4) The main channel will be clear from the hours of 6 p.m. to 7 a.m. daily, and every Sunday throughout the course of the project. Vessels may transit through the safety zone at these times without restriction.
(5) This section applies to all vessels wishing to transit through the safety zone except vessels that are engaged in the following operations: Enforcing laws; servicing aids to navigation, and emergency response vessels.
(d)
(e)
Environmental Protection Agency (EPA).
Final rule.
The Environmental Protection Agency (EPA) is taking final action to approve elements of state implementation plan (SIP) submissions by Michigan regarding the infrastructure requirements of section 110 of the Clean Air Act (CAA) for the 2008 ozone, 2010 nitrogen dioxide (NO
This final rule is effective on November 12, 2015.
EPA has established a docket for this action under Docket ID No. EPA-R05-OAR-2014-0657. All documents in the docket are listed in the
Sarah Arra, Environmental Scientist, Attainment Planning and Maintenance Section, Air Programs Branch (AR-18J), U.S. Environmental Protection Agency, Region 5, 77 West Jackson Boulevard, Chicago, Illinois 60604, (312) 886-9401,
Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA. This supplementary information section is arranged as follows:
This rulemaking addresses infrastructure SIP submissions from the Michigan Department of Environmental Quality (MDEQ) submitted on July 10, 2014, for the 2008 ozone, 2010 NO
Under sections 110(a)(1) and (2) of the CAA, states are required to submit infrastructure SIPs to ensure that their SIPs provide for implementation, maintenance, and enforcement of the NAAQS. These submissions must contain any revisions needed for meeting the applicable SIP requirements of section 110(a)(2), or certifications that their existing SIPs already meet those requirements.
EPA has highlighted this statutory requirement in multiple guidance documents, including the most recent guidance document entitled “Guidance on Infrastructure State Implementation Plan (SIP) Elements under CAA Sections 110(a)(1) and (2)” issued on September 13, 2013.
EPA is acting upon Michigan's SIP submissions that address the infrastructure requirements of CAA sections 110(a)(1) and 110(a)(2) for the 2008 ozone, 2010 NO
EPA has historically referred to these SIP submissions made for the purpose of satisfying the requirements of CAA sections 110(a)(1) and 110(a)(2) as “infrastructure SIP” submissions. Although the term “infrastructure SIP” does not appear in the CAA, EPA uses the term to distinguish this particular type of SIP submission from submissions that are intended to satisfy other SIP requirements under the CAA, such as “nonattainment SIP” or “attainment plan SIP” submissions to address the nonattainment planning requirements of part D of title I of the CAA, “regional haze SIP” submissions required by EPA rule to address the visibility protection requirements of CAA section 169A, and nonattainment new source review (NNSR) permit program submissions to address the permit requirements of CAA, title I, part D.
This rulemaking will not cover three substantive areas that are not integral to acting on the state's infrastructure SIP submission: (i) Existing provisions related to excess emissions during periods of start-up, shutdown, or malfunction (“SSM”) at sources, that may be contrary to the CAA and EPA's policies addressing such excess emissions; (ii) existing provisions related to “director's variance” or “director's discretion” that purport to permit revisions to SIP approved emissions limits with limited public process or without requiring further approval by EPA, that may be contrary to the CAA (collectively referred to as “director's discretion”); and, (iii) existing provisions for Prevention of Significant Deterioration (PSD) programs that may be inconsistent with current requirements of EPA's “Final NSR Improvement Rule,” 67 FR 80186 (December 31, 2002), as amended by 72 FR 32526 (June 13, 2007) (“NSR Reform”). Instead, EPA has the authority to address each one of these substantive areas in separate rulemaking. A detailed rationale, history, and interpretation related to infrastructure SIP requirements can be found in our May 13, 2014, proposed rule entitled, “Infrastructure SIP Requirements for the 2008 Lead NAAQS” in the section, “What is the scope of this rulemaking?” (
In addition, EPA is not acting on submissions related to a portion of section 110(a)(2)(D)(i)(II) with respect to visibility, section 110(a)(2)(J) with respect to visibility for the 2008 ozone, 2010 NO
EPA's June 24, 2015, proposed rulemaking also proposed approving a submission from Michigan addressing the state board requirements under section 128 of the CAA. EPA finalized this approval in a separate rulemaking on August 3, 2015 (see 80 FR 52399).
The public comment period for EPA's proposed actions with respect to Michigan's satisfaction of the infrastructure SIP requirements for the 2008 ozone, 2010 NO
Our interpretation that infrastructure SIPs are more general planning SIPs is consistent with the statute as understood in light of its history and structure. When Congress enacted the CAA in 1970, it did not include provisions requiring states and the EPA to label areas as attainment or nonattainment. Rather, states were required to include all areas of the state in “air quality control regions” (AQCRs), and section 110 set forth the core substantive planning provisions for these AQCRs. At that time, Congress anticipated that states would be able to address air pollution quickly pursuant to the very general planning provisions in section 110 and could bring all areas into compliance with the NAAQS within five years. Moreover, at that time, section 110(a)(2)(A)(i) specified that a section 110 plan must provide for “attainment” of the NAAQS, and section 110(a)(2)(B) specified that the plan must include “emission limitations, schedules, and timetables for compliance with such limitations, and such other measures as may be necessary to insure attainment and maintenance [of the NAAQS].” In 1977, Congress recognized that the existing structure was not sufficient and many areas were still violating the NAAQS. At that time, Congress for the first time added provisions requiring states and EPA to identify whether areas of the state were violating the NAAQS (
In 1990, many areas still had air quality that did not meet the NAAQS, and Congress again amended the CAA, adding yet another layer of more prescriptive planning requirements for each of the NAAQS, with the primary provisions for ozone in section 182. At that same time, Congress modified
Additionally, Congress replaced the clause “as may be necessary to insure attainment and maintenance [of the NAAQS]” with “as may be necessary or appropriate to meet the applicable requirements of this chapter.” Thus, the CAA has significantly evolved in the more than 40 years since it was originally enacted. While at one time section 110 did provide the only detailed SIP planning provisions for states and specified that such plans must provide for attainment of the NAAQS, under the structure of the current CAA, section 110 is only the initial stepping-stone in the planning process for a specific NAAQS. And, more detailed, later-enacted provisions govern the substantive planning process, including planning for attainment of the NAAQS.
With regard to the requirement for emission limitations, EPA has interpreted this to mean that, for purposes of section 110, the state may rely on measures already in place to address the pollutant at issue or any new control measures that the state may choose to submit. As EPA stated in “Guidance on Infrastructure State Implementation Plan (SIP) Elements under CAA Sections 110(a)(1) and 110(a)(2),” dated September 13, 2013 (Infrastructure SIP Guidance), “[t]he conceptual purpose of an infrastructure SIP submission is to assure that the air agency's SIP contains the necessary structural requirements for the new or revised NAAQS, whether by establishing that the SIP already contains the necessary provisions, by making a substantive SIP revision to update the SIP, or both. Overall, the infrastructure SIP submission process provides an opportunity . . . to review the basic structural requirements of the air agency's air quality management program in light of each new or revised NAAQS.” Infrastructure SIP Guidance at p. 2.
The commenter suggests that these provisions must apply to section 110 SIPs because, in the preamble to EPA's action “restructuring and consolidating” provisions in part 51, EPA stated that the new attainment demonstration provisions in the 1977 Amendments to the CAA were “beyond the scope” of the rulemaking. It is important to note, however, that EPA's action in 1986 was not to establish new substantive planning requirements, but rather to consolidate and restructure provisions that had previously been promulgated. EPA noted that it had already issued guidance addressing the new “Part D” attainment planning obligations. Also, as to maintenance regulations, EPA expressly stated that it was not making any revisions other than to re-number those provisions. Id. at 40657.
Although EPA was explicit that it was not establishing requirements interpreting the provisions of new “Part D” of the CAA, it is clear that the regulations being restructured and consolidated were intended to address control strategy plans. In the preamble, EPA clearly stated that 40 CFR 51.112 was replacing 40 CFR 51.13 (“Control strategy: SO
EPA's partial approval and partial disapproval of revisions to restrictions on emissions of sulfur compounds for the Missouri SIP addressed a control strategy SIP and not an infrastructure SIP (71 FR 12623).
Similarly, the Indiana action also does not support for the commenter's position (78 FR 78720). The review in that rule was of a completely different requirement than the 110(a)(2)(A) SIP. Rather, in that case, the state had an approved SO
In
The decision in
At issue in
In
The commenter suggests that
Two of the cases the commenter cites,
Furthermore, the commenter suggests that there are available controls for the state to adopt for reducing NO
The suggestion that the infrastructure SIP must include measures addressing violations of the standard that did not occur until shortly before or even after the SIP was due and submitted cannot be supported. The CAA provides states with three years to develop infrastructure SIPs and states cannot reasonably be expected to address the annual change in an area's design value for each year over that period. Moreover, the CAA recognizes and has provisions to address changes in air quality over time, such as an area slipping from attainment to nonattainment or changing from nonattainment to attainment. These include provisions providing for redesignation in section 107(d) and provisions in section 110(k)(5) allowing EPA to call on a state to revise its SIP, as appropriate.
We do not believe that section 110(a)(2)(A) requires detailed planning SIPs demonstrating either attainment or maintenance for specific geographic areas of the state. The infrastructure SIP is triggered by promulgation of the NAAQS, not designation. Moreover, infrastructure SIPs are due three years following promulgation of the NAAQS and designations are not due until two years (or in some cases three years) following promulgation of the NAAQS. Thus, during a significant portion of the period that the state has available for developing the infrastructure SIP, it does not know what the designation will be for individual areas of the state.
For all of the above reasons, we disagree with the commenter that EPA must disapprove an infrastructure SIP revision if there are monitored violations of the standard in the state and the section 110(a)(2)(A) revision does not have detailed plans for demonstrating how the state will bring that area into attainment. Rather, EPA believes that the proper inquiry when EPA is acting on a submittal is whether the state has met the basic structural SIP requirements.
Moreover, Michigan's SIP contains existing emission reduction measures that control emissions of VOCs and NO
The commenters assertion that CAA section 110(l) requirements should
The denial of the redesignation petition also is not relevant to Michigan's infrastructure SIP because as mentioned above, the designation process and infrastructure submittals are separable actions on completely different timelines and infrastructure requirements are the same regardless of the designation status of the area.
For the reasons discussed in our June 24, 2015, proposed rulemaking and the responses to comments, above, EPA is taking final action to approve Michigan's infrastructure SIP for the 2008 ozone, 2010 NO
In the above table, the key is as follows:
Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:
• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);
• Does not impose an information collection burden under the provisions 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).
In addition, 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
The Congressional Review Act, 5 U.S.C. 801
Under section 307(b)(1) of the CAA, petitions for judicial review of this action must be filed in the United States Court of Appeals for the appropriate circuit by December 14, 2015. Filing a petition for reconsideration by the Administrator of this final rule does not affect the finality of this action for the purposes of judicial review nor does it extend the time within which a petition for judicial review may be filed, and shall not postpone the effectiveness of such rule or action. This action may not be challenged later in proceedings to enforce its requirements. (See section 307(b)(2).)
Environmental protection, Air pollution control, Incorporation by reference, Intergovernmental relations, Nitrogen dioxide, Ozone, Particulate matter, Reporting and recordkeeping requirements, Sulfur oxides, Volatile organic compounds.
40 CFR part 52 is amended as follows:
42 U.S.C. 7401
(e) * * *
National Transportation Safety Board (NTSB).
Notice of interpretation; correction.
The NTSB published a notice of legal interpretation in the
This correction is effective October 13, 2015.
David Tochen, NTSB General Counsel, at (202) 314-6080.
The Notice of Legal Interpretation that was the subject of FR Doc. 2015-22933, published on September 11, 2015 (80 FR 54736), is corrected as follows: On page 54736, in the second column, first paragraph, line 17, is amended by changing the word “incidence” to “incidents.”
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Final rule; inseason adjustments to biennial groundfish management measures.
This final rule announces inseason changes to management measures in the Pacific Coast groundfish fisheries. This action, which is authorized by the Pacific Coast Groundfish Fishery Management Plan (PCGFMP), is intended to prevent exceeding the 2015 Area 2A Pacific halibut quota for incidental retention in the sablefish primary fishery and the Area 2A Total Allowable Catch (TAC) and to prevent exceeding the annual catch limit (ACL) for sablefish north 36° N. lat.
This final rule is effective October 13, 2015.
Sarah Williams, phone: 206-526-4646, fax: 206-526-6736, or email:
This rule is accessible via the Internet at the Office of the Federal Register Web site at
The International Pacific Halibut Commission (IPHC) sets the Pacific halibut total allowable catch (TAC) on an annual basis. A portion of the TAC is available to fisheries in Area 2A (waters off the U.S. West Coast). The Council's Catch Sharing Plan (CSP) guides allocation of the Area 2A portion of the TAC to the various commercial and recreational fisheries in Area 2A. Specifically, it provides that if the Area 2A TAC is greater than 900,000 lb, the portion of the Washington sport allocation that is in excess of 214,110 lb is available to the sablefish primary fishery north of Point Chehalis, WA.
The final Area 2A halibut TAC for 2015 was adopted by the IPHC at their January 26 through January 30, 2015 meeting. Following this meeting, NMFS published two final rules implementing the 2015 halibut TAC and the CSP. The first rule implementing the TAC published on March 17, 2015 (80 FR 13771) and second rule implementing the CSP published on April 1, 2015 (80 FR 17344). The final 2A TAC resulted in an allocation to the limited entry fixed gear (LEFG) sablefish primary fishery of 10,348 lb. The incidental fishery opened on April 1, 2015, with a landing limit of 75 lb dressed weight of halibut per 1,000 lb dressed weight of sablefish, and up to two additional Pacific halibut in excess of this ratio. This ratio is implemented in LEFG sablefish primary fishery regulations at § 660.231(b)(3)(iv).
In late August 2015, the Washington Department of Fish and Wildlife (WDFW) notified NMFS and IPHC that the incidental Pacific halibut quota was projected to be attained and that a closure was likely before the end of the scheduled season on October 31. Following this notification, NMFS, IPHC, and WDFW met on August 25, 2015, reviewed the catch data, and the IPHC closed incidental Pacific halibut retention in the LEFG sablefish primary fishery at 12:01 a.m. on September 1, 2015. This action was taken consistent with IPHC's inseason authority, as described in section 5 of the annual IPHC regulations and in the CSP.
The Council was notified of the IPHC inseason action at its September 11-16, 2015, meeting. To make clear that retention of incidentally caught Pacific halibut in the LEFG sablefish primary fishery north of Pt. Chehalis, WA, is closed, the Council recommended and NMFS is implementing a modification to § 660.231(b)(3)(iv). Currently that regulation states the incidental retention ratio; the modification would state that incidental retention is closed.
The best available fisheries information indicates that catch of sablefish in the commercial non-trawl fisheries north of 36° N. lat. is higher than anticipated. The Council considered updated projections and the status of ongoing groundfish fisheries at its September 11-16, 2015, meeting. Fishery models, updated with the best estimate reports from the Pacific Fishery Information Network through August 31, 2015, project that sablefish landings through the end of the year would exceed the sablefish allocations in both the LEFG and open access (OA) daily trip limit (DTL) fisheries north of 36° N. lat. Projected landings in the LEFG DTL fishery north of 36° N. lat. vary based on assumptions on the price per pound. If no action is taken and this higher than anticipated catch continues in the LEFG DTL fishery, projected landings range from 126 percent of the allocation (low price assumption) to 139 percent of the allocation (high price assumption). Also, if no action is taken and higher than anticipated catch continues in the OA fishery, projected landings are 126 percent of the allocation.
Sablefish is managed, in part, with two-month cumulative limits. Information regarding higher than anticipated catch of sablefish in these fisheries came during the Period 5 two-month cumulative limit period (September-October). It is very likely that most participating vessels will have caught their Period 5 two-month limits by the time a closure could be in effect. Therefore, the Council recommended a closure beginning at the start of the next bi-monthly cumulative limit period (Period 6, November-December), rather than during Period 5. Closing these sablefish fisheries November 1 is projected to reduce the overage of the allocations for both LEFG and OA DTL fisheries. Landings in the LEFG DTL fishery would be reduced to 111 percent—116 percent of the allocation and landings in the OA fishery reduced to 102 percent of the allocation. The Period 6 closure reduces the risk of exceeding the north 36° N. lat. ACL due to the overages in the LEFG and OA DTL allocations, and keeps total projected impacts across all fisheries below the 2015 sablefish north 36° N. lat. ACL (4,608 mt out of a 4,792 mt ACL)
NMFS agrees with the Council recommendation and rationale and is
This final rule makes routine inseason adjustments to groundfish fishery management measures, based on the best available information, consistent with the PCGFMP and its implementing regulations and the Halibut Act and its implementing regulations.
This action is taken under the authority of 50 CFR 660.60(c) and is exempt from review under Executive Order 12866.
The aggregate data upon which these actions are based are available for public inspection at the Office of the Administrator, West Coast Region, NMFS, during business hours.
NMFS finds good cause to waive prior public notice and comment on the revisions to groundfish management measures under 5 U.S.C. 553(b) because notice and comment would be impracticable and contrary to the public interest. Also, for the same reasons, NMFS finds good cause to waive the 30-day delay in effectiveness pursuant to 5 U.S.C. 553(d)(3), so that this final rule may become effective October 13, 2015.
At the September Council meeting, the Council recommended that these changes be implemented as quickly as possible to make the groundfish regulation consistent with the IPHC inseason action which has already been taken and the sablefish closure based on information available at the September Council meeting. There was not sufficient time after that meeting to draft this document and undergo proposed and final rulemaking before these actions need to be in effect. For the actions to be implemented in this final rule, affording the time necessary for prior notice and opportunity for public comment would prevent NMFS from managing fisheries using the best available science to approach, without exceeding, the halibut allocation to the sablefish fishery and ACLs for federally managed species in accordance with the PCGFMP and applicable law and the halibut allocations implemented under the authority in the Halibut Act. These adjustments to management measures must be implemented in a timely manner to prevent the Area 2A portion of the 2015 halibut TAC and the 2015 sablefish north 36° N. lat. ACL from being exceeded. The elimination of Pacific halibut retention in the LEFG sablefish primary fishery is intended to prevent exceeding the Area 2A portion of the 2015 Pacific halibut TAC and the allocation to the sablefish primary fishery. The closure of the sablefish fishery for LEFG and OA DTL fisheries is intended to prevent exceeding the 2015 sablefish ACL north 36° N. lat. No aspect of this action is controversial, and changes of this nature were anticipated in the groundfish biennial harvest specifications and management measures established for 2015-2016 and the 2015 Pacific halibut final rules.
Accordingly, for the reasons stated above, NMFS finds good cause to waive prior notice and comment and to waive the delay in effectiveness.
Fisheries, Fishing, Indian Fisheries.
For the reasons set out in the preamble, 50 CFR part 660 is amended as follows:
16 U.S.C. 1801
(b) * * *
(3) * * *
(iv)
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to supersede Airworthiness Directive (AD) 2010-04-03, for all Airbus Model A310 series airplanes. AD 2010-04-03 currently requires accomplishing repetitive detailed visual inspections for cracking around the fastener holes in certain wing top skin panels between the right side and left side of the front and rear spars, and repair if needed. Since we issued AD 2010-04-03, Airbus improved the ultrasonic inspection program to allow earlier crack detection and to extend the repetitive inspection intervals. We have determined these inspections are necessary to address the unsafe condition. This proposed AD would continue to require the repetitive detailed inspections for cracking around the fastener holes in certain wing top skin panels between the front and rear spars, and repair if needed, and would require supplemental repetitive ultrasonic inspections for cracking around the fastener holes in certain wing top skin panels and repair if needed. We are proposing this AD to detect and correct cracking around the fastener holes in certain wing top skin panels between the right side and left side of the front and rear spars, which could result in reduced structural integrity of the airplane.
We must receive comments on this proposed AD by November 27, 2015.
You may send comments by any of the following methods:
•
•
•
•
For service information identified in this proposed AD, contact Airbus SAS, Airworthiness Office—EAW, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 44 51; email
You may examine the AD docket on the Internet at
Dan Rodina, Aerospace Engineer, International Branch, ANM-116, Transport Airplane Directorate, FAA, 1601 Lind Avenue SW., Renton, WA 98057-3356; telephone 425-227-2125; fax 425-227-1149.
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 January 28, 2010, we issued AD 2010-04-03, Amendment 39-16196 (75 FR 6852, February 12, 2010). AD 2010-04-03 requires actions intended to address an unsafe condition on all Airbus Model A310 series airplanes.
Since we issued AD 2010-04-03, Amendment 39-16196 (75 FR 6852, February 12, 2010), the manufacturer improved the ultrasonic inspection program to allow earlier crack detection and to extend the repetitive inspection intervals. We have determined these inspections are necessary to address the unsafe condition.
The European Aviation Safety Agency, which is the Technical Agent for the Member States of the European Community, has issued EASA Airworthiness Directive 2014-0200R1, dated September 19, 2014 (referred to after this as the Mandatory Continuing Airworthiness Information, or “the MCAI”), to correct an unsafe condition on all Airbus Model A310 series airplanes. The MCAI states:
Following scheduled maintenance, cracks were found around the wing top skin panels fastener holes at Rib 2, between Stringer (STG) 2 and STG14.
This condition, if not detected and corrected, could affect the structural integrity of the aeroplane. The General Visual Inspection required by the existing applicable Airworthiness Limitation Items (ALI) tasks may not be adequate to detect these cracks.
To address this issue, Airbus developed an inspection programme based on repetitive detailed inspections (DET) to ensure that any visible cracks in the wing top skin panels 1 and 2 along Rib 2 are detected in time and repaired appropriately. EASA issued [EASA]
Since that [EASA] AD was issued, Airbus improved the inspection programme with an ultrasonic inspection to allow earlier crack detection, to subsequently reduce the scope of potential repair action, and to extend the intervals of the repetitive inspections.
For the reasons described above, this [EASA] AD [
Airbus has issued the following service information:
• Airbus Service Bulletin A310-57-2096, dated May 6, 2008,
• Airbus Service Bulletin A310-57-2096, Revision 01, dated August 5, 2010.
• Airbus Service Bulletin A310-57-2096, Revision 02, dated March 5, 2014.
This product has been approved by the aviation authority of another country, and is approved for operation in the United States. Pursuant to our bilateral agreement with the State of Design Authority, we have been notified of the unsafe condition described in the MCAI and service information referenced above. We are proposing this AD because we evaluated all pertinent information and determined an unsafe condition exists and is likely to exist or develop on other products of the same type design.
The FAA worked in conjunction with industry, under the Airworthiness Directive Implementation Aviation Rulemaking Committee (ARC), to enhance the AD system. One enhancement was a new process for annotating which procedures and tests in the service information are required for compliance with an AD. Differentiating these procedures and tests from other tasks in the service information is expected to improve an owner's/operator's understanding of crucial AD requirements and help provide consistent judgment in AD compliance. The procedures and tests identified as RC (required for compliance) in any service information have a direct effect on detecting, preventing, resolving, or eliminating an identified unsafe condition.
As specified in a NOTE under the Accomplishment Instructions of the specified service information, procedures and tests that are identified as RC in any service information must be done to comply with the proposed AD. However, procedures and tests that are not identified as RC are recommended. Those procedures and tests that are not identified as RC may be deviated from using accepted methods in accordance with the operator's maintenance or inspection program without obtaining approval of an alternative method of compliance (AMOC), provided the procedures and tests identified as RC can be done and the airplane can be put back in a serviceable condition. Any substitutions or changes to procedures or tests identified as RC will require approval of an AMOC.
We estimate that this proposed AD affects 13 airplanes of U.S. registry.
We also estimate that it would take about 5 work-hours per product to comply with the basic requirements of this proposed AD. The average labor rate is $85 per work-hour. Required parts would cost $0 per product. Based on these figures, we estimate the cost of this proposed AD on U.S. operators to be $5,525, or $425 per product.
We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this 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 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 this 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, Incorporation by reference, 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.
We must receive comments by November 27, 2015.
This AD replaces AD 2010-04-03, Amendment 39-16196 (75 FR 6852, February 12, 2010).
This AD applies to all Airbus Model A310-203, -204, -221, -222, -304, -322, -324, and -325 airplanes, certificated in any category, all manufacturer serial numbers.
Air Transport Association (ATA) of America Code 57, Wings.
This AD was prompted by cracking around the fastener holes in certain wing top skin panels between the right side and left side of the front and rear spars. This AD was also prompted by the development of an ultrasonic inspection program to allow for earlier crack detection and extend the repetitive inspection intervals. We are issuing this AD to detect and correct cracking around the fastener holes in certain wing top skin panels between the right side and left side of the front and rear spars, which could result in reduced structural integrity of the airplane.
Comply with this AD within the compliance times specified, unless already done.
Except as required by paragraph (i) of this AD: Within the initial compliance time and thereafter at repetitive intervals specified in paragraphs (h)(1) through (h)(3) of this AD, as applicable, accomplish the actions specified in paragraphs (g)(1) and (g)(2) concurrently and in sequence, in accordance with the Accomplishment Instructions of Airbus Service Bulletin A310-57-2096, Revision 02, dated March 5, 2014, except as provided by paragraph (j) of this AD.
(1) Accomplish a detailed inspection for cracking around fastener holes in the wing top skin panels 1 and 2, along rib 2 between the front and rear spars on both the left-side and right-side of the fuselage.
(2) Accomplish an ultrasonic inspection for cracking around fastener holes in the wing top skin panels 1 and 2, along rib 2, between stringer 2 and stringer 10 on the left-side and right-side of the fuselage.
(1) For Model A310-203, -204, -221, and -222 airplanes: Do the actions required by paragraph (g)(1) and (g)(2) of this AD at the later of the times specified in paragraph (h)(1)(i) or (h)(1)(ii) of this AD. Repeat the inspections specified in paragraphs (g)(1) and (g)(2) of this AD thereafter at intervals not to exceed 2,000 flight cycles or 4,100 flight hours, whichever occurs first.
(i) Prior to the accumulation of 18,700 flight cycles or 37,400 flight hours since first flight of the airplane, whichever occurs first.
(ii) Within 30 days after the effective date of this AD.
(2) For Model A310-304, -322, -324, and -325 airplanes having an average flight time (AFT) of less than 4 hours: Do the actions required by paragraph (g)(1) and (g)(2) of this AD at the later of the times specified in paragraph (h)(2)(i) or (h)(2)(ii) of this AD. Repeat the inspections specified in paragraphs (g)(1) and (g)(2) of this AD thereafter at intervals not to exceed 2,000 flight cycles or 5,600 flight hours, whichever occurs first.
(i) Prior to the accumulation of 17,300 flight cycles or 48,400 flight hours since first flight of the airplane, whichever occurs first.
(ii) Within 30 days after the effective date of this AD.
(3) For Model A310-304, -322, -324, and -325 airplanes having an AFT of equal to or more than 4 hours: Do the actions required by paragraph (g)(1) and (g)(2) of this AD at the later of the times specified in paragraph (h)(3)(i) or (h)(3)(ii) of this AD. Repeat the inspections specified in paragraphs (g)(1) and (g)(2) of this AD thereafter at intervals not to exceed 1,500 flight cycles or 7,500 flight hours, whichever occurs first.
(i) Prior to the accumulation of 12,800 flight cycles or 64,300 flight hours since first flight of the airplane, whichever occurs first.
(ii) Within 30 days after the effective date of this AD.
For airplanes previously inspected before the effective date of this AD using Airbus Service Bulletin A310-57-2096, dated May 6, 2008; or Airbus Service Bulletin A310-57-2096, Revision 01, dated August 5, 2010: At the applicable compliance times specified in paragraphs (i)(1) through (i)(3) of this AD, accomplish the actions specified in paragraphs (g)(1) and (g)(2) concurrently and in sequence, in accordance with the Accomplishment Instructions of Airbus Service Bulletin A310-57-2096, Revision 02, dated March 5, 2014. Repeat the inspections specified in paragraphs (g)(1) and (g)(2) of this AD, thereafter at the repetitive intervals specified in paragraphs (h)(1) through (h)(3) of this AD, as applicable.
(1) For Model A310-203, -204, -221, and -222 airplanes: Do the actions required by paragraph (g)(1) and (g)(2) of this AD within 3,500 flight hours or 1,700 flight cycles, whichever occurs first since the most recent inspection.
(2) For Model A310-304, -322, -324, and -325 airplanes having an AFT of less than 4 hours: Do the actions required by paragraph (g)(1) and (g)(2) of this AD within 4,600 flight hours or 1,600 flight cycles, whichever occurs first since the most recent inspection.
(3) For Model A310-304, -322, -324, and -325 airplanes having an AFT of equal to or more than 4 hours: Do the actions required by paragraph (g)(1) and (g)(2) of this AD within 6,100 flight hours or 1,200 flight cycles, whichever occurs first since the most recent inspection.
If no ultrasonic equipment is available for the initial or second inspection required by paragraph (g) or (h) of this AD, accomplish the detailed inspection specified in paragraph (g)(1) of this AD, within the applicable compliance times specified in paragraphs (j)(1) and (j)(2) of this AD. After accomplishing the detailed inspection, do the inspections specified in paragraphs (g)(1) and (g)(2) of this AD at the applicable compliance times specified by paragraphs (i)(1) through (i)(3) of this AD. Subsequently, repeat the inspections specified in paragraphs (g)(1) and (g)(2) of this AD thereafter at the applicable repetitive intervals specified in paragraphs (h)(1) through (h)(3) of this AD.
(1) For airplanes not previously inspected before the effective date of this AD: Do the actions required by paragraph (g)(1) of this AD within the initial compliance time specified by paragraphs (h)(1) through (h)(3) of this AD, as applicable.
(2) For airplanes previously inspected before the effective date of this AD using the service information identified in paragraph (j)(2)(i), (j)(2)(ii), or (j)(2)(iii) of this AD: Do the actions required by paragraph (g)(1) of this AD within the applicable compliance times specified in paragraphs (i)(1) through (i)(3) of this AD.
(i) Airbus Service Bulletin A310-57-2096, dated May 6, 2008.
(ii) Airbus Service Bulletin A310-57-2096, Revision 01, dated August 5, 2010.
(iii) Airbus Service Bulletin A310-57-2096, Revision 02, dated March 5, 2014.
If any cracking is found during any inspection required by paragraphs (g), (h), (i), or (j) of this AD, before further flight, repair the cracking using a method approved by the Manager, International Branch, ANM-116, Transport Airplane Directorate, FAA; or the European Aviation Safety Agency (EASA); or Airbus's EASA Design Organization Approval (DOA).
Accomplishment of a repair using the service information identified in paragraph (l)(1), (l)(2), or (l)(3) of this AD, constitutes terminating action for the requirements of paragraph (g) of this AD, only for the repaired areas of the airplane.
(1) Airbus Service Bulletin A310-57-2096, dated May 6, 2008.
(2) Airbus Service Bulletin A310-57-2096, Revision 01, dated August 5, 2010.
(3) Airbus Service Bulletin A310-57-2096, Revision 02, dated March 5, 2014.
For the purposes of this AD, the AFT should be established as specified in paragraphs (m)(1), (m)(2), and (m)(3) of this AD for the determination of the compliance times.
(1) The inspection threshold is defined as the total flight hours accumulated (counted from take-off to touch-down), divided by the total number of flight cycles accumulated at the effective date of this AD.
(2) The initial inspection interval is defined as the total flight hours accumulated divided by the total number of flight cycles accumulated at the time of the initial inspection threshold.
(3) The second inspection interval is defined as the total flight hours accumulated divided by the total number of flight cycles accumulated between the initial and second threshold.
This paragraph provides credit for actions required by paragraph (g)(1) of this AD, if those actions were performed before the effective date of this AD using Airbus Service Bulletin A310-57-2096, dated May 6, 2008; or Airbus Service Bulletin A310-57-2096, Revision 01, dated August 5, 2010.
The following provisions also apply to this AD:
(1)
(2)
(3)
(1) Refer to Mandatory Continuing Airworthiness Information (MCAI) EASA Airworthiness Directive 2014-0200R1, dated September 19, 2014, for related information. This MCAI may be found in the AD docket on the Internet at
(2) For service information identified in this AD, contact Airbus SAS, Airworthiness Office—EAW, 1 Rond Point Maurice Bellonte, 31707 Blagnac Cedex, France; telephone +33 5 61 93 36 96; fax +33 5 61 93 44 51; email
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain Dowty Propellers R352/6-123-F/1, R352/6-123-F/2, and R410/6-123-F/35 model propellers. This proposed AD was prompted by reports of dowel hole cracks in the face of the rear hub half. This proposed AD would require a records review to determine repair status and marking the affected propeller hubs as required. This proposed AD would also require installing dowel hole liners as necessary. We are proposing this AD to prevent loss of structural integrity of the propeller hub, which could result in damage to the propeller and damage to the airplane.
We must receive comments on this proposed AD by December 14, 2015.
You may send comments by any of the following methods:
•
•
•
•
For service information identified in this proposed AD, contact Dowty Propellers, 114 Powers Court, Sterling, VA 20166; phone: 703-421-4434; fax: 703-450-0087; email:
You may examine the AD docket on the Internet at
Michael Schwetz, Aerospace Engineer, Boston Aircraft Certification Office, FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7761; fax 781-238-7170; email:
We invite you to send any written relevant data, views, or arguments about this NPRM. Send your comments to an address listed under the
We will post all comments we receive, without change, to
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Community, has issued EASA AD 2015-0158, dated July 30, 2015 (referred to hereinafter as “the MCAI”), to correct an unsafe condition for the specified products. The MCAI states:
Cracking around the hub location dowel holes in the face of the rear hub half has occurred sporadically. Previous investigations found no manufacturing defects in cracked hubs and concluded that the hub cracking was caused by damage to the dowel holes during propeller installation.
Since that original SB was issued, three hubs have been found to show cracking around the location dowel holes. The hubs were all found cracked within a short period of time and all had low time since new.
This condition, if not detected, can adversely affect the structural integrity of the propeller hub, with possible damage to the propeller and to the aeroplane.
You may obtain further information by examining the MCAI in the AD docket on the Internet at
Dowty Propellers has issued Alert Service Bulletin (ASB) No. F50-61-A165, Revision 2, dated July 28, 2015. The service information describes procedures for installing liners in the hub location dowel holes in the face of the rear hub half and marking the hub with the repair number. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the
Dowty Propellers has issued Component Maintenance Manual, 61-10-34, Repair No. 53, dated May 15, 2013. The service information describes procedures for installing liners in the hub location dowel holes and marking the repair number on modified hubs.
This product has been approved by the aviation authority of the United Kingdom, and is approved for operation in the United States. Pursuant to our bilateral agreement with the European Community, EASA has notified us of the unsafe condition described in the MCAI and service information referenced above. We are proposing this NPRM because we evaluated all information provided by EASA and determined the unsafe condition exists and is likely to exist or develop on other products of the same type design. This NPRM would require marking and inspecting the affected propeller hubs to determine repair status and installing dowel hole liners as necessary.
We estimate that this proposed AD would affect 4 propellers installed on airplanes of U.S. registry. We also estimate that it would take about 5 hours per propeller to comply with this proposed AD. The average labor rate is $85 per hour. Required parts cost about $322 per propeller. Based on these figures, we estimate the cost of this proposed AD on U.S. operators to be $2,988.
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 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 this 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 to the extent that it justifies making a regulatory distinction, 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, Incorporation by reference, 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.
We must receive comments by December 14, 2015.
None.
This AD applies to Dowty Propellers R352/6-123-F/1, R352/6-123-F/2, and R410/6-123-F/35 model propellers, part numbers (P/Ns) 660715001, 660715004, and 660715005 with hub P/Ns 660715201, 660715255, 660720217, 660720241, 660720252, 660720260, and 660720288, installed.
This AD was prompted by reports of dowel hole cracks in the face of the rear hub half. We are issuing this AD to prevent loss of structural integrity of the propeller hub, which could result in damage to the propeller and damage to the airplane.
Comply with this AD within the compliance times specified, unless already done.
(1) At the next removal of the propeller from the airplane, or within 7,500 flight hours (FHs), whichever occurs first, after the effective date of this AD do the following:
(i) Review propeller maintenance records to determine if the affected propeller hub has been repaired in accordance with Dowty Propellers Alert Service Bulletin (ASB) No. F50-61-A165 Revision 2, dated July 28, 2015.
(ii) If, during the maintenance records review required by paragraph (e)(1)(i) of this AD, an affected hub is found not repaired then, before next flight, install liners into the hub location dowel holes and mark the hub. Use Dowty Propellers ASB No. F50-61-A165 Revision 2, dated July 28, 2015 to install the liners and mark the hub.
(iii) If, during the maintenance records review required by paragraph (e)(1)(i) of this AD, an affected hub is found repaired then, before next flight, mark the hub using Dowty Propellers ASB No. F50-61-A165 Revision 2, dated July 28, 2015.
(1) You may take credit for maintenance records reviews and installations that are required by paragraph (e) of this AD if you performed these actions before the effective date of this AD using Dowty Propellers ASB No. F50-61-A165 Revision 1, dated May 12, 2015 or initial issue dated November 19, 2012.
(2) You may take credit for any maintenance records reviews or corrective actions that are required by paragraph (e) of this AD if you performed these actions before the effective date of this AD using Component Maintenance Manual (CMM) 61-10-34, Repair No. 53, dated August 11, 2008, which relates to repair scheme 650510057.
The Manager, Boston Aircraft Certification Office, FAA, may approve AMOCs for this AD. Use the procedures found in 14 CFR 39.19 to make your request.
(1) For more information about this AD, contact Michael Schwetz, Aerospace Engineer, Boston Aircraft Certification Office, FAA, 12 New England Executive Park, Burlington, MA 01803; phone: 781-238-7761; fax: 781-238-7170; email:
(2) Refer to MCAI European Aviation Safety Agency AD 2015-0158, dated July 30, 2015, for more information. You may examine the MCAI in the AD docket on the Internet at
(3) Dowty Propellers ASB No. F50-61-A165 Revision 2, dated July 28, 2015 and CMM 61-10-34, Repair No. 53, dated August 11, 2008 can be obtained from Dowty Propellers, using the contact information in paragraph (h)(4) of this proposed AD.
(4) For service information identified in this proposed AD, contact Dowty Propellers, 114 Powers Court, Sterling, VA 20166; phone: 703-421-4434; fax: 703-450-0087; email:
(5) You may view this service information at the FAA, Engine & Propeller Directorate, 12 New England Executive Park, Burlington, MA. For information on the availability of this material at the FAA, call 781-238-7125.
Securities and Exchange Commission.
Request for comment; correction.
The Securities and Exchange Commission published a document in the
Todd E. Hardiman, Associate Chief Accountant, at (202) 551-3516, Division of Corporation Finance; Duc Dang, Special Counsel, at (202) 551-3386, Office of the Chief Accountant; or Matthew Giordano, Chief Accountant, at (202) 551-6892, Division of Investment Management, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549.
In the
Internal Revenue Service (IRS), Treasury.
Notice of proposed rulemaking; extension of comment period.
This document extends the comment period for a notice of proposed rulemaking (REG-115452-14) that was published in the
Written or electronic comments and requests for a public hearing for the notice of proposed rulemaking published on July 23, 2015 (80 FR 43652), is extended to November 16, 2015.
Send submissions to CC:PA:LPD:PR (REG-115452-14), Room 5203, Internal Revenue Service, P.O. Box 7604, Ben Franklin Station, Washington, DC 20044. Submissions may be hand-delivered Monday through Friday between the hours of 8 a.m. and 4 p.m. to CC:PA:LPD:PR (REG-115452-14), Courier's Desk, Internal Revenue Service, 1111 Constitution Avenue NW., Washington, DC, or sent electronically, via the Federal eRulemaking Portal at
Jacklyn M. Goldberg at (202) 317-6850 (not a toll free number).
A notice of proposed rulemaking that appeared in the
Defense Acquisition Regulations System, Department of Defense (DoD).
Proposed rule; extension of comment period.
DoD issued a proposed rule (DFARS Case 2013-D034) on August 3, 2015 to amend the Defense Federal Acquisition Regulation Supplement (DFARS) to implement a section of the National Defense Authorization Act (NDAA) for Fiscal Year (FY) 2013. The comment period on the proposed rule is being reopened and the deadline for submitting comments is being extended to November 13, 2015.
For the proposed rule published on August 3, 2015 (80 FR 45918), submit comments by November 13, 2015.
Submit comments identified by DFARS Case 2013-D034, using any of the following methods:
○
○
○
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Comments received generally will be posted without change to
Mr. Mark Gomersall, telephone 571-372-6099.
On August 3, 2015, DoD published a proposed rule in the
Government procurement.
Office of the Chief Financial Officer, USDA.
Notice and request for comments.
This notice announces the intention of the Office of the Chief Financial Officer to request approval from the Office of Management and Budget (OMB) to renew an approved information collection associated with Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants and Awardees.
Written comments on this notice must be received by December 14, 2015 to be assured of consideration.
Comments may be submitted by either one of the following methods:
•
•
• Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB),
All comments received will be available for public inspection and posted without change, including any personal information, to
Tyson P. Whitney, Director, Transparency and Accountability Reporting Division, Office of the Chief Financial Officer, Room 3027-S, Stop Code 9011, U.S. Department of Agriculture, 1400 Independence Avenue SW., Washington, DC 20250; (202) 720-8978;
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), this notice announces the intention of the Office of the Chief Financial Officer to request approval from the Office of Management and Budget (OMB) to renew an approved information collection associated with Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants and Awardees.
To comply with the appropriation restrictions, the information collection requires corporate applicants and awardees for USDA programs to represent accurately whether they have or do not have qualifying felony convictions or tax delinquencies that would prevent entrance into proposed business transactions with USDA. For non-procurement programs and transactions, these representations are collected on forms AD-3030 (Representations Regarding Felony Conviction and Tax Delinquent Status For Corporate Applicants) and AD-3031 (Assurance Regarding Felony Conviction Or Tax Delinquent Status For Corporate Applicants). This notice and proposed renewal of an approved information collection deal only with USDA non-procurement transactions. The categories of non-procurement transactions covered include: Non-procurement contracts, grants, loans, loan guarantees, cooperative agreements, and some memoranda of understanding/agreement. For more specific information about whether a particular non-procurement program or transaction is included in this list please contact the USDA agency or staff office responsible for the program or transaction in question.
In Fiscal Years 2012-2014 the appropriation restriction provisions were not uniform across the government. To effectuate compliance, USDA initially created and received clearance of two sets of forms—one set for use by all USDA agencies and offices, except the Forest Service (AD-3030, AD-3031) and one set for use by the Forest Service (AD-3030-FS and AD-3031-FS). In 2015, Congress eliminated the multiple versions of the appropriation restriction provisions and enacted a single set of government-wide provisions for all agencies and departments, thereby allowing USDA to collect this data with one set of forms—AD-3030 and AD-3031. The current
Form AD-3030 (required during the application process) will effectuate compliance with the appropriation restrictions by requiring all corporate applicants to represent at the time of application for a non-procurement program whether they have any felony convictions or tax delinquencies that would prevent USDA from doing business with them. Form AD-3031 (applicable at the time of the award) requires an affirmative representation that corporate awardees for non-procurement transactions do not have any felony convictions or tax delinquencies. If the application and award process occurs in a single step, the agency or staff office may require concurrent submission of both forms. Corporations (for profit and non-profit entities) include, but are not limited to, any entity that has filed articles of incorporation in one of the 50 States, the District of Columbia, or the various territories of the United States.
Collection of this information is necessary to ensure that USDA agencies and staff offices comply with the appropriation restrictions prohibiting the Government from doing business with corporations with felony convictions and/or tax delinquencies.
We are requesting comments on all aspects of this information collection to help us to:
(1) Evaluate whether the collection of information is necessary for the proper performance of the functions of the agencies and staff offices, including whether the information will have practical utility;
(2) Evaluate the accuracy of our estimate of the burden of the collection of information, including the validity of the methodology and assumptions used;
(3) Enhance the quality, utility, and clarity of the information to be collected; and
(4) Minimize the burden of the collection of information on those who are to respond, including the use of appropriate automated, electronic, mechanical, technological and other forms of information technology collection methods.
All responses to this notice, including names and addresses when provided, will be summarized and included in the request for OMB approval. All comments will also become a matter of public record.
The Department of Agriculture has submitted the following information collection requirement(s) to OMB for review and clearance under the Paperwork Reduction Act of 1995, Public Law 104-13. Comments regarding (a) whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information will have practical utility; (b) the accuracy of the agency's estimate of burden including the validity of the methodology and assumptions used; (c) ways to enhance the quality, utility and clarity of the information to be collected; (d) ways to minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical or other technological collection techniques or other forms of information technology.
Comments regarding this information collection received by November 12, 2015 will be considered. Written comments should be addressed to: Desk Officer for Agriculture, Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), New Executive Office Building, 725 17th Street NW., Washington, DC 20503. Commenters are encouraged to submit their comments to OMB via email to:
An agency may not conduct or sponsor a collection of information unless the collection of information displays a currently valid OMB control number and the agency informs potential persons who are to respond to the collection of information that such persons are not required to respond to the collection of information unless it displays a currently valid OMB control number.
Rural Utilities Service, USDA.
Notice of Solicitation of Applications (NOSA).
The Rural Utilities Service (RUS), an agency of the United States Department of Agriculture (USDA), announces the availability of up to $10 million in fiscal year 2015 (FY15) and application deadlines for competitive grants to assist communities with extremely high energy costs. These grants are made available under the authority of section 19 of the Rural Electrification Act, of 1936 as amended (7 U.S.C. 918a) and program regulations at 7 CFR part 1709. Eligibility is limited to communities with average annual residential energy costs exceeding 275 percent of the national average. Grant funds may be used to acquire, construct, extend, upgrade, or otherwise improve energy generation, transmission, or distribution facilities serving eligible communities. Grants may also be used for programs that install on-grid and off-grid renewable energy systems and energy efficiency improvements in eligible communities. This notice describes the eligibility and application requirements, the criteria that will be used by RUS to award funding, and how to obtain application materials.
You may submit completed grant applications on paper or electronically according to the following deadlines:
• Paper applications must be postmarked and mailed, shipped, or sent overnight, no later than December 14, 2015, or hand delivered to RUS by this deadline, to be eligible under this NOSA. Late or incomplete applications will not be eligible for FY 2015 grant funding.
• Electronic applications must be submitted through Grants.gov no later than midnight December 14, 2015, to be eligible under this notice for FY 2015 grant funding. Late or incomplete electronic applications will not be eligible.
• Applications will not be accepted by electronic mail.
Applications will be accepted upon publication of this notice until midnight (EST) of the closing date of December 14, 2015. If the submission deadline falls on Saturday, Sunday, or a Federal holiday, the application is due the next business day.
Copies of the 2015 Application Guide, required forms and other information on the High Energy Cost Grant Program may be obtained by the following:
(1) The program Web site (
(2) Grants.gov (
(3) Contacting the RUS Electric Programs at (202) 720-9545 to request paper copies of the Application Guides or other materials.
Completed applications may be submitted in the following ways:
• Paper applications are to be submitted to the Rural Utilities Service, Electric Programs, United States Department of Agriculture, 1400 Independence Avenue SW., STOP 1560, Room 5165 South Building, Washington, DC 20250-1560. Applications should be marked “Attention: High Energy Cost Grant Program.”
• Applications may be submitted electronically through Grants.gov. Information on how to submit applications electronically is available on the Grants.gov Web site (
Robin Meigel, Finance Specialist, Rural Utilities Service, Electric Program, Office of Portfolio Management and Risk Assessment, U.S. Department of Agriculture, 1400 Independence Avenue SW., STOP 1568, Room 1274-S, Washington, DC 20250-1568. Telephone (202) 720-9452, Fax (202) 720-1401, email:
The USDA through the Rural Utilities Service (RUS) provides grant assistance for energy facilities, including renewable energy systems and energy efficiency improvements, serving extremely high energy cost communities. This program is authorized by section 19 of the Rural Electrification Act of 1936, as amended (the “RE Act”) (7 U.S.C. 918a). Program regulations are found at 7 CFR part 1709.
This program was established in 2000 to provide assistance for communities most challenged by extremely high energy costs, defined by statute as average annual residential home energy expenditures that are 275 percent or more of the national average. RUS periodically establishes eligibility benchmarks using the most recent home energy data published by the Energy Information Administration. This notice contains the latest updates to these benchmarks. The benchmarks create a high threshold for community eligibility, but small rural communities from all regions of the United States and qualified insular areas have demonstrated eligibility under prior notices.
The purpose of this program is to provide financial assistance for a broad range of energy facilities, equipment and related activities to offset the impacts of extremely high home energy costs on eligible communities. The grants help communities provide basic energy needs. Grant funds may not be used to pay utility bills or to purchase fuel. No funding is available for education and outreach efforts except those associated with project-funded energy facilities, or upgrades. Grant projects under this program must provide community benefits and not be for the primary benefit of an individual applicant, household, or business.
With publication of this notice, USDA is making available up to $10 million in new competitive grants awards under the High Energy Cost Grant Program. This notice describes eligibility and application requirements for these grants. Grants will be awarded competitively based on the selection criteria in Part E of this notice.
Applicants should carefully read this notice and the 2015 Application Guide which contains more detailed information and resources. Applicants must prepare their application packages according to the instructions contained in these documents. The Application Guide is available electronically on the program Web site at
Applicants are advised that the application requirements in this notice and the 2015 Application Guide have been substantially revised from those in the 2014 Notice of Funding Availability published June 2, 2014 and 2014 Application Guide. These changes are in response to new uniform guidance on the content of grant opportunity
• Projects that provide assistance to USDA High Poverty Areas;
• Projects that serve small rural communities;
• Projects that support deployment of renewable energy technologies;
• Projects that address extraordinary circumstances affecting the eligible high energy cost community such as a disaster, imminent hazard, unserved areas, and other economic hardship, and
• Projects that serve Substantially Underserved Trust Areas.
More information is available in section E of this notice.
The RUS Administrator has established the application and selection requirements under this notice pursuant to and consistent with program regulations at 7 CFR part 1709, the Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards at 2 CFR part 200, and 2 CFR part 400 which adopts the Uniform Requirements for USDA awards. The total amount of funds available for high energy cost grants under this notice is up to $10 million. The maximum amount of grant assistance that may be requested or awarded for a grant application under this notice is $3,000,000. The minimum amount of assistance for a grant application under this program is $50,000.
No more than one award will be made per applicant or project. Applicants may submit multiple applications, provided each is for a different project, but only one award per applicant will be approved.
RUS anticipates making multiple awards under this notice. The number of grants awarded will depend on the number of complete applications submitted, the amount of grant funds requested, the quality and competitiveness of applications, and the availability of funds. There were six grant awards under the 2013 notice and awards ranged from $298,029 to $3,000,000. (See the program Web site (
The RUS reserves the right not to award all the funds made available under this notice. The final decision to make an award is at the discretion of the Administrator (7 CFR 1709.121). The Administrator will select finalists for grant awards after consideration of the applications, the rankings, comments, and recommendations of the rating panel, and other pertinent information, including availability of funds. Upon such consideration, the Administrator may elect to offer an award of less than the full amount of grant requested by an applicant. All awards will be in the form of grants. Awardees will have to execute a grant agreement with conditions established by the RUS.
Grant project performance periods typically range from one to three years. Grant agreements provide for terms of three years. Approvals of any extensions to this term are at the sole discretion of the agency.
Applicants must provide a complete grant application package with a narrative grant proposal prepared according to the instructions in this notice and Application Guide, and including all required forms and certifications.
Applicants that submitted an application under the 2014 notice and that were notified that their application was eligible, but did not receive funding may request reconsideration under this notice. Applicants may request reconsideration by letter and submit a statement with additional information and required forms. See section D of this notice for more information.
All timely submitted and complete applications will be reviewed for eligibility and rated according to the criteria described in this notice. Applications will be ranked in order of their numerical scores on the rating criteria and forwarded to the RUS Administrator. The RUS Administrator is the federal selection official of the competitive awards. The Administrator will review the rankings and the recommendations of the rating panel. The Administrator will select projects in rank order to the extent of available funds.
Under 7 CFR 1709.10, grant funds may not be used to pay costs of preparing the application package, or for any finders' fees or incentives for persons or entities assisting in the preparation or submission of an application. Applicants are cautioned that they undertake any pre-award project activities at their own risk. A letter advising the applicant that they have been selected for an award is not a binding commitment to provide funding. The award is only final after the Administrator has signed the grant agreement.
Program regulations provide that RUS will not pay any project construction costs of the project incurred before the date of grant award except as provided in 7 CFR 1709.10. Applicants are also advised that undertaking certain project activities before required environmental review has been completed could result in withdrawal of the selection (7 CFR 1794.15, or its successor).
Applicant eligibility under this program is established by the Rural Electrification Act of 1936, as amended, (7 U.S.C. 913 and 918a), High Energy Cost Grant Program regulations at 7 CFR 1709.106, and this notice.
An eligible applicant is any one of the following:
• A legally-organized for-profit or nonprofit organization such as, but not limited to, a corporation, association, partnership (including a limited liability partnership), cooperative, or trust;
• A sole proprietorship;
• A State or local government, or any agency or instrumentality of a State or local government, including a municipal utility or public power authority;
• An Indian tribe,
• An individual or group of individuals applying on behalf of unincorporated community associations, and not for the primary benefit of a single household or business (with any award subject to special conditions discussed below); or
• Any of the above entities located in a U.S. Territory or other area authorized by law to participate in programs of the Rural Utilities Service or under the Rural Electrification Act.
All applicants must demonstrate the legal authority and capacity to enter into a binding grant agreement with the Federal Government at the time of the award and to carry out the proposed grant funded project according to its terms to be an eligible applicant. The application must include information and/or documentation supporting your eligibility, legal existence, and capacity to enter into a grant agreement.
Individuals are eligible grant applicants under this program. However, any proposed grant project must provide community benefits and not be for the primary benefit of the individual applicant or and individual household. As a practical matter, because this program addresses community energy needs and to facilitate compliance with Federal grant requirements, individuals will likely find it preferable to establish an independent legal entity, such as a corporation to actually carry out the grant project if they are selected.
Individuals or other applicants who intend to form a new, separate legal entity to carry out the grant project should indicate their intent in their applications. The new entity must be in existence and legally competent to enter into a grant agreement with the Federal Government under appropriate State and Federal laws before a final grant award can be approved.
Corporations that have been convicted of a Federal felony within the past 24 months are not eligible applicants. Any corporation that has any unpaid federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability, is not eligible for financial assistance. All corporate applicants must complete Form AD-3030 “Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants.”
In addition, under program regulations at 7 CFR 1709.7, an outstanding judgment obtained against an applicant by the United States in a Federal Court (other than in the United States Tax Court), which has been recorded, shall cause the applicant to be ineligible to receive a grant or loan under this part until the judgment is paid in full or otherwise satisfied. RUS financial assistance under this part may not be used to satisfy the judgment.
Before submitting an application, all applicants must have an active registration with current information in the System for Award Management (SAM) (previously the Central Contractor Registry (CCR)) at
Consistent with section 306F of the RE Act (7 U.S.C. 936f) and regulations concerning SUTA applications at 7 CFR part 1700, subpart D this notice provides priority scoring for any complete and eligible application from an eligible entity that has been accepted by the Administrator for consideration under SUTA provisions. In addition to establishing that it is an eligible applicant under this notice, SUTA applicants must also establish its eligibility under SUTA regulations at 7 CFR part 1700, subpart D.
The applicant must submit a letter to the RUS Administrator that it is seeking consideration under provisions of 7 CFR part 1700, subpart D and the action that it is requesting. The letter must be accompanied by a copy of the application package submitted in response to this notice. The request must include all information required under the SUTA regulations establishing that its project is for an eligible trust area, documenting its high need for High Energy Cost Grant funds, and identifying the discretionary authorities that it seeks to have applied to its application.
The Administrator will review the request to determine whether the applicant is eligible to receive consideration under SUTA. RUS will notify the applicant in writing whether (1) the application has been accepted to receive special consideration or (2) the application has not been accepted for consideration under the SUTA regulation. If the request is not granted, the applicant may withdraw its application. If the application is still eligible without SUTA consideration and the applicant does not withdraw the application, RUS will review and score the application along with others received under this notice. For more detailed information on how to apply for a grant under SUTA, please refer to the FY 2015 Application Guide available at
This grant program has no cost sharing or matching funds requirement as a condition of eligibility. However, the RUS will consider other financial resources available to the grant applicant and any voluntary pledge of matching funds or other contributions in assessing the applicant's commitment and financial capacity to complete the proposed project successfully. If a successful applicant proposes to use matching funds or other cost contributions in its project, the grant agreement will include conditions requiring documentation of the availability of the matching funds and actual expenditure of matching funds or cost contributions. RUS may require the applicant to provide additional documentation confirming the availability of any matching contribution offered prior to approval of a project award. If an applicant fails to provide timely documentation of the availability of matching contributions, the RUS may, in its sole discretion, decline to award the project if uncertainties over availability of the match render the project financially unfeasible and impose additional conditions.
To establish community eligibility, the application must (1) clearly identify and define the geographic area that will be included in the grant project and (2) demonstrate that each of the communities in the proposed area meets one or more of the high energy cost benchmarks. Consult the program regulations at 7 CFR part 1709 and the 2015 Application Guide for additional definitions used in this program.
All grant projects must benefit communities with extremely high energy costs. The RE Act defines an extremely high energy cost community as one in which “the average residential expenditure for home energy
RUS periodically establishes community eligibility benchmarks based on the latest available information from the Energy Information Administration (EIA) residential energy surveys. Home energy cost benchmarks are calculated for average annual household energy expenditures; total annual expenditures for individual fuels; annual average per unit energy costs for residential energy sources and are set at 275 percent of the relevant national average household energy expenditures. The current benchmarks are shown in Table 1.
Applicants must demonstrate that proposed communities meet one or more benchmarks to qualify as an eligible beneficiary of a grant under this program. All applications must meet these current eligibility benchmarks for high energy cost. Based on available published information on residential energy costs, RUS anticipates that only those communities with the highest energy costs across the country will qualify.
The EIA's Residential Energy Consumption and Expenditure Surveys (RECS) and reports provide the baseline national average household energy costs that were used for establishing extremely high energy cost community eligibility criteria for this grant program. The RECS data base and reports provide national and regional information on residential energy use, expenditures, and housing characteristics. EIA published its latest available RECS home energy expenditure survey results in 2012. These estimates of home energy usage and expenditures are based on national surveys conducted in 2009 survey data and are shown in Table 1 as follows:
Extremely high energy costs in rural and remote communities typically result from a combination of factors including high energy consumption, high per unit energy costs, limited availability of energy sources, extreme climate conditions, and housing characteristics. The relative impacts of these conditions exhibit regional and seasonal diversity. Market factors have created an additional complication in recent years as the prices of the major commercial residential energy sources—electricity, fuel oil, natural gas, and LPG/propane— have fluctuated dramatically in some areas.
The applicant must demonstrate that each community in the grant project's
The benchmarks measure extremely high energy costs for residential consumers. These benchmarks were calculated using EIA's estimates of national average residential energy expenditures per household and by primary home energy source. The benchmarks recognize the diverse factors that contribute to extremely high home energy costs in rural communities. The benchmarks allow extremely high energy cost communities several alternatives for demonstrating eligibility. Communities may qualify based on: Total annual household energy expenditures; total annual expenditures for commercially-supplied primary home energy sources,
A community or area will qualify as an extremely high cost energy community if it meets one or more of the energy cost eligibility benchmarks described below.
(1)
• Average annual residential electricity expenditure of $3,685 per household;
• Average annual residential natural gas expenditure of $2,211 per household;
• Average annual residential expenditure on fuel oil of $3,680 per household;
• Average annual residential expenditure on propane or liquefied petroleum gas (LPG) as a primary home energy source of $2,673 per household; or
• Average annual residential energy expenditure (for all non-transportation uses) of $5,566 per household.
(2)
• Annual average cost per kilowatt hour for residential electricity customers of $0.33 per kilowatt hour (kWh);
• Annual average residential natural gas price of $33.50 per thousand cubic feet;
• Annual average residential fuel oil price of $6.68 per gallon;
• Annual average residential price of propane or LPG as a primary home energy source of $5.76 per gallon;
• Annual average residential price of Kerosene as a primary home energy source of $7.49 per gallon or
• Total annual average residential energy cost on a Btu basis of $62.12 per million Btu.
(3)
The grant applicant must establish eligibility for each community in the project's area. To determine eligibility, the applicant must identify each community included in whole or in part within the areas and provide supporting actual or estimated energy expenditure data for each community. The smallest area that may be designated as an area is a 2010 Census block. This minimum size is necessary to enable a determination of population size.
Potential applicants can compare the benchmark criteria to available information about local energy use and costs to determine their eligibility. Applicants should demonstrate their eligibility using historical energy use and cost information. Where such information is unavailable or does not adequately reflect the actual costs of supporting average home energy use in a local community, RUS will consider estimated commercial energy costs. The Application Guide includes examples of circumstances where estimated energy costs are used.
EIA does not collect or maintain data on home energy expenditures in sufficient detail to identify specific rural localities as extremely high energy cost communities. Therefore, grant applicants will have to provide information on local community energy costs from other sources to support their applications.
In many instances, historical community energy cost information can be obtained from a variety of public sources or from local utilities and other energy providers. For example, EIA publishes monthly and annual reports of residential prices by State and by service area for electric utilities and larger natural gas distribution companies. Average residential fuel oil and propane prices are reported regionally and for major cities by government and private publications. Many State agencies also compile and publish information on residential energy costs to support State programs.
Applications that contain information that is not reasonably based on credible sources of information and sound estimates will be rejected.
Where appropriate, RUS may consult standard sources to confirm the
In addition to meeting extremely high energy cost and other criteria in this notice, applicants requesting consideration under SUTA must also establish their eligible community is in a substantially underserved trust area under the provisions of 7 CFR part 1700, subpart D. Applicants should consult SUTA regulations at 7 CFR part 1709 subpart D for additional information on eligibility and qualifications of “trust lands” and of “substantially underserved trust areas.” Potential SUTA applicants are encouraged to consult with the Agency Contacts listed in this notice in preparation of their requests for consideration.
The determination of SUTA eligibility will be made by the Administrator before applications are scored and ranked.
Eligible projects must serve an eligible community and must include only eligible grant purposes. Grant funds may be used to acquire, construct, extend, upgrade, or otherwise improve energy generation, transmission, or distribution facilities serving eligible communities. All energy generation, transmission, and distribution facilities and equipment, used to provide electricity, natural gas, home heating fuels, and other energy service to eligible communities are eligible. Projects providing or improving energy services to eligible communities through on-grid and off-grid renewable energy projects, energy efficiency, and energy conservation projects are eligible. A grant project is eligible if it improves, or maintains energy services, or reduces the costs of providing energy services to eligible communities.
Funds may cover up to the full costs of any eligible projects subject to the statutory condition that no more than 4 percent of grant funds may be used for the planning and administrative expenses of the grantee.
The project must serve communities that meet the extremely high energy cost eligibility requirements described in this notice. The applicant must demonstrate that the proposed project will benefit the eligible communities. Projects that primarily benefit a single household or business are not eligible. Additional information and examples of eligible project activities are contained in the 2015 Application Guide.
The program regulations at 7 CFR part 1709 provide more detail on allowable use of grant funds, limitations on grant funds, and ineligible grant purposes. Grant funds may not be used to refinance or repay the applicant's outstanding loans or loan guarantees under the RE Act.
Each grant applicant must demonstrate the economic and technical feasibility of its proposed project. Activities or equipment that would commonly be considered as research, development, or demonstration, or commercialization activities are not eligible. Projects for deploying new energy technologies that are not in established commercial use will not be considered as technologically feasible projects and would, thus, be ineligible grant purposes. However, grant funds may be used for projects that involve the innovative use or adaptation of energy-related technologies that have been commercially proven. RUS, in its sole discretion, will determine if a project consists of ineligible research, development, demonstration, or commercialization activities or relies on unproven technology, and that determination shall be final.
Section 19(b)(2) of the RE Act provides that no more than 4 percent of the grant funds for any project may be used for planning and administrative expenses of the grantee not directly related to delivery of the project. RUS will not make awards for any such expenses exceeding 4 percent of grant funds. Because of this limitation, applicants must detail any indirect costs.
For High Energy Cost Grants, the maximum amount of grant assistance that will be considered for funding per grant application under this notice is $3,000,000. The minimum amount of assistance for a competitive grant application under this program is $50,000.
Eligible applicants must include only one project per application, but the project can include many locations. Applicants may submit applications for multiple projects. For high energy cost grants, no more than $3 million in grant funds will be awarded per project application. An applicant will only be awarded funding for one project under this notice. The award will be made to the highest ranked application submitted; other applications from the same applicant or project will remain unfunded under this notice.
Grant funds cannot be used for: Preparation of the grant application, fuel purchases, routine maintenance or other operating costs, and purchase of equipment, structures, or real estate not directly associated with provision of residential energy services. In general, grant funds may not be used to support projects that primarily benefit areas outside of eligible communities. However, grant funds may be used to finance an eligible community's proportionate share of a larger energy project.
Consistent with USDA policy and program regulations, grant funds awarded under this program generally cannot be used to replace other USDA assistance or to refinance or repay outstanding loans under the RE Act. Grant funds may, however, be used in combination with other USDA assistance programs including electric loans. Grants may be applied toward grantee contributions under other USDA programs depending on the specific terms of those programs. For example, an applicant may propose to use grant funds to offset the costs of electric system improvements in extremely high cost areas by increasing the utility's contribution for line extensions or system expansions to its distribution system financed in whole or part by an electric loan under the RE Act. An applicant may propose to finance a portion of an energy project for an extremely high energy cost community through this grant program and secure the remaining project costs through a loan or loan guarantee from RUS or other grant sources. The determination of whether a project will be completed in this manner will be made solely by the Administrator.
RUS may refuse to provide an award where the selected applicant has taken actions in violation of restrictions on certain project activities prior to completion of pre-award environmental review. See section F.2.ii of this notice and 7 CFR 1794.15, or its successor.
All applications must be prepared and submitted in compliance with this notice and the 2015 Application Guide. The Application Guide contains additional information on the grant programs, sources of information for use in preparing applications, examples of eligible projects, and copies of the required application forms.
The FY 2015 Application Guide, copies of required forms, and other information on the High Energy Cost Grant Program are available from these sources:
a. The Internet at the program Web site:
b. Through Grants.gov (
c. By request from Robin Meigel, Finance Specialist, Rural Utilities Service, Electric Program, Office of Portfolio Management and Risk Assessment, United States Department of Agriculture, 1400 Independence Avenue SW., STOP 1568, Room 1274-S, Washington, DC 20250-1568. Telephone (202) 720-9452, Fax (202) 720-1401, email:
Applicants must follow the directions in this notice and the 2015 Application Guide in preparing and submitting their application packages.
This program does not require or accept pre-applications. This program is not subject to E.O. 12372 “Intergovernmental Review of Federal Programs” as implemented by USDA.
Application packages must be prepared consistent with the requirements of this notice, the 2015 Application Guide and program regulations at 7 CFR 1709.117. Applicants are encouraged to consult the recently updated Uniform Administrative Requirements, Cost Principles, and Audit Requirements For Federal Awards, 2 CFR part 200 for additional requirements applicable to grants under this program. Application packages that do not comply with the eligibility and content provisions of this notice will be rejected. As used in this notice “narrative” means a written statement, description or other written material prepared by the applicant, for which no form exists.
The completed application consists of the following sections and forms. Narrative sections should be formatted as indicated above and assembled in the sequence specified. Table 2 lists the required content and form of a complete application. Applicants may use this table to assure that their applications are complete and assembled in order.
This form must be signed by a person authorized to submit the proposal on behalf of the applicant.
The Project Summary and Eligibility Statement is a short narrative that establishes the application's eligibility. It describes the applicant, the eligible high energy cost community, the proposed project, and any requested priority considerations. The Project Summary should be no longer than three (3) pages.
In Part B applicants must provide a brief summary of the project proposal. The project must be described in sufficient detail to establish that it is an eligible project under the High Energy Cost Grant Program, program regulations (7 CFR part 1709) and this notice. Applicants should take great care in preparing this section to include all elements listed below. RUS will make an initial determination of eligibility and whether to accept the application for further review and scoring based on the contents of this project summary. Application packages that do not meet eligibility requirements will be rejected.
Part B will not be scored so applicants must also include any information on eligibility or priority scoring in the full project narrative proposal.
Part B must include the following information.
This section of Part B must briefly describe the applicant, its capabilities, and provides information demonstrating that the applicant is an eligible entity under program regulations at 7 CFR 1709.106 and this notice. Applicants must also be free of any debarment or other restriction on their ability to contract with the Federal government as identified in section C.1.a of this notice.
This summary must describe the eligible community or communities to be served by the project including name, location, and population based on 2010 Census. It must also provide the name and population of the local government division (
This section provides a brief overview of the project including the project title, total project costs, the amount of grant funds requested, amount and source of matching contributions, major project goals and tasks, and the location of project activities and facilities to be supported with grant funds. It should indicate the proposed project duration. It must state how the grant project will provide benefits to the eligible community and offset or reduce the target community's extremely high energy costs. The summary should briefly identify any state or tribal rural development initiative that the project supports.
Applicants should indicate all Priority Considerations for which they are seeking additional points in project scoring. Priority points to be awarded under this notice are set forth in section E.1.
The project summary should list the Applicant's name, address, telephone number, fax, and email address and contact person for the application. Include the contact person's address, telephone number, fax and email address if different from the applicant.
The project narrative proposal describes in detail the proposed grant project, the project benefits, and the proposed budget. Part C follows sequentially after Parts A and B in assembling the package and contents should be assembled and paginated in the order described below.
In preparing the project narrative proposal, Applicants must address individually and in narrative form each of the proposal evaluation and selection criteria contained in section E.1 of this notice. The project narrative proposal of eligible applications will be scored competitively and the results used to rank applications for awards.
Format and length. The narrative proposal should be formatted according to the instructions in section D.2.ii. Applicants are strongly encouraged to keep the narrative proposal to no longer than approximately 30 pages, exclusive of required forms. Successful application narratives have been shorter in length. Applicants may use the Supplementary Materials section to include up to ten (10) pages of letters of support and other information for reviewers. Letters from Members of Congress and senior State government officials will not count against this page limit.
The project narrative proposal includes the following sections assembled in the order indicated.
Part C of the application package must include a Table of Contents immediately before the Executive Summary. The Table of Contents must provide page numbers for all sections, forms, and supplemental materials. The Table of Contents will help reviewers assure that all submitted materials are included in the application package and in correct, intended order. This section will not be scored or counted against any suggested page limits.
The Executive Summary is a one page introduction to the project that briefly identifies the applicant, project title, amount of grant funds requested, eligible communities, the activities and facilities to be supported, and how the grant project will benefit the community and offset or reduce the community's extremely high energy costs. Any priority considerations requested should be listed. The Executive Summary will be used to prepare any project descriptions or announcements and should list a key contact person for the application with telephone and fax numbers, mailing address and email address. The Executive Summary is a required component of the application (7 CFR 1709.117(b)(1)), but will not be scored. The Executive Summary immediately follows the Table of Contents.
The narrative project description should be no longer than about 30 pages in total and should be prepared using the formatting instructions above in section D.2.ii.
The Applicant must describe the community or communities to be served by the grant and provide supporting information establishing eligibility. The narrative must show that the proposed grant project's target area or areas are located in one or more communities where the average annual residential energy costs exceed one or more of the benchmark criteria for extremely high energy costs as described in section C3 and Table 1 of this notice. The narrative must clearly identify the location and population of the areas to be aided by the grant project and their energy costs. It must also include the population of the local government division in which each community is located. Local energy providers and sources of high
The population estimates should be based on the 2010 Census available from the U.S. Census Bureau. Additional information and exhibits supporting eligibility and community energy sources may be obtained from the U.S. Census, the Energy Information Administration, other Federal and State agencies, or private sources. The Application Guide provides additional information and sources that are useful in establishing community eligibility.
The Applicant must identify and analyze the major challenges that the eligible community faces and how their extremely high energy costs impair their ability to meet these needs or adversely affect other aspects of community wellbeing. The Applicant may, for example, describe how socioeconomic, environmental, or public policy considerations may affect the community's ability to meet its energy needs or influence the choices that they may make.
The Applicant must describe how the proposed grant project is responsive to the identified community challenges or needs by, for example, providing or improving critical energy infrastructure or offsetting or reducing the impacts of high energy costs on community residents through energy efficiency improvements. In providing community information, Applicants should bear in mind that they are presenting a case that their project community should be ranked higher than competing similar projects.
In analyzing community needs, Applicants should address any community characteristics or extraordinary conditions that reviewers should consider in weighing need for assistance. In particular, the narrative should address any circumstances that may qualify the application for one or more of the priority scoring considerations established in section E of this notice. Priority considerations include high poverty areas, rurality, renewable energy, extraordinary conditions or circumstances, and Substantially Underserved Trust Areas.
The narrative must describe the proposed project in sufficient detail to establish that it is an eligible project under program regulations at 7 CFR 1709.109 to 1709.111, the Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards at 2 CFR part 200, and this notice.
The applicant must describe the project design, construction, materials, equipment, and associated activities in sufficient detail to support a conclusion by reviewers of the project's eligibility and technical feasibility as required by program regulations 7 CFR 1709. 117 and this notice. Proposed projects involving construction, repair, replacement, or improvement of electric generation, transmission, and distribution facilities must generally be consistent with the standards and requirements for projects financed with loans and loan guarantees under the RE Act as set forth in RUS's Electric Programs Regulations and Bulletins and may reference these requirements.
The Applicant's proposed scope of work must include major tasks to be performed, any services to be provided directly to beneficiaries, a proposed timeline for completing each task; and an estimate of the overall project duration.
The application must identify the location of the project target area with the eligible extremely high energy cost communities to be served, and the locations, if any, outside of these areas where project funded activities will be conducted.
In describing the project plan and schedule, applicants must specifically identify any regulatory and other approvals required by Federal, State, local, or tribal agencies, or by private entities (as a condition of financing), that are necessary to carry out the proposed grant project. The Applicant must provide an estimated schedule for obtaining the necessary approvals. Prior to the obligation of any funds for the selected proposals, applicants will be required to gather specific information in order for RUS to comply with the National Environmental Policy Act of 1969 (NEPA) and National Historic Preservation Act (NHPA), for which the provision of funding is considered an undertaking subject to review. The environmental information that must be supplied by the applicant can be found in the RUS Environmental Questionnaire in the application materials.
Finally, the Applicant must address how the project responds to the community needs identified in its assessment and analysis of community needs above.
In this section the applicant must describe its organizational structure and capacity to carry out the project according to its proposed terms and consistent with Federal requirements. The Applicant must establish that it is an eligible applicant under this program as provided in section C.1.a above. Additionally, the Applicant must establish that it and its project are located in the United States, its territories, or an eligible insular area.
The narrative and supporting documentation must describe the applicant entity and establish its eligibility consistent with regulations at 7 CFR part 1709 and this notice. The description must include the entity's organizational structure, ownership, when it was established, where it operates, sources of funding, whether it is regulated, and identify any subsidiaries, affiliates, or parent entities. The applicant must describe its financial management system that it will use for grant activities. Finally, the applicant must demonstrate that it has or will have the legal authority to enter into a financial assistance relationship with the Federal Government. Examples of supporting evidence of applicant's legal existence and eligibility include: A reference to or copy of the relevant statute, regulation, executive order, or legal opinion authorizing a State, local, or tribal government program, articles of incorporation or certificates of incorporation or good standing for corporate applicants, partnership or trust agreements, and board resolutions. These documents will not be counted towards any page limitation and should be included at the end of the Application Package. Applicants must also be free of any debarment or other restriction on their ability to contract with the Federal Government or receive a Federal grant.
This section must provide a narrative describing the applicant's management structure, capabilities, and project performance plans. The application must include a description of the entity's organizational structure, method of funding, legal authority, key executives, project management experience, and financial management systems. Financial statements and other supporting documentation about applicant eligibility, experience, financial and legal capacity to carry out the project may be referenced here.
The applicant must describe how and by whom the project will be managed during construction and all phases of operation. The description must include the applicant's project management structure, key project personnel, and the degree to which applicant's full time employees, affiliated entities or contractors will be used to complete
The applicant must describe the identities, relationship, qualifications, and experience of these affiliated and contracted entities. The experience and capabilities of these affiliated and/or contracted entities will be reviewed by the rating panel.
Applicants are encouraged to review the financial management requirements for Federal grantees in 7 CFR part 1709 and government-wide financial assistance regulations at 2 CFR part 200, and to address their ability to comply with these requirements in their applications.
Overall, this section should provide information that will support a finding that the overall combination of management experience, financial management capabilities, resources and project structure will enable successful completion of the project.
This subsection should include a detailed description of the applicant's relevant experience and that of any other organization that will carry out the proposed projects. Information should be included on past projects, success rates, long-term results, and community and individual consumer benefits. If the applicant has received any prior High Energy Cost Grants or other Federal funding, a detailed description of these awards and past performance is required in this section.
The application must identify all key project staff and provide brief experience and qualifications descriptions. If the applicant proposes to use affiliated entities, contractors, or subcontractors to provide services funded under the grant, the applicant must describe the identities, relationship, qualifications, and experience of these affiliated entities. The rating panel will consider the experience and capabilities of these entities in scoring the proposal. If the application is selected for funding, key personnel provisions may be included in the grant agreement as a condition of the award.
Federal grant regulations provide that each grant award must include establishment of performance goals defined as “a target level of performance expressed as a tangible, measurable objective, against which actual achievement can be compared” (2 CFR 200.76. See also 2 CFRs 200.301, and 200.308 and 7 CFR1709.117).
In this section the applicant must explain how the project addresses the energy needs of the community and must clearly identify appropriate proposed measures of project performance and success. Measures of performance might include percent completion of construction projects over the proposed schedule. Objectives or measures of benefits might include, for example, expected reductions in home or community energy costs, avoided cost increases, enhanced reliability, or economic or social benefits from improvements in energy services available to the community. The applicant should include quantitative estimates of cost or energy savings and other benefits. The applicant should provide documentation or references to support its projections of cost-effectiveness savings and improved services.
The applicant must include a proposed progress reporting plan describing how it plans to measure, monitor, and report on the effectiveness of the project in delivering its projected benefits and on any significant developments or challenges that arise during project performance. RUS will use these proposed performance measures and reporting plans to establish the performance measures incorporated in the grant agreement in the event the proposal is selected for an award. These suggested performance criteria are not binding on the Agency.
In this subsection the applicant must present its proposed project budget for the full term of the project and also provide information about its own financial capability to support the project and manage it in compliance with requirements for Federal assistance.
The budget narrative must provide a detailed breakdown of all estimated costs and allocate these costs among the listed tasks in the work plan. The narrative and budget exhibits and forms must itemize and explain major proposed project cost components such as, but not limited to, the expected costs of design and engineering and other professional services, personnel costs (salaries/wages and fringe benefits), equipment, materials, property acquisition, travel (if any), and other direct costs, and proposed recovery of indirect costs, if any. The budget must document that planned administrative and other expenses of the project sponsor that are not directly related to performance of the grant will not total more than 4 percent of grant funds.
The applicant must explain the basis for any cost estimates. A pro forma operating budget for the three years of operations must be included as an exhibit in this section.
The applicant must clearly identify the source and amount of any other Federal or non-Federal contributions of funds or services that will be used to support the proposed project, including any program income.
The detailed budget narrative must be accompanied by SF-424A, “Budget Information—Non-Construction Programs,” or SF-424C “Budget Information—Construction Programs,” as applicable. All applicants that submit applications through Grants.gov must use SF-424A.
Consistent with the requirements of 2 CFR 200.205, the RUS must review the financial risk posed by applicants. In support of this review, applicants must provide additional narrative regarding the financial capability of their organization including, for example:
(1) Financial stability;
(2) Quality of management systems and ability to meet the management standards prescribed under Federal grant regulations in 2 CFR part 200;
(3) History of performance in managing any other Federal awards, including timeliness of compliance with applicable reporting requirements, conformance to the terms and conditions of previous Federal awards, and if applicable, the extent to which any previously awarded amounts will be expended prior to future awards;
(4) Reports and findings from audits performed for other Federal assistance under 2 CFR part 200, subpart F—Audit Requirements or the reports and findings of any other available audits; and/or
(5) Any contracts with certain parties that are debarred, suspended or otherwise excluded from or ineligible for participation in Federal programs or activities.
Applicants may cross reference relevant discussions elsewhere in the application in support of their financial stability and financial management capability.
The Applicant must address how the project will support rural economic
The Administrator has approved certain priority considerations in scoring and ranking applications consistent with program regulations at 7 CFR 1709.123. These priority scoring considerations and points to be awarded are described in Section E of this notice. In order to assure that applicants receive all of the priority points for which they are eligible, this section should identify each priority consideration that the Applicant is requesting and provide a brief statement of the circumstances that make them eligible for the priority criterion. Applicants may cross reference more detailed information elsewhere in the application package. Applicants should carefully read section E on scoring priority considerations before writing this section. Priority will be awarded for the following:
• High Poverty Communities;
• Rurality (population);
• Renewable Energy Projects;
• Extraordinary conditions/circumstances such as a disaster, imminent hazard, unserved areas, severe economic hardship for energy provider or community, or other circumstance; and
• Substantially Underserved Trust Areas.
In order to establish compliance with other Federal requirements for financial assistance programs, the applicant must execute and submit as parts of the application package the following forms and certifications:
• SF 424B, “Assurances—Non-Construction Programs” or SF 424D, “Assurances—Construction Programs” (as applicable). All applicants applying through Grants.gov must use form SF 424B.
• SF LLL, “Disclosure of Lobbying Activities.” All applicants must file this disclosure form (2 CFR 418.110). The applicant should complete name and address information. If no expenditure indicate $0, “none,” or “not applicable” in the reporting section.
• Form AD-3030 “Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants” (for corporate applicants only).
• Rural Utilities Service “Certification Regarding Debarment, Suspension and Other Responsibility Matter—Primary Covered Transactions”.
• High Energy Cost Grant Program RUS Environmental Questionnaire. The RUS environmental questionnaire solicits information about project characteristics and site-specific conditions that may involve environmental, historic preservation, and other resources. The information will be used by RUS's environmental staff to determine what, if any, additional environmental impact analyses may be necessary before a final grant award may be approved. A copy of the environmental questionnaire and instructions for completion are included in the Application Guide and may be downloaded from RUS's Web site or under funding opportunity announcement RD-RUS-HECG15 at Grants.gov.
Applicants may include additional information for reviewers such as letters of support and any other supplementary materials not included as exhibits in the project narrative that support eligibility, or priority considerations. Letters from Congress and senior State Officials will not be counted against the page limitation.
Application contents for entities that have requested SUTA consideration are identical to those for other applicants. The request for SUTA consideration is separate from the application package to be reviewed by the rating panel. See discussion of SUTA above in section C and SUTA regulations at 7 CFR 1700.108 for additional information on what is required in the separate SUTA request.
The Administrator has determined to use the discretion provided under agency regulations at 7 CFR 1709.122 to consider under this notice unfunded applications submitted in response to the 2014 funding opportunity notice. The application contents and scoring criteria are sufficiently alike, so that reviewers can find all required information in the application package and newly submitted information. Allowing reconsideration reduces burdens on eligible applicant in submitting a new application and on the agency in reviewing applications for eligibility and completeness.
Applicants that submitted applications in response to the notice published on June 2, 2014 (79 FR 31283) and that later were notified by RUS that the application was determined to be eligible and complete but was not selected for an award may request reconsideration of their applications under this notice. To request reconsideration, the applicant must submit a brief signed letter requesting reconsideration and identifying any additional information that they wish to be considered by the rating panel. The Applicant may also submit up to 10 pages of new explanatory or supplementary material to be attached to its application. This may include, for example, updated project budgets or schedules. The request must be accompanied by a new original, signed Standard Form SF-424, “Application for Federal Assistance” and a signed Form AD-3030 “Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants” (for corporate applicants only).
The required application package for reconsideration will consist of the new signed SF-424, the letter requesting reconsideration, additional information or supporting materials, plus the original application package submitted in 2014 maintained in Agency files. The Agency will add the newly submitted material to the existing application package for review by the rating panel. You do not need to send a copy of the 2014 application package. Required forms are available on our Web site (
Because this abbreviated application reconsideration package differs from the general application package for first time applicants, all requests for reconsideration must be submitted in paper form and sent to RUS at the addresses for paper applications indicated in section D.7 on or before the application deadline. RUS will not accept requests for reconsideration by email or fax. Requests for reconsideration cannot be submitted
(1) Paper application packages submitted to RUS must include the original signed application and two (2) copies.
(2) Grant applications may be submitted electronically through Grants.gov. Please carefully read the FY 2015 Application Guide and Special Instructions for Grants.gov applications for additional guidance on submitting an electronic application. Only one submission through Grants.gov is required.
In addition to the information required to be submitted in the application package, RUS may request that successful grant applicants provide additional information, analyses, forms and certifications before the grant agreement is signed and funds are obligated. These may include additional information and analyses for any environmental reviews and clearances under the National Environmental Policy Act (NEPA) (42 U.S.C. 4321-4370h), other statutes, and USDA regulations. The successful applicant may be required to submit additional certifications required under USDA and Government-wide assistance regulations. RUS will advise the applicant in writing of any additional information required.
The applicant for a grant must supply a Dun and Bradstreet Data Universal Numbering System (DUNS) number as part of an application. The Standard Form 424 (SF-424) contains a field for the DUNS number. The applicant can obtain a DUNS number free of charge by calling Dun and Bradstreet. Please see
Before submitting an application, the applicant must register in the System for Award Management (SAM) (formerly Central Contractor Registry (CCR)). Applicants must register for the SAM at
Applicants may submit applications on paper directly to the Agency or electronically through Grants.gov.
a. Paper grant applications, including requests for reconsideration and SUTA applications, must be postmarked and mailed, shipped, or sent overnight no later than December 14, 2015 to be eligible for FY 2015 grant funding. RUS will begin accepting applications on the date of publication of this notice. RUS will accept for review all applications postmarked or delivered by this deadline.
For the purposes of determining the timeliness of an application, RUS will accept the following as valid postmarks: The date stamped by the U.S. Postal Service on the outside of the package containing the application delivered by U.S. Mail; the date the package was received by a commercial delivery service as evidenced by the delivery label; the date received via hand delivery to the RUS headquarters. Late applications will not be considered and will be rejected.
RUS will not provide notifications acknowledging receipt of paper applications. Applicants should retain proof of mailing or shipping.
b. Electronic grant applications must be filed with Grants.gov on or before December 14, 2015 to be eligible for FY 2015 funding. RUS uses the date and time an electronic application was posted for submission to Grants.gov to determine timeliness of application submittal. Applications received by Grants.gov after the deadline will not be eligible for FY 2015 grant funding and will be rejected.
Applicants are encouraged to file electronic applications in advance of the deadline. Applicants encountering difficulty filing applications electronically must contact Grants.gov for assistance. Grants.gov will generate a receipt for application filing and for transmittal to USDA. RUS will not issue a separate acknowledgement of receipt. Acceptance of an application by Grants.gov or by the USDA grants warehouse does not constitute acceptance as an eligible and complete application by RUS.
c. If the submission deadline falls on Saturday, Sunday, or a Federal holiday, the application is due the next business day.
The High Energy Cost Grant Program is not subject to Executive Order 12372, “Intergovernmental Review of Federal Programs” as implemented by USDA in 2 CFR part 415. Applications do not have to be submitted to any State agencies for review before submittal.
Grant awards and use of High Energy Cost Grant program are subject to certain limitations established by Federal statutes, regulations, and policies. These restrictions may preclude awards or reimbursements to certain applicants or for certain proposed activities.
Grant funds cannot be used for:
(1) Preparation of the grant application; payment of any finder's fees or incentives for assisting in the preparation or submission of an application;
(2) Purchases of fuel or payment of utility bills;
(3) Payment of applicant's planning and administrative costs that are unrelated to the grant project and that exceed 4 percent of each grant award;
(4) Routine maintenance or other operating costs;
(5) Purchase of equipment, structures, or real estate not directly associated with provision of residential energy services;
(6) Project construction costs incurred prior to the date of the grant award, except as provided in 7 CFR 1709.11(d);
(7) Costs of project development and feasibility analyses exceeding 10 percent of total project costs;
(8) Projects that primarily or only consist of educational, outreach, and audit or assessment activities and do not include a substantial investment in physical infrastructure or energy saving improvements;
(9) Projects that primarily benefit a single household or business;
(10) Projects that primarily benefit areas outside of eligible communities;
(11) Research, development, demonstration, or commercialization activities;
(12) Refinancing or repayment of the applicant's outstanding loans or loan guarantees under the Rural Electrification Act of 1936, as amended (7 U.S.C. 901
(13) Funding of political activities;
(14) Payment of any judgment or debt owed to the United States; or
(15) Providing any share or benefit to a member of Congress except as provided in 7 CFR 1709.20.
In addition to the above, RUS may refuse to provide an award or reimbursement where the selected applicant has taken actions in violation of restrictions on certain project activities prior to completion of pre-award environmental review. See section F.2.a of this notice and 7 CFR 1794.15, or its successor.
Grant applications may be submitted on paper or electronically. A completed paper application package must contain all required parts in the order indicated in the above section D.2.iii on “Content and Form of Application Submission” and Table 2. The paper application package must include one original application with original signatures on all forms and certifications and two complete copies.
Completed paper applications, including requests for reconsideration and SUTA requests, must be delivered to the RUS headquarters in Washington, DC, using United States Mail, overnight delivery service, or by hand to the following address: Assistant Administrator, Electric Programs, Rural Utilities Service United States Department of Agriculture, 1400 Independence Avenue SW., STOP 1560, Room 5165 South Building, Washington, DC 20250-1560. Applications should be marked “Attention: High Energy Cost Community Grant Program.”
Applicants are advised that regular mail deliveries to Federal Agencies, especially of oversized packages and envelopes, are frequently delayed by increased security screening requirements that include irradiation which may damage contents. Applicants may wish to consider using Express Mail or a commercial overnight delivery service instead of regular mail. Applicants wishing to hand deliver or use courier services for delivery should contact an RUS representative in advance to arrange for building access. If an applicant wishes to submit such materials, they should contact the Agency Contact listed in section D.1 above for additional information.
a. RUS will not accept applications via fax or electronic mail.
b. Electronic applications must be submitted through the Federal government's Grants.gov portal at
c. How to use Grants.gov. Grants.gov contains full instructions on all required passwords, credentialing and software.
Electronic Application materials for the High Energy Cost Grant notice can be found by searching under Funding Opportunity Number: RD-RUS-HECG15 or Catalog of Federal Domestic Assistance (CFDA) Number 10.859. In addition to the Grants.gov mandatory forms, applicants must download, complete, and attach specific USDA and High Energy Cost Grant instructions, forms, and certifications to submit a complete electronic application package. Additional forms to be downloaded, completed, and uploaded to the Grants.gov application package include: The RUS “Certification Regarding Debarment, Suspension and Other Responsibility Matter—Primary Covered Transactions,” Form AD-3030 “Representations Regarding Felony Conviction and Tax Delinquent Status for Corporate Applicants” (for corporate applicants only), and the RUS Environmental Questionnaire. Electronic Applications that do not contain these required forms will be rejected as incomplete.
d. Credentials and Authorizations for Electronic Applications.
1. System for Award Management. All applicants must register with the System for Award Management. Submitting an application through Grants.gov requires that your organization list in the System for Award Management (SAM) (formerly Central Contractor Registry, CCR). The Agency strongly recommends that you obtain your organization's DUNS number and SAM listing well in advance of the deadline specified in this notice. See
2. Credentialing and authorization of applicants. Grants.gov will also require some credentialing and online authentication procedures before you can submit an application. These procedures may take several business days to complete, further emphasizing the need for early action by applicants to complete the sign-up, credentialing and authorization procedures at Grants.gov before you submit an application at that Web site.
3. Some or all of the SAM and Grants.gov registration, credentialing and authorizations require updates. If you have previously registered at Grants.gov to submit applications electronically, please ensure that your registration, credentialing and authorizations are up to date well in advance of the grant application deadline.
e. Difficulties in submitting electronic applications.
RUS encourages applicants who wish to apply through Grants.gov to submit their applications in advance of the deadlines.
If a system problem occurs or you have technical difficulties with an electronic application, please use the customer support resources available at the Grants.gov Web site.
In case of difficulty filing electronically that cannot be resolved, applicants may download application materials and complete forms online through Grants.gov without completing the registration requirements. Application materials prepared online may be printed and submitted in paper to RUS as detailed above.
This section describes the process and application review criteria that the RUS will use to evaluate the eligibility and merit of the applications packages submitted. This notice establishes the criteria and weights to be used and the evaluation process as provided by program regulations at 7 CFR part 1709.
The Administrator of RUS has established the merit selection and priority consideration criteria for evaluating and scoring the applications submitted under this notice pursuant to program regulations at 7 CFRs 1709.102 and 1709.123. The criteria set forth below will be used by one or more rating panels to be selected by the Assistant Administrator, Electric Programs. Additional information on how scoring criteria will be applied can be found in the FY 2015 Application Guide.
The maximum number of points to be awarded is 100. The maximum points available under project design and technical merit criteria is 65. The maximum number of points to be awarded under priority considerations that support USDA and RUS program priorities is 35.
The evaluation criteria and weights in this notice differ from those used in the 2014 notice. For this reason any 2014 applicant's packages being reconsidered will be rescored according to the criteria in this notice.
Table 3 shows the selection criteria and weights that will be used in scoring the 2015 applications.
Reviewers will consider the soundness of applicant's analysis of community needs and benefits, the adequacy of the proposed project plan, the technical feasibility of the project, the adequacy of financial and other resources, the competence and experience of the applicant and its team, project goals and objectives, and performance measures. Project proposals will be evaluated on how well the proposal addresses application content requirements and evaluation criteria and how well their application compares to other applicants. A total of 65 points may be awarded under the following criteria.
Under this criterion, reviewers will consider the applicant's assessment of community needs and how the grant project addresses those needs and how the severity of identified needs compares to other applications. Reviewers will consider the identification and documentation of eligible communities, their populations, and assessment of community energy needs targeted by the grant project. Information on the severity of physical and economic challenges affecting eligible communities will be considered. Reviewers will weigh: (1) The applicant's analysis of community energy challenges and (2) why the applicant's proposal presents a greater need for Federal assistance than other competing applications. In assessing the applicant's demonstration of community needs, the rating panel will consider information in the narrative proposal addressing the following:
(1) The burden placed on the community and individual households by extremely high energy costs. This burden may be evidenced by such quantitative measures as, for example, total energy expenditures, per unit energy costs, energy cost intensity for occupied space, or energy costs as a share of average household income, and persistence of extremely high energy costs compared to national or statewide averages.
(2) The hardships created by limited access to reliable and affordable energy services;
(3) The availability of other resources to support or supplement the proposed grant funding; and
(4) Indications of community support for the proposed project solution to their energy challenges.
Reviewers will assess the technical and economic feasibility of the project and how well its goals and objectives address the challenges of the extremely high energy cost community. The panel will review the proposed design, construction, equipment, and materials for the community energy facilities in establishing technical feasibility. Reviewers may propose additional conditions on the grant award to assure that the project is technically sound. Reviewers will consider the adequacy of the applicant's budget and resources to
In this section, the applicant will be awarded points on the technological design of the project. The applicant must provide a narrative description of the project including a proposed scope of work identifying major tasks and proposed schedules for task completion, a detailed description of the equipment, facilities and associated activities to be financed with grant funds, the location of the eligible extremely high energy cost communities to be served, and an estimate of the overall duration of the project. The Project Design description should be sufficiently detailed to support a finding of technical feasibility. Proposed projects involving construction, repair, replacement, or improvement of electric generation, transmission, and distribution facilities must generally be consistent with the standards and requirements for projects financed with loans and loan guarantees under the RE Act as set forth in the Agency's Electric Programs Regulations and Bulletins and may reference these requirements.
Reviewers will assess the adequacy of the proposed management plan against the content requirements in this notice and in comparison to the quality of other applications received. Applicants should take care to address all the required content materials. Points will be awarded for robust management plans, and realistic succinct schedules. If the applicant proposes to secure equipment, design, construction, or other services from non-affiliated entities, the applicant must briefly describe how it plans to procure and/or contract for such equipment or services consistent with Federal requirements. Reviewers will award the highest points to applications that fully include all required information and support a finding that the combination of management team's experience, financial management capabilities, resources and project structure will enable successful completion of the project.
Reviewers will assess the applicant's demonstrated experience in successfully administering and carrying out projects comparable to the grant proposal. In lieu of direct experience, reviewers will consider the efforts applicant has taken to secure the capacity to provide energy services in rural areas. The Agency will consider the experience of the project team and the effectiveness of the program design in compensating for lack of extensive experience. If the applicant has received any HECG funding, or other Federal funding a detailed description of past performance is required in this section. Points will be awarded to organizations with proven track records or that have established a management structure and team with capacity and experience to carry out the project. Points will be awarded based on how well the applicant addressed the content requirements of this notice, the quality of the proposed project organizational capacity and how the proposal compares with other applications.
Reviewers will assess the quality and capacity of project team to carry out the proposal. Reviewers will consider whether the key project staff members possess demonstrated experience in successfully administering and carrying out projects that are comparable to the grant proposal. Reviewers may consider whether the project team includes staff or other identified consultants or contractors needed to successfully complete the project. If the applicant proposes to use affiliated entities, contractors, or subcontractors to provide services funded under the grant, reviewers will consider the identities, relationship, qualifications, and experience of these affiliated entities. Points will be awarded based on how well the applicant addressed the requirements in this notice and how the applicant's proposal compares to other applications.
Applicants must clearly identify project goals, objectives and performance measures to track the progress and success of their proposed project. Reviewers will assess how well the applicant's plan to evaluate and report on the success and cost-effectiveness of financed activities. Reviewers will consider how well the results obtained measure any benefits to the eligible community such as, for example, energy saved, costs saved or avoided, or renewable energy produced. Reviewers will also assess whether applicant's proposed measures provide a quantitative basis for tracking project success and whether the application provides documentation or references to support its statements about cost-effectiveness savings and improved services. Reviewers will award points based on how well the applicant meets the requirements of the notice, the effectiveness of the proposed measures to monitor performance, and how the application compares against other proposals.
Reviewers will consider applicant's description of the reporting plan and how it contributes to tracking progress and performance and the consequences if project falls behind schedule. Reviewers will assess points based on the adequacy of the plan and how well it compares to other applications.
Reviewers will consider whether applicant has fully responded to requirements of this notice and whether the narrative, forms and exhibits provide sufficient information to assess the adequacy of the project budget and the financial feasibility of the project.
The budget materials must document that planned administrative and other expenses of the project sponsor that are not directly related to performance of the grant will not total more than 4 percent of grant funds. The application must also identify the source and amount of any other Federal or non-Federal contributions of funds or services that will be used to support completion of the proposed project. Points will be awarded for completeness, realistic budget costs, and feasibility. Reviewers may consider total grant funds requested as a share of total project costs in assessing feasibility. All matching contributions must be clearly identified. No additional points will be awarded for matching contribution. Reviewers will consider them in assessing feasibility and commitment to completing the project. Reviewers will score the proposal based on how well the applicant's budget submission fully complied with requirements of the notice and whether project resources, including the grant request and identified matching contributions, are adequate to complete the project as proposed. Reviewers will also assess how well the applicant's proposal compared with other projects.
The reviewing panel will assess how effectively the proposed project is coordinated with State rural development initiatives, if any, and is consistent with and supports these
In addition to the points awarded for project design and technical merit, all proposals will be reviewed and awarded additional points based on certain characteristics of the project or the target community. USDA Rural Development Mission Area policies generally encourage agencies to give priority in their programs to rural areas of greatest need and to support other Federal policy initiatives. In furtherance of these policies, the RUS will award additional points for the priorities identified in this notice. The priority criteria and point scores used in this notice are consistent with the program regulations in 7 CFR part 1709. The Agency will give priority consideration to areas suffering high poverty, smaller rural and remote communities, projects that support renewable energy, projects serving communities experiencing extraordinary circumstances affecting their ability to provide energy services, and Priority points will also be awarded to applications that the Administrator has accepted for consideration under Substantially Underserved Trust Area regulations at 7 CFR part 1700, subpart D. A maximum of 35 total points may be awarded under the following priority criteria.
USDA Rural Development is committed to reducing the impacts of high and persistent poverty in rural communities. The economic hardship of extensive and persistent poverty exacerbates the impacts of extremely high energy costs on families and businesses and hampers the community's ability to meet their energy needs. In support of this USDA initiative, we will award 10 priority points for projects that serve communities in counties that are classified as High Poverty or Persistent Poverty by the USDA Economic Research Service “Geography of Poverty” Web page (
Note on Alternative Economic and Population Data for Eligible Territories and Insular Areas: RUS recognizes that comparable economic and household income information may not be available for eligible areas that are not States. Applicants from these areas should provide any public information that is readily available on territorial or national median household income and local community economic characteristics and other indications of economic challenge posed by extremely high energy costs. Applications from these areas will be scored based on the provided data.
Consistent with the USDA Rural Development policy to target resources to smaller rural communities with significant needs and recognizing that smaller and remote communities are often comparatively disadvantaged in seeking assistance, RUS has established a sliding scale for awarding points based on population. RUS has also determined to award the full 10 points to applications from the Virgin Islands and eligible Pacific Insular areas. Reviewers will award additional points based on the rurality (as measured by population) of the project communities to be served with grant funds under one of two options below.
(a) 2,500 or less, 10 points;
(b) Between 2,501 and 5,000, inclusive, 7 points;
(c) Between 5,001 and 10,000, inclusive, 5 points;
(d) Between 10,001 and 20,000, inclusive, 3 points; and
(e) Above 20,000, 0 points.
Applicants must use the latest available population figures from the 2010 U.S. Census available at American Fact Finder (
The priority scoring criteria are intended to carry out Rural Development policy to give priority to areas most challenged by extremely high energy costs and those without access to substantial alternative economic and institutional resources to address these challenges, particularly rural, remote, and substantially-underserved areas. U.S. Census population and economic data have been used as proxy measures for rurality, remoteness, and economic challenges. It has become evident that comparable, up-to-date U.S. Census population and economic information are not easily available or unavailable for communities in the Virgin Islands or Pacific insular areas. After consideration, the RUS has decided to adopt an alternative for scoring eligible applications from these areas. RUS will assign a rurality score of “10” to applications from the Virgin Islands and eligible insular areas in the Pacific. This policy will place these applications on an equal footing with competing applications from other rural and remote areas.
Reviewers will award up to 5 points for projects that install, upgrade, integrate, or connect renewable energy systems to increase availability of renewable generation in rural communities. This includes, but is not limited to, projects that support deployment of renewable energy technologies through acquisition, installation, improvement, upgrade, or integration of renewable energy for electricity generation, water heating, building or process heating systems, system controls and other smart grid
The Administrator in his sole discretion has decided to provide up to 5 points for project applications for communities that exhibit one or more extraordinary conditions or circumstances that affect the community's ability to provide energy services or to make investments to reduce energy use or costs. This priority includes considerations that were recognized separately under prior notices as well as allowing for recognition of other extraordinary circumstances adversely impacting eligible high energy cost communities. The 2015 Application Guide has more detail on situations that may qualify an application for priority points under this criterion. Reviewers may award up to a total of 5 points, based on their assessment of the hardship presented, for the following extraordinary circumstances:
(1)
e. Substantially Underserved Trust Areas (5 points).
Under SUTA regulations at 7 CFR part 1700, subpart D, eligible entities may request special consideration for applications for communities in trust areas that lack adequate levels or quality of service and are in high need of grant assistance. The Administrator, in his sole discretion, has determined, to award 5 points to any application from an eligible SUTA entity for projects serving eligible areas that are also eligible for the High Energy Cost Grant Program. To receive these points, the entity must submit a separate application and request for consideration under SUTA to the Agency on or before the closing date of this opportunity notice December 14, 2015. The Administrator will review the application and issue a letter indicating whether the application is complete and is accepted for consideration under SUTA. The decision to provide SUTA consideration to an eligible application is solely at the discretion of the Administrator.
Reviewers will award 5 points to any project application that has been accepted for consideration under SUTA.
There is no requirement for matching contributions under the High Energy Cost Grant Program. The Agency has determined not to make cost contributions a separate scoring criterion. Consideration of matching contributions may be considered by the rating panel in assessing project design, financial capacity to complete the project, budget, and rural development initiative criteria.
RUS will review all application packages received to determine if they were submitted on or before December 14, 2015. Applications that are not timely submitted will be rejected. All timely received application packages will be reviewed for eligibility and completeness. Project proposals that contain all required application package content in acceptable format and that meet eligibility criteria will be accepted for consideration.
Application packages that are late, incomplete or ineligible will be rejected. Applicants will be notified if they were found to be ineligible when project selections are announced. The determinations on timeliness, completeness and eligibility will be final. The rejection notice will provide information on any appeals.
After the application closing date, RUS will not consider any unsolicited information from the applicant. The Agency may contact the applicant for additional information or to clarify statements in the application required to establish applicant or community eligibility and completeness. The RUS will not accept or solicit any additional information relating to the technical merits and feasibility of the grant proposal after the application closing date.
The Agency will look only at the three page narrative in Part B of the application package to determine if the applicant, community and project meet program eligibility requirements established in this notice and program regulations.
The Agency will use one or more rating panels composed of Agency employees to review and score eligible applications. The panel will evaluate and score the applications using the selection criteria and weights established in this notice along with the additional information provided in the 2015 Application Guide. As part of the proposal review and ranking process, panel members may make comments and recommendations for appropriate conditions on grant awards to promote
The rating panel members' individual scores for each application will be consolidated with those from other members to create a total score for each application. The panel will forward their individual scores and the ranked list of projects to the Assistant Administrator, Electric Programs for review of consistency with this notice and program regulations. The Assistant Administrator may refer the ranked list or individual project scores back to the rating panel or to an individual member to correct any apparent error or inconsistency (such as awarding a higher number of points than allowed) or for questions about scoring of individual projects. The Assistant Administrator will then prepare a selection memo for the Administrator along with a list of ranked projects.
The RUS Administrator will review the rankings and recommendations of the applications provided by the rating panel and consistent with the requirements of this notice. The Administrator may return any application to the rating panel with written instruction for reconsideration if, in his sole discretion, he finds that the scoring of an application is inconsistent with this notice and the directions provided to the rating panel.
Following any adjustments to the project in ranking, as a result of reconsideration, the Administrator will select finalists for grant awards. Administrator will consider projects in rank order taking in to account the applications, the rankings, comments, and recommendations of the rating panel, and other pertinent information, including availability of funds. The Administrator may fund grant requests in rank order to the extent of available funds. Upon consideration of panel recommendations and availability of funds, the Administrator may, in his sole discretion, decide to offer an award of less than the full amount of grant requested by an applicant. The applicant will be notified and offered a partial award. If the applicant declines an award, the offer will be withdrawn. If at any point in the selection process sufficient funds are not available to fund the next ranked project, the Administrator may, in his sole discretion, offer a partial award to the next project, or skip over that project to the next ranking project that can be supported with available funding. The Administrator may in his sole discretion, make additional awards to unfunded applications in rank order if additional funds become available.
Because of the limited amount of funds available, no applicant or project will receive more than one award under this notice. If two projects from the same applicant score high enough to potentially receive funding, the Administrator will select the project with the highest score.
The Administrator may decide based on the recommendations of the rating panel, or in his sole discretion, that a grant award should be made contingent upon the applicant satisfying certain conditions. For example, RUS will not obligate funding for a selected project—such as projects requiring extensive environmental review and mitigation, preparation of detailed site specific engineering studies and designs, or requiring local permitting, or availability of supplemental financing—until any such additional conditions are satisfied and adequate funds remain available. In the event that any selected applicant fails to comply with the all pre-award conditions within the time set by RUS, the award selection will be withdrawn.
This notice may result in awards where the total Federal share will be greater than the simplified acquisition threshold (See 2 CFR 200.88) on any Federal award under this notice over the period of performance (see 7 CFR 200.88). Therefore, applicants are advised that:
(i) RUS, prior to making a Federal award with a total amount of Federal share greater than the simplified acquisition threshold, is required to review and consider any information about the applicant that is in the designated integrity and performance system accessible through SAM (currently FAPIIS) (see 41 U.S.C. 2313);
(ii) An applicant, at its option, may review information in the designated integrity and performance systems accessible through SAM and comment on any information about itself that a Federal awarding agency previously entered and is currently in the designated integrity and performance system accessible through SAM; and
(iii) RUS will consider any comments by the applicant, in addition to the other information in the designated integrity and performance system, in making a judgment about the applicant's integrity, business ethics, and record of performance under Federal awards when completing the review of risk posed by applicants as described in 2 CFR part 200.
After the Administrator's decision, the RUS will notify successful applicants that they have been selected for a grant award. This selection is subject to continued availability of funds and compliance with all post-award requirements including but not limited to completion of any additional environmental reviews and execution of a grant agreement satisfactory to the RUS. This selection does not bind the Government to making a final grant award. Only an agreement executed by the Administrator will constitute a binding obligation and commitment of Federal funds. Grant funds will not be awarded or disbursed until all requirements have been satisfied and are contingent on the continued availability of funds at the time of the award. The RUS will advise selected applicants of any additional requirements or conditions.
RUS anticipates that award decisions will be made within 6 months of the closing date, depending on availability of funds. Final selection announcements will be posted on our Web site (
After review, the RUS will reject any application package that in its sole discretion is not complete or that does not demonstrate that the applicant, community or project is eligible under the requirements of this NOSA and applicable program regulations. Applicants will be notified in writing of RUS's decision. Applicants may appeal the eligibility rejection pursuant to program regulations on appeals at 7 CFR 1709.6 for the high energy cost grant program. Applicants must appeal in writing to the RUS Administrator within 10 days after the applicant is notified of the determination to reject the application. The appeal must state the basis for the appeal. Appeals must be directed to the Administrator, Rural Utilities Service, United States Department of Agriculture, 1400 Independence Ave. SW., STOP 1500, Washington, DC 20250-1500. The Administrator will review the appeal to determine whether to sustain, reverse, or modify the original determination by the Assistant Administrator. The Administrator's decision shall be final. A written copy of the Administrator's
The RUS will notify all applicants in writing whether they have been selected for an award. Successful applicants will be advised in writing of their selection. The receipt of an award selection letter is not a binding award of Federal funds. The selection letter does not authorize the applicant to commence performance under the award. After notification of selection, applicants will have to meet all pre-award requirements under program and other federal regulations and policies. The Agency will advise the applicant of any additional requirements or pre-award conditions. After the pre-award conditions are satisfied, the Agency will send a conditions letter with all project-specific terms and conditions to be included in the grant agreement. After the applicant indicates acceptance of these terms and conditions the Administrator will approve the award and execute the grant agreement.
Successful applicants will be required to sign a grant agreement acceptable to the Agency and complete additional grant forms and certifications required by USDA as part of the process.
Grant funds will not be advanced unless and until the applicant has executed a grant agreement and funds will not be advanced until all conditions have been satisfied in a manner satisfactory to RUS.
Following the announcement, selected applicants will be required to submit the appropriate environmental review documentation, as outlined in the RUS environmental questionnaire and to prepare and submit any other environmental impact analyses required by RUS Environmental Policies and Procedures (7 CFR part 1794, or its successor). Successful applicants will be advised whether additional environmental review requirements apply to their proposals. These reviews may result in additional project conditions that RUS will include in the grant agreement. Also, as a condition of any award, applicants must agree to comply with conditions imposed on the grant project by any other Federal, State, or Tribal environmental laws and regulations, license, or permit.
In accordance with 7 CFR 1794.15, or its successor, applicants are restricted from taking actions that may have an adverse environmental impact or limit the choice of alternatives being considered until the environmental review process is concluded. If an applicant takes such actions, RUS will not award or advance grant funds. If the proposed grant project involves physical development activities or property acquisition, the applicant is generally prohibited from acquiring, rehabilitating, converting, leasing, repairing or constructing property or facilities, or committing or expending RUS or non-RUS funds for proposed grant activities until the RUS has completed any environmental review in accordance with 7 CFR part 1794 or its successor and determined that no environmental review is required.
High Energy Cost Grant Program Regulations (7 CFR part 1709), the requirements of this notice, the 2015 Application Guide and accompanying materials establish the appropriate administrative and national policy requirements for awards under this program. These requirements include but are not limited to:
(1) Executing a Grant Agreement acceptable to the Agency;
(2) Signing Form AD-3031 (“Assurance Regarding Felony Conviction or Tax Delinquent Status for Corporate Applicants”) (for corporate applicants only);
(3) Using the forms specified in the Grant Agreement for requesting advances and reimbursements and submitting and maintaining supporting documentation of expenditures and receipts for use of funds awarded under this grant;
(4) Providing quarterly project performance activity reports with required forms specified in the grant agreement until the expiration of the project term;
(5) Ensuring that records are maintained to document all grant supported activities and expenditures and matching contributions;
(6) Providing a final project performance report after completion of construction and one year's worth of operation; and
(7) Complying with policies, guidance, and requirements as described in the following applicable Federal regulations, and any successor regulations:
• 2 CFR part 200, (Office of Management and Budget, Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards);
• 2 CFR part 400, (United States Department of Agriculture, Uniform Administrative Requirements, Cost Principles, and Audit Requirements for Federal Awards);
• 2 CFR part 180, (Office of Management and Budget Government-wide Debarment and Suspension (nonprocurement);
• 2 CFR part 416, (United States Department of Agriculture, General Program Administrative Regulations for Grants and Cooperative Agreements to State and Local Governments);
• 2 CFR part 417, (United States Department of Agriculture, Government-wide debarment and suspension (non-procurement);
• 2 CFR part 418 (United States Department of Agriculture, New restrictions on Lobbying);
• 2 CFR part 421 (United States Department of Agriculture, Government-wide requirements for drug-free workplace (grants);
• 7 CFR part 15, subpart A, (United States Department of Agriculture, Nondiscrimination in Federally Assisted Programs of the Department of Agriculture—Effectuation of Title VI of the Civil Rights Act of 1964);
• 7 CFR part 1767 Rural Utilities Service, (Accounting Requirements for RUS Electric Borrowers); and
• 7 CFR part 1773 Rural Utilities Service, (Policy on Audits of RUS Borrowers).
Compliance with additional OMB Circulars or government-wide regulations may be specified in the grant agreement.
i. The grantee must provide periodic financial and performance reports under USDA grant regulations, program rules and the grant agreement. The grantee must submit a final project performance report. The nature and frequency of required reports is established in USDA grant regulations and the project-specific grant agreements.
ii. The applicant must have the necessary processes and systems in place to comply with the reporting requirements for first-tier sub-awards and executive compensation under the Federal Funding Accountability and Transparency Act of 2006 in the event the applicant receives funding unless such applicant is exempt from such reporting requirements pursuant to 2 CFR 170.110(b). The reporting requirements under the Transparency Act pursuant to 2 CFR part 170 are as follows:
(a) First Tier Sub-Awards of $25,000 or more in non-Recovery Act funds (unless they are exempt under 2 CFR
(b) The Total Compensation of the Recipient's Executives (5 most highly compensated executives) must be reported by the Recipient (if the Recipient meets the criteria under 2 CFR part 170) to
(c) Total Compensation of the Subrecipient's Executives.
The Total Compensation of the Subrecipient's Executives (5 most highly compensated executives) must be reported by the Subrecipient (if the Subrecipient meets the criteria under 2 CFR part 170) to the Recipient by the end of the month following the month in which the subaward was made.
(d) If the total value of the Recipient's currently active grants, cooperative agreements, and procurement contracts from all Federal awarding agencies exceeds $10,000,000 for any period of time during the period of performance of this Federal award, then during that period of time the Recipient must maintain the currency of information reported to SAM that is made available in the designated integrity and performance system (currently the Federal Awardee Performance and Integrity Information System (FAPIIS)) about civil, criminal, or administrative proceedings as outlined further in 2 CFR part 200, Appendix XII.
The RUS Contact for this grant announcement is Robin Meigel, Finance Specialist, Rural Utilities Service, Electric Program, Office of Portfolio Management and Risk Assessment, United States Department of Agriculture, 1400 Independence Avenue SW., STOP 1568, Room 1274-S, Washington, DC 20250-1568. Telephone (202) 720-9452, Fax (202) 720-1401, email:
All material submitted by the applicant or grantee may be made available to the public in accordance with the Freedom of Information Act (5 U.S.C. 552) and USDA's implementing regulations at 7 CFR part 1.
In addition, in compliance with statutory requirements for Federal spending transparency, USDA will announce all Federal awards publicly and publish the required information on a publicly available OMB-designated government-wide Web site (at time of publication,
USDA prohibits discrimination against its customers, employees, and applicants for employment on the bases of race, color, national origin, age, disability, sex, gender identity, religion, reprisal, and where applicable, political beliefs, marital status, familial or parental status, sexual orientation, or all or part of an individual's income is derived from any public assistance program, or protected genetic information in employment or in any program or activity conducted or funded by USDA. (Not all prohibited bases will apply to all programs and/or employment activities.)
If you wish to file an employment complaint, you must contact your agency's EEO Counselor within 45 days of the date of the alleged discriminatory act, event, or in the case of a personnel action. Additional information can be found online at
If you wish to file a Civil Rights program complaint of discrimination, complete the USDA Program Discrimination Complaint Form (PDF), found online at
Individuals who are deaf, hard of hearing or have speech disabilities and that wish to file either an EEO or program complaint may contact USDA through the Federal Relay Service at (800) 877-8339 or (800) 845-6136 (in Spanish).
Persons with disabilities, who wish to file a program complaint, please see information above on how to contact us by mail directly or by email. If you require alternative means of communication for program information (
U.S. Commission on Civil Rights.
Announcement of meeting.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Illinois Advisory Committee (Committee) will hold a meeting on Friday, November 20, 2015, at 12:00 p.m. CST for the purpose of reviewing and discussing current civil rights concerns in the state, and potential next topics of study for the Committee.
Members of the public can listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 888-428-9480, conference ID: 284644. Any interested member of the public may call this number and listen to the meeting. An open comment period will be provided to allow members of the public to make a statement at the end of the meeting. The conference call operator will ask callers to identify themselves, the organization they are affiliated with (if any), and an email address prior to placing callers into the conference room. Callers can expect to incur regular charges for calls they initiate over wireless lines, according to their wireless plan, and the Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Persons with hearing impairments may also follow the proceedings by first calling the Federal Relay Service at 1-800-977-8339 and providing the Service with the
Member of the public are also entitled to submit written comments; the comments must be received in the regional office within 30 days following the meeting. Written comments may be mailed to the Regional Programs Unit, U.S. Commission on Civil Rights, 55 W. Monroe St., Suite 410, Chicago, IL 60615. They may also be faxed to the Commission at (312) 353-8324, or emailed to Administrative Assistant, Carolyn Allen at
Records and documents discussed during the meeting will be available for public viewing prior to and after the meeting at
The meeting will be held on Friday, November 20, 2015, at 12:00 p.m. CST.
Melissa Wojnaroski at
U.S. Commission on Civil Rights.
Announcement of meeting.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Nebraska Advisory Committee (Committee) will hold a meeting on Thursday, October 29, 2015, at 2:00 p.m. CDT for the purpose of discussing and findings and recommendations related to its inquiry regarding the civil rights impact of Nebraska's 2009 Legislative Bill 403. The Committee will also begin discussion of civil rights topics for future consideration.
Members of the public may listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 888-430-8709, conference ID: 908320. Any interested member of the public may call this number and listen to the meeting. The conference call operator will ask callers to identify themselves, the organization they are affiliated with (if any), and an email address prior to placing callers into the conference room. Callers can expect to incur regular charges for calls they initiate over wireless lines according to their wireless plan, and the Commission will not refund any incurred charges. Callers will incur no charge for calls they initiate over land-line connections to the toll-free telephone number. Persons with hearing impairments may also follow the proceedings by first calling the Federal Relay Service at 1-800-977-8339 and providing the Service with the conference call number and conference ID number.
Members of the public are also invited and welcomed to make statements at the end of the conference call. In addition, members of the public may submit written comments; the comments must be received in the regional office by November 30, 2015. Written comments may be mailed to the Regional Programs Unit, U.S. Commission on Civil Rights, 55 W. Monroe St., Suite 410, Chicago, IL 60615. They may also be faxed to the Commission at (312) 353-8324, or emailed to Administrative Assistant, Corrine Sanders at
Records and documents discussed during the meeting will be available for public viewing prior to and after the meeting at:
The meeting will be held on Thursday, October 29, 2015, at 2:00 p.m. CDT.
Melissa Wojnaroski, DFO, at 312-353-8311 or
U.S. Commission on Civil Rights.
Notice of meeting.
Notice is hereby given, pursuant to the provisions of the rules and regulations of the U.S. Commission on Civil Rights (Commission) and the Federal Advisory Committee Act that the Missouri Advisory Committee (Committee) will hold a meeting on Monday, November 02, 2015, for the purpose of discussing oral and written testimony received during two public meetings focused on civil rights and police and community interactions in Missouri. Themes and findings discussed during this meeting will form the basis of a report to be issued to the Commission on this topic.
Members of the public can listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 888-455-2263, conference ID: 3504640. Any interested
Members of the public are also entitled to submit written comments; the comments must be received in the regional office within thirty days following the meeting. Written comments may be mailed to the Midwestern Regional Office, U.S. Commission on Civil Rights, 55 W. Monroe St., Suite 410, Chicago, IL 60615. They may also be faxed to the Commission at (312) 353-8324, or emailed to Carolyn Allen at
Records generated from this meeting may be inspected and reproduced at the Midwestern Regional Office, as they become available, both before and after the meeting. Records of the meeting will be available at
The meeting will be held on Monday, November 02, 2015, at 12:00 p.m. CST.
Public Call Information: Dial: 888-455-2263 Conference ID: 3504640.
Melissa Wojnaroski, DFO, at 312-353-8311 or
An application has been submitted to the Foreign-Trade Zones (FTZ) Board by the City of Hitchcock to establish a foreign-trade zone at a site in Hitchcock, Texas, adjacent to the Houston Customs and Border Protection (CBP) port of entry, under the alternative site framework (ASF) adopted by the FTZ Board (15 CFR Sec. 400.2(c)). The ASF is an option for grantees for the establishment or reorganization of zones and can permit significantly greater flexibility in the designation of new “subzones” or “usage-driven” FTZ sites for operators/users located within a grantee's “service area” in the context of the FTZ Board's standard 2,000-acre activation limit for a zone project. The application was submitted pursuant to the provisions of the Foreign-Trade Zones Act, as amended (19 U.S.C. 81a-81u), and the regulations of the Board (15 CFR part 400). It was formally docketed on October 6, 2015. The applicant is authorized to make the proposal under Texas Statutes, Business and Commerce Code, Title 15, Chapter 681.
The proposed zone would be the sixth zone for the Houston CBP port of entry. The existing zones are as follows: FTZ 36, Galveston (Grantee: Board of Trustees of the Galveston Wharves, Board Order 129, May 4, 1978); FTZ 84, Houston (Grantee: Port of Houston Authority, Board Order 214, July 15, 1983); FTZ 171, Liberty County (Grantee: Liberty County Economic Development Corp., Board Order 501, January 4, 1991); FTZ 199, Texas City (Grantee: Texas City Foreign-Trade Zone Corp., Board Order 681, February 1, 1994); and, FTZ 265, Conroe (Grantee: City of Conroe, Board Order 1410, September 16, 2005).
The applicant's proposed service area under the ASF would be the City of Hitchcock, Texas. If approved, the applicant would be able to serve sites throughout the service area based on companies' needs for FTZ designation. The proposed service area is within and adjacent to the Houston CBP port of entry.
The proposed zone would include one “magnet” site: Proposed Site 1 (280.54 acres)—Blimp Base, 7529 Blimp Base Road, Hitchcock. The ASF allows for the possible exemption of one magnet site from the “sunset” time limits that generally apply to sites under the ASF, and the applicant proposes that Site 1 be so exempted.
The application states that there is a need for zone services in the Hitchcock area and that several firms have indicated an interest in using zone procedures. Specific production approvals are not being sought at this time. Such requests would be made to the FTZ Board on a case-by-case basis.
In accordance with the FTZ Board's regulations, Camille Evans of the FTZ Staff is designated examiner to evaluate and analyze the facts and information presented in the application and case record and to report findings and recommendations to the FTZ Board.
Public comment is invited from interested parties. Submissions shall be addressed to the FTZ Board's Executive Secretary at the address below. The closing period for their receipt is December 14, 2015. Rebuttal comments in response to material submitted during the foregoing period may be submitted during the subsequent 15-day period to December 28, 2015.
A copy of the application will be available for public inspection at the Office of the Executive Secretary, Foreign-Trade Zones Board, Room 21013, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230-0002, and in the “Reading Room” section of the FTZ Board's Web site, which is accessible via
On March 27, 2015, in the U.S. District Court for the Eastern District of
Section 766.25 of the Export Administration Regulations (“EAR” or “Regulations”)
BIS has received notice of Maralit's conviction for violating the AECA, and has provided notice and an opportunity for Maralit to make a written submission to BIS, as provided in Section 766.25 of the Regulations. BIS has not received a submission from Maralit.
Based upon my review and consultations with BIS's Office of Export Enforcement, including its Director, and the facts available to BIS, I have decided to deny Maralit's export privileges under the Regulations for a period of 10 years from the date of Maralit's conviction. I have also decided to revoke all licenses issued pursuant to the Act or Regulations in which Maralit had an interest at the time of his conviction.
Accordingly, it is hereby
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 Regulations, or in any other activity subject to the Regulations; 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 Regulations, or in any other activity subject to the Regulations.
A. Export or reexport to or on behalf of the Denied Person any item subject to the Regulations;
B. Take any action that facilitates the acquisition or attempted acquisition by the Denied Person of the ownership, possession, or control of any item subject to the Regulations that has been or will be exported from the United States, including financing or other support activities related to a transaction whereby the 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 the Denied Person of any item subject to the Regulations that has been exported from the United States;
D. Obtain from the Denied Person in the United States any item subject to the Regulations 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 Regulations that has been or will be exported from the United States and which is owned, possessed or controlled by the Denied Person, or service any item, of whatever origin, that is owned, possessed or controlled by the Denied Person if such service involves the use of any item subject to the Regulations that has been or will be exported from the United States. For purposes of this paragraph, servicing means installation, maintenance, repair, modification or testing.
On March 27, 2015, in the U.S. District Court for the Eastern District of New York, Wilfredo Maralit (“Maralit”), was convicted of violating Section 38 of the Arms Export Control Act (22 U.S.C. 2778 (2012)) (“AECA”). Specifically, Maralit knowingly and willfully exported from the United States to the Philippines one or more defense articles, designated on the United States Munitions List, to wit: Various firearms and firearms accessories and components, without first obtaining the required license or written approval from the State Department. Maralit was sentenced to 36 months of imprisonment, three years of supervised release, and fined a $100 assessment.
Section 766.25 of the Export Administration Regulations (“EAR” or “Regulations”)
BIS has received notice of Maralit's conviction for violating the AECA, and has provided notice and an opportunity for Maralit to make a written submission to BIS, as provided in Section 766.25 of the Regulations. BIS has not received a submission from Maralit.
Based upon my review and consultations with BIS's Office of Export Enforcement, including its Director, and the facts available to BIS, I have decided to deny Maralit's export privileges under the Regulations for a period of 10 years from the date of Maralit's conviction. I have also decided to revoke all licenses issued pursuant to the Act or Regulations in which Maralit had an interest at the time of his conviction.
Accordingly, it is hereby
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 Regulations, or in any other activity subject to the Regulations; 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 Regulations, or in any other activity subject to the Regulations.
A. Export or reexport to or on behalf of the Denied Person any item subject to the Regulations;
B. Take any action that facilitates the acquisition or attempted acquisition by the Denied Person of the ownership, possession, or control of any item subject to the Regulations that has been or will be exported from the United States, including financing or other support activities related to a transaction whereby the 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 the Denied Person of any item subject to the Regulations that has been exported from the United States;
D. Obtain from the Denied Person in the United States any item subject to the Regulations 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 Regulations that has been or will be exported from the United States and which is owned, possessed or controlled by the Denied Person, or service any item, of whatever origin, that is owned, possessed or controlled by the Denied Person if such service involves the use of any item subject to the Regulations that has been or will be exported from the United States. For purposes of this paragraph, servicing means installation, maintenance, repair, modification or testing.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) has completed the administrative review of the countervailing duty (CVD) order on circular welded carbon steel pipes and tubes (steel pipes and tubes) from Turkey for the January 1, 2013, through December 31, 2013, period of review (POR) in accordance with section 751(a) of the Tariff Act of 1930, as amended (the Act). This review covers four exporters/producers, one of which is being individually examined as a mandatory respondent. In these final results, the Department has made changes to the net subsidy rate determined for the sole mandatory respondent, Borusan Mannesmann Boru Sanayi ve Ticaret A.S. (BMB), Borusan Istikbal Ticaret T.A.S. (Istikbal), and Borusan Lojistik Dagitim Pepolama Tasimacilik ve Tic A.S. (Borusan Lojistik) (collectively, the Borusan Companies). Further, in these final results, we have continued to apply the net subsidy rate calculated for the Borusan Companies to the following three respondents not subject to individual review: Tosyali dis Ticaret A.S. (Tosyali) and Toscelik Profil ve Sac Endustrisi A.S. (Toscelik Profil), (collectively, the Toscelik Companies), Umran Celik Born Sanayii A.S. (also known as Umran Steel Pipe Inc.) (Umran), and Guven Steel Pipe (also known as Guven Celik Born San. Ve Tic. Ltd.) (Guven). Additionally, in these final results the Department is rescinding the review of two companies Erbosan Erciyas Boru Sanayi ve Ticaret A.S. (Erbosan AS) and Erbosan Erciyas Pipe Industry and Trade Co. Kayseri Free Zone Branch (Erbosan FZB), (collectively, the Erbosan Companies) and the Yucel Group and all affiliates including Yucel Boru ye Profil Endustrisi A.S, Yucelboru Ihracat Ithalat ye Pazarlama A.S, and Cayirova Born Sanayi ye Ticaret A.S.) (collectively, the Yucel Companies) that timely certified that they had no shipments of subject merchandise during the POR.
John Conniff at 202-482-1009, or Jolanta Lawska at 202-482-8362, AD/CVD Operations, Office III, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230.
On March 7, 1986, the Department published in the
On April 8, 2015 the Borusan Companies requested a hearing. On June 1, 2015, the Borusan Companies withdrew their request for a hearing.
On June 16, 2015, the Department extended the deadline for the final results of this administrative review until October 5, 2015.
The products covered by this order are certain welded carbon steel pipe and tube with an outside diameter of 0.375 inch or more, but not over 16 inches, of any wall thickness (pipe and tube) from Turkey. These products are currently classifiable under the Harmonized Tariff Schedule of the United States (HTSUS) subheadings as 7306.30.10, 7306.30.50, and 7306.90.10. Although the HTSUS subheadings are provided for convenience and customs purposes, the written description of the merchandise is dispositive.
The Department conducted this review in accordance with section 751(a)(1)(A) of the Act. For each of the subsidy programs found countervailable during the POR, we determine that there is a subsidy,
All issues raised in the case briefs of the Borusan Companies, the GOT, and the Toscelik Companies are addressed in the Issues and Decision Memorandum. A list of the issues raised and to which we responded in the Issues and Decision Memorandum, is attached to this notice as an Appendix. The Issues and Decision Memorandum is a public document and is on file electronically via Enforcement and Compliance's Antidumping and Countervailing Duty Centralized Electronic Service System (ACCESS). ACCESS is available to registered users at
The Department did not receive any information from interested parties or U.S. Customs and Border Protection (CBP) that was contrary to the claims of the Erbosan Companies and the Yucel Companies of no sales, shipments, or entries of subject merchandise to the United States during the POR after we indicated our intent to rescind the administrative review. Accordingly, based on record evidence, we determine that the Erbosan Companies and the Yucel Companies did not ship subject
In accordance with 19 CFR 351.221(b)(4)(i), we calculated an individual subsidy rate for the mandatory respondent, the Borusan Companies. Because the Borusan Companies are the sole mandatory respondent, we assigned to those companies not selected for individual review, the rate calculated for the Borusan Companies. As a result of this review, we determine the listed net subsidy rates for January 1, 2013, through December 31, 2013:
In accordance with 19 CFR 351.212(b)(2), the Department intends to issue assessment instructions to CBP 15 days after the date of publication of these final results of review to liquidate shipments of subject merchandise produced and/or exported by respondents listed above entered, or withdrawn form warehouse, for consumption on or after January 1, 2013, through December 31, 2013.
For the Erbosan Companies and Yucel Companies, the rescinded companies, countervailing duties shall be assessed at rates equal to the rates for the cash deposit of estimated countervailing duties required at the time of entry, or withdrawal from warehouse, for consumption, in accordance with 19 CFR 351.212(c)(1)(i). The Department intends to issue appropriate assessment instructions to CBP 15 days after the date of publication of this notice.
Pursuant to section 751(a)(2)(C) of the Act, the Department also intends to instruct CBP to collect cash deposits of estimated CVDs, in the amounts shown above for each of the respective companies shown above, on shipments of subject merchandise entered, or withdrawn from warehouse, for consumption on or after the date of publication of the final results of this review. For all non-reviewed firms, we will instruct CBP to continue to collect cash deposits at the most-recent company-specific or all-others rate applicable to the company, as appropriate. These cash deposit requirements, when imposed, shall remain in effect until further notice.
This notice also serves as a reminder to parties subject to an administrative protective order (APO) of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3), which continues to govern business proprietary information in this segment of proceeding. Timely written notification of the return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation which is subject to sanction.
These final results are issued and published in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) determines that welded line pipe from the Republic of Turkey (Turkey) is being, or is likely to be, sold in the United States at less than fair value (LTFV), as provided in section 735(a) of the Tariff Act of 1930, as amended (the Act). The period of investigation (POI) is October 1, 2013,
Alice Maldonado or David Crespo, AD/CVD Operations, Office II, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-4682 or (202) 482-3693, respectively.
On May 22, 2015, the Department published the
In May and June 2015, the Department verified the sales and cost of production (COP) information submitted by the two participating mandatory respondents in this investigation, Çayirova Boru Sanayi ve Ticaret A.S./Yücel Boru Ithalat-Ihracat ve Pazarlama A.S. (collectively, Çayirova) and Tosçelik Profil ve Sac Endustrisi A.S./Tosyali Dis Ticaret A.S. (collectively, Tosçelik), in accordance with section 782(i) of the Act.
On July 27, 2015, we requested that Tosçelik submit a revised COP database to reflect minor corrections made at verification. On August 7, 2015, we received Tosçelik's revised COP database.
We invited interested parties to comment on the
The scope of the investigation covers welded line pipe, which is carbon and alloy steel pipe of a kind used for oil and gas pipelines, not more than 24 inches in nominal outside diameter. For a complete description of the scope of the investigation,
All issues raised in the case and rebuttal briefs by parties in this investigation are addressed in the Issues and Decision Memorandum, which is hereby adopted by this notice.
As provided in section 782(i) of the Act, in May and June 2015, we verified the sales and cost information submitted by Çayirova and Tosçelik for use in our final determination. We used standard verification procedures, including an examination of relevant accounting and production records, and original source documents provided by Çayirova and Tosçelik.
Based on our analysis of the comments received and our findings at verification, we made certain changes to the margin calculations for Çayirova and Tosçelik. For a discussion of these changes,
Section 735(c)(5)(A) of the Act provides that the estimated all-others rate shall be an amount equal to the weighted-average of the estimated weighted-average dumping margins established for exporters and producers individually investigated excluding any zero or
The final weighted-average dumping margins are as follows:
We will disclose the calculations performed within five days of the date of publication of this notice to parties in this proceeding in accordance with 19 CFR 351.224(b).
In accordance with section 735(c)(1)(B) of the Act, the Department will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all appropriate entries of welded line pipe from Turkey, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after May 22, 2015, the date of publication of the preliminary determination of this investigation in the
Further, the Department will instruct CBP to require a cash deposit equal to the estimated amount by which the normal value exceeds the U.S. price as shown above. If a CVD order is issued and suspension of liquidation is resumed, the Department will instruct CBP to require a cash deposit equal to the estimated amount by which the normal value exceed the U.S. price as shown above, adjusted for export subsidies, as appropriate, found in the final determination of the companion countervailing duty investigation on welded line pipe from Turkey.
Accordingly, if a CVD order is issued, for cash deposit purposes, we will subtract from the applicable cash deposit rate that portion of the rate attributable to the export subsidies found in the affirmative countervailing duty determination for each respondent (
In accordance with section 735(d) of the Act, we will notify the ITC of the final affirmative determination of sales at LTFV. Because the final determination in this proceeding is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports of welded line pipe from Turkey no later than 45 days after our final determination. If the ITC determines that material injury or threat of material injury does not exist, the proceeding will be terminated and all cash deposits will be refunded. If the ITC determines that such injury does exist, the Department will issue an antidumping duty order directing CBP to assess, upon further instruction by the Department, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation.
This notice serves as a reminder to parties subject to APO of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
This determination and this notice are issued and published pursuant to sections 735(d) and 777(i)(1) of the Act.
The merchandise covered by this investigation is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of this investigation.
The welded line pipe that is subject to this investigation is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) determines that countervailable subsidies are not being provided to producers and exporters of welded line pipe from the Republic of Korea (Korea). The period of investigation is January 1, 2013, through December 31, 2013.
Effective date: October 13, 2015.
Rebecca Trainor or Reza Karamloo, Office II, AD/CVD Operations, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-4007 or (202) 482-4470, respectively.
The petitioners in this investigation are American Cast Iron Pipe Company, Energex (a division of JMC Steel Group), Maverick Tube Corporation (Maverick), Northwest Pipe Company, Stupp Corporation (a division of Stupp Bros., Inc.), Tex-Tube Company, TMK IPSCO, and Welspun Tubular LLC USA (collectively, the petitioners). In addition to the Government of the Republic of Korea, the mandatory respondents in this investigation are SeAH Steel Corporation and NEXTEEL Co. Ltd.
The events that have occurred since the Department published the
The scope of the investigation covers welded line pipe, which is carbon and alloy steel pipe of a kind used for oil or gas pipelines, not more than 24 inches in nominal outside diameter. For a complete description of the scope of the investigation,
The subsidy programs under investigation and the issues raised in the case and rebuttal briefs by parties in this investigation are discussed in the Issues and Decision Memorandum, dated concurrently with this notice. A list of the issues that parties raised, and to which we responded in the Issues and Decision Memorandum, is attached to this notice as Appendix II.
We determine the countervailable subsidy rates to be:
Because the total estimated net countervailable subsidy rate for each examined company is
In the
In accordance with section 705(d) of the Act, we will notify the ITC of our final determination. Because our final determination is negative, this investigation is terminated.
This notice serves as the only reminder to parties subject to the administrative protective order (APO) of their responsibility concerning the destruction of proprietary information disclosed under APO in accordance
This determination is issued and published pursuant to sections 705(d) and 777(i) of the Act.
The merchandise covered by this investigation is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of this investigation.
The welded line pipe that is subject to this investigation is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) determines that welded line pipe from the Republic of Korea (Korea) is being, or is likely to be, sold in the United States at less than fair value (LTFV), as provided in section 733(b) of the Tariff Act of 1930, as amended (the Act). The period of investigation (POI) is October 1, 2013, through September 30, 2014. The final dumping margins of sales at LTFV are listed below in the “Final Determination” section of this notice.
David Goldberger or Ross Belliveau, AD/CVD Operations, Office II, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Ave. NW., Washington, DC 20230; telephone: (202) 482-4136 or (202) 482-4952, respectively.
On May 22, 2015, the Department published the
The scope of the investigation covers welded line pipe, which is carbon and alloy steel pipe of a kind used for oil and gas pipelines, not more than 24 inches in nominal outside diameter. For a complete description of the scope of the investigation,
All issues raised in the case and rebuttal briefs by parties in this investigation are addressed in the Issues and Decision Memorandum,
As provided in section 782(i) of the Act, during the period June through August 2015, we verified the sales and cost information submitted by HYSCO and SeAH for use in our final determination. We used standard verification procedures, including an examination of relevant accounting and production records, and original source documents provided by HYSCO and SeAH.
Based on our analysis of the comments received and our findings at verification, we made certain changes to the margin calculations for HYSCO and SeAH. For a discussion of these changes,
Section 735(c)(5)(A) of the Act provides that the estimated all-others rate shall be an amount equal to the weighted-average of the estimated weighted-average dumping margins
The final weighted-average dumping margins are as follows:
We
In accordance with section 735(c)(1)(B) of the Act, the Department will instruct U.S. Customs and Border Protection (CBP) to continue to suspend liquidation of all appropriate entries of welded line pipe from Korea, as described in Appendix I of this notice, which were entered, or withdrawn from warehouse, for consumption on or after May 22, 2015, the date of publication of the preliminary determination of this investigation in the
Further, the Department will instruct CBP to require a cash deposit equal to the amount by which normal value exceeds U.S. price as follows: (1) For the mandatory respondents listed above, the cash deposit rate will be equal to the dumping margin which the Department determined in this final determination adjusted, as appropriate, for export subsidies found in the final determination of the companion countervailing duty investigation;
In accordance with section 735(d) of the Act, we will notify the ITC of the final affirmative determination of sales at LTFV. Because the final determination in this proceeding is affirmative, in accordance with section 735(b)(2) of the Act, the ITC will make its final determination as to whether the domestic industry in the United States is materially injured, or threatened with material injury, by reason of imports of welded line pipe from Korea no later than 45 days after our final determination. If the ITC determines that material injury or threat of material injury does not exist, the proceeding will be terminated and all cash deposits will be refunded. If the ITC determines that such injury does exist, the Department will issue an antidumping duty order directing CBP to assess, upon further instruction by the Department, antidumping duties on all imports of the subject merchandise entered, or withdrawn from warehouse, for consumption on or after the effective date of the suspension of liquidation.
This notice serves as a reminder to parties subject to APO of their responsibility concerning the disposition of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely notification of the return or destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
This determination and this notice are issued and published pursuant to sections 735(d) and 777(i)(1) of the Act.
The merchandise covered by this investigation is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of this investigation.
The welded line pipe that is subject to this investigation is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
On June 5, 2015, the Department of Commerce (the Department) published the preliminary results of the administrative review of the antidumping duty order on certain stilbenic optical brightening agents (OBAs) from Taiwan.
Catherine Cartsos or Minoo Hatten, 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) 482-1757, and (202) 482-1690, respectively.
On June 5, 2015, the Department published the
The merchandise subject to the
All issues raised in the case brief submitted in this review are addressed in the Issues and Decision Memorandum, which is hereby adopted with this notice. A list of the issues raised is attached as an Appendix to this notice. The Issues and Decision Memorandum is a public document and is on file electronically
Based on our analysis of the comments received, we made certain changes to the
As a result of this review, we determine that a weighted-average dumping margin of 0.00 percent exists for TFM for the period May 1, 2013, through April 30, 2014.
In accordance with 19 CFR 351.212 and the
Consistent with the Department's assessment practice, for entries of subject merchandise during the POR produced by TFM for which it did not know that the merchandise was destined for the United States, we will instruct CBP to liquidate un-reviewed entries at the all-others rate if there is no rate for the intermediate company(ies) involved in the transaction.
We intend to issue instructions to CBP 15 days after publication of the final results of this review.
The following cash deposit requirements will be effective upon publication of the notice of final results of administrative review for all shipments of OBAs from Taiwan entered, or withdrawn from warehouse, for consumption on or after the date of publication as provided by section 751(a)(2) of the Act: (1) The cash deposit rate for TFM will be 0.00 percent, the weighted average dumping margin established in the final results of this administrative review; (2) for other manufacturers and exporters covered in a prior segment of the proceeding, the cash deposit rate will continue to be the company-specific rate published for the most recently completed segment of this proceeding; (3) if the exporter is not a firm covered in this review, a prior review, or the original investigation, but the manufacturer is, the cash deposit rate will be the rate established for the most recently completed segment of this proceeding for the manufacturer of subject merchandise; and (4) the cash deposit rate for all other manufacturers or exporters will continue to be 6.19 percent, the all-others rate established in the less than fair value investigation.
This notice serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping duties prior to liquidation of the relevant entries during this review period. Failure to comply with this requirement could result in the Secretary's presumption
This notice also serves as a reminder to parties subject to administrative protective order (APO) of their responsibility concerning the destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return or destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a sanctionable violation.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
In response to a request from Petitioners,
George McMahon or Eric Greynolds, AD/CVD Operations, Office III, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-1167 or (202) 482-6071, respectively.
The merchandise subject to the antidumping duty order is brass sheet and strip, other than leaded brass and tin brass sheet and strip, from Germany, which is currently classified under subheading 7409.21.00.50, 7409.21.00.75, 7409.21.00.90, 7409.29.00.50, 7409.29.00.75, and 7409.29.00.90 of the Harmonized Tariff Schedule of the United States (HTSUS). Although the HTSUS subheadings are provided for convenience and customs purposes, the written description of the merchandise subject to the order is dispositive.
In accordance with sections 776(a) and (b) of the Tariff Act of 1930, as amended (the Act), we relied on facts available with an adverse inference with respect to Messingwerk, the sole company selected for individual examination in this review. Thus, we are assigning a rate of 55.60 percent as the dumping margin for Messingwerk.
Additionally, as indicated in the “Final Results of Review” section below, we determine that a margin of 22.61 percent applies to the six firms not selected for individual review. We have determined to base the dumping margin for the six companies not selected for individual examination in this review on an average of the range of certain dumping margins contained in the underlying Petition.
For a full description of the methodology underlying our
The Issues and Decision Memorandum is a public document and is on file electronically
Based on our analysis of U.S. Customs and Border Protection (CBP) information and information provided by Schwermetall, ThyssenKrupp, and Wieland, we determine that Schwermetall, ThyssenKrupp, and Wieland had no shipments of the subject merchandise, and, therefore, no reviewable transactions, during the POR. For a full discussion of this determination,
As a result of this review, the Department determines that the following dumping margins on brass sheet and strip from Germany exist for the period March 1, 2013, through February 28, 2014:
Pursuant to section 751(a)(2)(C) of the Act and 19 CFR 351.212(b)(1), the Department determined, and CBP shall assess, antidumping duties on all appropriate entries of subject merchandise, in accordance with the final results of this review. The Department intends to issue assessment instructions to CBP 15 days after the date of publication of these final results of review.
We will instruct CBP to apply an
Consistent with the Department's “automatic assessment” regulation,
The following cash deposit requirements will be effective upon publication of the notice of final results of administrative review for all shipments of subject merchandise entered, or withdrawn from warehouse, for consumption on or after the publication of the final results of this administrative review, as provided by section 751(a)(2) of the Act: (1) The cash deposit rate for respondents noted above will be the rate established in the final results of this administrative review; (2) for merchandise exported by manufacturers or exporters not covered in this administrative review but covered in a prior segment of the proceeding, the cash deposit rate will continue to be the company specific rate published for the most recently completed segment of this proceeding; (3) if the exporter is not a firm covered in this review, a prior review, or the original investigation, but the manufacturer is, the cash deposit rate will be the rate established for the most recently completed segment of this proceeding for the manufacturer of the subject merchandise; and (4) the cash deposit rate for all other manufacturers or exporters will continue to be 7.30 percent, the all-others rate determined in the less than fair value investigation. These cash deposit requirements, when imposed, shall remain in effect until further notice.
This notice also serves as a final reminder to importers of their responsibility under 19 CFR 351.402(f)(2) to file a certificate regarding the reimbursement of antidumping and/or countervailing duties prior to liquidation of the relevant entries during the POR. Failure to comply with this requirement could result in the Department's presumption that reimbursement of antidumping and/or countervailing duties occurred and the subsequent assessment of doubled antidumping duties.
This notice also serves as a reminder to parties subject to administrative protective orders (APO) of their responsibility concerning the return or destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3), which continues to govern business proprietary information in this segment of the proceeding. Timely written notification of the return/destruction of APO materials, or conversion to judicial protective order, is hereby requested. Failure to comply with the regulations and the terms of an APO is a sanctionable violation.
We are issuing and publishing these results in accordance with sections 751(a)(1) and 777(i)(1) of the Act.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the Department) determines that countervailable subsidies are being provided to producers and exporters of welded line pipe from the Republic of Turkey (Turkey) as provided in section 705 of the Tariff Act of 1930, as amended (the Act). The period of investigation (POI) is January 1, 2013, through December 31, 2013. For information on the estimated subsidy rates, see the “Suspension of Liquidation” section of this notice.
Elizabeth Eastwood or Dennis McClure, Office II, AD/CVD Operations, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-3874 and (202) 482-5973, respectively.
The petitioners in this investigation are American Cast Iron Pipe Company, Energex (a division of JMC Steel Group), Maverick Tube Corporation, Northwest Pipe Company, Stupp Corporation (a division of Stupp Bros., Inc.), Tex-Tube Company, TMK IPSCO, and Welspun Tubular LLC USA. In addition to the Government of Turkey, the mandatory respondents in this investigation are Borusan Istikbal Ticaret, Borusan Mannesmann Boru Sanayi ve Ticaret A.S., Borusan Mannesmann Boru Yatirim Holding A.S., and Borusan Holding A.S. (collectively, Borusan) and Toscelik Profil ve Sac Endustrisi A.S., Tosyali Demir Celik Sanayi A.S., Tosyali Dis Ticaret A.S., Tosyali Elektrik Enerjisi Toptan Satis Ith. Ihr. A.S., and Tosyali Holding A.S. (collectively, Toscelik).
The events that have occurred since the Department published the
The scope of the investigation covers welded line pipe, which is carbon and alloy steel pipe of a kind used for oil or gas pipelines, not more than 24 inches in nominal outside diameter. For a complete description of the scope of the investigation,
The subsidy programs under investigation and the issues raised in the case and rebuttal briefs by parties in this investigation are discussed in the Issues and Decision Memorandum, dated concurrently with this notice. A list of the issues that parties have raised, and to which we responded in the Issues and Decision Memorandum, is attached to this notice as Appendix II.
On April 14, 2015, Borusan notified the Department that it would not participate in the statutorily mandated verification in this investigation. By refusing to participate in verification, Borusan significantly impeded this proceeding and provided information that cannot be verified as provided by section 782(i) of the Act. Thus, for the final determination, we are basing the countervailing duty (CVD) rate for Borusan on facts otherwise available, pursuant to sections 776(a)(2)(C) and (D) of the Act. Further, because Borusan did not cooperate to the best of its ability in this investigation, we also determine that an adverse inference is warranted, pursuant to section 776(b) of the Act. As adverse facts available (AFA), we have assigned Borusan a rate of 152.20 percent. For a full discussion of this issue,
In accordance with section 705(c)(1)(B)(i) of the Act, we calculated a rate for Toscelik. Section 705(c)(5)(A)(i) of the Act states that, for companies not individually investigated, we will determine an “all others” rate equal to the weighted-average countervailable subsidy rates established for exporters and producers individually investigated, excluding any zero and
We determine the total estimated net countervailable subsidy rates to be:
As a
In accordance with section 703(d) of the Act, we later issued instructions to CBP to discontinue the suspension of liquidation for CVD purposes for subject merchandise entered, or withdrawn from warehouse, on or after July 18, 2015, but to continue the suspension of liquidation of all entries from March 20, 2015, through July 17, 2015, as appropriate.
We will issue a CVD order and reinstate the suspension of liquidation in accordance with our final determination and under section 706(a) of the Act if the United States International Trade Commission (ITC) issues a final affirmative injury determination, and we will instruct CBP to require a cash deposit of estimated countervailing duties for such entries of merchandise in the amounts indicated above. If the ITC determines that material injury, or threat of material injury, does not exist, this proceeding will be terminated and all estimated duties deposited as a result of the suspension of liquidation will be refunded.
In accordance with section 705(d) of the Act, we will notify the ITC of our determination. In addition, we are making available to the ITC all non-privileged and non-proprietary information related to this investigation. We will allow the ITC access to all privileged and business proprietary information in our files, provided the ITC confirms that it will not disclose such information, either publicly or under an administrative protective order (APO), without the written consent of the Assistant Secretary for Enforcement and Compliance.
In the event that the ITC issues a final negative injury determination, this notice will serve as the only reminder to parties subject to the APO of their responsibility concerning the destruction of proprietary information disclosed under APO in accordance with 19 CFR 351.305(a)(3). Timely written notification of the return/destruction of APO materials or conversion to judicial protective order is hereby requested. Failure to comply with the regulations and terms of an APO is a violation which is subject to sanction.
This determination is issued and published pursuant to sections 705(d) and 777(i) of the Act.
The merchandise covered by this investigation is circular welded carbon and alloy steel (other than stainless steel) pipe of a kind used for oil or gas pipelines (welded line pipe), not more than 24 inches in nominal outside diameter, regardless of wall thickness, length, surface finish, end finish, or stenciling. Welded line pipe is normally produced to the American Petroleum Institute (API) specification 5L, but can be produced to comparable foreign specifications, to proprietary grades, or can be non-graded material. All pipe meeting the physical description set forth above, including multiple-stenciled pipe with an API or comparable foreign specification line pipe stencil is covered by the scope of this investigation.
The welded line pipe that is subject to this investigation is currently classifiable in the Harmonized Tariff Schedule of the United States (HTSUS) under subheadings 7305.11.1030, 7305.11.5000, 7305.12.1030, 7305.12.5000, 7305.19.1030, 7305.19.5000, 7306.19.1010, 7306.19.1050, 7306.19.5110, and 7306.19.5150. The subject merchandise may also enter in HTSUS 7305.11.1060 and 7305.12.1060. While the HTSUS subheadings are provided for convenience and customs purposes, the written description of the scope of this investigation is dispositive.
Enforcement and Compliance, International Trade Administration, Department of Commerce.
The Department of Commerce (the “Department”) and the International Trade Commission (the “ITC”) have determined that revocation of the antidumping duty (“AD”) and countervailing duty (“CVD”) orders on prestressed concrete steel wire strand (“PC Strand”) from the People's Republic of China (“PRC”) would likely lead to a continuation or recurrence of dumping, net countervailable subsidies, and material injury to an industry in the United States. Therefore, the Department is publishing a notice of continuation of the antidumping and countervailing duty orders.
Bob Palmer (AD Order), AD/CVD Operations, Office V or Brendan Quinn (CVD Order), AD/CVD Operations, Office III; Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-9068 and (202) 482-5848, respectively.
On May 1, 2015, the Department initiated
On October 1, 2015, the ITC published its determination that revocation of the AD and CVD orders on PC Strand from the PRC would likely lead to continuation or recurrence of material injury to an industry in the United States within a reasonably foreseeable time, pursuant to section 751(c) of the Act.
The merchandise subject to the antidumping duty orders is PC strand, produced from wire of non-stainless, non-galvanized steel, which is suitable for use in prestressed concrete (both pretensioned and post-tensioned) applications. The product definition encompasses covered and uncovered strand and all types, grades, and diameters of PC strand. PC strand is normally sold in the United States in sizes ranging from 0.25 inches to 0.70 inches in diameter. PC strand made from galvanized wire is only excluded from the scope if the zinc and/or zinc oxide coating meets or exceeds the 0.40 oz./ft
As a result of the determinations by the Department and the ITC that revocation of the AD and CVD orders would likely lead to a continuation or recurrence of dumping and net countervailable subsidies, and of material injury to an industry in the United States, pursuant to sections 751(c) and 751(d)(2) of the Act, the Department hereby orders the continuation of the AD and CVD orders on PC Strand from the PRC. U.S. Customs and Border Protection will continue to collect AD and CVD cash deposits at the rates in effect at the time of entry for all imports of subject merchandise.
The effective date of the continuation of the orders will be the date of publication in the
This five-year (sunset) review and this notice are in accordance with section 751(c) of the Act and published pursuant to section 777(i)(1) of the Act and 19 CFR 351.218(f)(4).
International Trade Administration, Department of Commerce.
Notice.
The United States Department of Commerce, International Trade Administration (ITA), is organizing an Executive-led Water Infrastructure Business Development Mission to Singapore, Vietnam, and the Philippines.
The purpose of the mission is to introduce U.S. firms and trade associations to Southeast Asia's water infrastructure markets and to assist U.S. companies to find business partners and export their products and services to the region. The mission is intended to include representatives from U.S. companies and U.S. trade associations with members that provide water infrastructure-related materials, products, services, and technology. The trade mission will visit three of Southeast Asia's most dynamic markets and will help participants gain first-hand market knowledge and establish business contacts with senior decision makers. Participating firms will gain market insights, make industry contacts, solidify business strategies, and advance specific projects, with the goal of increasing U.S. exports of products and services to Southeast Asia. The mission will include customized one-on-one business appointments with pre-screened potential buyers, agents, distributors and joint venture partners; meetings with state, local government officials (except in the Philippines) and industry leaders; and networking events.
The mission will help participating firms and trade associations to gain market insights, make industry contacts, solidify business strategies, and advance specific projects, with the goals of creating and strengthening water infrastructure programs, increasing U.S. exports of plumbing products to the region, as well as resolving waste and salinity contamination in Southeast Asia. By participating in an official U.S. industry delegation, U.S. companies will enhance their ability to secure meetings in these countries and gain greater exposure to the region through association with our diplomatic mission.
All parties interested in participating in the trade mission must complete and submit an application package for consideration by the DOC. All applicants will be evaluated on their ability to meet certain conditions and best satisfy the selection criteria as outlined below. A minimum of 15 and maximum of 20 firms and/or trade associations will be selected to participate in the mission from the applicant pool.
After a firm or trade association has been selected to participate on the mission, a payment to the Department of Commerce in the form of a participation fee is required. Expenses for travel, lodging, meals, and incidentals will be the responsibility of each mission participant. Interpreter and driver services can be arranged for additional cost. Delegation members will be able to take advantage of U.S. Embassy rates for hotel rooms.
Participation fee for small or medium sized enterprises (SME): $3,300.00.
Participation fee for large firms or trade associations: $4,500.00.
Fee for each additional firm representative (large firm or SME/trade organization): $1,000.
All interested firms and associations may register via the following link:
The mission fee does not include any personal travel expenses such as lodging, most meals, local ground transportation, and air transportation from the U.S. to the mission sites, between mission sites, and return to the United States. Business visas may be required. Government fees and processing expenses to obtain such visas are also not included in the mission costs. However, the U.S. Department of Commerce will provide instructions to each participant on the procedures required to obtain necessary business visas.
Mission recruitment will be conducted in an open and public manner, including publication in the
The following criteria will be evaluated in selecting participants:
• Relevance of the company's (or in the case of a trade association/organization, represented companies') business to the mission goals
• Company's (or in the case of a trade association/organization, represented companies') market potential for business in Indonesia, Singapore, Vietnam and the Philippines.
• Provision of adequate information on the company's products and/or services, and communication of the company's (or in the case of a trade association/organization, represented companies') primary objectives.
Diversity of company size and location may also be considered during the review process. Referrals from political organizations and any documents containing references to partisan political activities (including political contributions) will be removed from an applicant's submission and not considered during the selection process.
Mr. Gemal Brangman, Project Officer, U.S. Department of Commerce, Washington,
National Oceanic and Atmospheric Administration, Department of Commerce.
Notice of solicitation for nominations for the National Sea Grant Advisory Board and notice of public meeting.
This notice responds to Section 209 of the Sea Grant Program Improvement Act of 1976 (Pub. L. 94-461, 33 U.S.C. 1128), which requires the Secretary of Commerce (Secretary) to solicit nominations at least once a year for membership on the National Sea Grant Advisory Board (Board), a Federal Advisory Committee that provides advice on the implementation of the National Sea Grant College Program (NSGCP) . To apply for membership to the Board, applicants should submit a current resume as indicated in the
This notice also sets forth the schedule and proposed agenda of a forthcoming meeting of the Board. Board members will discuss and provide advice on the NSGCP in the areas of program evaluation, strategic planning, education and extension, science and technology programs, and other matters as described in the agenda found on the National Sea Grant College Program Web site at
Solicitation of nominations is open ended. Resumes may be sent to the address specified at any time.
The announced meeting is scheduled for Tuesday, November 3, 2015 from 8:30 a.m. to 5:00 p.m. HST and Wednesday, November 4, 2015, from 8:00 a.m. to 12:00 p.m. HST.
(a) Security clearance (on-line background security check process and fingerprinting), and other applicable forms, both conducted through NOAA Workforce Management; and (b) Confidential Financial Disclosure Report-As an SGE, you are required to file a Confidential Financial Disclosure Report annually to avoid involvement in a real or apparent conflict of interest. You may find the Confidential Financial Disclosure Report at the following Web site.
For any additional questions concerning the meeting, please contact Mrs. Hinden using the contact information above.
The November meeting will be held at the Hilton Hotel located at 2005 Kalia Road, Honolulu, HI 96815.
The Board expects that public statements presented at its meetings will not be repetitive of previously submitted verbal or written statements. In general, each individual or group making a verbal presentation will be limited to a total time of three (3) minutes. Written comments should be received by Mrs. Jennifer Hinden by Friday, October 29, 2015 to provide sufficient time for the Board review. Written comments received after the deadline will be distributed to the Board, but may not be reviewed prior to the meeting date. Seats will be available on a first-come, first-serve basis.
Established by Section 209 of the Act and as amended the National Sea Grant College Program Amendments Act of 2008 (Pub. L. ll0-394), the duties of the Board are as follows:
(l) In general. The Board shall advise the Secretary and the National Sea Grant College Program Director (Director) concerning:
(A) Strategies for utilizing the Sea Grant College Program to address the Nation's highest priorities regarding the understanding, assessment, development, management, utilization, and conservation of ocean, coastal, and Great Lakes resources;
(B) The designation of Sea Grant Colleges and Sea Grant Institutes; and
(C) Such other matters as the Secretary refers to the Board for review and advice.
(2) Biennial Report. The Board shall report to the Congress every two years on the state of the National Sea Grant College Program. The Board shall indicate in each such report the progress made toward meeting the priorities identified in the strategic plan in effect under section 204(c). The Secretary shall make available to the Board such information, personnel, and administrative services and assistance as it may reasonably require to carry out its duties under this title.
The Board shall consist of 15 voting members who will be appointed by the Secretary for a 4-year term. The Director and a director of a Sea Grant program who is elected by the various directors of Sea Grant programs shall serve as nonvoting members of the Board. Not less than 8 of the voting members of the Board shall be individuals who, by reason of knowledge, experience, or training, are especially qualified in one or more of the disciplines and fields included in marine science. The other voting members shall be individuals who, by reason of knowledge, experience, or training, are especially qualified in, or representative of, education, marine affairs and resource management, coastal management, extension services, State government, industry, economics, planning, or any other activity which is appropriate to,
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a public meeting.
The North Pacific Fishery Management Council (Council) Ecosystem Committee will meet October 29-30, 2015, in Anchorage, AK.
The meeting will be held on Thursday, October 29, 2015, from 1 p.m. to 5 p.m., finishing in the afternoon on Friday, October 30, 2015.
The meeting will be held in the New Federal Building, 222 W. 7th Ave., Suite 552, Anchorage, AK 99513; telephone: (907) 271-6368.
Steve MacLean, Council staff; telephone: (907) 271-2809.
The agenda will include: (a) Bering Sea Fishery Ecosystem Plan discussion paper, (b) NMFS draft policy on Ecosystem Based Fishery Management, and (c) the Groundfish Work Plan. The Agenda is subject to change, and the latest version will be posted at
These meetings are physically accessible to people with disabilities. Requests for sign language interpretation or other auxiliary aids should be directed to Shannon Gleason at (907) 271-2809 at least 7 working days prior to the meeting date.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice; revision of an incidental harassment authorization; request for comments.
We, NMFS, have received a request from Point Blue Conservation Science (Point Blue) to revise an issued Incidental Harassment Authorization (Authorization) to take marine mammals, by harassment, incidental to conducting seabird research activities on Southeast Farallon Island, Año Nuevo Island, and Point Reyes National Seashore in central California. Point Blue's current Authorization is effective until January 30, 2016, and authorizes the incidental harassment, by Level B harassment only, of approximately 9,871 California sea lions (
NMFS must receive comments and information on or before November 12, 2015.
Address comments on the application to Jolie Harrison, Chief, Permits and Conservation Division, Office of Protected Resources, National Marine Fisheries Service, 1315 East-West Highway, Silver Spring, MD 20910. The mailbox address for providing email comments is
To obtain an electronic copy of the application containing a list of the references used in this document, write to the previously mentioned address, telephone the contact listed here (see
Jeannine Cody, NMFS, Office of Protected Resources, NMFS (301) 427-8401.
On December 23, 2014, NMFS published a
On September 22, 2015, NMFS received a request from Point Blue seeking to revise the Authorization issued on January 31, 2015 (80 FR 10066, February 25, 2015) to increase the number of authorized take of small numbers of California sea lions from approximately 9,871 to a total of 44,871 for the duration of the current Authorization which expires on January 30, 2016. Current environmental conditions in the Pacific Ocean offshore California—which researchers have attributed to an impending El Nino event—have contributed to unprecedented numbers of California sea lions hauled out in areas where Point Blue conducts surveys and maintains critical infrastructure. As such, Point Blue has requested a modification to their current Authorization to increase the number of authorized take for California sea lions to continue their critical operations and research. This is the only requested change to the current Authorization.
This
Point Blue will continue to monitor and census seabird colonies; observe seabird nesting habitat; restore nesting burrows; and resupply a field station annually in central California (
NMFS outlined the purpose of Point Blue's activities in a previous notice for the proposed authorization (79 FR 76975, December 23, 2014). Point Blue's activities and level of survey effort have not changed since the publication of the
The Authorization requires Point Blue to monitor for marine mammals in order to implement mitigation measures to effect the least practicable adverse impact on marine mammals. Monitoring activities consist of conducting and recording observations on pinnipeds within the vicinity of the research areas. The monitoring reports provide dates, location, species, and the researcher's activities. The reports will also include the behavioral state of marine mammals present, numbers of animals that moved greater than one meter, and numbers of pinnipeds that flushed into the water.
Point Blue reports that between January and March, 2015, California sea lion incidental take patterns were relatively normal at the South Farallon Islands survey locations. However, during the summer of 2015, warm water conditions along the California coast in summer have resulted in more California sea lions hauling out in areas where Point Blue conducts its activities. Point Blue reports that throughout the summer months, sea lion numbers continued to grow, with greater numbers hauled out in areas where researchers have not normally recorded sea lion attendance. For example, since August 15, 2015 at the South Farallon Islands, Point Blue reports that thousands of sea lions hauled out in unusual locations high on the islands. Many California sea lions climbed onto critical infrastructure, including boat landings, a water storage structure, and main access paths.
Point Blue reports that for the period between August 15 and September 20, 2015, they recorded 13,559 Level B harassment takes; 16 percent involved animals slowly flushing into the water, and the remaining 84 percent of recorded take involved California sea lions moving greater than one meter (3.2 feet) on land.
During this period, Point Blue has restricted their activities as much as possible to still perform basic
With the exception of a proposed increase in the number of authorized takes for California sea lions, no other substantive changes have occurred in the interim. Based on the analysis contained herein of the likely effects of the specified activity on marine mammals and their habitat, and taking into consideration the implementation of the required monitoring and mitigation measures, NMFS preliminarily finds that the total marine mammal take from Point Blue's survey activities will have a negligible impact on the affected marine mammal species or stocks.
NMFS invites comment on the proposed revised Incidental Harassment Authorization to Point Blue. Please include with your comments any supporting data or literature citations to help inform NMFS' final decision on Point Blue's request for a revised Authorization.
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 December 14, 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 and instructions should be directed to John Clary, (206) 526-4039 or email
This request is for extension of a currently approved information collection. The groundfish tagging program provides scientists with information necessary for effective conservation, management, and scientific understanding of the groundfish fishery off Alaska and the Northwest Pacific. The program area includes the Pacific Ocean off Alaska (the Gulf of Alaska, the Bering Sea and Aleutian Islands Area, and the Alexander Archipelago of Southeast Alaska), California, Oregon, and Washington. Fish movement information from recovered tags is used in population dynamics models for stock assessment. There are two general categories of tags. Simple plastic tags (spaghetti tags) are external tags approximately two inches long, printed with code numbers. When a tag is returned, the tag number is correlated with databases of released, tagged fish to determine the net movement and growth rate of the tagged fish. Archival tags are microchips with sensors
This is a volunteer program requiring the actual tag from the fish to be returned, along with recovery information. Reporting forms with pre-addressed and postage-free envelopes are distributed to processors and catcher vessels.
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, Commerce.
Notice of availability; request for comments.
We, NMFS, announce that the
We will consider and address, as appropriate, all substantive comments received during the comment period. Comments on the Proposed Plan must be received no later than 5 p.m. Pacific daylight time on December 14, 2015.
You may submit comments on the Public Draft Recovery Plan by the following methods:
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•
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Electronic copies of the Proposed Plan are available on the NMFS Web site at:
Robert Walton, NMFS Oregon Coast Coho Salmon Recovery Coordinator, at (503) 231-2285, or
We are responsible for developing and implementing recovery plans for Pacific salmon and steelhead listed under the ESA of 1973, as amended (16 U.S.C. 1531
We believe it is essential to have local support of recovery plans by those whose activities directly affect the listed species and whose continued commitment and leadership will be needed to implement the necessary recovery actions. We therefore support and participate in locally led, collaborative efforts to develop recovery plans that involve state, tribal, and
For the purpose of recovery planning for the ESA-listed species of Pacific salmon and steelhead in Idaho, Oregon and Washington, NMFS designated five geographically based “recovery domains.” The Oregon Coast Coho Salmon ESU spawning range is in the Oregon Coast domain. For each domain, NMFS appointed a team of scientists, nominated for their geographic and species expertise, to provide a solid scientific foundation for recovery plans. The Oregon and Northern California Coasts Technical Recovery Team (TRT) included scientists from NMFS, other Federal agencies, the state of Oregon, and the private sector.
A primary task for the Oregon and Northern California Coasts Technical Recovery Team was to recommend criteria for determining when the ESU should be considered viable (
For this Proposed Plan, we collaborated with state, tribal and Federal scientists and resource managers and stakeholders to provide technical information that NMFS used to write the Proposed Plan which is built upon locally-led recovery efforts.
The Proposed Plan, including the recovery plan modules, is now available for public review and comment.
The Proposed Plan contains biological background and contextual information that includes description of the ESU, the planning area, and the context of the plan's development. It presents relevant information on ESU structure, biological status and proposed biological viability criteria and threats criteria for delisting.
The Proposed Plan also describes specific information on the following: Current status of Oregon Coast Coho Salmon; limiting factors and threats for the full life cycle that contributed to the species decline; recovery strategies and actions addressing these limiting factors and threats; key information needs, and a proposed research, monitoring, and evaluation program for adaptive management. For recovery strategies and actions, Chapter 6 in the Proposed Plan includes proposed actions at the ESU and strata levels. Population level information will be posted on the recovery plan Web site (see below). The plan also describes how implementation, prioritization of actions, and adaptive management will proceed at the population, strata, and ESU scales. The Proposed Plan also summarizes time and costs (Chapter 7) required to implement recovery actions. In addition to the information in the Proposed Plan, readers are referred to the recovery plan Web site for more information on all these topics. (
With approval of the final Plan, we will commit to implement the actions in the Plan for which we have authority and funding; encourage other Federal and state agencies and tribal governments to implement recovery actions for which they have responsibility, authority and funding; and work cooperatively with the public and local stakeholders on implementation of other actions. We expect the Plan to guide us and other Federal agencies in evaluating Federal actions under ESA section 7, as well as in implementing other provisions of the ESA and other statutes. For example, the Plan will provide greater biological context for evaluating the effects that a proposed action may have on a species by providing delisting criteria, information on priority areas for addressing specific limiting factors, and information on how future populations within the ESU can tolerate varying levels of risk.
When we are considering a species for delisting, the agency will examine whether the section 4(a)(1) listing factors have been addressed. To assist in this examination, we will use the delisting criteria described in Chapter 4 of the Plan, which includes both biological criteria and criteria addressing each of the ESA section 4(a)(1) listing factors, as well as any other relevant data and policy considerations.
We will also work with the Oregon Coast Coho Conservation Plan Implementation Team described in the Proposed Plan to develop implementation schedules that provide greater specificity for recovery actions to be implemented over three-to five-year periods. This Team will also help promote implementation of recovery actions and subsequent implementation schedules, and will track and report on implementation progress.
Section 4(f)(1)(B) of the ESA requires that recovery plans incorporate, to the maximum extent practicable, (1) objective, measurable criteria which, when met, would result in a determination that the species is no longer threatened or endangered; (2) site-specific management actions necessary to achieve the plan's goals; and (3) estimates of the time required and costs to implement recovery actions. We conclude that the Proposed Plan meets the requirements of ESA section 4(f) and are proposing to adopt it as the
We are soliciting written comments on the Proposed Plan. All substantive comments received by the date specified above will be considered and incorporated, as appropriate, prior to our decision whether to approve the plan. We will issue a news release announcing the adoption and availability of the final plan. We will post on the NMFS West Coast Region Web site (
16 U.S.C. 1531
Department of the Air Force, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to Separation and Retirement Division (DPSOR), Air Force Personnel Center, ATTN: Gail Weber, 550 C Street West, Suite 3, Joint Base San Antonio, TX 78150-4713 or call 210-565-2461.
Respondents are Air Force retired members and certain Reserve members who have gained jobs with a foreign government and who must obtain approval of the Secretary of the Air Force and Secretary of State to do so. Information, in the form of a letter, includes a detailed description of duty, name of employer, Social Security Number, and statements specifying whether or not the employee will be compensated; declaring if the employee will be required or plans to obtain foreign citizenship; declaring that the member will not be required to execute an oath of allegiance to the foreign government; verifying that the member understands that that retired pay equivalent to the amount received from the foreign government may be withheld if he or she accepts employment with a foreign government before receiving approval. Reserve members only must include a request to be reassigned to Inactive Status List Reserve Section (Reserve Section Code RB). After verifying the status of the individual, the letter is forwarded to the Air Force Review Board for processing. If the signed letter is not included in the file, individuals reviewing the file cannot furnish the necessary information to the Secretary of the Air Force and Secretary of State on which a decision can be made. Requested information is necessary to maintain the integrity of the Request for Approval of Foreign Government Employment Program.
Department of the Air Force, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Air Force Office of Scientific Research, AFOSR/RSPP, 875 North Randolph Street, Suite 325, Room 3112, Arlington, VA 22203.
Respondents are students enrolled in doctoral programs in science and engineering desiring to complete their education. The on-line, electronic application provides information necessary for evaluation and selection of fellowships.
The NDSEG fellowships allow recipients to pursue their graduate studies at whichever United States institution they choose to attend. The goal is to provide the United States with talented, doctorally trained American men and women who will lead state of the art research projects in disciplines having the greatest payoff to national defense requirements. Approximately 190-200 3-year fellowships are anticipated to be awarded in the fields of Aeronautical and Astronautical Engineering, Biosciences, Chemical Engineering, Chemistry, Civil Engineering, Cognitive, Neural, and Behavioral Sciences, Computer and Computational Sciences, Electrical Engineering, Geosciences, Material Science and Engineering, Mathematics, Mechanical Engineering, Naval Architecture and Ocean Engineering, Oceanography, and Physics.
Department of the Air Force, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to HQ USAFA/RRS, ATTN: Patty Edmond, 2304 Cadet Drive, Suite 2400, USAF Academy, CO 80840 or call 719-333-3358.
Respondents are candidates applying to the Air Force Academy, instructors of candidates, and their high school counselors. Information collection is necessary in order to determine which candidates have been nominated by their Congress person or Senator; to evaluate background and aptitude for commissioned service; to provide a candidate's participation in athletic and non-athletic extracurricular activities, family and personal background, and academic and school background data by a candidate's high school official. This data also includes eligibility by verification of age, U.S. citizenship, law infractions, schooling beyond high school, previous active duty tours, and previous applications to service academies. It is also necessary in order to provide a candidate opportunity to show through English, Math, or other instructors that they can meet Air Force academic performance. This data allows the selection panel to evaluate the “whole person” concept. Without this information it would be difficult to accurately determine if an initial applicant would be qualified to enter into the candidate phase of the process. It would also be difficult to accurately determine a candidate's leadership abilities, physical stamina, and academic abilities. Final USAF Academy selections could not be made if reviewing committees are not able to determine if basic requirements have or have not been met.
Department of Defense Medical Examination Review Board, Department of the Air Force, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to Department of Defense Medical Examination Review Board (DoDMERB), 8034 Edgerton Drive, Suite 132, USAF Academy, CO 80840-2200.
Respondents are individuals who are interested in applying to attend one of the five Service academies, the four-year
The completed forms are processed through medical reviewers representing their respective services to determine a medical qualification status. Associated forms may or may not be required depending on the medical information contained in the medical examination. If the medical examination and associated forms, if necessary, are not accomplished, individuals reviewing the medical examination cannot be readily assured of the medical qualifications of the individual. Without this process the individual applying to any of these programs could not have a medical qualification determination. It is essential that individuals have a medical qualification determination to ensure compliance with the physical standards established for each respective military service program.
Global Positioning System Directorate (GPSD)
Notice of meeting—2015 Public Interface Control Working Group and Open Forum for the NAVSTAR GPS public documents
This notice informs the public that the Global Positioning Systems (GPS) Directorate will host the 2015 Public Interface Control Working Group and Open Forum on 9 and 10 December 2015 for the following NAVSTAR GPS public documents: IS-GPS-200 (Navigation User Interfaces), IS-GPS-705 (User Segment L5 Interfaces), and IS-GPS-800 (User Segment L1C Interface). Additional logistical details can be found below.
The purpose of this meeting is to update the public on GPS public document revisions and collect issues/comments for analysis and possible integration into future GPS public document revisions. All outstanding comments on the GPS public documents will be considered along with the comments received at this year's open forum in the next revision cycle. The 2015 Interface Control Working Group and Open Forum are open to the general public. For those who would like to attend and participate, we request that you register no later than November 23, 2015. Please send the registration information to
Comments will be collected, catalogued, and discussed as potential inclusions to the version following the current release. If accepted, these changes will be processed through the formal directorate change process for IS-GPS-200, IS-GPS-705, and IS-GPS-800. All comments must be submitted in a Comments Resolution Matrix (CRM). These forms along with current versions of the documents and the official meeting notice are posted at:
Please submit comments to the SMC/GPS Requirements (SMC/GPER) mailbox at
Date/Time: 9-10 Dec. 2015, 0830-1600 * (Pacific Standard Time P.S.T.).
Registration/check-in on 9 Dec. 2015 will begin at 0800 hours.
* Identification will be required at the entrance of the Salient facility (
Captain Robyn Anderson,
Department of the Army, DoD.
Notice to alter a system of records.
The Department of the Army proposes to alter system of records notice, A0027-40 CE, Corps of Engineers Case Management Information Files. This system allows the Corps of Engineers' legal offices to manage legal work and to identify and contact individuals involved in litigation, contract claims and appeals, procurement fraud, potentially responsible party negotiations under the Comprehensive Environmental Response Compensation and Liability Act; and patents and technology transfer, involving the Corps of Engineers.
Comments will be accepted on or before November 12, 2015. This proposed action will be effective on the day 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:
*
*
Ms. Tracy Rogers, Department of the Army, Privacy Office, U.S. Army Records Management and Declassification Agency, 7701 Telegraph Road, Casey Building, Suite 144, Alexandria, VA 22315-3860 or by phone at 703-428-7499.
The Department of the Army systems of records notices subject to the Privacy Act of 1974 (5 U.S.C. 552a), as amended, have been published in the
The proposed systems reports, as required by 5 U.S.C. 552a(r) of the Privacy Act, as amended, were submitted on July 17, 2015, to the House Committee on Oversight and Government Reform, the Senate Committee on Homeland Security and Governmental Affairs, and the Office of Management and Budget (OMB) pursuant to paragraph 4c of Appendix I to OMB Circular No. A-130, “Federal Agency Responsibilities for Maintaining Records About Individuals,” dated February 8, 1996, (February 20, 1996, 61 FR 6427).
Corps of Engineers Case Management Information Files (September 19, 1994, 59 FR 47843)
Delete entry and replace with “U.S. Army Corps of Engineers Central Processing Center, 3909 Halls Ferry Road, Vicksburg, MS 39180-6199, with input and access locations at all Corps of Engineers' Counsel Offices. Official mailing addresses are published as an appendix to the Army's compilation of system of records notices or may be obtained from the system manager.”
Delete entry and replace with “Records relating to litigation, contract claims and appeals, procurement fraud, potentially responsible party negotiations under the Comprehensive Environmental Response Compensation and Liability Act and patents and technology transfer, involving the Corps of Engineers; including names, addresses and phone numbers of individuals; docket or contract number; office symbol; file number; case name; the forum name; title of action; date of action; type of action; category of action; status of the action; disposition of action; summaries of the action; action number; amount of award; project name and location; remedies or relief requested; milestones and suspense dates; title of invention; and royalty information.”
Delete entry and replace with “5 U.S.C. 301, Departmental Regulations; 15 U.S.C. Chapter 1, Monopolies and Combinations in Restraint of Trade; 31 U.S.C. 3729 False Claims; and 42 U.S.C. 9601
Delete entry and replace with “To allow the Corps of Engineers legal offices to manage legal work and to identify and contact individuals involved in litigation, contract claims and appeals, procurement fraud, potentially responsible party negotiations under the Comprehensive Environmental Response Compensation and Liability Act; and patents and technology transfer, involving the Corps of Engineers.”
Delete entry and replace with “In addition to those disclosures generally permitted under 5 U.S.C. 552a(b) of the Privacy Act of 1974, as amended, these records contained therein may specifically be disclosed outside the DoD as a routine use pursuant to 5 U.S.C. 552a(b)(3) as follows:
Litigation, contract claims and appeals and procurement fraud records may be disclosed to Department of Justice and U.S. Attorney's offices for use in litigation. Most of this information is filed in the courts and is therefore a public record.
Names of companies or organizations, and their representatives, involved in potentially responsible party negotiations may be disclosed to the Environmental Protection Agency, Department of Justice, and the involved parties to facilitate potentially responsible party negotiations.
Patent records may be disclosed to The U.S. Patent and Trademark Office; Department of Commerce; appropriate authorities in foreign countries, for foreign patent filings; parties to a licensing arrangement for specific files involved; and contractors and government agencies, to conduct patent investigations and evaluations.
The DoD Blanket Routine Uses set forth at the beginning of the Army's compilation of systems of records notices may apply to this system. The complete list of DoD blanket routine uses can be found online at:
Delete entry and replace with “Electronic storage media and paper records.”
Delete entry and replace with “By individual's name, address and telephone number; in conjunction with the title of the action; forum name; docket or contract number; office symbol; file number; type of action; category of action; disposition of action; date of action and amount of award.”
Delete entry and replace with “Electronic and paper records are maintained in controlled areas accessible only to authorized legal office personnel. Physical security differs from site to site, but the automated records are maintained in controlled areas accessible only by authorized personnel. Access to electronic records is restricted by use of common access cards (CACs) and is accessible only by users with an authorized account. The system and electronic backups are maintained in controlled facilities that employ physical restrictions and safeguards such as security guards, identification badges, key cards, and locks.”
Delete entry and replace with “Chief Counsel, U.S. Army Corps of Engineers, 441 G Street NW., Washington, DC 20314-1000.”
Delete entry and replace with “Individuals seeking to determine whether information about themselves is contained in this system should address written inquiries to the Chief Counsel, ATTN: CECC-ZB, U.S. Army Corps of Engineers, 441 G Street NW., Washington, DC 20314-1000.
Individuals must provide full name, current address and telephone number,
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States: ‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature).'
If executed within the United States, its territories, possessions, or commonwealths: ‘I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature).'”
Delete entry and replace with “Individuals seeking access to records about themselves contained in this system should address written inquiries to the Chief Counsel, U.S. Army Corps of Engineers, ATTN: CECC-ZB, 441 G Street NW., Washington, DC 20314-1000.
Individual must provide full name, current address and telephone number, category of record (litigation, contract claims and appeals, procurement fraud, potentially responsible party negotiations, patents or technology transfer) and signature.
In addition, the requester must provide a notarized statement or an unsworn declaration made in accordance with 28 U.S.C. 1746, in the following format:
If executed outside the United States: ‘I declare (or certify, verify, or state) under penalty of perjury under the laws of the United States of America that the foregoing is true and correct. Executed on (date). (Signature).'
If executed within the United States, its territories, possessions, or commonwealths: ‘I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on (date). (Signature).'”
Delete entry and replace with “From documents provided by the individual, his/her attorney, court records, Army records, investigation reports, other Federal agencies, and state and local agencies.”
Office of the Administrative Assistant to the Secretary of the Army (OAA-AAHS), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Department of the Army, U.S. Army Corps of Engineers, Institute for Water Resources, Corps of Engineers Waterborne Commerce Statistics Center, 7400 Leake Avenue, New Orleans, LA 70118, ATTN: CEIWR-NDC-C (Mickey LaMaca), or call Department of the Army Reports Clearance Officer at (703) 428-6440.
On September 28, 1998, the Office of Management and Budget (OMB) designated the U.S. Army corps of Engineers (Corps) as the “central collection agency” for the U.S. Foreign Waterborne Transportation Statistics Program effective October 1, 1998. The U.S. Bureau of Census (Census) was previously responsible for this program. As central collection agency for foreign waterborne transportation statistics, the Corps is responsible for meeting the needs of other federal agencies that require these data. The Maritime Administration, the U.S. Coast Guard, the Bureau of Transportation Statistics, the Environmental Protection Agency, and the Bureau of Economic Analysis also require these data.
Office of the Under Secretary of Defense for Acquisition, Technology, and Logistics, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Under Secretary of Defense for Acquisition, Technology, and Logistics, 3330 Defense Pentagon, Washington, DC 20301-3330.
Office of the Assistant Secretary of Defense for Health Affairs, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to TRICARE Management Activity Program, Policy and Benefits Branch,
Respondents are individuals who are or were beneficiaries of the Military Health System (MHS) and who desire to enroll in the CHCBP following their loss of entitlement to health care coverage in the MHS. These beneficiaries include the active duty service member or former service member (who, for purposes of this notice shall be referred to as “service member”), an unmarried former spouse of a service member, an unmarried child of a service member who ceases to meet requirements for being considered a dependent, and a child placed for adoption or legal custody with the service member. In order to be eligible for health care coverage under CHCBP, an individual must first enroll in CHCBP. DD Form 2837 is used as the information collection vehicle for that enrollment. The CHCBP is a legislatively mandated program and it is anticipated that the program will continue indefinitely.
Office of the Assistant Secretary of Defense for Health Affairs, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Appeals, Hearings and Claims Collection Division, Office of General Counsel, TRICARE® Management Activity, ATTN: Mark P. Donahue, 16401 East Centretech Parkway, Aurora, CO 80011-9066, or via telephone at (303) 676-3411.
Respondents are medical professionals who provide medical and peer review of cases appealed to the Office of Appeals, Hearings and Claims Collection Division, Office of General Counsel, TRICARE® Management Activity. CHAMPUS Form 780 records the professional qualifications of the medical or peer reviewer. The completed form is included as an exhibit in the appeal or hearing case file, and documents for anyone reviewing the file, the professional qualifications of the medical professional who reviewed the case. If the form is not included in the case file, individuals reviewing the file cannot be readily assured of the qualifications of the reviewing medical professional. Having qualified professionals provide medical and peer review is essential in maintaining the integrity of the appeal and hearing process.
DoD.
Meeting notice.
The Department of Defense is publishing this notice to announce the following Federal advisory committee meeting of the Defense Business Board. This meeting is open to the public.
The public meeting of the Defense Business Board (“the Board”) will be held on Thursday, October 22, 2015. The meeting will begin at 1:15 p.m. and end at 2:30 p.m. (Escort required; see guidance in the
Room 3E863 in the Pentagon, Washington, DC (Escort required; See guidance in the
The Board's Designated Federal Officer (DFO) is Ms. Roma Laster, Defense Business Board, 1155 Defense Pentagon, Room 5B1088A, Washington, DC 20301-1155,
Due to circumstances beyond the control of the Designated Federal Officer and the Department of Defense, the Defense Business Board was unable to provide public notification of its meeting of October 22, 2105, as required by 41 CFR 102-3.150(a). Accordingly, the Advisory Committee Management Officer for the Department of Defense, pursuant to 41 CFR 102-3.150(b), waives the 15-calendar day notification requirement.
This meeting is being held under the provisions of the Federal Advisory Committee Act (FACA) 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 102-3.140.
The mission of the Board is to examine and advise the Secretary of Defense on overall DoD management and governance. The Board provides independent advice which reflects an outside private sector perspective on proven and effective best business practices that can be applied to DoD.
Written public comments are strongly encouraged.
Special Accommodations: Individuals requiring special accommodations to access the public meeting should contact Mr. Cruddas at least five (5) business days prior to the meeting so that appropriate arrangements can be made.
Pursuant to 41 CFR 102-3.105(j) and 102-3.140, and section 10(a)(3) of the Federal Advisory Committee Act of 1972, the public or interested organizations may submit written comments to the Board about its mission and topics pertaining to this public meeting.
Written comments should be received by the DFO at least five (5) business days prior to the meeting date so that the comments may be made available to the Board for their consideration prior to the meeting. Written comments should be submitted via email to the email address for public comments given in the
Office of the Under Secretary of Defense (Personnel and Readiness), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Under Secretary of Defense (Personnel and Readiness) (Military Community and Family Policy), ATTN: Mr. James M. Ellis, 4000 Defense Pentagon, Washington, DC 20301-4000 or call at (703) 602-5009.
Section 401 of Public Law 95-202 (codified at 38 U.S.C. 106 Note) authorized the Secretary of Defense: (1) To determine if civilian employment or contractual service rendered to the Armed Forces of the United States by certain groups shall be considered active duty service, and (2) to issue members of approved groups an appropriate certificate of service where the nature and duration of service so warrants. Such persons shall be eligible for benefits administered by the Department of Veterans Affairs. The information collected on DD Form 2168, “Application for Discharge of Member or Survivor of Member Group Certified To Have Performed Duty with the Armed Forces of the United States,” is necessary to assist the Secretaries of the Military Departments in: (1) Determining if an applicant was a member of an approved group that performed civilian employment or contractual service for the U.S. Armed Forces and (2) to assist in issuing an appropriate certificate of service to the applicant. Information provided by the applicant will include: The name of the group served with; dates and place of service; highest grade/rank/rating held during service; highest pay grade; military installation where ordered to report; specialty/job title(s). If the information requested on a DD Form 2168 is compatible with that of a corresponding approved group, and the applicant can provide supporting evidence, he or she will receive veteran's status in accordance with the provisions of DoD Directive 1000.20. Information from the DD Form 2168 will be extracted and used to complete the DD Form 214, “Certificate for Release or Discharge from Active Duty.”
Office of the Assistant Secretary of Defense for Health Affairs, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the TRICARE Dental Care Office, Health Agency (DHA), Rm 3M451, ATTN: COL Colleen C. Shull, Falls Church, VA 22042 or call (703) 681-9517, DSN 761.
The Defense Health Agency (DHA) under the authority of the Office of the Assistant Secretary of Defense (Health Affairs)/Office of the Deputy Assistant Secretary of Defense has responsibility for management of the TRICARE Dental Program (TDP) as established in Title 10, United States Code, Section 1076a. The information collected to make payment for covered dental procedures provided by a licensed dentist to an eligible beneficiary can be sent to the TDP contractor electronically, fax or mail. Approximately 35% of all TDP network dental claims are filed electronically. Dental offices and patients can download the TDP claim form from the contractor's Web site.
For non-network dentists, to include those in overseas locations, the use of the TDP Claim Form is highly encouraged. However, dental claims will be paid if all the required information is provided on a similar claim form.
Office of the Under Secretary of Defense (Personnel and Readiness), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Department of Defense Education Activity,
The following categories will be included in this data collection.
Office of the Under Secretary of Defense (Personnel and Readiness), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Department of Defense Education Activity, ATTN: Dr. Sandra D. Embler, 4040 North Fairfax Drive, Arlington, VA 22203-1635, or call at (703) 588-3175.
NCA CASI/AdvancED is the largest accreditation organization in the United States, covering 30 states and 65 countries. As part of the accreditation process, NCA CASI/AdvancED conducts Quality Assurance Review (QAR) visits to DoDEA schools in February and April of each year on a rotating schedule that ensures that each school is evaluated within a 5-year cycle. The visits are two days in length in order to gather data, information, and evidence to accomplish the following:
• Evaluate adherence to the AdvancED standards;
• Provide high quality feedback in the form of commendations and recommendations; and
• Determine an accreditation status recommendation.
The Quality Assurance Review team's interview process includes students and parents/guardians. The purpose of the interview session is to help the Quality Assurance Review team gain a deeper understanding of the school improvement process. The review team uses the information to review how well each school is progressing, provide commendations on areas in which each school is excelling, and recommendations that will help each school continuously improve. The review team also uses the information gathered to make an accreditation status recommendation at the end of the visit.
Defense Security Service, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Security Service, OCIO, Russell-Knox Building, 27130 Telegraph Road, Quantico, VA 22134-2253, or call Defense Security Service at (571) 305-6445.
In accordance with Department of Defense (DoD), 5220.22-R, “Industrial Security Regulation,” DSS is required to maintain a record of the results of surveys and security reviews. Documentation for each survey and/or security review will be compiled addressing areas applicable to the contractor's security program. Portions of the data collected will be stored in databases. All data collected will be handled and marked “For Official Use Only.”
DSS is the office of record for the maintenance of information pertaining to contractor facility clearance records
Office of the Under Secretary of Defense (Personnel and Readiness), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Under Secretary of Defense (Personnel and Readiness), Department of Defense Education Activity (Human Resources Regional Center), ATTN: Patti Ross, 4800 Mark Center Drive, Alexandria, VA 22350 or call (571) 372-0787.
The primary objective of the information collection is to screen applicants for educational qualification and employment eligibility, to obtain pertinent evaluation information about an applicant to assist management in making a hiring decision, and to obtain applicant consent to obtain personal information from former employers about applicants' employment. The forms associated with this data collection include: (1) Department of Defense Dependents Schools Supplemental Application for Overseas Employment (DoDEA Form 5010). The primary objective of this voluntary form is to ascertain applicants' eligibility for educator positions. (2) Department of Defense Dependents Schools Professional Evaluation (DoDEA Form 5011). This form is provided to officials who served in managerial and supervisory positions above the applicant as a means of verifying abilities and qualifications of applicants for educator positions. (3) Department of Defense Dependents Schools Verification of Professional Educator Employment for Salary Rating Purposes (DoDEA Form 5013). The purpose of this voluntary form is to verify employment history of educator applicants and to determine creditable previous experience for pay-setting purposes. The paper forms and electronic data systems containing the sponsor and dependent personally identifying information are secured in accordance with the requirements of Federal law and implementing DoD regulations.
Defense Logistics Agency, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
• Federal eRulemaking Portal:
• Mail: Department of Defense, Office of the Deputy Chief Management Officer, Directorate of Oversight and Compliance, Regulatory and Audit Matters Office, 9010 Defense Pentagon, Washington, DC 20301-9010.
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Logistics Agency, U.S./Canada Joint Certification Office, DLA Logistics Information Service-BFC, Attn: George A. Bredehoft, Federal Center, 74 Washington Ave. N., Battle Creek, MI 49017-3084; or call (269) 961-5339.
Use of DD Form 2345 permits U.S. and Canada defense contractors to certify their eligibility to obtain certain unclassified technical data with military and space applications. Nonavailability of this information prevents defense contractors from accessing certain restricted databases and obstructs conference attendance where restricted data will be discussed. The form is available on the Defense Technical Information Center (DTIC) Web page and DLA Logistics Information Services Web page.
Office of the Under Secretary of Defense for Personnel and Readiness (Military Personnel Policy), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Under Secretary of Defense (Personnel and Readiness) (Military Personnel Policy), ATTN: MAJ Justin DeVantier, 4000 Defense Pentagon, Washington, DC 20301-4000 or call at (703) 695-5527.
This information is collected to provide Armed Services with specific background information on an applicant. History of criminal activity, arrests, or confinement is disqualifying for military service. An applicant, with such a disqualifier, is required to submit references from community leaders who will attest to his or her character, attitudes or work habits. The DD Form 370 is the method of information collection which requests an evaluation and reference from a specific individual, within the community, who has the knowledge of the applicant's habits, behavior, personality, and character. The information will be used to determine suitability of the applicant for military service and the issuance of a waiver for acceptance.
Office of the Assistant Secretary of Defense for Health Affairs, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
• Federal eRulemaking Portal:
• Mail: Department of Defense, Office of the Deputy Chief Management Officer, Directorate of Oversight and Compliance, Regulatory and Audit Matters Office, 9010 Defense Pentagon, Washington, DC 20301-9010.
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Defense Health Agency, Medical Benefits and Reimbursement Systems, 16401 East Centretech Parkway, ATTN: Elan Green, Aurora, CO 80011-9043, or call Defense Health Agency, Medical Benefits and Reimbursement Office, at (303) 676-3907.
On March 10, 1999, TRICARE Management Activity (TMA), formerly known as OCHAMPUS, published a final ruse in the
The collected information will be used by TRICARE contractors to process claims and verify authorized provider status. Verification involves collecting and reviewing copies of the provider's licenses, certificates, accreditation documents, etc. If the criteria are met, the provider is granted TRICARE authorization status. The documentation and information are collected when: (1) A provider requests permission to become a TRICARE-authorized provider; (2) a claim is filed for care received from a provider who is not listed on the contractor's computer listing of authorized providers; or (3) when a former TRICARE-authorized provider requests reinstatement. The contractors develop the forms used to gather information based on the TRICARE conditions for participation listed above. Without the collection of this information, contractors cannot determine if the provider meets TRICARE-authorization requirements for corporate services providers. If the contractor is unable to verify that a provider meets these authorization requirements, the contractor may not reimburse either the provider or the beneficiary for the provider's health care services. To reduce the reporting burden to a minimum, TRICARE has carefully selected the information requested from respondents. Only that information which has been deemed absolutely essential is being requested. If necessary, contractors may verify credentials with Medicare, JCAHO and other national organizations by telephone. TRICARE is also participating with Medicare in the development of a National Provider System which will eliminate duplication of provider certification and data collection among Federal government agencies. TRICARE contractors are required to maintain a computer listing before requesting documentation from providers. Since the providers affected by this information generally have not previously been eligible to be authorized providers, TRICARE contractors will have no information on file. The providers will have to submit the information requested on the data collection form (Application for TRICARE-Providers Status: Corporate Services Provider) in order to obtain provider authorization status under TRICARE. The information will usually be collected from each respondent only once. It is estimated that there will be approximately 300 applicants per year. TRICARE will request the provider authorization documentation and information when the provider asks to become TRICARE-authorized or when a claim is filed for a new provider's services. If after a provider has been authorized by a contractor, no claims are filed during two-year period of time, the provider's information will be placed in the inactive file. To reactivate a file, the provider must verify that the information is still correct, or supply new or changed information. The total annual reporting burden is estimated to be approximately 100 hours (approximately 300 respondents with 20 minutes to complete the form).
Notice.
The Department of Defense has submitted to OMB for clearance, the following proposal for collection of information under the provisions of the Paperwork Reduction Act.
Consideration will be given to all comments received by November 12, 2015.
Fred Licari, 571-372-0493.
Comments and recommendations on the proposed information collection should be emailed to Ms. Meredith DeDona, DoD Desk Officer, at
You may also submit comments and recommendations, identified by Docket ID number and title, by the following method:
•
Written requests for copies of the information collection proposal should be sent to Mr. Licari at WHS/ESD Directives Division, 4800 Mark Center Drive, East Tower, Suite 02G09, Alexandria, VA 22350-3100.
Office of the Under Secretary of Defense for Acquisition, Technology, and Logistics/Defense Technical Information Center (DTIC).
Notice.
In compliance with the
Consideration will be given to all comments received by December 8, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write or send an email to the DTIC-BC Registration Team, Defense Technical Information Center, 8725 John J. Kingman Road, Suite 0944, Fort Belvoir, VA 22060-6218, or email Ms. Kerry Christensen:
The DD Form 1540 serves as a registration tool for Federal Government agencies and their contractors to access DTIC services. Potential users registering for services are required to obtain certification from a designated approving official. Collected information is verified by DTIC's Marketing and Registration Division.
Office of the Under Secretary of Defense (Personnel and Readiness), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Under Secretary of Defense (Personnel and Readiness), ATTN: Lieutenant Colonel Ronald S. Hunter, 4000 Defense Pentagon, Washington, DC 20301-4000, or call at (703) 695-3176.
A former spouse who has been awarded coverage under the Survivor Benefit Plan either by court order or written agreement, may, within one year of such court order or written agreement, submit a request to have an election for such coverage deemed on behalf of the member. Such requests will be made by submitting the proposed form and a copy of the court order, regular on its face, which requires such election or incorporates, ratifies, or approves the written agreement of such person; or a statement from the clerk of the court (or other appropriate official) that such agreement has been filed with the court in accordance with applicable state law. A former spouse is not required to submit a request for a deemed election. However, if a request for deemed election is not submitted within the one year period described above and the members fail to elect former spouse SBP coverage, no former spouse coverage will be provided. The proposed form DD Form 2656-10, “Survivor Benefit Plan (SBP)/Reserve Component (RC) SBP Request for Deemed Election,” will become the prescribed form required for submitting such requests.
Department of Defense, Office of the Deputy Under Secretary of Defense (Installations and Environment).
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Office of the Deputy Under Secretary of Defense (Installations & Environment), 3400 Defense Pentagon, Washington, DC 20301-3400, or call (703) 695-6107.
Respondents are community members of restoration advisory boards or technical review committees requesting technical assistance to interpret scientific and engineering issues regarding the nature of environmental hazards at an installation. This assistance will assist communities in participating in the cleanup process. The information, directed by 10 U.S.C. 2705, will be used to determine the eligibility of the proposed project, begin the procurement process to obtain the requested products or services, and determine the satisfaction of community members of restoration advisory boards and technical review communities receiving the products and services.
Defense Contract Management Agency, DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
• Federal eRulemaking Portal:
• Mail: Department of Defense, Office of the Deputy Chief Management Officer, Directorate of Oversight and Compliance, Regulatory and Audit Matters Office, 9010 Defense Pentagon, Washington, DC 20301-9010.
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Director, Defense Contract Management Agency, Attn: Gary Moorman, 6350 Walker Lane, Suite 300 Alexandria, VA 22310, or call Mr. Gary Moorman at (703) 254-2134.
The requirement to have government approval of contract flight crewmembers is in Defense Contract Management Agency Directive 1, Chapter 8, Contractor's Flight and Ground Operations. The contractor provides a personal history and requests the government to approve training in a particular type government aircraft (DD Form 2627). The contractor certifies the crewmember has passed a flight evaluation and, with the DD Form 2628, requests approval for the personnel to operate and fly government aircraft. Without the correct approvals, the contractor cannot use their personnel as requested.
Marine Junior Reserve Officer's Training Corps (MCJROTC), DoD.
Notice.
In compliance with the
Consideration will be given to all comments received by December 14, 2015.
You may submit comments, identified by docket number and title, by any of the following methods:
•
•
Any associated form(s) for this collection may be located within this same electronic docket and downloaded for review/testing. Follow the instructions at
To request more information on this proposed information collection or to obtain a copy of the proposal and associated collection instruments, please write to the Commanding General, Training and Education Command (C46JR), MCCDC, 1019 Elliott Road, Quantico, VA 22134-5001, or telephone Mr. Robert Davis at (703) 784-0478.
This form provides a written record of the overall performance of duty of MCJROTC instructors who are responsible for implementing the MCJROTC curriculum. The Individual MCJROTC Instructor Evaluation Summary is completed by principles to evaluate the effectiveness of individual MCJROTC instructors.
The form is further used as a performance related counseling tool and as a record of service performance to document performance and growth of individual MCJROTC instructors. Evaluating the performance of instructors is essential in ensuring that they provide quality training.
Federal Student Aid (FSA), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before December 14, 2015.
To access and review all the documents related to the information collection listed in this notice, please use
For specific questions related to collection activities, please contact Ian Foss, 202-377-3681.
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.
Federal Student Aid (FSA), Department of Education (ED).
Notice.
In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. chapter 3501
Interested persons are invited to submit comments on or before November 12, 2015.
To access and review all the documents related to the information collection listed in this notice, please use
For specific questions related to collection activities, please contact Beth Grebeldinger, 202-377-4018.
The Department of Education (ED), in accordance with the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3506(c)(2)(A)), provides the general public and Federal agencies with an opportunity to comment on proposed, revised, and continuing collections of information. This helps the Department assess the impact of its information collection requirements and minimize the public's reporting burden. It also helps the public understand the Department's information collection requirements and provide the requested data in the desired format. ED is soliciting comments on the proposed information collection request (ICR) that is described below. The Department of Education is especially interested in public comment addressing the following issues: (1) Is this collection necessary to the proper functions of the Department; (2) will this information be processed and used in a timely manner; (3) is the estimate of burden accurate; (4) how might the Department enhance the quality, utility, and clarity of the information to be collected; and (5) how might the Department minimize the burden of this collection on the respondents, including through the use of information technology. Please note that written comments received in response to this notice will be considered public records.
In notice document 2015-25354, appearing on pages 60358-60369 in the Issue of Tuesday, October 6, 2015, make the following correction:
On page 60368, in the third column, under the heading
Department of Energy.
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Hanford. The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Wednesday, November 4, 2015, 10:00 a.m.-4:30 p.m.
Red Lion Hanford House, 802 George Washington Way, Richland, WA 99352.
Kristen Skopeck, Federal Coordinator, Department of Energy Richland Operations Office, 825 Jadwin Avenue, P.O. Box 550, A7-75, Richland, WA 99352; Phone: (509) 376-5803; or Email:
Department of Energy (DOE).
Notice of open meeting.
This notice announces a meeting of the Environmental Management Site-Specific Advisory Board (EM SSAB), Portsmouth. The Federal Advisory Committee Act (Pub. L. 92-463, 86 Stat. 770) requires that public notice of this meeting be announced in the
Thursday, November 5, 2015, 6:00 p.m.
Ohio State University, Endeavor Center, 1862 Shyville Road, Piketon, Ohio 45661.
Greg Simonton, Alternate Deputy Designated Federal Officer, Department of Energy Portsmouth/Paducah Project Office, Post Office Box 700, Piketon, Ohio 45661, (740) 897-3737,
Purpose of the Board: The purpose of the Board is to make recommendations to DOE-EM and site management in the areas of environmental restoration, waste management and related activities.
Take notice that the Commission received the following exempt wholesale generator filings:
Take notice that the Commission received the following electric rate filings:
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric corporate filings:
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:
Take notice that the Commission has received the following Natural Gas Pipeline Rate and Refund Report filings:
Any person desiring to intervene or protest in any of the above proceedings must file in accordance with Rules 211 and 214 of the Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00 p.m. Eastern time on the specified comment date. Protests may be considered, but intervention is necessary to become a party to the proceeding.
Any person desiring to protest in any of the above proceedings must file in accordance with Rule 211 of the Commission's Regulations (18 CFR 385.211) on or before 5:00 p.m. Eastern time on the specified comment date.
The filings are accessible in the Commission's eLibrary system by clicking on the links or querying the docket number.
eFiling is encouraged. More detailed information relating to filing requirements, interventions, protests, service, and qualifying facilities filings can be found at:
Take notice that the Commission received the following electric rate 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:
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency (EPA) is inviting comment on its analysis of the greenhouse gas emissions attributable to the production and transport of
Comments must be received on or before October 13, 2015.
Submit your comments, identified by Docket ID No. EPA-HQ-OAR-2015-0293 to the
Christopher Ramig, Office of Transportation and Air Quality, Transportation and Climate Division, Mail Code: 6401A, U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue NW., 20460; telephone number: (202) 564-1372; fax number: (202) 564-1177; email address:
A.
B.
• Identify the rulemaking by docket number and other identifying information (subject heading,
• Follow directions—The agency may ask you to respond to specific questions or organize comments by referencing a Code of Federal Regulations (CFR) part or section number.
• Explain why you agree or disagree; suggest alternatives and substitute language for your requested changes.
• Describe any assumptions and provide any technical information and/or data that you used.
• 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, avoiding the use of profanity or personal threats.
• Make sure to submit your comments by the comment period deadline identified.
This notice is organized as follows:
As part of changes to the Renewable Fuel Standard (RFS) program regulations published on March 26, 2010
EPA's lifecycle analyses are used to assess the overall greenhouse gas (GHG) impacts of a fuel throughout each stage of its production and use. The results of these analyses, considering uncertainty and the weight of available evidence, are used to determine whether a fuel meets the necessary greenhouse gas reductions required under the Clean Air Act (CAA) for it to be considered renewable fuel or one of the subsets of renewable fuel. Lifecycle analysis includes an assessment of emissions related to the full fuel lifecycle, including feedstock production, feedstock transportation, fuel production, fuel transportation and distribution, and tailpipe emissions. Per the CAA definition of lifecycle GHG emissions, EPA's lifecycle analyses also include an assessment of significant indirect emissions such as emissions from land use changes, agricultural sector impacts, and production of co-products from biofuel production.
EPA received a petition submitted pursuant to 40 CFR 80.1416 from Global Clean Energy Holdings (“GCEH” or the “GCEH petition”) and Emerald Biofuels, LLC, submitted under a claim of confidential business information (CBI), requesting that EPA evaluate the lifecycle GHG emissions for biofuels (biodiesel, renewable diesel, jet fuel and naphtha) produced from the oil extracted from
EPA has conducted an evaluation of the GHG emissions associated with the production and transport of jatropha oil when it is used as a biofuel feedstock, and is seeking public comment on the methodology and results of this evaluation. In this document, we are describing EPA's evaluation of the GHG emissions associated with the feedstock production and feedstock transport stages of the lifecycle analysis of jatropha oil when it is used to produce a biofuel, including the indirect agricultural and forestry sector impacts. We are seeking public comment on the methodology and results of this evaluation. For the reasons described in Section III below, we believe that it is reasonable to apply the GHG emissions estimates we established in the March 2010 rule for the production and transport of soybean oil to the production and transport of jatropha oil.
If appropriate, EPA will update its evaluation of the feedstock production and transport phases of the lifecycle analysis for jatropha oil based on comments received in response to this action. EPA will then use this feedstock production and transport information to evaluate facility-specific petitions, received pursuant to 40 CFR 80.1416, that propose to use jatropha oil as a feedstock for the production of biofuel. In evaluating such petitions, EPA will consider the GHG emissions associated with the production and transport of jatropha oil feedstock. In addition, EPA will determine—based on information in the petition and other relevant information, including the petitioner's energy and mass balance data—the GHG emissions associated with petitioners' biofuel production processes, as well as emissions associated with the transport and use of the finished biofuel. We will then combine our assessments into a full lifecycle GHG analysis and determine whether the fuel produced at an individual facility satisfies CAA renewable fuel GHG reduction requirements.
EPA has evaluated the GHG emissions associated with the production and transport of jatropha oil for use as a biofuel feedstock, based on information provided in the GCEH petition and other data gathered by EPA. Section III-A includes an overview of our GHG analysis of jatropha oil production and transport. Section III-B describes jatropha oil and available information about the growing conditions suitable for commercial-scale production. Section III-C explains our analysis of the GHG emissions attributable to growing and harvesting jatropha seeds. Section III-D describes our analysis of the land use change and other agricultural sector emissions, including significant indirect emissions, attributable to producing jatropha oil for use as a biofuel feedstock. Section III-E explains our assessment of the GHG emissions associated with feedstock transport and processing, including oil extraction and pre-treatment. Section III-F discusses the potential invasiveness of jatropha. Section III-G summarizes GHG emissions from jatropha oil production and transport. Section III-H discusses how EPA intends to consider the GHG emissions associated with fuel production and
This Notice explains and seeks comment on each component of EPA's GHG assessment of jatropha oil production and transportation. We also discuss and seek comment on potential invasiveness concerns for jatropha as they relate to GHG emissions. In this Notice we compare our assessment of jatropha oil to our previous evaluation of soybean oil for the March 2010 RFS rule because jatropha oil and soybean oil can be used in the same types of production processes to produce biodiesel, renewable diesel, jet fuel, and other similar types of biofuels. In the March 2010 RFS rule, EPA determined that several renewable fuel pathways using soybean oil feedstock meet the required 50% lifecycle GHG reduction threshold under the RFS for biomass-based diesel and advanced biofuel.
Based on the limited data available on where jatropha will be produced at commercial scale for use in making biofuels for the RFS program, we evaluated a number of scenarios with different assumptions about where jatropha will be grown and what type of land jatropha plantations will use. This section briefly discusses the two main scenarios that we evaluated and our overall findings based on these analyses.
As explained in more detail in Section III-B below, based on information in the GCEH petition and other data gathered by EPA through literature review and expert consultations, we believe that southern Mexico (specifically the states of Yucatan, Oaxaca and Chiapas) and northeastern Brazil
In a second scenario, we considered the possibility that jatropha will be grown on land that would have otherwise been used for agriculture (crop production or grazing/pasture). For this analysis we used the Food and Agricultural Policy and Research Institute international models as maintained by the Center for Agricultural and Rural Development at Iowa State University (the FAPRI-CARD model),
Based on the two scenarios described above, we believe it is reasonable, as a conservative approach, to apply the GHG emissions estimates we established in the March 2010 rule for the production and transport of soybean oil to jatropha oil when evaluating future facility-specific petitions from biofuel producers seeking to generate RINs for volumes of biofuel produced from jatropha oil.
Jatropha is a deciduous, perennial shrub or tree species belonging to the Euphorbiaceae family that grows approximately 8 to 15 meters tall. Experts agree that jatropha is native to the American tropics; however there is disagreement in the literature regarding its origin and the borders of jatropha's native range.
Jatropha does not have a long history as a planted crop. As a result, empirical data on crop yields, crop inputs, and other key agricultural characteristics are not readily available. In order to fill these knowledge gaps to the greatest extent possible, EPA conducted a literature review of agronomic and lifecycle GHG analysis studies of jatropha.
Several past efforts to cultivate jatropha for biofuel use attempted, without commercial success, to produce jatropha on marginal agricultural land with minimal inputs.
Based on conversations with researchers at the United States Department of Agriculture Agricultural Research Service (USDA-ARS) and other organizations, we determined that jatropha is unlikely to be commercially grown in the United States because of its high intolerance to frost.
Projecting where jatropha will be produced is difficult, as evidenced by previous government projects to support the expansion of jatropha production that did not materialize.
Mexico and Brazil offer hospitable environments for jatropha. Both countries are part of jatropha's naturalized range, and several efforts to commercialize jatropha have been reported there.
There have been several efforts to commercialize jatropha in other parts of the world, including Sub-Saharan Africa, India, East Asia, Southeast Asia, and Oceania. However, the commercial scale viability of jatropha farms in all of these regions is currently uncertain. The global surveys conducted by GEXSI and Leuphana reported that the vast majority of jatropha being cultivated worldwide was being grown in Southeast Asia, including India, China and Indonesia. The most recent of these surveys collected data in 2011.
Africa is another region with significant potential for jatropha production. However, we decided not to model jatropha oil from Africa in our analysis. First, there is uncertainty about whether African jatropha oil production would qualify as renewable biomass, because it is not clear that the land where it would be grown could be considered existing agricultural land, as required in the CAA to qualify as renewable biomass.
Although we are specifically modelling jatropha growth and transport in Mexico and Brazil, and expect most jatropha oil used as renewable fuel feedstock for the RFS program to be grown in those countries, we intend to apply our analysis of the GHG emissions attributable to jatropha oil production and transport when evaluating facility-specific petitions that propose to use jatropha oil as biofuel feedstock, regardless of the country of origin where their jatropha oil feedstock is grown. In the future, some jatropha oil feedstock used to produce biofuels for the RFS may be sourced from countries other than Mexico and Brazil, but this would be unlikely to change our overall assessment of the aggregate GHG impacts from growing and transporting jatropha oil. Consistent with EPA's approach for previous RFS pathway analyses, we will periodically reevaluate whether our assessment of GHG impacts will need to be updated in the future based on new information or a new methodology that has the potential to significantly change our assessment.
Our assessment includes the GHG emissions attributable to growing and harvesting jatropha seeds, including field preparation, planting, annual inputs and harvesting, and replanting. We also estimate the average yields, in terms of tonnes of dry jatropha seed per hectare, in both Mexico and Brazil. The GHG emissions associated with cultivation and harvesting are the same, per tonne of delivered jatropha oil, in both of the main scenarios that we evaluated, as the type of land converted is not expected to impact the emissions from these stages of jatropha oil production. The data for our evaluation of these stages of jatropha oil production came from the GCEH petition, as well as EPA's literature review and our previous lifecycle GHG assessments for the RFS program. The values and calculations in our analysis are discussed briefly here and in more
Based on the information discussed in Section III-E below, we assume that after crushing, pre-treatment and transport, each tonne of dry jatropha seeds yields 0.26 tonnes of jatropha oil delivered to a biofuel production facility. (This figure is used to convert cultivation and harvesting GHG emissions from kgCO
We assumed that jatropha has a 20 year crop cycle, meaning that every 20 years the existing jatropha plants are removed and the crop is replanted.
Table III-4 provides a summary of the average GHG emissions attributable to growing and harvesting jatropha in southern Mexico and northeastern Brazil. Each of the emissions categories listed in the table are explained above in this section.
As explained in Section III-B, above, we believe that southern Mexico and northeastern Brazil are the most likely locations for commercial-scale production of jatropha for use in making biofuels for the RFS program. According to the GCEH petition, there are large areas of grasslands in southern Mexico that are suitable areas for jatropha production. These areas were used for crop production or pasture, but they are now fallow or used for very low intensity grazing. For example, Skutsch et al. evaluated jatropha land use change impacts in Yucatan, Mexico and found two plantations that had been planted on estates that had previously been used for low-intensity grazing.
Based on this information, the first scenario we evaluated for land use change emissions considers jatropha production on grasslands that would otherwise not be used for crops or pasture. In a second scenario, we used economic modeling to look at the potential land use change and agricultural sector emissions (including indirect emissions) of growing jatropha on land that would otherwise be used for crops or pasture.
For comparison, based on our analysis for the March 2010 RFS rule we estimate that grasslands in Mexico and Brazil contain approximately 4.1 and 10.9 tonnes of carbon per hectare, respectively. For our first scenario, we looked at the land use change and agricultural sector emissions associated with growing jatropha on grassland in Mexico and Brazil that would not otherwise be used for crop production or pasture. Comparing the carbon stocks
For our agricultural sector modeling of jatropha oil, we used a similar approach to the one we used for sugarcane in the March 2010 RFS rule, in which agricultural sector modeling was conducted using only the FAPRI-CARD model, and not the Forestry and Agricultural Sector Optimization Model (FASOM). For other feedstocks (
To date, jatropha has not achieved a significant presence in global agricultural markets. For example, EPA is not aware that it is traded on any agricultural exchange, and there does not appear to be any publicly available data on jatropha prices or trade flows. These limitations create significant difficulties when attempting to model jatropha in an agro-economic framework, such as the FAPRI-CARD model. The creation of robust assumptions for production costs at various levels of production (
For other crops that EPA has evaluated for the RFS program, we have used the FAPRI-CARD model to project international agricultural sector impacts by running different biofuel volume scenarios and allowing the model to decide where to grow the additional crops needed to produce the biofuel volumes. Because of the data limitations regarding jatropha, the FAPRI-CARD model is not able to decide where to grow jatropha or what other types of land uses to displace for its production. Therefore, to model the agricultural sector impacts of expanding jatropha production, we exogenously specified how much and what types of land it would displace in Mexico and Brazil. The FAPRI-CARD model then estimated how the crops and pasture displaced by jatropha would be made up elsewhere via crop switching, land conversion and other market-mediated effects.
First, similar to our modeling for other feedstocks, we used available information to project the amount of jatropha oil produced as biofuel feedstock for the RFS program in the year 2022. We developed two analyses for the production of 130 million gallons of biodiesel in 2022, one where all of the jatropha oil is produced in Mexico (the “Mexico only case”) and one where the jatropha oil production is split evenly between Mexico and Brazil (the “Mexico and Brazil case”). Although there is limited historical data available to use as the basis for formulating jatropha oil volume scenarios for modeling, we believe that a total production level of 130 million gallons of biodiesel in 2022 is sufficiently large to produce robust estimates of agricultural and GHG impacts in the FAPRI-CARD model, while still being feasible. As described elsewhere in this notice, we conservatively project that in 2022 Mexico and Brazil will have delivered jatropha oil yields of 1.3 and 1.0 tonnes per hectare per year, respectively.
To model the agricultural sector impacts of jatropha production in Mexico, we specified in the FAPRI-CARD model the area and types of crop land that jatropha would displace. Based on the information provided in the GCEH petition and collected through EPA's literature review, jatropha production in southern Mexico will most likely occur in the states of Yucatan, Chiapas and Oaxaca because they offer the most suitable climate conditions and available land. Over 80 percent of the agricultural land in this area is used for corn production, with smaller areas devoted to specialty crops such as fruits, vegetables, herbs and spices.
For Brazil we used a slightly different approach to take advantage of the fact that the FAPRI-CARD model for Brazil is significantly more detailed than the Mexico module. As explained above, based on EPA's literature review we determined that jatropha production in Brazil would predominantly occur in the northeastern part of the country, which correlates with the Northeast Coast and North-Northeast Cerrados regions in the FAPRI-CARD Brazil module. Unlike the Mexico part of the FAPRI-CARD model, the Brazil module includes crop and pasture land, and allows for switching between the two. Instead of specifying how much of each type of crop and pasture to displace with jatropha, we specified the area needed for jatropha production and allowed the FAPRI-CARD model to project the land used for jatropha production.
Table III-5 summarizes the land use changes projected in our modeling. We evaluated two cases: one involving jatropha production only in Mexico, and the other involving production in both Brazil and Mexico. In both cases, the land use impacts in Mexico are the replacement of other crops (primarily corn) with jatropha. In the Brazil and Mexico case, jatropha is planted on roughly three-quarters pasture and one-quarter crop land in Brazil. In both cases, the rest of the world (outside of Mexico and Brazil) increases its crop area. However, globally the total area devoted to non-jatropha crops and pasture decreases. Overall, the rest of the world expands their agricultural land (the sum of crop and pasture land including jatropha), meaning that other types of land, including unmanaged grassland and forest, are converted for agricultural uses.
Table III-6
Table III-7 summarizes the projected impacts on global meat production. In both of the cases, meat production declines. These changes are on the order of approximately 0.01%, or less, of projected global livestock production in 2022.
Overall, the projected agricultural sector impacts in 2022 of growing jatropha on agricultural land in Mexico and Brazil in the two cases we evaluated can be summarized as a reduction in crop and pasture land in Mexico and Brazil which triggers an increase in crop area in other countries. Just over half of the increase in crop area in other countries comes at the expense of pasture land, with the rest coming from other types of land, including unmanaged grassland and forest. Globally, corn production increases, while soybean, sugarcane and meat production declines. Detailed modeling results and further explanation are provided in the docket for this notice,
To estimate the GHG emissions associated with the land use changes summarized in Table III-5, EPA used the same methodology as developed for the March 2010 RFS rule. Per this methodology, the crop and pasture area changes in 2022 derived from the FAPRI-CARD model were evaluated with Moderate Resolution Imaging Spectroradiometer (MODIS) satellite data to project what types of land (
The land use change GHG emissions are summarized in Table III-8, including results for both the Mexico only and Mexico and Brazil cases. The results are broken out regionally by Mexico, Brazil, and Rest of World, because as discussed above, the great majority of land use change impacts came from Mexico and Brazil. Table III-8 also includes the total emissions for the low and high ends of the 95% confidence range for land use change GHG emissions, based on the land use change uncertainty analysis methodology developed for the March 2010 RFS rule, which considers the uncertainty in the satellite data and land use change emissions factors used in our assessment.
In both cases, the mean values suggest negative land use change emissions (net sequestration) associated with growing jatropha on agricultural land. This is due primarily to the net sequestration that we project from replacing corn fields with jatropha plantations in Mexico. Per our analysis for the March 2010 RFS rule, corn in Mexico has average biomass carbon stocks of five tonnes per hectare.
In both cases, we project positive land use change emissions in Brazil and other countries. We project land use change emissions in Brazil for a number of reasons. In the Mexico only case, Brazil expands its crop production to backfill for some of the lost production in Mexico. Some of this crop expansion occurs on pasture, which results in net land use change emissions from both biomass and soil carbon, and some of the crop expansion occurs on other types of land, including forests. In particular, the FAPRI-CARD model projects crop and pasture expansion in the Amazon, an area with particularly high carbon stocks, resulting in large emissions per hectare of conversion. In the Brazil and Mexico case, the expansion of jatropha onto corn or soybean land results in a net sequestration, but this net sequestration is smaller than the emissions associated with replacing sugarcane and pasture with jatropha.
In both cases, we also project land use change emissions from the rest of the world (all regions other than Mexico and Brazil). In our modeling the main impact in other countries is increased crop production to respond to higher prices and to backfill for some of the lost production from Mexico and Brazil. The additional cropland replaces some pasture and some other types of land, including unmanaged grasslands and forests, which results in net land use change emissions.
For this second scenario, our analysis also considers indirect emissions associated with changes in fertilizer, pesticide and energy use for crop production, and methane and nitrous oxide emissions associated with changes in crop production. The sources of indirect livestock emissions include emissions from energy use for livestock production, and methane and nitrous oxide emissions associated with raising cattle, dairy cows, swine and poultry. The emissions for indirect crop production were estimated based on international crop input data and emission factors developed and peer reviewed for the March 2010 RFS rule. The livestock emissions factors are from the IPCC.
In the first main scenario we evaluated, where jatropha production occurs on grassland that is not otherwise used for crop production or grazing, there are no indirect emissions associated with changes in fertilizer, pesticide and energy use for crop production, and methane and nitrous oxide emissions associated with changes in crop production. In the second scenario, where jatropha is grown on agricultural land, there are indirect emissions associated with how the agricultural sector responds to the displacement of crop and grazing land for jatropha. Table III-9 summarizes the indirect crop production and livestock emissions impacts for both of the cases we evaluated for scenario two. Indirect agricultural emissions are negative in both cases, primarily because of emission reductions from decreased corn production in Mexico. Indirect livestock emissions are negative, because as shown in Table III-7, we project reductions in meat production in the cases evaluated.
Table III-10 summarizes the land use change, and agricultural sector emissions in the two main scenarios that we evaluated. Note that this table does not include the emissions associated with cultivation and harvesting discussed above in Section III-C.
Producing fuels from jatropha requires oil to be first extracted from its seeds, and then refined into a finished fuel product. Oil can either be expelled from the seeds by mechanical treatment or extracted using chemical solvents. There are two commonly used types of mechanical expellers, the screw press and the ram press. The screw press is typically used, and is somewhat more efficient at expelling oil (75-80% yield) than the ram press (60-65% yield). Up to three passes is common to achieve these yields. Certain pretreatments of jatropha seeds, such as cooking, can increase the expelled oil yield to 89% after a single pass using a screw press and 91% after a second pass. Chemical extraction can achieve greater oil yields than mechanical expulsion. (The most commonly used chemical extraction method, the n-hexane method, can achieve yields of 99%). However, chemical extraction is capital intensive and only economical at very large scales of production. According to Bailis and Baka, all jatropha oil produced in Brazil is extracted by screw press at one facility. Based on our review of available literature, EPA's evaluation considered oil recovery from jatropha seeds to occur via screw press mechanical expulsion assuming oil yield of 75% and seed oil content of 35%.
Our evaluation also considers emissions associated with pretreating the jatropha oil.
For our GHG analysis, we assumed that jatropha is produced, and the jatropha oil is extracted and pre-treated in Mexico and Brazil, and that the pre-treated oil is then transported to the United States for use as biofuel feedstock. First, we calculate the emissions associated with transporting the jatropha seed 20 miles by truck to a facility where the crude jatropha is extracted via screw press and then pre-treated. The truck is loaded with kernel shells and seedcake and returns 20 miles to the plantation. The pre-treated jatropha oil is transported 75 miles by truck to a port and then shipped 500 miles by barge to a port in the U.S. Gulf of Mexico. For this scenario we estimate the seed transport emissions to be 24 kgCO
Jatropha is not currently widespread in the United States, and is not listed on the federal noxious weed list.
The results of our analysis of the GHG emissions associated with jatropha oil production and transport are summarized in Table III-11. The table summarizes the results for the two main scenarios that we evaluated: the first scenario where jatropha is grown on unused grassland in Mexico and Brazil and a second scenario where it is grown on agricultural land. For the second scenario, results are summarized for two cases: the first with jatropha production on agricultural land in Mexico, and the second with jatropha production on agricultural land in Mexico and Brazil. For comparison, Table III-11 also includes a summary of soybean oil production and transport GHG emissions as estimated for the March 2010 RFS rule. (Some emissions categories for the soybean results have been combined to align as much as possible with the jatropha results.) The results summarized in Table III-11 show that based on the scenarios we evaluated, the GHG emissions associated with producing and transporting jatropha oil as a biofuel feedstock are less than similar emissions for soybean oil. When evaluating petitions to use jatropha oil as biofuel feedstock we would also consider GHG emissions from fuel production and fuel distribution, in addition to the emissions summarized in Table III-11 (adjusted as appropriate for petitioners' individual circumstances).
The agency also conducted an uncertainty analysis and estimated the 95 percent confidence range for each of the scenarios evaluated. For this evaluation, we used the same methodology and spreadsheet model used for the March 2010 RFS rule. For the unused grassland scenarios we considered the uncertainty in the emissions factors used in our analysis. For the agricultural land scenarios, we considered the uncertainty in both the range of potential values for the satellite data and land use change emissions factors used in our modeling. The low and high ends of the 95 percent confidence range are presented below in Table III-11, with results from the jatropha scenarios displayed along with the results from our soybean oil modeling for the March 2010 RFS rule. The range is narrowest for the unused grassland-only scenario because it does not incur uncertainty associated with using satellite data to project land use change patterns. Comparing the uncertainty estimates for the scenario with jatropha oil produced on agricultural land and the estimates for the soybean oil results, the confidence range is narrower for the soybean results because a greater proportion of the land use change impacts for soybeans are in regions and impact types of land where EPA has better quality data. We invite comment on our analysis and the results presented below.
Based on the results summarized in Table III-11, we believe it is reasonable, as a conservative approach (and subject to confirmation upon review of individual petition submissions), to apply the GHG emissions estimates we established in the March 2010 rule for the production and transport of soybean oil to jatropha oil when evaluating future facility-specific petitions from biofuel producers seeking to generate RINs for volumes of biofuel produced from jatropha oil. While it is possible that jatropha could be grown on other types of land, such as shrubland or secondary forest, that would result in higher GHG emissions than the scenarios we evaluated, the RFS program's qualification requirements for renewable biomass would prevent the use of jatropha grown on such lands from use as an RFS renewable fuel feedstock. The renewable biomass definition would not prevent a scenario where jatropha is planted on agricultural land, and the displaced crops or pasturage is then shifted to shrubland or forestland. However, as discussed above, our modeling suggests that this scenario is not expected. Therefore, we believe it is reasonable to conclude that the overall emissions attributable to the production and transportation of jatropha oil used to produce biofuels for the RFS program will be equal to or less than the same types of emissions attributable to soybean oil. We welcome public comments on all aspects of our assessment.
Jatropha oil is suitable for the same conversion processes as soybean oil and other previously approved feedstocks for making biodiesel, renewable diesel, jet fuel, naphtha and liquefied petroleum gas. In addition, the fuel yield per pound of oil is expected to be similar for fuel produced from jatropha oil and soybean oil through these processes. Jatropha may also be suitable for other conversion processes and types of fuel that EPA has not previously evaluated. After reviewing comments received in response to this action, we will combine our evaluation of agricultural sector GHG emissions associated with the use of jatropha oil feedstock with our evaluation of the GHG emissions associated with individual producers' production processes and finished fuels to determine whether any proposed pathway satisfies CAA lifecycle GHG emissions reduction requirements for RFS-qualifying renewable fuels. Each biofuel producer seeking to generate RINs for non-grandfathered volumes of biofuel produced from jatropha oil will first need to submit a petition requesting EPA's evaluation of their new renewable fuel pathway pursuant to 40 CFR 80.1416 of the RFS regulations, and include all of the information specified at 40 CFR 80.1416(b)(1). Because EPA is evaluating the greenhouse gas emissions associated with the production and transport of jatropha oil feedstock through this action and comment process, petitions requesting EPA's evaluation of biofuel pathways involving jatropha oil feedstock will not have to include the information for new feedstocks specified at 40 CFR 80.1416(b)(2).
EPA invites public comment on its analysis of GHG emissions associated with the production and transport of jatropha oil as a feedstock for biofuel production. EPA will consider public comments received when evaluating the lifecycle GHG emissions of biofuel production pathways described in
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency is planning to submit an information collection request (ICR), “Information collection request for reporting requirements for BEACH act grants (renewal)” (EPA ICR No. 2048.05, OMB Control No. 2040-0244) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Comments must be submitted on or before December 14, 2015.
Submit your comments, referencing Docket ID No. EPA-HQ 20415-0614 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.
Tracy Bone, OW, 4305T, Environmental Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: 202-564-5257; 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
Pursuant to section 3506(c)(2)(A) of the PRA, EPA is soliciting comments and information to enable it to: (i) 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; (ii) 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; (iii) enhance the quality, utility, and clarity of the information to be collected; and (iv) 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,
Export-Import Bank of the U.S.
Submission for OMB review and comments request.
The Export-Import Bank of the United States (EXIM Bank), as a part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal Agencies to comment on the proposed information collection, as required by the Paperwork Reduction Act of 1995.
EXIM Bank's financial institution policy holders provide this form to U.S. exporters, who certify to the eligibility of their exports for EXIM Bank support. The completed forms are held by the financial institution policy holders, only to be submitted to EXIM Bank in the event of a claim filing. A requirement of EXIM Bank's policies is that the insured financial institution policy holder obtains a completed Exporter's Certificate at the time it provides financing for an export. This form will enable EXIM Bank to identify the specific details of the export transaction. These details are necessary for determining the eligibility of claims for approval. EXIM Bank staff and contractors review this information to assist in determining that an export transaction, on which a claim for non-payment has been submitted, meets all of the terms and conditions of the insurance coverage.
The form can be viewed at
Comments must be received on or before November 12, 2015 to be assured of consideration.
Comments may be submitted electronically on
Government Expenses:
Export-Import Bank of the United States
Submission for OMB review and comments request.
Form Title: EIB 11-05 Exporter's Certificate for Loan Guarantee & MT Insurance Programs.
The Export-Import Bank of the United States (Ex-Im Bank), as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal Agencies to comment on the proposed information collection, as required by the Paperwork Reduction Act of 1995.
Ex-Im Bank's borrowers, financial institution policy holders and guaranteed lenders provide this form to U.S. exporters, who certify to the eligibility of their exports for Ex-Im Bank support. For direct loans and loan guarantees, the completed form is required to be submitted at time of disbursement and held by either the guaranteed lender or Ex-Im Bank. For MT insurance, the completed forms are held by the financial institution, only to be submitted to Ex-Im Bank in the event of a claim filing.
Ex-Im Bank uses the referenced form to obtain exporter certifications regarding the export transaction, content sourcing, and their eligibility to participate in USG programs. These details are necessary to determine the value and legitimacy of Ex-Im Bank financing support and claims submitted. It also provides the financial institutions a check on the export transaction's eligibility at the time it is fulfilling a financing request.
The information collection tool can be reviewed at:
Comments must be received on or before November 12, 2015 to be assured of consideration.
Comments may be submitted electronically on
(time*wages)
Federal Communications Commission.
Notice and request for comments.
As part of its continuing effort to reduce paperwork burdens, and as required by the Paperwork Reduction Act (PRA) of 1995 (44 U.S.C. 3501-3520), the Federal Communications Commission (FCC or Commission) invites the general public and other Federal agencies to take this opportunity to comment on the following information collections. Comments are requested concerning: Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; the accuracy of the Commission's burden estimate; ways to enhance the quality, utility, and clarity of the information collected; ways to minimize the burden of the collection of information on the respondents, including the use of automated collection techniques or other forms of information technology; and ways to further reduce the information collection burden on small business concerns with fewer than 25 employees.
The FCC may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number.
No person shall be subject to any penalty for failing to comply with a collection of information subject to the PRA that does not display a valid OMB control number.
Written PRA comments should be submitted on or before December 14, 2015. If you anticipate that you will be submitting comments, but find it difficult to do so within the period of time allowed by this notice, you should advise the contact listed below as soon as possible.
Direct all PRA comments to Nicole Ongele, FCC, via email
For additional information about the information collection, contact Nicole Ongele at (202) 418-2991.
Part 63 of Title 47 of the Code of Federal Regulations (CFR) implements Section 214. Part 63 also implements provisions of the Cable Communications Policy Act of 1984 pertaining to video which was approved under this OMB Control Number 3060-0149. In 2009, the Commission modified Part 63 to extend to providers of interconnected Voice of Internet Protocol (VoIP) service the discontinuance obligations that apply to domestic non-dominant telecommunications carriers under Section 214 of the Communications Act of 1934, as amended.
In 2014, the Commission adopted improved administrative filing procedures for domestic transfers of control, domestic discontinuances and notices of network changes, and among other adjustments, modified Part 63 to require electronic filing for applications for authorization to discontinue, reduce, or impair service under section 214(a) of the Act.
Federal Communications Commission.
Notice.
The Commission announces the next meeting date, time, and agenda of its Consumer Advisory Committee (hereinafter the “Committee”). The mission of the Committee is to make recommendations to the Commission regarding consumer issues within the jurisdiction of the Commission and to facilitate the participation of consumers (including underserved populations, such as Native Americans, persons living in rural areas, older persons, people with disabilities, and persons for whom English is not their primary language) in proceedings before the Commission.
October 26, 2015, 2:00 p.m. to 4:00 p.m.
Federal Communications Commission, 445 12th Street SW., Room 4-B516, Washington, DC 20554.
Scott Marshall, Consumer and Governmental Affairs Bureau, (202) 418-2809 (voice or Relay), or email
This is a summary of the Commission's document DA 15-1123, released October 6, 2015, announcing the Agenda, Date, and Time of the Committee's Next Meeting.
At its October 26, 2015 meeting, the Committee will consider a recommendation from its Open Internet Order Consumer Disclosure Task Force regarding a proposed Open Internet enhanced transparency rule disclosure format as required by the Open Internet Order (Protecting and
The meeting is open to the public, and the site is fully accessible to people using wheelchairs or other mobility aids. Reasonable accommodations for people with disabilities, such as sign language interpreters, open captioning, assistive listening devices, and Braille copies of the agenda are available upon request. The request should include a detailed description of the accommodation needed and contact information. Please provide as much advance notice as possible; last minute requests will be accepted, but may not be possible to fill. To request an accommodation, send an email to
Federal Communications Commission.
The Federal Deposit Insurance Corporation (FDIC), as Receiver for 10404, Piedmont Community Bank, Gray, Georgia (Receiver) has been authorized to take all actions necessary to terminate the receivership estate of Piedmont Community Bank (Receivership Estate); The Receiver has made all dividend distributions required by law.
The Receiver has further irrevocably authorized and appointed FDIC-Corporate as its attorney-in-fact to execute and file any and all documents that may be required to be executed by the Receiver which FDIC-Corporate, in its sole discretion, deems necessary; including but not limited to releases, discharges, satisfactions, endorsements, assignments and deeds.
Effective October 1, 2015 the Receivership Estate has been terminated, the Receiver discharged, and the Receivership Estate has ceased to exist as a legal entity.
Federal Deposit Insurance Corporation
Update Listing of Financial Institutions in Liquidation
Notice is hereby given that the Federal Deposit Insurance Corporation (Corporation) has been appointed the sole receiver for the following financial institutions effective as of the Date Closed as indicated in the listing. This list (as updated from time to time in the
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 October 27, 2015.
A. Federal Reserve Bank of Kansas City (Dennis Denney, Assistant Vice President) 1 Memorial Drive, Kansas City, Missouri 64198-0001:
1.
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 must be received at the Reserve Bank indicated or the offices of the Board of Governors not later than November 6, 2015.
A. Federal Reserve Bank of Minneapolis (Jacquelyn K. Brunmeier, Assistant Vice President) 90 Hennepin Avenue, Minneapolis, Minnesota 55480-0291:
1.
Agency for Toxic Substances and Disease Registry (ATSDR) 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 the proposed information collection is published to obtain comments from the public and affected agencies.
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
Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery (OMB No. 0923-0047, exp. 05/31/2016)—Revision—Agency for Toxic Substances and Disease Registry (ATSDR).
As part of a Federal Government-wide effort to streamline the process to seek feedback from the public on service delivery, the ATSDR has submitted a Generic Information Collection Request (Generic ICR): “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery ” to OMB for approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501 et. seq.).
To request additional information, please contact Leroy A. Richardson, Centers for Disease Control and Prevention, 1600 Clifton Road, MS-D74, Atlanta, GA 30333 or send an email to
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: the target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-
The Agency received no comments in response to the 60-day notice published in the
Respondents will be screened and selected from Individuals and Households, Businesses, Organizations, and/or State, Local or Tribal Government. There is no cost to respondents other than their time. ATSDR is requesting an increase in the annual burden hours from 2,425 to 7,075 and an increase in the annual number of respondents from 2,800 to 8,300. These estimates of burden hours and respondents are based on an anticipated increase in the number of the Agency's generic information collections (GenICs) each year over the next three years. The estimated annualized burden hours for this data collection activity are 7,075.
Part J (Agency for Toxic Substances and Disease Registry) of the Statement of Organization, Functions, and Delegations of Authority of the Department of Health and Human Services (50 FR 25129-25130, dated June 17, 1985, as amended most recently at 77 FR 68125-68127, dated November 12, 2012) is amended to reflect the Order of Succession for the Agency for Toxic Substances and Disease Registry.
Section J-C, Order of Succession:
Delete in its entirety the Section C-C, Order of Succession, and insert the following:
During the absence or disability of the Administrator, Agency for Toxic Substances and Disease Registry (ATSDR), or in the event of a vacancy in that office, the first official listed below who is available shall act as Administrator, except during a planned period of absence, the Administrator may specify a different order of succession:
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Cancellation of notice with comment period
The notice “Proposed Data Collection Submitted for Public Comment and Recommendations” on Personal Protective Equipment Information (PPE-Info) Database (80 FR 60906, October 8, 2015) is cancelled. This noticed invited comment on the Personal Protective Equipment Information (PPE-Info) Database which is a compendium of personal protective equipment (PPE) Federal regulations and consensus standards. This proposed data collection will be resubmitted at a later date for public comment once the review to include one additional standard is completed on the data collection instrument.
(404) 639-7570 or send comments to CDC, Leroy Richardson, 1600 Clifton Road, MS D-74, Atlanta, GA 30333 or send an email to
National Institute for Occupational Safety and Health (NIOSH) of the Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Notice of issuance of final guidance publications.
The National Institute for Occupational Safety and Health (NIOSH) of the Centers for Disease Control and Prevention (CDC), announces the availability of the following 15
These documents may be obtained at the following link:
Naomi Hudson, NIOSH, Robert A. Taft Laboratories, 1090 Tusculum Avenue, MS C-32, Cincinnati, OH 45226. (513) 533-8388 (
Copies of the proposed collection may be obtained by writing to the Administration for Children and Families, Office of Planning, Research and Evaluation, 370 L'Enfant Promenade SW., Washington, DC 20447, Attn: ACF Reports Clearance Officer. All requests should be identified by the title of the information collection. Email address:
OMB is required to make a decision concerning the collection of information between 30 and 60 days after publication of this document in the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is withdrawing approval of 67 new drug applications (NDAs) and 128 abbreviated new drug applications (ANDAs) from multiple applicants. The holders of the applications notified the Agency in writing that the drug products were no longer marketed and requested that the approval of the applications be withdrawn.
Florine P. Purdie, Center for Drug Evaluation and Research, Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm. 6248, Silver Spring, MD 20993-0002, 301-796-3601.
The holders of the applications listed in table 1 in this document have informed FDA that these drug products are no longer marketed and have requested that FDA withdraw approval of the applications under the process in § 314.150(c) (21 CFR 314.150(c)). The applicants have also, by their requests, waived their opportunity for a hearing. Withdrawal of approval of an application or abbreviated application under § 314.150(c) is without prejudice to refiling.
Therefore, under section 505(e) of the Federal Food, Drug, and Cosmetic Act (21 U.S.C. 355(e)) and under authority delegated to the Director of Food and Drugs, Center for Drug Evaluation and Research, by the Commissioner, approval of the applications listed in table 1 in this document, and all amendments and supplements thereto, is hereby withdrawn, effective November 12, 2015. Introduction or delivery for introduction into interstate commerce of products without approved new drug applications violates section 301(a) and (d) of the Act (21 U.S.C. 331(a) and (d)). Drug products that are listed in table 1 that are in inventory on the date that this notice becomes effective (see the
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA or we) is announcing an opportunity for public comment on our proposed collection of certain information. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies must publish a notice in the
Submit either electronic or written comments on the collection of information by December 14, 2015.
You may submit comments as follows:
Submit electronic comments in the following way:
•
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).
Submit written/paper submissions as follows:
•
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked, and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION”. The Agency will review this copy, including the claimed confidential information, in its consideration of comments. The second copy, which will have the claimed confidential information redacted/blacked out, will be available for public viewing and posted on
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
Under the PRA (44 U.S.C. 3501-3521), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, we invite comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of our functions, including whether the information will have practical utility; (2) the accuracy of our estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
The draft guidance, entitled “Draft Guidance for Industry: Cosmetic Good Manufacturing Practices,” (available at
Section 301 of the Federal Food, Drug, and Cosmetic Act (the FD&C Act) (21 U.S.C. 331) prohibits the introduction, or delivery for introduction, into interstate commerce of cosmetics that are adulterated or misbranded. Manufacturers of cosmetics can reduce the risk of adulterating or misbranding cosmetics by following the GMP recommendations in the draft guidance.
The draft guidance recommends that manufacturers of cosmetics prepare written procedures and maintain records pertaining to: (1) Buildings and facilities; (2) equipment; (3) personnel; (4) raw materials; (5) production; (6) laboratory controls; (7) internal audits; and, (8) complaints, adverse events, and recalls.
We expect that manufacturers of cosmetics that choose to follow the recommendations of this Cosmetic GMP draft guidance would maintain records of their written procedures as well as their test methods or other appropriate verification procedures. It is also possible that manufacturers would obtain and maintain records of Certificates of Analysis, test results, or other appropriate verification procedures from their suppliers.
GMP is concerned with both manufacturing and quality control procedures. Manufacturers of cosmetics will use their written procedures and records as that part of quality assurance aimed at ensuring that products are consistently manufactured to a quality appropriate to their intended use. Records would be compiled and retained at each manufacturing facility.
Our draft guidance remains unchanged by this notice. We are publishing this notice in compliance with the PRA. This notice does not represent any new regulatory initiative.
We estimate the burden of this collection of information as follows:
In table 1 we list the one-time burdens associated with establishing written procedures. In table 2 we list the annual burdens associated with recordkeeping. We base our estimates of the number of recordkeepers reported in column 2 of tables 1 and 2 on data available to us, our knowledge of and experience with the cosmetics industry, and our communications with industry, as well as our estimate of the number of recordkeepers subject to cosmetic labeling regulations, published in the
We base our estimates of the number of records per recordkeeper and the average burden per recordkeeping reported in columns 3 and 5 of tables 1 and 2 on our experience with good manufacturing practices used to control the identity and composition of food and dietary supplements and to limit contaminants and prevent adulteration, as well as our estimate of the burden of similar recordkeeping activities described in the dietary supplement final rule published in the
The estimates for the recordkeeping burdens presented here are averages. We anticipate that the time spent to develop written procedures and recordkeeping would vary based on the type of cosmetic product manufactured. The estimated burdens for developing recordkeeping includes record maintenance, periodically reviewing records to determine if they may be discarded, and any associated documentation for that activity.
This draft guidance also refers to previously approved collections of information found in our regulations. These collections of information are subject to review by the Office of Management and Budget (OMB) under the PRA (44 U.S.C. 3501-3521). The collections of information in our recall regulations in 21 CFR part 7 have been approved under OMB control number 0910-0249. The collection of information in 21 CFR 70.25, which requires that color additives subject to certification be labeled with the lot number assigned by the Color Certification Branch, has been approved under OMB control number 0910-0016.
Food and Drug Administration, HHS.
Notice.
The Food and Drug Administration (FDA) is announcing an opportunity for public comment on the proposed collection of certain information by the Agency. Under the Paperwork Reduction Act of 1995 (the PRA), Federal Agencies are required to publish notice in the
Submit either electronic or written comments on the collection of information by December 14, 2015.
You may submit comments as follows:
Submit electronic comments in the following way:
•
• If you want to submit a comment with confidential information that you do not wish to be made available to the public, submit the comment as a written/paper submission and in the manner detailed (see “Written/Paper Submissions” and “Instructions”).
Submit written/paper submissions as follows:
•
• For written/paper comments submitted to the Division of Dockets Management, FDA will post your comment, as well as any attachments, except for information submitted, marked and identified, as confidential, if submitted as detailed in “Instructions.”
• Confidential Submissions—To submit a comment with confidential information that you do not wish to be made publicly available, submit your comments only as a written/paper submission. You should submit two copies total. One copy will include the information you claim to be confidential with a heading or cover note that states “THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION”. The Agency will review this copy, including
FDA PRA Staff, Office of Operations, Food and Drug Administration, 8455 Colesville Rd., COLE-14526, Silver Spring, MD 20993-0002,
Under the PRA (44 U.S.C. 3501-3520), Federal Agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. “Collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes Agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. Section 3506(c)(2)(A) of the PRA (44 U.S.C. 3506(c)(2)(A)) requires Federal Agencies to provide a 60-day notice in the
With respect to the following collection of information, FDA invites comments on these topics: (1) Whether the proposed collection of information is necessary for the proper performance of FDA's functions, including whether the information will have practical utility; (2) the accuracy of FDA's estimate of the burden of the proposed collection of information, including the validity of the methodology and assumptions used; (3) ways to enhance the quality, utility, and clarity of the information to be collected; and (4) ways to minimize the burden of the collection of information on respondents, including through the use of automated collection techniques, when appropriate, and other forms of information technology.
Section 1701(a)(4) of the Public Health Service Act (42 U.S.C. 300u(a)(4)) authorizes the FDA to conduct research relating to health information. Section 1003(d)(2)(C) of the Federal Food, Drug, and Cosmetic Act (the FD&C Act) (21 U.S.C. 393(b)(2)(c)) authorizes FDA to conduct research relating to drugs and other FDA regulated products in carrying out the provisions of the FD&C Act.
A previous FDA study found that simple quantitative information could be conveyed in direct-to-consumer (DTC) television ads in ways that increased consumer's knowledge about the drug (OMB control number 0910-0663, “Experimental Study: Presentation of Quantitative Effectiveness Information to Consumers in Direct-to-Consumer (DTC) Television and Print Advertisements for Prescription Drugs”).
The objective of this project is to test consumers' understanding of quantitative information about prescription drugs in DTC television ads. In study 1, we plan to examine experimentally the presence and complexity of quantitative benefit and risk information in DTC television ads (table 1). We hypothesize that, replicating past studies, adding simple quantitative information about benefits and risks will lead to increased understanding among consumers. We will test whether adding complex quantitative information results in the same outcomes as simple quantitative information or whether it is too much quantitative information for consumers to process. In study 2, we plan to examine experimentally the presence of quantitative benefit information and how the ad visually represents efficacy (by having no images, images that accurately reflect the improvement in health that could be expected with treatment, or images that overstate the improvement in health that could be expected with treatment (table 2). We hypothesize that overstated images of improvement will lead consumers to overestimate the drug's efficacy; however, adding a quantitative claim may moderate this effect. To test these hypotheses, we will conduct inferential statistical tests such as analysis of variance (ANOVA). With the sample sizes described below, we will have sufficient power to detect small- to medium-sized effects in each study.
All participants will be 60 years of age or older. We will exclude individuals who work in healthcare or marketing. We selected a sample of participants 60 years and older to increase the likelihood that participants will be interested in the fictitious study drug and therefore motivated to pay attention to the ad during the study. The studies will be conducted with an Internet panel.
In both studies, participants will be randomly assigned to one experimental condition and view the corresponding television ad. The ad will be for a fictitious drug to treat cataracts. The ads will be created and pretested to ensure that consumers perceive different levels of complexity across the ads in study 1, and different levels of image accuracy in study 2. “Pretests for a Study on Quantitative Information in Direct-to-Consumer Television Advertisements” will be submitted under OMB control number 0910-0695. After viewing the ad twice, participants will complete a questionnaire that assesses consumers' understanding of the drug information, their retention of the information, and their perceptions of the drug. We will also measure covariates such as demographics and numeracy. The
FDA estimates the burden of this collection of information as follows:
In accordance with section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463), notice is hereby given of the following meeting:
Further information regarding the NACNHSC including the roster of members and past meetings summaries is available at the following Web site:
In addition, please be advised that committee members are given copies of all written statements submitted from the public. Any further public participation will be solely at the discretion of the Chair, with approval of the DFO. Registration through the designated contact for the public comment session is required.
• The conference call-in number is 1-800-619-2521. The passcode is 9271697.
• The webinar link is
Anyone requesting information regarding the NACNHSC should contact CAPT Shari Campbell, Designated Federal Official, Bureau of Health Workforce, Health Resources and Services Administration, in one of three ways: (1) Send a request to the following address: CAPT Shari Campbell, Designated Federal Official, Bureau of Health Workforce, Health Resources and Services Administration, Room 8C-26, 5600 Fishers Lane, Rockville, Maryland 20857; (2) call (301) 594-4251; or (3) send an email to
Office of the Secretary, Department of Health and Human Services.
Notice.
As stipulated by the Federal Advisory Committee Act, the Department of Health and Human Services (HHS) is hereby giving notice that the National Advisory Committee on Children and Disasters (NACCD) will be holding a meeting via teleconference. The meeting is open to the public.
The November 13, 2015, NACCD meeting is scheduled from 3:00 p.m. to 4:00 p.m. EST. The agenda is subject to change as priorities dictate. Please check the NACCD Web site, located at
To attend the meeting via teleconference, call toll-free: 1-888-989-6485, international dial-in: 1-312-470-0178. The pass-code is: 5885575. Please call 15 minutes prior to the beginning of the conference call to facilitate attendance. Pre-registration is required for public attendance. Individuals who wish to attend the meeting should submit an inquiry via the NACCD Contact Form located at
Please submit an inquiry via the NACCD Contact Form located at
Pursuant to the Federal Advisory Committee Act (FACA) of 1972 (5 U.S.C., Appendix, as amended), and section 2811A of the Public Health Service (PHS) Act (42 U.S.C. 300hh-10a), as added by section 103 of the Pandemic and All Hazards Preparedness Reauthorization Act of 2013 (Pub. L. 113-5), the HHS Secretary, in consultation with the Secretary of the U.S. Department of Homeland Security, established the NACCD. The purpose of the NACCD is to provide advice and consultation to the HHS Secretary with respect to the medical and public health needs of children in relation to disasters. The Office of the Assistant Secretary for Preparedness and Response provides management and administrative oversight to support the activities of the NACCD.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is
The meetings will be closed to the public as indicated below in accordance with the provisions set forth in section 552b(c)(6), Title 5 U.S.C., as amended for the review, discussion, and evaluation of individual intramural programs and projects conducted by the National Cancer Institute, including consideration of personnel qualifications and performance, and the competence of individual investigators, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
This notice is being published less than 15 days prior to the meeting due to the timing limitations imposed by the review and funding cycle.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
National Institute of Environmental Health Sciences Special Emphasis Panel; Environmental Health Science Cores.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meetings.
This meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Under the provisions of section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the National Institute of Mental Health (NIMH), National Institutes of Health (NIH), has submitted to the Office of Management and Budget (OMB) a request for review and approval of the information collection listed below. This proposed information collection was previously published in the
To obtain a copy of the data collection plans and instruments or request more information on the proposed project contact: NIMH Project Clearance Liaison, Science Policy and Evaluation Branch, OSPPC, NIMH, NIH, Neuroscience Center, 6001 Executive Boulevard, MSC 9667, Rockville Pike, Bethesda, MD 20892, or call 301-443-4335, or Email your request, including your address to:
National Institute of Mental Health (NIMH) Recruitment Milestone Reporting System (OMB control number 0925-0697)—REVISION—National Institute of Mental Health (NIMH), National Institute of Health (NIH).
The Recruitment Milestone Reporting (RMR) System allows NIMH staff to monitor more effectively the
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total estimated annualized burden hours are 2,295.
Under the provisions of Section 3507(a)(1)(D) of the Paperwork Reduction Act of 1995, the National Institutes of Health (NIH) has submitted to the Office of Management and Budget (OMB) a request to review and approve the information collection listed below. This proposed information collection was previously published in the
To obtain a copy of the data collection plans and instruments or request more information on the proposed project contact: Steve W. Gust, Ph.D., Director, NIDA International Program, NIDA, NIH, 6001 Executive Blvd., Bethesda, Maryland 20892-0234; or call non-toll-free number (301) 443-6480; or Email: your request, including your address to:
OMB approval is requested for 3 years. There are no costs to respondents other than their time. The total annual estimated burden hours are 83.
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, HUD.
Notice.
This notice establishes operating cost adjustment factors (OCAFs) for project based assistance contracts for eligible multifamily housing projects having an anniversary date on or after February 11, 2016. OCAFs are annual factors used to adjust Section 8 rents in Housing Assistance Payments contracts renewed under section 515 and section 524 of the Multifamily Assisted Housing Reform and Affordability Act of 1997 (MAHRA).
Stan Houle, Program Analyst, Office of Asset Management and Portfolio Oversight, Office of Housing, Department of Housing and Urban Development, 451 7th Street SW., Washington, DC 20410; telephone number 202-402-2572 (this is not a toll-free number). Hearing- or speech-impaired individuals may access this number through TTY by calling the toll-free Federal Relay Service at 800-877-8339.
Section 514(e)(2) of MAHRA (42 U.S.C. 1437f note) requires HUD to establish guidelines for rent adjustments based on an OCAF. The statute requiring HUD to establish OCAFs for Low-Income Housing Preservation and Resident Homeownership Act (LIHPRHA) (12 U.S.C. 4101,
LIHPRHA projects are low-income housing projects insured by the Federal Housing Administration (FHA). LIHPRHA projects are primarily low-income housing projects insured under section 221(d)(3) below-market interest rate (BMIR) and section 236 of the National Housing Act, respectively. Both categories of projects have low-income use restrictions that have been extended beyond the 20-year period specified in the original documents, and both categories of projects also receive assistance under section 8 of the U.S. Housing Act of 1937 to support the continued low-income use.
MAHRA gives HUD broad discretion in setting OCAFs, referring, for example, in sections 524(a)(4)(C)(i), 524(b)(1)(A), 524(b)(3)(A) and 524(c)(1) simply to “an operating cost adjustment factor established by the Secretary.” The sole limitation to this grant of authority is a specific requirement in each of the foregoing provisions that application of an OCAF “shall not result in a negative adjustment.” Contract rents are adjusted by applying the OCAF to that portion of the rent attributable to operating expenses exclusive of debt service.
The OCAFs provided in this notice and applicable to eligible projects having a project based assistance contracts anniversary date of on or after February 11, 2016, are calculated using the same method as those published in HUD's 2015 OCAF notice published on October 2, 2014 (79 FR 59502). Specifically, OCAFs are calculated as the sum of weighted average cost changes for wages, employee benefits, property taxes, insurance, supplies and equipment, fuel oil, electricity, natural gas, and water/sewer/trash using publicly available indices. The weights used in the OCAF calculations for each of the nine cost component groupings are set using current percentages attributable to each of the nine expense categories. These weights are calculated in the same manner as in the October 2, 2014, notice. Average expense proportions were calculated using three years of audited Annual Financial Statements from projects covered by OCAFs. The expenditure percentages for these nine categories have been found to be very stable over time, but using three years of data increases their stability. The nine cost component weights were calculated at the state level, which is the lowest level of geographical aggregation with enough projects to permit statistical analysis. These data were not available for the Western Pacific Islands, so data for Hawaii were used as the best available indicator of OCAFs for these areas.
The best current price data sources for the nine cost categories were used in calculating annual change factors. State-level data for fuel oil, electricity, and natural gas from Department of Energy surveys are relatively current and continue to be used. Data on changes in employee benefits, insurance, property taxes, and water/sewer/trash costs are only available at the national level. The data sources for the nine cost indicators selected used were as follows:
•
•
•
•
•
•
•
•
The sum of the nine cost component percentage weights equals 100 percent of operating costs for purposes of OCAF calculations. To calculate the OCAFs, state-level cost component weights developed from AFS data are multiplied by the selected inflation factors. For instance, if wages in Virginia comprised 50 percent of total operating cost expenses and increased by 4 percent from 2014 to 2015, the wage increase component of the Virginia OCAF for 2016 would be 2.0 percent (50% * 4%). This 2.0 percent would then be added to the increases for the other eight expense categories to calculate the 2016 OCAF for Virginia. The OCAFs for 2016 are included as an Appendix to this Notice.
MAHRA, as amended, created the Mark-to-Market Program to reduce the cost of federal housing assistance, enhance HUD's administration of such assistance, and ensure the continued affordability of units in certain multifamily housing projects. Section 524 of MAHRA authorizes renewal of Section 8 project-based assistance contracts for projects without restructuring plans under the Mark-to-Market Program, including projects that are not eligible for a restructuring plan and those for which the owner does not request such a plan. Renewals must be at rents not exceeding comparable market rents except for certain projects. As an example, for Section 8 Moderate Rehabilitation projects, other than single room occupancy projects (SROs) under the McKinney-Vento Homeless Assistance Act (42 U.S.C. 11301
LIHPRHA (see, in particular, section 222(a)(2)(G)(i), 12 U.S.C. 4112 (a)(2)(G) and HUD's regulations at 24 CFR 248.145(a)(9)) requires that future rent adjustments for LIHPRHA projects be made by applying an annual factor, to be determined by HUD to the portion of project rent attributable to operating expenses for the project and, where the owner is a priority purchaser, to the portion of project rent attributable to project oversight costs.
This issuance sets forth rate determinations and related external administrative requirements and procedures that do not constitute a development decision affecting the physical condition of specific project areas or building sites. Accordingly, under 24 CFR 50.19(c)(6), this notice is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321).
The Catalog of Federal Domestic Assistance Number for this program is 14.187.
Fish and Wildlife Service, Interior.
Notice; request for information.
We, the U.S. Fish and Wildlife Service (Service), announce our intention to conduct a 5-year status review under the Endangered Species Act of 1973, as amended (ESA), for the polar bear (
To ensure consideration of your comments in our preparation of this 5-year status review, we must receive your comments and information by December 14, 2015. However, we will accept information about any species at any time.
Please submit your information on the current status of the polar bear by one of the following methods:
•
•
For more about submitting information, see Request for Information in the
Hilary Cooley, Polar Bear Lead, Marine Mammals Management, by telephone at 907-786-3800. Individuals who are hearing impaired or speech impaired may call the Federal Relay Service at 800-877-8339 for TTY assistance.
We are initiating a 5-year status review under the ESA for the polar bear (
Under the ESA (16 U.S.C. 1531
A 5-year review considers all new information available at the time of the review. In conducting these reviews, we consider the best scientific and commercial data that have become available since the listing determination or most recent status review, such as:
(1) The biology of the species, including, but not limited to, population trends, distribution, abundance, demographics, and genetics;
(2) Habitat conditions, including, but not limited to, amount, distribution, and suitability;
(3) Conservation measures that have been implemented that benefit the species;
(4) Threat status and trends in relation to the five listing factors (as defined in section 4(a)(1) of the Act); and
(5) Other new information, data, or corrections, including, but not limited to, taxonomic or nomenclatural changes, identification of erroneous information contained in the List, and improved analytical methods.
Any new information will be considered during the 5-year review and will also be useful in evaluating the ongoing recovery programs for the species.
To ensure that a 5-year review is complete and based on the best available scientific and commercial information, we request new information from all sources. See What Information Do We Consider in Our Review? for specific criteria. If you submit information, please support it with documentation such as maps, bibliographic references, methods used to gather and analyze the data, and/or copies of any pertinent publications, reports, or letters by knowledgeable sources.
Before including your address, phone number, email address, or other personal identifying information in your comments, 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.
A list of all completed and currently active 5-year reviews addressing species for which the Alaskan Region of the Service has lead responsibility is available at
This document is published under the authority of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Bureau of Indian Affairs, Interior.
Notice.
This notice publishes the Albuquerque Indian School District (AISD) Liquor Control Ordinance. The ordinance regulates and controls the possession, sale, and consumption of liquor within Albuquerque Indian School (AIS) lands. The ordinance allows for the possession and sale of alcoholic beverages within the jurisdiction of the Albuquerque Indian School District, the governing entity formed by the 19 Pueblos of New Mexico to establish a governance structure for Albuquerque Indian School lands. The ordinance will increase the
This law is effective October 13, 2015.
Ms. Patricia Mattingly, Tribal Government Officer, Southwest Regional Office, Bureau of Indian Affairs, 1011 Indian School Road, NW., Suite 254, Albuquerque, NM 87104; Telephone: (505) 563-3446; Fax: (505) 563-3101, or Ms. Laurel Iron Cloud, Bureau of Indian Affairs, Office of Indian Services, 1849 C Street, NW., MS-4513-MIB, Washington, DC 20240; Telephone: (202) 513-7641.
Pursuant to the Act of August 15, 1953, Public Law 83-277, 67 Stat. 586, 18 U.S.C. 1161, as interpreted by the Supreme Court in
This notice is published in accordance with the authority delegated by the Secretary of the Interior to the Assistant Secretary—Indian Affairs. I certify that the Albuquerque Indian School District Governing Council duly adopted the Albuquerque Indian School District Liquor Control Ordinance by Resolution No. GC2013-03 on July 24, 2013.
Section 1-1-1.
Section 1-1-2.
Section 1-1-3.
A. For purposes of 18 U.S.C. 1161, this Chapter shall be interpreted and applied as constituting the liquor ordinance adopted under the authority of the Indian Pueblos having jurisdiction over the District.
B. For purposes of the exemption from the New Mexico Liquor Control Act provided by NMSA 1978 § 60-3A-5(D), this Chapter shall be interpreted and applied as constituting the law of the Indian Pueblos authorizing the sale, service, possession or public consumption of liquor within the boundaries of the District, on the terms and conditions stated in this Chapter.
Section 1-1-4.
A.
B.
C.
D.
E.
F.
G.
(1) An application for a liquor license constitutes a request that the Governing Council make a decision on the applicant's general suitability, character, integrity, and ability to import, sell, dispense, or distribute liquor within the District in conformity with this Chapter.
(2) An applicant for a liquor license and a person to whom a liquor license has been granted shall at all times bear the burden of proving its qualification to hold a liquor license.
(3) No liquor license shall be issued to or held by a person who has been convicted of two or more violations of this Chapter in a twelve month period, or whose liquor license (issued by any jurisdiction) has been revoked at any time. If a person who owns ten percent (10%) or more of the ownership interests in the entity holding an AISD liquor license is disqualified to hold the liquor license under this Section 1-1-4(G)(3), then the entity is also disqualified to hold an AISD liquor license.
(4) The person holding an AISD liquor license must have the character, integrity, financial ability, and business skills necessary to acquire, sell, dispense, or distribute liquor within the District in conformity with this Chapter.
H.
I.
J.
(1) Public Events. Any person holding a license under this chapter authorizing sales of liquor by the drink within the licensed premises may dispense liquor at a special public event located outside of the licensed premises upon receiving a permit from the Oversight Commission with the concurrence of the Chairman and Vice Chairman of the Governing Council of the District and upon the payment of the permit fee fixed by the Oversight Commission. As used in this subsection, “special public event” includes any fair, cultural or artistic performance, athletic competition of a seasonal nature, or other event held on an intermittent basis. The permit shall be valid for no longer than the duration of the special public event.
(2) Private Events. Any person holding a license under this chapter authorizing sales of liquor by the drink within the licensed premises may dispense liquor at a private event located outside of the licensed premises and catered by the licensee upon receiving a permit from the Oversight Commission with the concurrence of the Chairman and Vice Chairman of the Governing Council of the District and upon the payment of the permit fee fixed by the Oversight Commission. The permit shall be valid for no more than twelve hours.
(3) The person holding a license to sell liquor by the drink and its employees shall be the only persons permitted to dispense liquor during the function for which the special event permit was issued.
(4) Issuance of the special event permit is within the discretion of the Oversight Commission.
(5) The special event permit shall identify the location where the special event will take place, the hours and days during which the permit is in effect, and the types of liquor that may be dispensed under authority of the permit. The permit shall not authorize package sales of liquor.
(6) The permittee shall be subject to all District laws and regulations regulating the sale of liquor by the drink.
Section 1-1-5.
A.
B.
C.
Section 1-1-6.
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(1) investigate applicants for a liquor license or permit and holders of a liquor license or permit to ensure their eligibility to obtain or hold a liquor license or permit, as applicable,
(2) impose civil penalties under Section 1-1-11,
(3) issue written demands to comply with this Chapter or any requirement of a liquor license or permit,
(4) issue administrative subpoenas requiring the production of relevant records, books, information, evidence or other documents and/or the presence and testimony of any person relating to any matter under consideration or investigation by the District Manager under this Section 1-1-10,
(5) suspend a liquor license for up to forty-five (45) days for any violation of this Chapter,
(6) perform such other actions that are reasonably necessary and proper to carry out the authority granted by this Section 1-1-10.
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Section 1-1-11.
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Bureau of Land Management, Interior.
60-Day notice and request for comments.
In compliance with the Paperwork Reduction Act, the Bureau of Land Management (BLM) invites public comments on, and plans to request approval to continue, the collection of information that enables the BLM to monitor compliance with timber export restrictions. The Office of Management and Budget (OMB) has assigned control number 1004-0058 to this information collection.
Please submit comments on the proposed information collection by December 14, 2015.
Comments may be submitted by mail, fax, or electronic mail.
Please indicate “Attn: 1004-0058” regardless of the form of your comments.
Michael Bechdolt at 202-912-7234. Persons who use a telecommunication device for the deaf may call the Federal Information Relay Service at 1-800-877-8339, to leave a message for Mr. Bechdolt.
OMB regulations at 5 CFR part 1320, which implement provisions of the Paperwork Reduction Act, 44 U.S.C. 3501-3521, require that interested members of the public and affected agencies be given an opportunity to comment on information collection and recordkeeping activities (see 5 CFR 1320.8 (d) and 1320.12(a)). This notice identifies an information collection that the BLM plans to submit to OMB for approval. The Paperwork Reduction Act provides that an agency may not conduct or sponsor a collection of information unless it displays a currently valid OMB control number. Until OMB approves a collection of information, you are not obligated to respond.
The BLM will request a 3-year term of approval for this information collection activity. Comments are invited on: (1) The need for the collection of information for the performance of the functions of the agency; (2) the accuracy of the agency's burden estimates; (3) ways to enhance the quality, utility and clarity of the information collection; and (4) ways to minimize the information collection burden on respondents, such as use of automated means of collection of the information. A summary of the public comments will accompany our submission of the information collection requests to OMB.
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.
The following information pertains to this request:
The estimated burdens are itemized in the following table:
Bureau of Land Management, Interior.
Notice.
The Approved Resource Plan Amendments and Approved Resource Plan/Records of Decision (RODs) for the Great Basin Region and Rocky Mountain Regions were signed by the BLM Director and the Assistant Secretary, Lands and Minerals Management, on September 21, 2015. The RODs constitute the final decision of the BLM and the Approved Plan Amendments and Approved Plan were effective immediately upon their signing. In accordance with its regulations, the BLM is publishing the reasons for rejecting the recommendations of the Governors of Idaho, Nevada, North Dakota, South Dakota, and Utah regarding Idaho, Nevada, North Dakota, and Utah Greater Sage-Grouse (GRSG) Proposed Resource Management Plans Amendments (PRMPAs) and Final Environmental Impact Statements (FEISs) and the South Dakota Proposed Resource Management Plan (PRMP) and Final Environmental Impact Statement (FEIS) which were published on May 29, 2015.
Brian Amme, Acting Division Chief for Decision Support, Planning and NEPA, telephone 202-912-7289; address 1849 C Street NW., Room 2134LM, Washington, DC 20240; email
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 individuals during normal business hours. The FIRS is available 24 hours a day, 7 days a week, to leave a message or question with the above individual. You (Governor) will receive a reply during normal business hours.
The RODs amend and revise Resource Management Plans (RMPs) across the range of the Greater Sage Grouse (GRSG), including RMPs in the states of Idaho, Nevada, North Dakota, South Dakota, and Utah. The RODs incorporate conservation measures to conserve, enhance and restore GRSG and its habitat.
In accordance with the regulations at 43 CFR 1610.3-2(e), the BLM submitted the Proposed Plan Amendments (Idaho, Nevada, North Dakota, and Utah) and Proposed Plan (South Dakota) for a 60-day Governors' Consistency Review. The 60-day review period ended on July 29, 2015. The relevant BLM State Directors (State Directors) received letters from the Governors of Idaho, Nevada, North Dakota, South Dakota, and Utah identifying alleged inconsistencies with State and local plans, policies, and programs and identifying recommendations to address those potential inconsistencies. These letters are available at
By September 11, 2015, the BLM Director had received appeals from the Governors of Idaho, Nevada, North Dakota, South Dakota, and Utah on the State Directors' decisions on their recommendations.
In reviewing these appeals, the regulations at 43 CFR 1610.3-2(e) state that “[t]he Director shall accept the (consistency) recommendations of the Governor(s) if he/she determines they provide for a reasonable balance between the state's interest and the national interest.” On September 16, 2015, the BLM Director issued final responses to the Governors detailing the reasons that the recommendations did not meet this standard. Copies of both the incoming appeal letters from the Governors and the outgoing responses are available at
Your (Governor's) letter states that the BLM responses to the Idaho Consistency Review letter failed to follow section 202(c)(9) of FLPMA, which states that land use plans be consistent with state and local plans to the maximum extent the Secretary of the Interior finds consistent with Federal law. A cornerstone of the BLM's sage grouse planning process has been coordination and collaboration with the affected states, as demonstrated by the detailed consideration and, in many cases, adoption of the strong GRSG conservation approaches put in place by or suggested by the states, including those put in place by or suggested by the State of Idaho. However, in order to provide the necessary regulatory certainty, the BLM found it necessary to ensure that there are consistently strong approaches to the management of BLM-managed lands range-wide. The purpose of these common elements is to provide for a net conservation gain for the GRSG. However, the plans also recognize that different circumstances exist across the range, which is why the plans have allowed for flexibility where appropriate in the sub-regional plans, such as the three-tier mapping and management approach adopted as part of the Idaho plans. As such, I (BLM Director) must respectfully disagree with your contention that the ARMPA is materially inconsistent with the Governor's Plan. The three-tier approach in the Governor's Plan is the basis of the Idaho/Southwest Montana ARMPA. The BLM has also worked with the State of Idaho to tailor many of the “range-wide” management actions in the Idaho ARMPA, such as the recent inclusion of prioritization actions for grazing management in Sagebrush Focal Area (SFAs). These actions demonstrate how the PRPMA has adopted the fundamental tenets of the State plan.
Your (Governor's) appeal letter states that the BLM erroneously relied on Manual 6840, Special Status Species Management, in the development of the PRMPA and the response to the Governor's Consistency Review letter. This statement does not identify an inconsistency with state or local resource related plans, policies, or programs, therefore, a response is not required under the Governor's consistency review process. The purpose of the amendment is the conservation of a special status species, the GRSG, and the management actions in the amendment are limited to those which will conserve, enhance, and restore GRSG and its habitat consistent with the agency's multiple-use and sustained yield mission. The management actions are consistent with
You (Governor) also assert that the BLM has improperly delegated authority to the FWS by permitting that agency to effectively veto land management decisions for an unlisted species. This statement does not identify an inconsistency with state or local resource related plans, policies, or programs, therefore, a response is not required under the Governor's consistency review process. That said, I would note that the BLM is not and has not delegated its authority. Rather, the BLM has focused on making its planning decisions based on input from local and national experts on these issues. For example, in order to provide the most protection to GRSG in Priority Habitat Management Areas (PHMA), the areas of highest importance for the species, decisions on allowing surface occupancy during fluid mineral development will be made with the Idaho Department of Fish and Game and the FWS, the local and national experts on GRSG, respectively. The BLM is not delegating authority, but ensuring that all experts evaluate whether there would be direct, indirect, or cumulative effects on GRSG before allowing surface-disturbing fluid mineral development in areas of important habitat. While the BLM retains the final decision-making authority for decisions on the public lands, this input is critically important.
In your (Governor's) appeal letter, you request that I reconsider the request to exempt Idaho from SFAs. I have reviewed your prior comments on the development of the SFAs and I understand that your office is strongly opposed to them. While I understand these concerns, I uphold the determination of the BLM Idaho State Director that the SFAs are consistent with the BLM's range-wide GRSG conservation strategy. I also want to reiterate that the SFAs are a subset of PHMA, with limited additional management actions to ensure that the “best of the best” habitat receives the attention it deserves. In addition to the recommended mineral withdrawal and the fluid mineral no surface occupancy (NSO) stipulation without waivers, exceptions, or modifications, the ARMPA clarifies (in response to your Governor's consistency review letter) that these areas will be prioritized for a broader group of activities, including vegetation management, wild horse and burro management, habitat restoration, fire and fuels actions, as well as the review of livestock grazing permits and leases, consistent with the State of Idaho Plan.
You also assert in your (Governor's) appeal that in developing the SFAs the BLM has created Areas of Critical Environmental Concern (ACECs) without following the proper regulatory process. This concern does not identify an inconsistency with state or local resource or related plans, policies or programs, and therefore, a response is not required under the Governor's consistency review process. It should be noted that the SFAs are not ACECs—they are a subset of PHMAs with additional management protections, all of which were fully analyzed in the Draft and Final EISs for the Idaho plan. These additional measures include NSO without waiver, exception, or modification for fluid mineral development and a recommendation for withdrawal from the 1872 Mining Law. These actions and recommendations do not constitute an ACEC designation under the applicable regulations.
Both your (Governor's) consistency review and appeal letter requested the removal of the project level disturbance caps. The BLM included the project-level disturbance cap to ensure that disturbance is limited at both a local and landscape scale and to encourage co-location of disturbance. Based on best available science, when disturbance exceeds three percent at either scale, GRSG numbers are affected and tend to decline (derived from Holloran 2005, Walker et al. 2007, Doherty et al. 2008, Naugle et al. 2011). Disturbance caps at both the BSU and the project scale are necessary to account for the amount of existing disturbance at both scales. Calculating disturbance for each additional anthropogenic disturbance placed on the landscape is particularly important at the project scale to ensure that GRSG numbers and habitat acreages remain stable or increase. Further, calculations at both of these scales are intended to encourage clustering of disturbance and discouraging development in undisturbed habitat. This is a critically important aspect of the GRSG strategy, and therefore, I (BLM Director) respectfully deny your appeal on this issue and uphold the State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
It should be noted that based upon further review across the Great Basin region, the BLM is including an exception to the project-level disturbance cap for designated utility corridors, to ensure that these areas are used to the fullest extent possible as intended for utility lines and associated disturbance. This modification is consistent with BLM's goal of encouraging co-location of disturbance.
Your (Governor's) appeal notes that the Governor's “. . . strategy is in many ways in and of itself a mitigation plan,” and as a result, you expresses concern that the BLM mitigation standard of net conservation gain is in conflict with this. I respectfully disagree with this statement. Based on the way the ARPMA is structured, the Idaho State Plan, especially the three-tier approach, will serve as a key component of the BLM's mitigation strategy, and therefore the AMPRA is not in conflict or inconsistent with the state strategy. Additionally, as noted in the State Director's response, the mitigation standard in the amendment is consistent with numerous national policies, including Secretarial Order 3330 and BLM's Draft—Regional Mitigation Manual Section (MS)-1794. As a result, I deny your appeal on this issue and uphold the State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
I would also note that going forward it will be critical for BLM and its partners to work together to develop and implement effective mitigation on the ground. This mitigation will be developed working with existing and developing mitigation approaches that are being utilized in individual states and west-wide. To do this, the BLM will utilize the expertise of state and Federal partners, through WAFWA Management Zone conservation teams, to develop mitigation strategies. Participation of your Office of Species Conservation and the Idaho Department of Fish and Game will be critical to this effort.
You (Governor) identified numerous concerns with the livestock grazing
“Management and conservation action prioritization will occur at the Conservation Area (CA) scale and be based on GRSG population and habitat trends: Focusing management and conservation actions first in SFAs followed by areas of PHMA outside SFA.”
You (Governor) also express concerns with the habitat objectives table, that the management direction associated with its use is vague and subjective. The use of the metrics in the table will be site-specific. Specifically, the habitat objectives table sets forth the desired habitat condition for permitted uses. The metrics in the table will be used, as appropriate, based on ecological site potential, in the development of land use authorizations, including but not limited to livestock grazing permits, and land health assessments. Please note, the BLM creates and uses habitat objectives for many special status species and includes them in land health assessments it prepares routinely across the west.
Finally, you (Governor) expressed concern about the BLM's statement that “current grazing management will not change as a result of the SFA designation.” Specifically, with respect to your statement that prioritization of grazing permit renewals in SFAs “. . . is really a subterfuge for elevating the activity ((
Based on the foregoing, I respectfully deny your appeal on these grazing issues and uphold the State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy range-wide.
In your (Governor's) Consistency Review, you recommended that the BLM remove the uniform lek buffers from the plans. The BLM Idaho State Director's response explained that the buffers are not uniform and that local data and regulations can be considered in their application at the project development stage. The application of buffers also varies according to habitat type, with more exceptions provided in General Habitat Management Areas (GHMA) than in PHMA. Additionally, the use of the buffers identified in the Governor's Plan is allowed under the considerations put forth in the amendment, provided they provide the same level of protection for GRSG and its habitat in any particular circumstance. Again, the use of buffers will be determined on a site- and project-specific basis, during project development. Based on the foregoing, I (BLM Director) respectfully deny your appeal on this issue and uphold the State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
In your (Governor's) appeal, you request that I (BLM Director) consider removing the Required Design Features (RDFs) which are not contained in the Governor's Plan. I agree with the Idaho State Director that the RDFs are an important aspect of the BLM strategy and respectfully deny your request. Similar to the buffers, there is flexibility in the application of the RDFs, such that if there is a Best Management Practice in the Governor's Plan which provides equal protection for GRSG and its habitat, it may be used instead, and therefore the RDFs do not create an inconsistency with state or local resource related plans, policies, or programs.
As you (Governor) know, the BLM adopted much of the State GRSG Plan into the PRMPA. However, in addition to the measures in the State plan, the BLM is required under the applicable regulations to include in its land use plans goals, objectives, allocation decisions and management actions that help the BLM to specifically manage certain resources on public land. These components are also a critical part of BLM's Special Status Species policy, under which disturbance-limiting land use plan allocation decisions are a key component. The State's Plan does not contain such allocation decisions or management actions as it relies largely on cost-based incentives to implement an avoid, minimize, and mitigate strategy. In effect, if an applicant has sufficient funds to buy credits, a project could be allowed to be placed anywhere, even in the most important habitat. The BLM has found that this approach, especially before it has built an implementation track record, may not address the BLM's land use planning requirements and does not provide the requisite level of regulatory certainty for a landscape-level species like the GRSG. As noted above, the allocation decisions presented in the BLM's plans and amendments range-wide were designed to provide that level of certainty. Therefore, I (BLM Director) concur with the Acting Nevada State Director's response and respectfully deny your (Governor's) appeal on this issue because it is inconsistent with the goal of the BLM's GRSG conservation strategy.
Your (Governor's appeal) letter states that the Disturbance Cap Protocol (DCP) would encourage habitat fragmentation because it provides an incentive to locate new disturbances in areas with little existing disturbance. The goal of the DCP has always been to encourage the co-location of new disturbances with existing disturbances if the activity cannot be avoided altogether within GRSG habitat in order to limit overall disturbance levels in these areas and the impact that they have on the species. The BLM Nevada State Director worked closely with your office to craft the DCP. Due to that close coordination and in recognition of the State's work and
With respect to the suggestion that the DCP will encourage disturbance in previously undisturbed areas, the Nevada ARMPA contains allocation decisions separate and apart from the DCP that will limit or preclude new disturbance in PHMA and minimize disturbance in GHMA. The BLM believes that these protective allocation decisions (
In addition, the ARMPA has been clarified to provide for exceedance of the 3% disturbance cap within open designated utility corridors. This clarification has now been added to the BLM Nevada and Northeastern California's ARMPA in order to ensure co-location with existing disturbances. Based on best available science, when disturbance exceeds three percent at either the biologically significant unit or project scale, GRSG numbers are affected and tend to decline (derived from Holloran 2005, Walker et al. 2007, Doherty et al. 2008, Naugle et al. 2011).
Based on the foregoing, I (BLM Director) therefore deny your (Governor's) appeal on this issue and concur with the Acting State Director's determination that this recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
As explained in the Acting BLM Nevada State Director's response, the BLM continues to rely on the FWS expertise as a cooperating agency in this planning effort. In that role, the FWS' provided the BLM with a memorandum identifying highly important landscapes. These areas represent the recognized “strongholds” for GRSG that have been noted and referenced as having the highest densities of GRSG and other criteria important for the persistence of the species. By recognizing these areas and applying consistent management within them across the Great Basin, the BLM believes it is providing regulatory certainty to the FWS that these areas will be protected. Additionally, although the SFAs are a high priority for protection from anthropogenic disturbances, and disturbances from fire, invasives, and conifer encroachment, the protection of all other GRSG habitat is also a major component of the ARMPA, contrary to the suggestion in your (Governor's) appeal. The ARMPA contains numerous pages of protective decisions that apply to PHMA, GHMA, and Other Habitat Management Areas; no habitat category is being ignored. I (BLM Director), therefore, respectfully deny your appeal on these issues and uphold the Acting State Director's determination that your recommendations are inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
Your letter also states that segregating the SFA lands from mineral entry for a two-year period would have a negative effect on investment in the region, to the detriment of local, state, and national interests. This statement does not identify an inconsistency with State or local resource related plans, policies, or programs, therefore a response is not required under the Governor's consistency review process. Nevertheless, it is important to note that the SFAs comprise less than 3% of the lands in Nevada. The withdrawal process, beginning with the temporary segregation, includes a public process to consider information provided by the states, stakeholders and others on mineral potential, as well as the importance of these areas as sage-grouse habitat. This information will be included in the analyses which the Secretary will use to make a decision about a potential withdrawal.
The ARMPA does not deny the application of the State of Nevada's CCS or say that it will not provide for a net conservation gain. In fact, BLM recognizes that CCS will play an important role in mitigation efforts in Nevada. That said, the ARMPA also recognizes that there are other forms of mitigation that can result in a net conservation gain to GRSG and its habitat. As a result, the ARPMA commits to consideration of the CCS, as appropriate, and looks forward to utilizing the CCS as an important tool in mitigating the impacts of habitat disturbance. The relationship between BLM management of the public lands and the CCS is currently being negotiated through a Memorandum of Understanding (MOU) with the SETT. Working through the specific factors of how and when the BLM and applicants would use the CCS is not a planning decision, and is outside of the scope of the planning effort, and therefore is not subject to consistency review of appeal. The MOU reflects the plan decision to consider the CCS as a means of mitigation. The ARMPA includes language to clarify the relationship between the CCS and proposed uses in GRSG habitat. I (BLM Director) therefore respectfully deny your (Governor's) appeal on this issue and uphold the State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy.
Your (Governor's appeal) letter indicates that BLM is not committed to using the best available science. This statement does not identify an inconsistency with State or local resource related plans, policies, or programs, and therefore a response is not required under the Governor's consistency review process. The BLM will incorporate new science as it becomes available. New information, updated analyses, or new resource use or protection proposals may require amending or revising land use plans and updating implementation decisions. In this case, the primary requirement for considering new information is as follows:
Finally, your letter also includes a concern regarding the leadership of the Western Association of Fish and Wildlife Agencies (WAFWA) Management Zone Greater Sage-Grouse
Your (Governor's) consistency review and appeal letter expressed concern that the PRMPA does not include adequate information on land use. This concern does not identify an inconsistency with State or local resource related plans, policies, or a program, therefore a response is not required under the Governor's consistency review process. I (BLM Director) do, however, concur with the response from the BLM Montana/Dakotas State Director that the purpose of the plan amendment is to conserve, enhance and restore GRSG habitat by reducing, minimizing, or eliminating threats to the habitat of GRSG in accordance with the BLM's multiple-use and sustained yield mandate. Management direction in the amendment is specific to those activities on BLM land in southwestern North Dakota which may impact GRSG. Other programs/uses outside of GRSG habitat that are not addressed in the ARMPA are carried forward from the existing North Dakota Resource Management Plan (1988) and are not altered by this decision.
The North Dakota Governor's consistency review and appeal letter states that the proposed amendment is unclear about new technologies. The appeal does not raise an issue of inconsistency to resolve in this regard. I (BLM Director) do, however, concur with the response from the Montana/Dakotas State Director Jamie Connell which noted that the majority of the southwestern area of North Dakota is already leased and predominately developed using one well per pad. I would also note that the amendment includes flexibility for oil and gas development and location, such as collocation of wells on well pads and directional drilling from outside of habitat, and therefore is not inconsistent with modern drilling technologies and approaches.
In your (Governor's) consistency review and appeal letter, you expressed a need for case-by-case management decisions. This statement does not identify an inconsistency with State or local resource related plans, policies, or programs, and therefore a response is not required under the Governor's consistency review process. Nevertheless, I (BLM Director) concur with the response from the BLM Montana/Dakotas State Director that the BLM's planning regulations require that we use land use plan allocation decisions to specifically manage certain resources on public land. Disturbance-limiting allocation decisions are the keystone to the BLM's Special Status Species Policy. In contrast, the North Dakota State Plan is voluntary, and does not contain allocation decisions. Such an approach does not provide the necessary level of regulatory certainty necessary to achieve the goals of the BLM's range-wide GRSG conservation strategy for a landscape-level species such as GRSG. It is important to note that the BLM will continue to work with the State of North Dakota and proponents on a case-by-case basis on all future project level implementation activities, to ensure that they utilize the best available science and local information, in conformance with the decisions in the ARMPA. Also, please note that all of the management decisions in the ARMPA are subject to valid existing rights.
With respect to your concerns about new information and mapping data, the BLM will consider and incorporate new information and habitat mapping, when applicable, and as it becomes available. New information, updated analyses, or new resource use or protection proposals may require subsequent plan maintenance, revision, or amendment, as appropriate.
You state that the net conservation gain mitigation standard put forth in the PRMPA is inconsistent with FLPMA. This statement does not identify an inconsistency with State or local resource related plans, policies, or a program, therefore a response is not required under the Governor's consistency review process. I (BLM Director) do, however, concur with the response provided the BLM Montana/Dakotas State Director that included an extensive explanation of how this landscape-scale goal is consistent with the BLM's GRSG Strategy as well as Federal policy.
Your (Governor's) consistency review and appeal letter state that the management actions for “tall structures” are unworkable. As noted in the response from the BLM Montana/Dakotas State Director, this statement does not identify an inconsistency with State or local resource related plans, policies, or programs, and therefore a response is not required under the Governor's consistency review process. It should be noted, however, that tall structures are a concern because they can provide habitat for predators of GRSG. Therefore, managing the placement and mitigating impacts of tall structures is an important aspect of the BLM's range-wide conservation strategy. The management approaches in the amendment, such as required design features and application of lek buffer distances, allow for the development and use of appropriately designed and mitigated tall structures.
The North Dakota Governor's consistency review and appeal letter state that there was not adequate opportunity for public review and comment. As noted in the response from the BLM Montana/Dakotas State Director, this statement does not identify an inconsistency with State or local resource related plans, policies, or programs, and therefore a response is not required under the Governor's consistency review process. It should be noted, however, that the BLM provided full opportunity for public comment and involvement in accordance with applicable law and regulations. More details on this can be found in Chapter 6 of the Final Environmental Impact Statement, as well as in the ARMPA and Record of Decision, found at
In both your Governor's consistency review letter and in your (Governor's) appeal letter, you recommend that the BLM provide more flexibility regarding fluid mineral development to allow for the development of oil and gas resources in South Dakota. I (BLM Director) concur with the assertion of Montana/Dakotas State Director Jamie Connell that adoption of the recommendation offered, namely allowing waivers and modifications to no surface occupancy stipulations in Priority Habitat Management Areas, is not consistent with the goals of the
You state that you wish the BLM to reconsider the decision not to update the Reasonable Foreseeable Development (RFD) analysis in the Final Environmental Impact Statement. This statement does not identify an inconsistency with State or local resource related plans, policies, or programs; therefore, a response is not required under the Governor's consistency review process. I (BLM Director) do, however, concur with the response from the BLM Montana/Dakotas State Director that, while the RFD may not have utilized the 2014 data provided by South Dakota, the analysis provides adequate information with regard to overall potential development and serves as an appropriate basis for the BLM's planning process.
In connection with the development of the PRMP, the BLM reviewed the RFD Scenario for Oil and Gas Activities on Bureau Managed Lands in the South Dakota Study Area (RFD; BLM, 2009) and the report reviewed by the Wyoming Reservoir Management Group, which includes BLM technical experts. The BLM also reviewed information provided by the State of South Dakota and data on drilling that has occurred in the first 4 years and 10 months of the analysis period for the 2009 RFD. Based on a review of this data, the BLM has determined that the current drilling rate does not support the projections offered by the State of South Dakota. Additionally, the reviewers determined that the 2009 RFD adequately accounted for variables such as increased gas prices. While the RFD is not able to accurately predict the exact locations of future wells, the reviewers determined that in aggregate, it still provides the best available information with regard to overall potential development. Therefore, I respectfully deny your appeal on this issue.
You (Governor) expressed concern about the use of the WAFWA Management Zone GRSG Conservation Team in your Governor's Consistency Review and reiterate the concern in your (Governor's) appeal. This concern does not identify an inconsistency with state or local resource related plans, policies, or programs, and therefore a response is not required under the Governor's consistency review process.
I (BLM Director) understand that the State of Utah is in a unique position, with habitat in four WAFWA Zones, and agree that the WAFWA Management Zone GRSG Conservation Teams should utilize existing approaches and constructs to the fullest extent possible in connection with their work. The ARMPA and the ROD include language to reflect this direction. It should also be remembered that the primary purpose of these teams are to advise on cross-state issues, such as regional mitigation strategies and adaptive management monitoring and response. In connection with these efforts, I am confident that the BLM Acting Utah State Director will ensure that the good work the State of Utah has done, including the State's mitigation plan, is considered as the PLUPA is implemented. Notably, the State of Utah has done outstanding work on vegetation treatments to improve habitat condition, including its conifer removal implementation plans.
Your (Governor's) Consistency Review and appeal letters recommend that the BLM adopt planning provisions in the amendment which provide equivalent protections for the activities of the Department of Defense as those found in the State's Conservation Plan. The Department of Defense has been a partner throughout the GRSG planning process and has worked with us to address the potential impacts of the amendment on base readiness across the range. Therefore, I (BLM Director) respectfully deny your (Governor's) appeal on this issue and uphold the Acting Utah State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy range-wide and the applicable legal authorities.
The BLM was able to provide clarifying information in the ROD to make clear that appropriately managed livestock grazing may continue under the GRSG plans. However, the additional changes you recommend in your (Governor's) appeal letter are beyond the scope of the appeal process and do not relate to an inconsistency with State or local resource related plans, policies, or programs; therefore, a response is not required under the Governor's consistency review process. That said, I (BLM Director) remain committed to working with the state and other stakeholders to ensure that these plans are implemented in a manner that demonstrates well-managed grazing practices are compatible with long-term sage-grouse conservation.
In the Governor's Consistency Review and the appeal, you recommended that the BLM identify the Alton Coal Lease-By-Application (LBA) tract as GHMA, as opposed to a PHMA. Based on data collected by the State, the company, FWS, and the BLM, the area in and around the Alton tract contains active dancing and strutting grounds, and may contain the southernmost lek in the United States. Based on this data, the FWS, working with the State and others, identified the area as a priority area for conservation in the FWS Conservation Objectives Team Report, which led to the BLM identifying it as PHMA. After carefully reviewing the available information related to GRSG in and around the Alton Coal tract and the response by the BLM Acting Utah State Director, I (BLM Director) am upholding the decision to retain this area as PHMA and deny your recommendation because it is inconsistent with the goal of the BLM's GRSG conservation strategy range-wide.
Your consistency review and appeal letter express concern about the provision which requires agreement by the State and FWS prior to approving exceptions to the NSO stipulation for fluid mineral development in PHMA. This does not raise an issue of inconsistency with State or local resource or related plans, policies or programs; therefore, a response is not required under the Governor's consistency review process. Moreover, the involvement of FWS in the determination as to whether there would be direct, indirect, or cumulative impacts to GRSG does not unlawfully or unconstitutionally infringe on state authority or unlawfully delegate BLM's authority over the public lands. Rather, in order to provide the most protection
The appeal letter requests that I (BLM Director) reconsider the decision of the Acting Utah State Director related to land tenure adjustments involving lands owned and managed by the School and Institutional Trust Lands Administration. I have reviewed the response, as well as the clarifying language that we have added to the amendment in response to your consistency review letter, which allows for disposal
The State of Utah has recommended that the BLM eliminate the management actions in its plans for areas outside of PHMA. After having reviewed the information provided with your recommendation, I (BLM Director) respectfully deny your (Governor's) appeal and uphold the decision of the Acting Utah State Director that your recommendation is inconsistent with the goal of the BLM's GRSG range-wide conservation strategy. GHMA provides important connectivity and restoration areas and its protection is an essential aspect of the BLM's GRSG conservation strategy. Additionally, as stated above, the PLUPA amendment already incorporates additional flexibility for GHMA in the state of Utah because of the limited number of birds in GHMA.
In your (Governor's) appeal letter, you request that I (BLM Director) reconsider the request to exempt Utah from SFAs. I have reviewed your prior comments on the development of the SFAs and while I understand these concerns, I uphold the determination of the Acting Utah State Director, that the SFAs are consistent with the BLM's range-wide GRSG conservation strategy. I also want to reiterate that the SFAs are a subset of PHMA, with limited additional management actions to ensure that the “best of the best” receives the attention it deserves. In addition to the recommended mineral withdrawal and the fluid mineral NSO stipulation without waivers, exceptions, or modifications, these areas will be prioritized for vegetation management, review of livestock grazing permits and leases, habitat restoration, and fire and fuels actions. Therefore, I respectfully deny your (Governor's) appeal on this issue and uphold the Acting Utah State Director's determination that your recommendation is inconsistent with the goal of the BLM's range-wide GRSG conservation strategy range-wide.
43 CFR 1610.3-2(e).
Notice is hereby given pursuant to the Antitrust Procedures and Penalties Act, 15 U.S.C. 16(b)-(h), that a proposed Final Judgment, Hold Separate Stipulation and Order, and Competitive Impact Statement have been filed with the United States District Court for the District of Columbia in
Copies of the Complaint, proposed Final Judgment, and Competitive Impact Statement are available for inspection on the Antitrust Division's Web site at
Public comment is invited within 60 days of the date of this notice. Such comments, including the name of the submitter, and responses thereto, will be posted on the Antitrust Division's Web site, filed with the Court, and, under certain circumstances, published in the
The United States of America, acting under the direction of the Attorney General of the United States, brings this civil action to enjoin the proposed acquisition by Defendants Cox Enterprises, Inc. and Cox Automotive, Inc. (collectively, “Cox”) of Defendant Dealertrack Technologies, Inc. (“Dealertrack”). The United States alleges as follows:
1. Cox intends to acquire all of the outstanding shares of common stock of Dealertrack through a cash tender offer totaling approximately $4 billion. Cox and Dealertrack are both leading providers of automated solutions and marketing services to the automotive industry, and are significant direct competitors in the development, marketing, and sale of inventory management solutions (“IMSs”) to automotive dealerships in the United States.
2. Cox and Dealertrack are the two leading providers of full-featured IMSs that are employed primarily for inventory management in the used vehicle businesses of larger automotive dealerships, particularly those that operate franchises associated with new vehicle original equipment manufacturers (“OEMs”). The IMSs of Cox and Dealertrack participate in a market with only four significant competitors. The two firms compete head-to-head in the development, marketing, and sale of their respective IMSs. Cox's proposed acquisition of Dealertrack would eliminate this competition, resulting in higher prices and lower quality for dealership consumers.
3. Accordingly, the transaction is likely to substantially lessen competition in the provision of full-featured IMSs in the United States, in violation of Section 7 of the Clayton Act, 15 U.S.C. § 18, and should be enjoined.
4. The United States brings this action under Section 15 of the Clayton Act, 15 U.S.C. § 25, to prevent and restrain Defendants from violating Section 7 of the Clayton Act, 15 U.S.C. § 18. This Court has subject-matter jurisdiction over this action under Section 15 of the Clayton Act, 15 U.S.C. § 25, and 28 U.S.C. §§ 1331, 1337(a), and 1345.
5. Defendants market, sell, operate, and service their products, including their IMSs, throughout the United States and regularly and continuously transact business and transmit data in connection with these activities in the flow of interstate commerce, which has a substantial effect upon interstate commerce.
6. Defendants consent to personal jurisdiction and venue in this district. This Court has personal jurisdiction over each Defendant and venue is proper under Section 12 of the Clayton Act, 15 U.S.C. § 22, and 28 U.S.C. § 1391(b) and (c).
7. Cox Enterprises, Inc., and its subsidiary, Cox Automotive, Inc., are both Delaware corporations headquartered in Atlanta, Georgia. Cox develops and sells a diverse portfolio of automated solutions and services for automotive dealers and consumers, including vAuto, a full-featured IMS. The total annual net revenue of Cox's automotive businesses in 2014 was approximately $4.9 billion. Its U.S. IMS revenue was a relatively small part of its total revenue.
8. Dealertrack Technologies, Inc. is a Delaware corporation headquartered in Lake Success, New York. Dealertrack develops and sells a variety of automated solutions and services for automotive dealers, including Inventory+, a full-featured IMS that combines the functionality from two IMSs that Dealertrack acquired—AAX and eCarList. Dealertrack's total annual net revenue in 2014 was approximately $854 million. Its U.S. IMS revenue was a relatively small part of its total revenue. Dealertrack also owns a 50% interest in Chrome Data Solutions, LP (“Chrome”), a company that compiles and licenses vehicle information data. The remaining 50% interest in Chrome is owned by Autodata Solutions, Inc. and Autodata Solutions Company (collectively, “Autodata”).
9. On June 12, 2015, Cox Automotive and Dealertrack entered into an Agreement and Plan of Merger whereby Cox agreed to commence a cash tender offer to acquire all of the outstanding shares of Dealertrack for $63.25 per share, for a total of approximately $4 billion.
10. In the United States, new and used vehicles are typically sold to consumers through automotive dealerships. A dealership may be “franchised,” meaning it is associated with an OEM, or “independent” of any association with an OEM. New vehicles are acquired by franchised dealers directly from OEMs and resold to consumers. Used vehicles are purchased or otherwise acquired (often through trade-ins) by franchised or independent dealers and then sold to consumers or at wholesale (often at auction). A dealer may have more than one physical store (or “rooftop”) and franchised dealers may be associated with more than one OEM. The type of automated products and services that a dealer uses to manage its business often depends on its size, its level of sophistication, and whether it is franchised or independent.
11. Most franchised and larger independent dealers rely on dealer management systems (“DMSs”) to manage the primary functions of their businesses, including sales, finance, accounting, service, parts, and personnel. The DMS is the central repository for a large amount of data about the dealer's day-to-day business activities. IMSs are a type of “point” solution that offer enhanced functionality that is not provided in the DMS. IMSs communicate and share data with the dealer's DMS and other point solutions.
12. Full-featured IMSs traditionally have been used to assist dealers in managing their used vehicle inventories, although the leading IMSs increasingly offer extended functionality to manage new vehicle inventories. A full-featured IMS uses algorithms and sophisticated analytics to help dealers: (1) optimize their inventories; (2) appraise the value of vehicles they want to acquire; (3) set prices for vehicles they want to sell; (4) publish listings of vehicles that they have for sale; and (5) run detailed reports and analytics on vehicle and dealership performance relative to other vehicles and dealerships. This combination of automated analytics, reporting, optimization, pricing, and merchandising enables dealers using full-featured IMSs to operate their businesses more efficiently and to increase the rate at which they sell vehicles (“inventory turns”) and their overall profitability.
13. To perform the functionality described above, a full-featured IMS must be able to exchange data and communicate with other automated solutions. The performance and competitive viability of a full-featured IMS depends on the breadth and quality of its data.
14. A full-featured IMS obtains data about the dealer's current inventory and vehicle sales history from its DMS and provides the DMS with new or updated information, such as new or changed vehicle prices. A full-featured IMS collects a large amount of wholesale and retail pricing data, which may include data from auction services, book value guides, vehicle history reports, and online listings. It may also collect indicators of consumer interest in a particular vehicle, such as click data relating to consumers' online browsing activities. Further, a full-featured IMS prepares and distributes vehicle listings to the dealer's Web site and third-party vehicle retail sites.
15. Defendants own or otherwise control access to many of the most
16. To operate efficiently, a full-featured IMS must access and be able to transmit and receive data about specific vehicles with other automated solutions. This vehicle-specific data includes, but is much broader than, information about the year, make, model, engine, plant location, and country of origin of a vehicle that is encoded in the 17-digit vehicle identification number (“VIN”). A full-featured IMS also relies on many additional categories of vehicle-specific data, such as editorial content, stock images, stock videos, ordering guide pricing data, OEM features and specifications data, configuration data, factory service schedule data, accessories data, warranty information, OEM new vehicle rebates and incentives data, and OEM build data (the “as built” equipment manifest and pricing data). Chrome is the leading provider of this vehicle-specific information, and Chrome offers significantly more vehicle data than any other supplier.
17. Every full-featured IMS relies on Chrome data, as do most other automotive solutions and Web sites with which IMSs exchange vehicle data. Chrome has become a
18. A hypothetical monopolist of full-featured IMSs profitably could increase its prices by at least a small but significant and non-transitory amount. Full-featured IMSs are most frequently used by large franchised and independent dealers. These dealers generally have larger information technology budgets, make more decisions centrally, and have more complex operating requirements than smaller dealers due to larger vehicle inventories, higher inventory turns, and more rooftops. They are therefore more dependent on robust, integrated automated solutions to effectively manage their businesses. Although some other solutions offer dealers certain aspects of inventory management functionality, they are less comprehensive and less robust than full-featured IMSs. These solutions are used primarily by smaller dealers and are not meaningful alternatives to full-featured IMSs. Accordingly, full-featured IMSs constitute a relevant product market and line of commerce for purposes of analyzing the likely competitive effects of the proposed acquisition under Section 7 of the Clayton Act, 15 U.S.C. § 18.
19. Defendants market and sell IMSs to dealerships located across the United States, and customers do not differentiate between IMSs on the basis of location. A hypothetical monopolist of full-featured IMSs profitably could increase its prices to dealers in the United States by a small but significant and non-transitory amount. Accordingly, the United States is a relevant geographic market for purposes of analyzing the likely competitive effects of the proposed acquisition under Section 7 of the Clayton Act, 15 U.S.C. § 18.
20. Cox and Dealertrack are the two leading providers of full-featured IMSs. Cox is the market leader, with a market share of approximately 60%. Dealertrack is the second leading provider with a market share of approximately 26%. Cox's proposed acquisition of Dealertrack would enable the merged firm to control approximately 86% of full-featured IMS sales.
21. Market concentration is often a useful indicator of the level of competitive vigor in a market and the likely competitive effects of a merger. The more concentrated a market, and the more a transaction would increase that concentration, the more likely it is that the transaction would result in reduced competition, harming consumers. Market concentration commonly is measured by the Herfindahl-Hirschman Index (“HHI”), as discussed in Appendix A. Markets in which the HHI exceeds 2,500 points are considered highly concentrated, and transactions that increase the HHI by more than 200 points in highly concentrated markets are presumed likely to enhance market power. Here, the proposed acquisition would substantially increase market concentration in a highly concentrated market, raising the HHI by approximately 3120 points to a post-acquisition HHI of approximately 7526 points.
22. Cox and Dealertrack currently compete head-to-head and their IMSs are close substitutes. Cox's proposed acquisition of Dealertrack would eliminate this competition and further concentrate a market that is already highly concentrated. As a result, Cox would emerge as the clearly dominant provider of full-featured IMSs with the ability to exercise substantial market power, thereby increasing the likelihood that Cox could unilaterally increase prices or reduce its investment or other efforts to improve the quality of its products and services. Moreover, with the acquisition of Dealertrack, Cox would acquire an ownership interest in Chrome that could enable Cox to deny or restrict access to Chrome data and thereby unilaterally undermine the competitive viability of Cox's remaining IMS competitors.
23. It is unlikely that any firm would enter the relevant product and geographic markets alleged herein in a timely manner sufficient to defeat the likely anticompetitive effects of the proposed acquisition. Successful entry in the development, marketing, operation, and sale of a full-featured IMS to dealers in the United States is difficult, time-consuming, and costly.
24. Any new entrant would be required to expend significant time and capital to design and develop an automated solution with functionality that is at least comparable to the Defendants' full-featured IMSs, including developing robust algorithms that could accurately source, price, and market a dealer's vehicles. Successful entry would also require a substantial effort in identifying and obtaining access to the data sources necessary to power the IMS algorithms, and significant payments for such data and for access to the interfaces necessary to allow the IMS to work with a dealer's DMS and other automated solutions. In particular, it is unlikely that any such effort would produce an economically viable alternative to Chrome data in the near future.
25. The United States incorporates the allegations of paragraphs 1 through 24 above.
26. The proposed acquisition of Dealertrack by Cox is likely to substantially lessen competition for full-featured IMSs in the United States in violation of Section 7 of the Clayton Act, 15 U.S.C. § 18.
27. Unless enjoined, the proposed acquisition likely will have the following anticompetitive effects, among others:
(a) actual and potential competition between Cox and Dealertrack in the development, marketing, and sale of IMSs in the United States will be eliminated;
(b) competition in the development, marketing, and sale of IMSs in general will be substantially lessened;
(c) prices of IMSs will increase;
(d) improvements or upgrades to the quality or functionality of IMSs will be less frequent and less substantial; and
(e) the quality of service for IMSs will decline.
28. The United States requests that this Court:
(a) adjudge and decree that Cox's proposed acquisition of Dealertrack would be unlawful and would violate Section 7 of the Clayton Act, 15 U.S.C. 18;
(b) permanently enjoin and restrain Defendants and all persons acting on their behalf from carrying out the Agreement and Plan of Merger dated June 12, 2015, or from entering into or carrying out any other contract, agreement, plan, or understanding to combine Cox with Dealertrack;
(c) award the United States its costs for this action; and
(d) award the United States such other and further relief as this Court deems just and proper.
The term “HHI” means the Herfindahl-Hirschman Index, a commonly accepted measure of market concentration. The HHI is calculated by squaring the market share of each firm competing in the relevant market and then summing the resulting numbers. For example, for a market consisting of four firms with shares of 30, 30, 20, and 20 percent, the HHI is 2,600 (30
Markets in which the HHI is between 1,500 and 2,500 points are considered to be moderately concentrated, and markets in which the HHI is in excess of 2,500 points are considered to be highly concentrated.
Plaintiff United States of America (“United States”), pursuant to Section 2(b) of the Antitrust Procedures and Penalties Act (“APPA” or “Tunney Act”), 15 U.S.C. 16(b)-(h), files this Competitive Impact Statement relating to the proposed Final Judgment submitted for entry in this civil antitrust proceeding.
On June 12, 2015, Defendant Cox Automotive, Inc., a subsidiary of Defendant Cox Enterprises, Inc. (collectively “Cox”), and Defendant Dealertrack Technologies, Inc. (“Dealertrack”) entered into an Agreement and Plan of Merger whereby Cox agreed to commence a cash tender offer to acquire all of the outstanding shares of Dealertrack for $63.25 per share, for a total of approximately $4 billion. The United States filed a civil antitrust Complaint on September 29, 2015, seeking to enjoin the proposed acquisition. The Complaint alleges that the likely effect of this acquisition would be to lessen competition substantially for the development, marketing, and sale of full-featured inventory management solutions (“IMSs”) in the United States in violation of Section 7 of the Clayton Act, 15 U.S.C. 18. This loss of competition likely would result in higher prices and lower quality for dealership consumers.
At the same time the Complaint was filed, the United States also filed a proposed Final Judgment and Hold Separate Stipulation and Order (“Hold Separate”), which are designed to prevent the alleged anticompetitive effects of the acquisition. Under the proposed Final Judgment, which is explained more fully below, Defendants are required: (1) to divest to DealerSocket, Inc., or to another Acquirer that is acceptable to the United States, all of Dealertrack's interest in its IMS products and related assets; (2) to provide short-term transition services and support to enable the Acquirer to operate the divested assets without any disruption as of the date of the divestiture; (3) to permit for up to four years the continuing exchange of data and content between the divested assets and other data sources, Internet sites, and automotive solutions that are owned, controlled, provided, or managed by Defendants; and (4) to undertake various obligations to prevent Defendants from exploiting Dealertrack's interest in Chrome Data Solutions, LP. (“Chrome”). The parties have submitted a proposed agreement to sell the divestiture assets to DealerSocket, which is currently under review by the United States.
Under the terms of the Hold Separate, Defendants will take certain steps to ensure that the assets to be divested are operated as a competitively independent, economically viable, and ongoing business concern that will remain independent and uninfluenced by the consummation of the acquisition, and that competition is maintained during the pendency of the ordered divestiture.
The United States and Defendants have stipulated that the proposed Final Judgment may be entered after compliance with the APPA, and the Hold Separate provides that Defendants will comply with the terms of the proposed Final Judgment pending its entry. Entry of the proposed Final Judgment would terminate this action, except that the Court would retain jurisdiction to construe, modify, or enforce the provisions of the proposed Final Judgment and to punish violations thereof.
Cox Automotive, Inc. and Cox Enterprises, Inc. are privately-held Delaware corporations, with their headquarters in Atlanta, Georgia. The automotive products managed by Cox encompass a broad portfolio of automated solutions and services for automotive dealers and consumers, including vAuto, a full-featured IMS. Cox's total annual automotive revenue in 2014 was about $4.9 billion, of which its U.S. IMS revenue was a small part.
Dealertrack is a Delaware corporation with its headquarters in Lake Success, New York. Dealertrack develops and sells a variety of automated solutions and services for automotive dealers, including Inventory+, a full-featured IMS that combines the functionality from two IMSs that Dealertrack acquired—AAX and eCarList. Dealertrack's total annual revenue in 2014 was about $854 million, of which its U.S. IMS revenue was a small part. Dealertrack also owns a 50% interest in Chrome, a company that compiles and licenses vehicle information data for use in IMSs and other automated solutions and services for the automotive industry. The remaining 50% interest in Chrome is owned by Autodata Solutions, Inc. and Autodata Solutions Company (collectively, “Autodata”).
Cox's proposed acquisition of Dealertrack would lessen competition substantially in the development, marketing, and sale of full-featured IMSs in the United States. The acquisition is the subject of the Complaint and proposed Final Judgment filed by the United States on September 29, 2015.
In the United States, new and used vehicles are typically sold to consumers through automotive dealerships. A dealership may be “franchised,” meaning it is associated with an original equipment manufacturer (“OEM”), or “independent” of any association with an OEM. New vehicles are acquired by franchised dealers directly from OEMs and resold to consumers. Used vehicles are purchased or otherwise acquired (often through trade-ins) by franchised or independent dealers and then sold to consumers or at wholesale (often at auction). A dealer may have more than one physical store (or “rooftop”) and franchised dealers may be associated with more than one OEM. The type of automated products and services that a dealer uses to manage its business often depends on its size, its level of sophistication, and whether it is franchised or independent.
Most large franchised and independent dealers rely on dealer management systems (“DMSs”) to manage the primary functions of their businesses, including sales, finance, accounting, service, parts, and personnel. The DMS is the central repository for a large amount of data about the dealer's day-to-day business activities. IMSs are a type of “point” solution that a dealer may use to obtain enhanced functionality that is not provided in its DMS. IMSs communicate and share data with the dealer's DMS and other point solutions.
Full-featured IMSs have traditionally been used to assist dealers in managing their used vehicle inventory, although the leading IMSs increasingly offer extended functionality to manage new vehicle inventories. A full-featured IMS uses algorithms and sophisticated analytics to help dealers: (1) Optimize their inventories; (2) appraise the value of vehicles they want to acquire; (3) set prices for vehicles they want to sell; (4) publish listings of vehicles that they have for sale; and (5) run detailed reports and analytics on vehicle and dealership performance relative to other vehicles and dealerships. This combination of automated analytics, reporting, optimization, pricing, and merchandising enables dealers using full-featured IMSs to operate their used vehicle businesses more efficiently and to increase the rate at which they sell vehicles (“inventory turns”) and their overall profitability.
To perform the functionality described above, a full-featured IMS must be able to exchange data and communicate with other automated solutions. The performance and competitive viability of a full-featured IMS depends on the breadth and quality of its data sets.
To optimize a dealer's inventory, a full-featured IMS obtains data about the dealer's current inventory from its DMS and analyzes it against certain benchmarks. The IMS recommends vehicles that the dealer should add to its inventory and identifies and scores the desirability of vehicles that are available for acquisition, thereby allowing dealers to pick the fastest-selling or most profitable vehicles. It also identifies vehicles in inventory that are not selling well and recommends actions the dealer should take to price or dispose of those vehicles.
To appraise and price a vehicle, a full-featured IMS collects, aggregates, and analyzes a large amount of wholesale and retail pricing data, which may include data from auction services, book value guides, vehicle history reports, and online listings, as well as historical data from the DMS relating to transactions involving other similar vehicles. A full-featured IMS uses this data to provide the dealer with a view of the current competitive landscape for a vehicle, including suggested prices for meeting various objectives the dealer may have for the sale of the vehicle. In addition, a full-featured IMS may provide an indication of consumer interest in a particular vehicle, based on an analysis of when the current inventory of similar vehicles in an area will be exhausted or click data relating to consumers' online browsing activities.
A full-featured IMS also automates the online merchandising of a vehicle by preparing online postings with vehicle descriptions and uploading the vehicle listings, together with photos and marketing descriptions, to the dealer's Web site and third-party vehicle retail sites. These tools save time by providing dealers access to multiple sites through a single platform and allowing them to create effective, professional vehicle listings that are consistent across multiple Web sites.
Defendants own or otherwise control access to many significant data sources and destinations for full-featured IMSs.
To operate efficiently, a full-featured IMS must access and communicate data about specific vehicles with other automated solutions. This vehicle-specific data includes, but is much broader than, information about the year, make, model, engine, plant location, and country of origin of a vehicle that is encoded in the 17-digit vehicle identification number (“VIN”). A full-featured IMS also relies on many additional categories of vehicle-specific data, such as editorial content, stock images, stock videos, ordering guide pricing data, OEM features and specifications data, configuration data, factory service schedule data, accessories data, warranty information, OEM new vehicle rebates and incentives data, and OEM build data (the “as built” equipment manifest and pricing data). Chrome is the leading provider of this vehicle-specific information, and Chrome offers significantly more vehicle data than any other supplier
Every full-featured IMS relies on Chrome data, as do most other automotive solutions and Web sites with which the IMSs exchange information about specific vehicles. Indeed, Chrome has become the
Full-featured IMSs are most frequently used by large franchised and independent dealers. These dealers generally have larger IT budgets, make more decisions centrally, and have more complex operating requirements than smaller dealers due to larger vehicle inventories, higher inventory turns, and more rooftops. These dealers are more dependent on full-featured IMSs and other robust, integrated automated solutions to effectively manage their businesses. Although some other solutions offer dealers certain aspects of inventory management functionality, they are less comprehensive and less robust than full-featured IMSs. These solutions are used primarily by smaller dealers and are not meaningful alternatives to full-featured IMSs.
Cox and Dealertrack are by far the two leading providers of full-featured IMSs. Cox is the market leader with a market share of approximately 60%; Dealertrack has a market share of about 26%.
Cox and Dealertrack currently compete head-to-head in the development, marketing, and sale of their respective full-featured IMSs. The proposed acquisition would eliminate this competition, and Cox would emerge as the clearly dominant full-featured IMS provider with the ability to exercise substantial market power, thereby increasing the likelihood that Cox can and would unilaterally increase prices or reduce its investment or other efforts to improve the quality of its products and services. Moreover, with the acquisition of Dealertrack, Cox would acquire an ownership interest in Chrome that could enable Cox to deny or restrict access to Chrome data and thereby unilaterally undermine the competitive viability of Cox's remaining IMS competitors.
The divestiture and other remedial measures of the proposed Final Judgment will prevent the alleged anticompetitive effects of the acquisition by preserving Dealertrack's IMS business as an economically viable competitor. Pursuant to Section IV, the proposed Final Judgment requires Defendants, within ten (10) days after the Court's signing of the Hold Separate or the closing of Cox's acquisition of Dealertrack, whichever is later, to divest the products, related assets, and ongoing business operations relating to Dealertrack's IMS business operations in the United States.
Defendants must use their best efforts to complete the required divestiture as expeditiously as possible. Defendants have proposed a divestiture to DealerSocket. If the proposed divestiture to DealerSocket is delayed, abandoned, or not approved, the United States, in its sole discretion, may agree to one or more extensions of the time for Defendants to complete the divestiture to DealerSocket or another Acquirer that is acceptable to the United States. All such extensions may not exceed one hundred and twenty (120) calendar days.
If Defendants do not complete the divestiture within the prescribed time, Section VI of the Final Judgment provides that the Court will appoint a trustee selected by the United States to effect the divestiture. Defendants are required to use their best efforts to assist the trustee in accomplishing the divestiture and will pay the trustee's costs and expenses. The trustee's commission will be structured so as to provide an incentive for the trustee based on the price obtained and the speed with which the divestiture is accomplished. The trustee will file monthly reports with the Court and the United States setting forth his or her efforts to accomplish the divestiture. If the trustee does not complete the divestiture within six months, the trustee and the United States will make recommendations to the Court, which shall enter such orders as appropriate to carry out the purpose of the proposed Final Judgment, including potentially extending the trust or the term of the trustee's appointment.
Section V of the proposed Final Judgment imposes additional obligations to foster a smooth transfer of Dealertrack's IMS business to DealerSocket or another Acquirer and to ensure for a reasonable time that Defendants permit the uninterrupted exchange of data and content between the divested IMS products and other data sources, Internet sites, and automotive solutions that are owned, controlled, provided, or managed by Defendants. Section V.A requires Defendants to provide for up to one year any transition services that are necessary to enable the Acquirer to operate the divested assets and compete effectively in the market for IMSs as of the date of the divestiture.
Section V.B requires Defendants to enable for up to four years the exchange of data and other content that is currently being exchanged between the divested IMS products and any destinations, sites, or other data sources that Defendants control. This section provides for the continuing exchange of
Section V.F requires Defendants to enable, at cost, for up to four years the exchange of an IMS customer's data that is currently being exchanged between the divested IMS products and any of the customer's other sites or solutions that are provided or managed by Defendants. This section provides for the continuing exchange of a customer's data between the divested IMS product used by the customer and, for example, the customer's Web site that is managed by Dealertrack's Dealer.com or the customer's Dealertrack DMS. Section V.G requires Defendants to provide for the exchange of this customer data on the same terms that were in effect before the divestiture and specifies conditions when the Acquirer may elect to exchange the data under more favorable terms.
Sections V.L through V.P impose various obligations to ensure that Defendants do not take any action to disrupt access to Chrome data by their IMS competitors, including the Acquirer, or to reduce or limit the value that Defendants' IMS competitors derive from Chrome's status as a
CDK Global and Reynolds currently account for the vast majority of all DMS sales, and Dealertrack currently has the right to veto any Chrome license with CDK Global or Reynolds. Section V.M would substantially limit Defendants' use of this preexisting right to when either CDK Global or Reynolds terminates, without reasonable cause, the ability of CDK Global's or Reynolds' DMS products to interoperate with the Defendants' products. This provision preserves an industry dynamic that favors interoperability and benefits consumers.
Section XI of the proposed Final Judgment provides that, on application of the United States, the Court shall appoint a Monitoring Trustee selected by the United States. The Monitoring Trustee will have the power and authority to investigate and report on Defendants' compliance with the Final Judgment and Hold Separate, including Defendants' compliance with all of the obligations in Section V relating to transition services, data exchange, and Chrome data. The Monitoring Trustee will not have any responsibility or obligation for the operation of Defendants' businesses. The Monitoring Trustee will serve at Defendants' expense, on such terms and conditions as the United States approves, and Defendants must use their best efforts to assist the trustee in fulfilling its obligations. The Monitoring Trustee will file quarterly reports and will serve until the required divestiture is complete and for so long as Defendants continue to have obligations under Section V.
Section 4 of the Clayton Act, 15 U.S.C. 15, provides that any person who has been injured as a result of conduct prohibited by the antitrust laws may bring suit in federal court to recover three times the damages the person has suffered, as well as costs and reasonable attorneys' fees. Entry of the proposed Final Judgment will neither impair nor assist the bringing of any private antitrust damage action. Under the provisions of Section 5(a) of the Clayton Act, 15 U.S.C. 16(a), the proposed Final Judgment has no prima facie effect in any subsequent private lawsuit that may be brought against Defendants.
The United States and Defendants have stipulated that the proposed Final Judgment may be entered by the Court after compliance with the provisions of the APPA, provided that the United States has not withdrawn its consent. The APPA conditions entry upon the Court's determination that the proposed Final Judgment is in the public interest.
The APPA provides a period of at least sixty (60) days preceding the effective date of the proposed Final Judgment within which any person may submit to the United States written comments regarding the proposed Final Judgment. Any person who wishes to comment should do so within sixty (60) days of the date of publication of this Competitive Impact Statement in the
Written comments should be submitted to:
James J. Tierney, Chief
Networks & Technology Enforcement Section
Antitrust Division
United States Department of Justice
450 Fifth Street NW., Suite 7100
Washington, DC 20530
The United States considered, as an alternative to the proposed Final Judgment, a full trial on the merits against Defendants. The United States could have continued the litigation and sought preliminary and permanent injunctions against Cox's acquisition of Dealertrack. The United States is satisfied, however, that the divestiture
The Clayton Act, as amended by the APPA, requires that proposed consent judgments in antitrust cases brought by the United States be subject to a sixty-day comment period, after which the Court shall determine whether entry of the proposed Final Judgment “is in the public interest.” 15 U.S.C. 16(e)(1). In making that determination, the Court, in accordance with the statute as amended in 2004, is required to consider:
(A) the competitive impact of such judgment, including termination of alleged violations, provisions for enforcement and modification, duration of relief sought, anticipated effects of alternative remedies actually considered, whether its terms are ambiguous, and any other competitive considerations bearing upon the adequacy of such judgment that the court deems necessary to a determination of whether the consent judgment is in the public interest; and
(B) the impact of entry of such judgment upon competition in the relevant market or markets, upon the public generally and individuals alleging specific injury from the violations set forth in the complaint including consideration of the public benefit, if any, to be derived from a determination of the issues at trial.
As the United States Court of Appeals for the District of Columbia Circuit has held, under the APPA a court considers, among other things, the relationship between the remedy secured and the specific allegations set forth in the government's complaint, whether the decree is sufficiently clear, whether enforcement mechanisms are sufficient, and whether the decree may positively harm third parties.
Courts have greater flexibility in approving proposed consent decrees than in crafting their own decrees following a finding of liability in a litigated matter. “[A] proposed decree must be approved even if it falls short of the remedy the court would impose on its own, as long as it falls within the range of acceptability or is `within the reaches of public interest.'”
Moreover, the Court's role under the APPA is limited to reviewing the remedy in relationship to the violations that the United States has alleged in its Complaint, and does not authorize the Court to “construct [its] own hypothetical case and then evaluate the decree against that case.”
In its 2004 amendments, Congress made clear its intent to preserve the practical benefits of utilizing consent decrees in antitrust enforcement, adding the unambiguous instruction that “[n]othing in this section shall be construed to require the court to conduct an evidentiary hearing or to require the court to permit anyone to intervene.” 15 U.S.C. 16(e)(2);
There are no determinative materials or documents within the meaning of the APPA that were considered by the United States in formulating the proposed Final Judgment.
WHEREAS, Plaintiff United States of America filed its Complaint on September 29, 2015, the United States and Defendants, Cox Enterprises, Inc., Cox Automotive, Inc., and Dealertrack Technologies, Inc., by their respective attorneys, have consented to the entry of this Final Judgment without trial or adjudication of any issue of fact or law, and without this Final Judgment constituting any evidence against or admission by any party regarding any issue of fact or law;
AND WHEREAS, Defendants agree to be bound by the provisions of this Final Judgment pending its approval by the Court;
AND WHEREAS, the essence of this Final Judgment is the prompt and certain divestiture of certain rights or assets by the Defendants to assure that competition is not substantially lessened;
AND WHEREAS, the United States requires Defendants to make certain divestitures and to undertake certain actions and refrain from certain conduct for the purpose of remedying the loss of competition alleged in the Complaint;
AND WHEREAS, Defendants have represented to the United States that the divestiture and conduct restrictions required below can and will be made and that Defendants will later raise no claim of hardship or difficulty as grounds for asking the Court to modify any of the provisions contained below;
NOW THEREFORE, before any testimony is taken, without trial or adjudication of any issue of fact or law, and upon consent of the parties, it is ORDERED, ADJUDGED AND DECREED:
This Court has jurisdiction over the subject matter of and each of the parties to this action. The Complaint states a claim upon which relief may be granted against Defendants under Section 7 of the Clayton Act, as amended, 15 U.S.C. 18.
As used in this Final Judgment:
A. “Acquirer” means DealerSocket, Inc. or another entity to whom Defendants divest the Divestiture Assets.
B. “Affiliate” means directly or indirectly controlling, controlled by, or under common control with a Person.
C. “Autodata” means Autodata Solutions, Inc., a Delaware corporation; Autodata Solutions Company, a Nova Scotia unlimited liability company; and all of their successors and assigns, and their subsidiaries, divisions, groups, Affiliates, partnerships and joint ventures, and their directors, officers, managers, agents, trustees, and employees.
D. “Chrome” means Chrome Data Solutions, LP, a Delaware limited partnership; Chrome Data Operating, LLC, a Delaware limited liability company; AutoChrome Company, a Nova Scotia unlimited liability company; and all of their successors and assigns, and their subsidiaries, division, groups, Affiliates, partnerships and joint ventures, and their directors, officers, managers, agents, trustees and employees.
E. “Chrome Agreements” means the Operating Agreement of Chrome Data Operating, LLC, effective as of January 1, 2012; the Amended and Restated Agreement of Limited Partnership of Chrome Data Solutions, LP, effective as
F. “Chrome Data” means any vehicle information data, databases, or data sets for any make or model of vehicle, and related software and services, licensed, sold, or resold by Chrome, including but not limited to editorial content, stock images, stock videos, ordering guide pricing data, automotive feature and specification data from new vehicle original equipment manufacturer (“OEM”) publications, new vehicle OEM rebates and incentives data, configuration related data, factory service schedule data, Vehicle Identification Number (“VIN”) decode data, OEM build data, and accessories data, and including any improvement, enhancement, or modification made thereto.
G. “Competitively Sensitive Information” means non-public information relating to (i) the terms and conditions (including but not limited to fees or prices) of any actual or prospective contract, agreement, understanding, or relationship concerning the licensing of Chrome Data, to specific or identifiable customers or classes or groups of customers, or (ii) the existence of any such prospective contract, agreement, understanding, or relationship, as well as any proprietary customer information, including but not limited to customer-specific vehicle queries, vehicle lists, or vehicle inventory. Competitively Sensitive Information does not include information (1) disclosed in public materials or otherwise in the public domain through no fault of the receiving party, (2) lawfully obtained by the receiving party from a third party without any obligation of confidentiality, (3) lawfully known to the receiving party prior to disclosure by the disclosing party, or (4) independently developed by the receiving party.
H. “Cox” means Cox Automotive, Inc., a Delaware corporation with its headquarters in Atlanta, Georgia; Cox Enterprises, Inc., a Delaware corporation with its headquarters in Atlanta, Georgia; and all of their successors and assigns, and their subsidiaries, divisions, groups, Affiliates, partnerships and joint ventures, and their directors, officers, managers, agents, trustees, and employees (including but not limited to the Cox Family Voting Trust u/a/d 7/26/13 and its trustees).
I. “Dealertrack” means Dealertrack Technologies, Inc., a Delaware corporation with its headquarters in Lake Success, New York, its successors and assigns, and its subsidiaries, divisions, groups, Affiliates, partnerships and joint ventures, and their directors, officers, managers, agents, trustees, and employees.
J. “DealerSocket” means DealerSocket, Inc., a Delaware corporation with its headquarters in San Clemente, California, its successors and assigns, and its subsidiaries, divisions, groups, Affiliates, partnerships and joint ventures, and their directors, officers, managers, agents, trustees, and employees.
K. “Defendants” means Cox and Dealertrack, acting individually or collectively. Where this Final Judgment imposes an obligation to engage in or refrain from engaging in certain conduct, that obligation shall apply to each Defendant individually and to any combination of Defendants.
L. “Divested Product” means Dealertrack eCarList®, Dealertrack AAX®, and Dealertrack's Inventory+ and InventoryPro, and all products, options, applications, features, functions, modules, add-ons, and services relating to any such product, including the products listed in Schedule A. A Divested Product includes each predecessor version of the product and each version that has been or is currently under development or that has been developed but has not been sold or distributed.
M. “Divestiture Assets” means the ongoing business relating to any Divested Product and all tangible and intangible assets owned or licensed by Dealertrack relating to developing, testing, producing, marketing, licensing, selling, or distributing any Divested Product on a standalone basis or in supplying any support or maintenance services for any Divested Product on a standalone basis, including:
(1) all tangible assets related to the Divested Product, including all research and development activities; computer systems, databases, networking equipment and data centers; personal property, inventory, office furniture, materials, supplies, and other tangible property and all assets used exclusively in connection with the Divested Product; licenses; permits, licenses and authorizations issued by any governmental organization relating to the Divested Product to the extent transferrable; contracts, teaming arrangements, supply agreements, agreements, leases, commitments, certifications, and understandings relating to the Divested Product; customer lists, contracts, accounts, and credit records; sales support material; repair, maintenance and performance records; and all other records relating to the Divested Product; and
(2) all intangible assets related to the Divested Product, including, but not limited to, all vehicle data and information accessed by a Divested Product as of August 1, 2015; all patents, licenses and sublicenses, including data licenses; intellectual property; copyrights, trademarks, trade names, service marks, service names; computer software and related documentation, including software customizations, optional modules and add-ons for a Divested Product; source code, object code, and related documentation; development tools, development environments, proprietary programming languages, know-how, designs, drawing, specifications, research data, trade secrets, historic and current research and development, results of successful and unsuccessful designs and experiments, and all other intellectual property used to develop, upgrade or maintain a Divested Product; and software programs, instructions, manuals and all other technical information Dealertrack provides to its own employees, customers, suppliers, agents, or licensees to facilitate the operation of any Divested Product.
N. “DMS” means dealer management solution software, hardware, or services, or any combination thereof, used for automotive dealership management, including keeping track of, organizing, or in any way managing the operations, including sales, inventory, maintenance, service, payroll, accounting, personnel, and other aspects of the dealership's business.
O. “IMS” means inventory management solution software, hardware, or services, or any combination thereof, used for vehicle inventory management, including optimization, analytics, organization, stocking, provisioning, appraising, pricing, merchandising, sourcing, buying, selling, acquisition or disposal at auction or at wholesale, and inter-enterprise transfers.
P. “Person” means any natural person, corporation, company, partnership, joint venture, firm, association, proprietorship, agency, board, authority, commission, office, trust, or other business or legal entity, whether private or governmental.
Q. “Transition Services Agreement” means an agreement between Defendants and Acquirer for Defendants to provide all necessary transition services and support to enable Acquirer to fully operate the Divestiture Assets and compete effectively in the market
A. This Final Judgment applies to Defendants, and all other Persons in active concert or participation with any of them who receive actual notice of this Final Judgment by personal service or otherwise.
B. If Defendants sell or otherwise dispose of all or substantially all of their assets, or of lesser business units that include the Divestiture Assets, they shall require the purchaser to be bound by the provisions of this Final Judgment. Defendants need not obtain such an agreement from Acquirer of the assets divested pursuant to this Final Judgment.
A. Defendants are ordered and directed, within ten (10) calendar days after (i) the Court's signing of the Hold Separate Stipulation and Order in this matter, (ii) the closing of Cox's acquisition of Dealertrack, whichever is later, to divest the Divestiture Assets in a manner consistent with this Final Judgment to DealerSocket or another Acquirer acceptable to the United States, in its sole discretion. The United States, in its sole discretion, may agree to one or more extensions of this time period, with any one extension not to exceed sixty (60) calendar days and all extensions not to exceed one hundred and twenty (120) calendar days in total, and shall notify the Court in such circumstances. Defendants agree to use their best efforts to divest the Divestiture Assets as expeditiously as possible. As to any Divestiture Asset that is not primarily related to the Divested Product because its primary use or application is in a product that will be retained by the Defendants, the asset may be divested pursuant to Section IV or VI of this Final Judgment by granting Acquirer a perpetual, non-exclusive license.
B. In the event Defendants attempt to divest the Divestiture Assets to an Acquirer other than DealerSocket, Defendants promptly shall make known, by usual and customary means, the availability of the Divestiture Assets. Defendants shall inform any Person making an inquiry regarding a possible purchase of the Divestiture Assets that they are being divested pursuant to this Final Judgment and provide that Person with a copy of this Final Judgment.
C. In accomplishing the divestiture ordered by this Final Judgment, Defendants shall offer to furnish to all prospective Acquirers, subject to customary confidentiality assurances, all information and documents relating to the Divestiture Assets customarily provided in a due diligence process except such information or documents subject to the attorney-client privilege or work-product doctrine. Defendants shall make available such information to the United States at the same time that such information is made available to any other Person.
D. Defendants shall provide Acquirer and the United States information relating to the personnel involved in the operation, development, service, maintenance, customer support, license, and sale of the Divestiture Assets to enable Acquirer to make offers of employment. Defendants shall not interfere with any negotiations, offers, or actions by Acquirer to employ any Defendant employee whose primary responsibility is in the operation, development, service, maintenance, customer support, license, or sale of the Divestiture Assets.
E. Defendants shall permit prospective Acquirers of the Divestiture Assets to have reasonable access to personnel and to make inspections of the physical facilities of Dealertrack that relate in any way to the Divestiture Assets; access to any and all environmental, zoning, and other permit documents and information; and access to any and all financial, operational, or other documents and information customarily provided as part of a due diligence process.
F. Defendants shall warrant to Acquirer that each of the Divestiture Assets will be in good working condition and repair on the date of sale.
G. Defendants shall not take any action that will impede in any way the permitting, operation, or divestiture of the Divestiture Assets.
H. Defendants shall warrant to Acquirer that the Divestiture Assets are in material compliance with the terms of each of, and have not received any written notices of violation or alleged violation with respect to any of, the environmental, zoning or other permits necessary for the operation of each of the Divestiture Assets.
I. Unless the United States otherwise consents in writing, the divestiture required pursuant to this Section IV, or by a Divestiture Trustee appointed pursuant to Section VI of this Final Judgment, shall include the entire Divestiture Assets, and shall be accomplished in such a way as to satisfy the United States, in its sole discretion, that the Divestiture Assets can and will be used by Acquirer as part of a viable, ongoing business of providing IMS. The divestiture, whether pursuant to Section IV or Section VI of this Final Judgment,
(1) shall be made to an Acquirer that, in the United States' sole judgment, has the intent and capability (including the necessary managerial, operational, technical and financial capability) of competing effectively in the business of providing IMS; and
(2) shall be accomplished so as to satisfy the United States, in its sole discretion, that none of the terms of any agreement between an Acquirer and Defendants gives Defendants the ability unreasonably to raise Acquirer's costs, to lower Acquirer's efficiency, or otherwise to interfere in the ability of Acquirer to compete effectively.
A. At the election of Acquirer, Defendants and Acquirer shall enter into a Transition Services Agreement for a period of up to one (1) year from the date of the divestiture. The Transition Services Agreement shall enumerate all the duties and services that Acquirer requires of Defendants to support the development, marketing, and sale of any Divested Product. Defendants shall perform all duties and provide any and all services required of Defendants under the Transition Services Agreement. Any amendments, modifications, or extensions of the Transition Services Agreement may only be entered into with the approval of the United States, in its sole discretion.
B. In order for Acquirer to continue to have the uninterrupted ability to transfer, receive, or otherwise exchange content and other data between any Divested Product and destinations, sites, or other data sources controlled by Defendants, including but not limited to Manheim, AutoTrader, Kelly Blue Book (KBB), and any Dealertrack solution or database that prepares or stores data in an aggregated, normalized, and anonymized form, for three (3) years following the date of the sale of the Divestiture Assets, Defendants shall: (1) provide to Acquirer for use in its IMS business access to all such data sources under their control that were accessed by the Divestiture Assets as of August 1, 2015; and (2) allow Acquirer to provide content or other data (such as automotive listings) to any such destination or site under their control to which the Divestiture Assets provided content or other data as of August 1, 2015. Defendants shall, upon receiving a written request from Acquirer at least thirty (30) calendar days before expiration of the third year, continue to provide the services covered by this Section V.B for another one (1) year.
C. For any data or content subject to Section V.B, Defendants shall provide
(1) speed and frequency of content transmission;
(2) server lag time and/or uptime;
(3) database or API synchronization; and
(4) data content or data fields transmitted or utilized.
Provided, further, that this Section V.C. does not require Defendants:
(1) To provide, or, if provided, to refrain from charging any additional fee for, any additional data fields that were not accessed by the Divestiture Assets as of August 1, 2015 and that Defendants do not make commercially available to any other third party; or
(2) to allow Acquirer to cache any data that Cox prohibited Dealertrack from caching in connection with the operation or use of any Divested Product as of August 1, 2015, and that Defendants prohibit all other third parties from caching.
D. For any data or content subject to Section V.B, Defendants shall not change except for good cause the format of any data or content exchange provided to Acquirer. For any such change, Defendants shall provide adequate notice for Acquirer to modify its IMS products and any customer installations to use the new data format without disruption.
E. Defendants may require as a condition of providing aggregated, normalized, and anonymized data that is covered by Section V.B that Acquirer provide the same data the Divested Product currently provides as an input into the aggregated, normalized, and anonymized data, if Acquirer is permitted to provide its data under terms that require Defendants to preserve the confidentiality of Acquirer's data and not use Acquirer's data except in the aggregated, normalized, and anonymized form.
F. In order for Acquirer to continue to have the uninterrupted ability to transfer, receive, or otherwise exchange a customer's content and other data between any Divested Product and the customer's other sites or solutions that are provided or managed by Defendants, and with which any Divested Product exchanges data as of August 1, 2015 (“Designated Sites or Solutions”) including but not limited to Dealer.com Web sites and the Dealertrack DMS, for three (3) years following the date of sale of the Divestiture Assets, upon a customer's approval, Defendants shall enable, at cost, the exchange of the customer's data and content between Acquirer's IMS products and any Designated Sites or Solutions . Defendants shall, upon receiving a written request from Acquirer at least thirty (30) calendar days before expiration of the third year, continue to provide the services covered by this Section V.F for another one (1) year.
G. For any customer data or content subject to Section V.F, Defendants shall provide for the exchange of such data or content on the same terms that were applicable to such data or content exchanges with the Divestiture Assets as of August 1, 2015. Provided, however, that if Defendants allow for the exchange of any such data or content with any other provider's IMS (including any IMS of Defendants) and any of the Designated Sites or Solutions on terms (other than price) that are more favorable than the terms made available to Acquirer, Defendants shall notify Acquirer of the more favorable terms and Acquirer may elect to exchange the data or content on those terms. For the avoidance of doubt, the following is a non-exhaustive list of terms that may not be more favorable than those that are made available to Acquirer:
(1) Speed and frequency of content transmission;
(2) server lag time and/or uptime;
(3) database or API synchronization; and
(4) data content or data fields transmitted or utilized.
H. Defendants may impose, with a customer's approval and as a condition of enabling the exchange of the customer's data and content that is covered by Section V.F, conditions that are reasonably related to maintaining the security, integrity and confidentiality of the data, except that Defendants may not impose conditions that are materially less favorable than the conditions under which Defendants allow the exchange of a customer's content or data between any IMS owned or controlled by Defendants and any of the customer's other solutions or sites that are provided or managed by Defendants.
I. For any data or content subject to Section V.F, Defendants shall not change except for good cause the format of any customer data or content exchange. For any such change, Defendants shall provide adequate notice for Acquirer to modify its IMS products and any customer installations to use the new data format without disruption.
J. Defendants shall take all reasonable steps to cooperate with and assist Acquirer in obtaining any third party license or permission that may be required for Defendants to convey, license, sublicense, assign or otherwise transfer to Acquirer rights in any of the Divestiture Assets or in any data that Defendants are required to provide to Acquirer pursuant to this Section V.
K. Defendants are prohibited from retaining a copy of, using, or offering for sale any of the Divestiture Assets other than those items provided to Acquirer through a non-exclusive license, except that Defendants may retain, use or sell Dealertrack SmartChat® and the Broker Connection access and interoperability software.
L. Effective immediately upon consummation of Cox's acquisition of control of Dealertrack, Defendants are prohibited from taking any action that would prevent Autodata from immediately exercising any or all of the following rights: (1) Acquiring a majority interest in the ownership of Chrome; (2) appointing the Chief Executive Officer of Chrome; or (3) appointing a third Director to the Board of Directors of Chrome, each pursuant to the change of control provisions of the applicable Chrome Agreements (but without requiring any of the specified waiting periods); provided, however, that Defendants may exercise any right to contest the price that Autodata proposes to pay to acquire a majority interest in the ownership of Chrome, as set forth in the applicable Chrome Agreements.
M. Effective immediately upon consummation of Cox's acquisition of control of Dealertrack, Defendants are hereby enjoined from exercising any rights with respect to the licensing or pricing of Chrome Data to any actual or prospective Chrome customer that competes with Defendants. Provided, however, that nothing in this Section V.M shall prevent Defendants from: (i) Engaging in discussions or negotiations relating to the licensing of Chrome Data to Defendants; or (ii) exercising any rights that Defendants may hold to prevent the renewal of any license that is applicable to the use of Chrome Data in the DMS of either CDK Global, Inc. or The Reynolds and Reynolds
N. Effective immediately upon consummation of Cox's acquisition of control of Dealertrack, Defendants are hereby enjoined from reviewing, receiving, obtaining, sharing, using, or attempting to obtain, share, or use any Competitively Sensitive Information, other than (i) Competitively Sensitive Information relating solely to Defendants; (ii) Competitively Sensitive Information relating solely to Chrome customers with whom Defendants do not compete; or (iii) information about the existence and prospective renewal of Chrome Data licensing agreements with CDK or Reynolds solely to the extent necessary to exercise Defendants' rights in Section V.M.(ii). For the avoidance of doubt, the following is a non-exhaustive list of activities as to which Defendants are enjoined:
(1) exercising any otherwise available audit right for the purpose of, or which would result in, Defendants obtaining access to any such Competitively Sensitive Information;
(2) participating in discussions or meetings of the Board of Directors of Chrome in which any such Competitively Sensitive Information is discussed or otherwise disclosed;
(3) requesting, obtaining, or reviewing any portion of any business plan, strategy, periodic report, or other document in which any such Competitively Sensitive Information is included or otherwise disclosed; and
(4) sharing or using any such Competitively Sensitive Information obtained from, or otherwise disclosed through or by, Chrome, whether inadvertently disclosed or otherwise, for any purpose whatsoever.
O. Defendants shall not acquire, directly or indirectly, any additional assets of or interest in Chrome, or any owner of any interest in Chrome, including Autodata, other than that which Dealertrack owned as of August 1, 2015. If Autodata acquires a majority ownership in Chrome, Defendants shall take no action to increase, directly or indirectly, their resulting minority interest in Chrome. Nothing in this Section V.O shall prohibit Defendants from receiving a proportional or less than proportional distribution of Chrome equity securities in connection with any equity distribution or any future conversion of Chrome into a corporation so long as Defendants' economic share in Chrome does not increase as a result of such distribution.
P. Promptly after Cox's acquisition of control of Dealertrack, Defendants shall use all reasonable efforts to amend or otherwise change the Chrome Agreements to incorporate into such agreements all of the requirements in Sections V.L through V.O. The required amendments or changes shall: (i) be acceptable to the United States, in its sole discretion; (ii) have no expiration date; and (iii) provide that they may not be withdrawn, amended, or otherwise changed without the consent of Autodata and, prior to the expiration of this Final Judgment, the United States. Provided, however, that any such amendments or changes to the Chrome Agreements may be applicable only to Defendants and may automatically terminate upon Defendants' sale of their entire interest in Chrome.
A. If Defendants have not divested the Divestiture Assets within the time period specified in Section IV.A of this Final Judgment, Defendants shall notify the United States of that fact in writing. Upon application of the United States, the Court shall appoint a Divestiture Trustee selected by the United States and approved by the Court to effect the divestiture of the Divestiture Assets.
B. After the appointment of a Divestiture Trustee becomes effective, only the Divestiture Trustee shall have the right to sell the Divestiture Assets. The Divestiture Trustee shall have the power and authority to accomplish the divestiture to an Acquirer acceptable to the United States at such price and on such terms as are then obtainable upon reasonable effort by the Divestiture Trustee, subject to the provisions of Sections IV, VI and VII of this Final Judgment, and shall have such other powers as this Court deems appropriate. Subject to Section VI.D. of this Final Judgment, the Divestiture Trustee may hire at the cost and expense of Defendants any investment bankers, attorneys, or other agents, who shall be solely accountable to the Divestiture Trustee, reasonably necessary in the Divestiture Trustee's judgment to assist in the divestiture. Any such investment bankers, attorneys, or other agents shall serve on such terms and conditions as the United States approves, including confidentiality requirements and conflict of interest certifications.
C. Defendants shall not object to a sale by the Divestiture Trustee on any ground other than the Divestiture Trustee's malfeasance. Any such objections by Defendants must be conveyed in writing to the United States and the Divestiture Trustee within ten (10) calendar days after the Divestiture Trustee has provided the notice required under Section VII of this Final Judgment.
D. The Divestiture Trustee shall serve at the cost and expense of Defendants pursuant to a written agreement, on such terms and conditions as the United States approves, including confidentiality requirements and conflict of interest certifications. The Divestiture Trustee shall account for all monies derived from the sale of the assets sold by the Divestiture Trustee and all costs and expenses so incurred. After approval by the Court of the Divestiture Trustee's accounting, including fees for its services yet unpaid and those of any professionals and agents retained by the Divestiture Trustee, all remaining money shall be paid to Defendants and the trust shall then be terminated. The compensation of the Divestiture Trustee and any professionals and agents retained by the Divestiture Trustee shall be reasonable in light of the value of the Divestiture Assets and based on a fee arrangement providing the Divestiture Trustee with an incentive based on the price and terms of the divestiture and the speed with which it is accomplished, but timeliness is paramount. If the Divestiture Trustee and Defendants are unable to reach agreement on the Divestiture Trustee's or any agents' or consultants' compensation or other terms and conditions of engagement within fourteen (14) calendar days of appointment of the Divestiture Trustee, the United States may, in its sole discretion, take appropriate action, including making a recommendation to the Court. The Divestiture Trustee shall, within three (3) business days of hiring any other professionals or agents, provide written notice of such hiring and the rate of compensation to Defendants and the United States.
E. Defendants shall use their best efforts to assist the Divestiture Trustee in accomplishing the required divestiture. The Divestiture Trustee and any consultants, accountants, attorneys, and other agents retained by the Divestiture Trustee shall have full and complete access to the personnel, books, records, and facilities of the business to be divested, and Defendants shall develop financial and other information relevant to such business as the Divestiture Trustee may reasonably request, subject to reasonable protection for trade secret or other confidential research, development, or commercial information or any applicable privileges. Defendants shall take no
F. After its appointment, the Divestiture Trustee shall file monthly reports with the United States and, as appropriate, the Court setting forth the Divestiture Trustee's efforts to accomplish the divestiture ordered by this Final Judgment. To the extent such reports contain information that the Divestiture Trustee deems confidential, such reports shall not be filed in the public docket of the Court. Such reports shall include the name, address, and telephone number of each Person who, during the preceding month, made an offer to acquire, expressed an interest in acquiring, entered into negotiations to acquire, or was contacted or made an inquiry about acquiring, any interest in the Divestiture Assets, and shall describe in detail each contact with any such Person. The Divestiture Trustee shall maintain full records of all efforts made to divest the Divestiture Assets.
G. If the Divestiture Trustee has not accomplished the divestiture ordered under this Final Judgment within six (6) months after its appointment, the Divestiture Trustee shall promptly file with the Court a report setting forth (1) the Divestiture Trustee's efforts to accomplish the required divestiture, (2) the reasons, in the Divestiture Trustee's judgment, why the required divestiture has not been accomplished, and (3) the Divestiture Trustee's recommendations. To the extent such report contains information that the Divestiture Trustee deems confidential, such report shall not be filed in the public docket of the Court. The Divestiture Trustee shall at the same time furnish such report to the United States, which shall have the right to make additional recommendations consistent with the purpose of the trust. The Court thereafter shall enter such orders as it shall deem appropriate to carry out the purpose of this Final Judgment, which may, if necessary, include extending the trust and the term of the Divestiture Trustee's appointment by a period requested by the United States.
H. If the United States determines that the Divestiture Trustee has ceased to act or failed to act diligently or in a reasonably cost-effective manner, it may recommend that the Court appoint a substitute Divestiture Trustee.
A. Within two (2) business days following execution of a definitive divestiture agreement, Defendants or the Divestiture Trustee, whichever is then responsible for effecting the divestiture required herein, shall notify the United States of any proposed divestiture required by Section IV or VI of this Final Judgment. If the Divestiture Trustee is responsible, it shall similarly notify Defendants. The notice shall set forth the details of the proposed divestiture and list the name, address, and telephone number of each Person not previously identified who offered or expressed an interest in or desire to acquire any ownership interest in the Divestiture Assets, together with full details of the same.
B. Within fifteen (15) calendar days of receipt by the United States of such notice, the United States may request from Defendants, the proposed Acquirer, any other third party, or the Divestiture Trustee, if applicable, additional information concerning the proposed divestiture, the proposed Acquirer, and any other potential Acquirer. Defendants and the Divestiture Trustee shall furnish any additional information requested within fifteen (15) calendar days of the receipt of the request, unless the parties shall otherwise agree.
C. Within thirty (30) calendar days after receipt of the notice or within twenty (20) calendar days after the United States has been provided the additional information requested from Defendants, the proposed Acquirer, any third party, and the Divestiture Trustee, whichever is later, the United States shall provide written notice to Defendants and the Divestiture Trustee, if there is one, stating whether or not it objects to the proposed divestiture. If the United States provides written notice that it does not object, the divestiture may be consummated, subject only to Defendants' limited right to object to the sale under Section VI.C. of this Final Judgment. Absent written notice that the United States does not object to the proposed Acquirer or upon objection by the United States, a divestiture proposed under Section IV or Section V shall not be consummated. Upon objection by Defendants under Section VI.C., a divestiture proposed under Section VI shall not be consummated unless approved by the Court.
Defendants shall not finance all or any part of any purchase made pursuant to Section IV or VI of this Final Judgment.
Until the divestiture required by this Final Judgment has been accomplished, Defendants shall take all steps necessary to comply with the Hold Separate Stipulation and Order entered by this Court. Defendants shall take no action that would jeopardize the divestiture ordered by this Court.
A. Within twenty (20) calendar days of the filing of the Complaint in this matter, and every thirty (30) calendar days thereafter until the divestiture has been completed under Section IV or VI, Defendants shall deliver to the United States an affidavit as to the fact and manner of its compliance with Section IV or VI of this Final Judgment. Each such affidavit shall include the name, address, and telephone number of each Person who, during the preceding thirty (30) calendar days, made an offer to acquire, expressed an interest in acquiring, entered into negotiations to acquire, or was contacted or made an inquiry about acquiring, any interest in the Divestiture Assets, and shall describe in detail each contact with any such Person during that period. Each such affidavit shall also include a description of the efforts Defendants have taken to solicit buyers for the Divestiture Assets, and to provide required information to prospective Acquirers, including the limitations, if any, on such information. Assuming the information set forth in the affidavit is true and complete, any objection by the United States to information provided by Defendants, including limitation on information, shall be made within fourteen (14) calendar days of receipt of such affidavit.
B. Within twenty (20) calendar days of the filing of the Complaint in this matter, Defendants shall deliver to the United States an affidavit that describes in reasonable detail all actions Defendants have taken and all steps Defendants have implemented on an ongoing basis to comply with Section IX of this Final Judgment. Defendants shall deliver to the United States an affidavit describing any changes to the efforts and actions outlined in Defendants' earlier affidavits filed pursuant to this section within fifteen (15) calendar days after the change is implemented.
C. Defendants shall keep all records of all efforts made to preserve and divest the Divestiture Assets until one year after such divestiture has been completed.
A. Upon application of the United States, the Court shall appoint a Monitoring Trustee selected by the United States and approved by the Court.
B. The Monitoring Trustee shall have the power and authority to monitor Defendants' compliance with the terms of this Final Judgment and the Hold Separate Stipulation and Order entered by this Court, and shall have such other powers as this Court deems appropriate. The Monitoring Trustee shall be required to investigate and report on the Defendants' compliance with this Final Judgment and the Hold Separate Stipulation and Order and the Defendants' progress toward effectuating the purposes of this Final Judgment, including but not limited to:
(1) Defendants' compliance with the terms of the Transition Services Agreement; and
(2) Defendants' compliance with the terms listed in Section V, “Other Required Conduct.”
C. Subject to Section XI.E. of this Final Judgment, the Monitoring Trustee may hire at the cost and expense of Defendants any consultants, accountants, attorneys, or other agents, who shall be solely accountable to the Monitoring Trustee, reasonably necessary in the Monitoring Trustee's judgment. Any such consultants, accountants, attorneys, or other agents shall serve on such terms and conditions as the United States approves, including confidentiality requirements and conflict of interest certifications.
D. Defendants shall not object to actions taken by the Monitoring Trustee in fulfillment of the Monitoring Trustee's responsibilities under any Order of this Court on any ground other than the Monitoring Trustee's malfeasance. Any such objections by Defendants must be conveyed in writing to the United States and the Monitoring Trustee within ten (10) calendar days after the action taken by the Monitoring Trustee giving rise to the Defendants' objection.
E. The Monitoring Trustee shall serve at the cost and expense of Defendants pursuant to a written agreement with Defendants and on such terms and conditions as the United States approves including confidentiality requirements and conflict of interest certifications. The compensation of the Monitoring Trustee and any consultants, accountants, attorneys, and other agents retained by the Monitoring Trustee shall be on reasonable and customary terms commensurate with the individuals' experience and responsibilities. If the Monitoring Trustee and Defendants are unable to reach agreement on the Monitoring Trustee's or any agents' or consultants' compensation or other terms and conditions of engagement within fourteen (14) calendar days of appointment of the Monitoring Trustee, the United States may, in its sole discretion, take appropriate action, including making a recommendation to the Court. The Monitoring Trustee shall, within three (3) business days of hiring any consultants, accountants, attorneys, or other agents, provide written notice of such hiring and the rate of compensation to Defendants and the United States.
F. The Monitoring Trustee shall have no responsibility or obligation for the operation of Defendants' businesses.
G. Defendants shall use their best efforts to assist the Monitoring Trustee in monitoring Defendants' compliance with their individual obligations under this Final Judgment and under the Hold Separate Stipulation and Order. The Monitoring Trustee and any consultants, accountants, attorneys, and other agents retained by the Monitoring Trustee shall have full and complete access to the personnel, books, records, and facilities relating to compliance with this Final Judgment, subject to reasonable protection for trade secret or other confidential research, development, or commercial information or any applicable privileges. Defendants shall take no action to interfere with or to impede the Monitoring Trustee's accomplishment of its responsibilities.
H. After its appointment, the Monitoring Trustee shall file reports quarterly, or more frequently as needed, with the United States, and, as appropriate, the Court setting forth Defendants' efforts to comply with its obligations under this Final Judgment and under the Hold Separate Stipulation and Order. To the extent such reports contain information that the Monitoring Trustee deems confidential, such reports shall not be filed in the public docket of the Court.
I. The Monitoring Trustee shall serve until the divestiture of all the Divestiture Assets is finalized pursuant to either Section IV or Section VI of this Final Judgment and for so long as the Defendant's obligations outlined in Section V persist.
J. If the United States determines that the Monitoring Trustee has ceased to act or failed to act diligently or in a reasonably cost-effective manner, it may recommend the Court appoint a substitute Monitoring Trustee.
A. For the purposes of determining or securing compliance with this Final Judgment, or of any related orders such as any Hold Separate or Asset Preservation Order, or of determining whether the Final Judgment should be modified or vacated, and subject to any legally recognized privilege, from time to time authorized representatives of the United States Department of Justice, including consultants and other persons retained by the United States, shall, upon written request of an authorized representative of the Assistant Attorney General in charge of the Antitrust Division, and on reasonable notice to Defendants, be permitted:
(1) access during Defendants' office hours to inspect and copy, or at the option of the United States, to require Defendants to provide hard copy or electronic copies of, all books, ledgers, accounts, records, data, and documents in the possession, custody, or control of Defendants, relating to any matters contained in this Final Judgment; and
(2) to interview, either informally or on the record, Defendants' officers, employees, or agents, who may have their individual counsel present, regarding such matters. The interviews shall be subject to the reasonable convenience of the interviewee and without restraint or interference by Defendants.
B. Upon the written request of an authorized representative of the Assistant Attorney General in charge of the Antitrust Division, Defendants shall submit written reports or response to written interrogatories, under oath if requested, relating to any of the matters contained in this Final Judgment as may be requested.
C. No information or documents obtained by the means provided in this Section XII shall be divulged by the United States to any person other than an authorized representative of the executive branch of the United States, except in the course of legal proceedings to which the United States is a party (including grand jury proceedings), or for the purpose of securing compliance with this Final Judgment, or as otherwise required by law.
D. If at the time information or documents are furnished by Defendants to the United States, Defendants represent and identify in writing the material in any such information or documents to which a claim of protection may be asserted under Rule 26(c)(1)(G) of the Federal Rules of Civil Procedure, and Defendants mark each pertinent page of such material, “Subject to claim of protection under Rule 26(c)(1)(G) of the Federal Rules of Civil Procedure,” then the United States shall give Defendants ten (10) calendar days notice prior to divulging such material in any legal proceeding (other than a grand jury proceeding).
Defendants may not reacquire any part of the Divestiture Assets during the term of this Final Judgment.
This Court retains jurisdiction to enable any party to this Final Judgment to apply to this Court at any time for further orders and directions as may be necessary or appropriate to carry out or construe this Final Judgment, to modify any of its provisions, to enforce compliance, and to punish violations of its provisions.
Unless this Court grants an extension, this Final Judgment shall expire ten (10) years from the date of its entry.
Entry of this Final Judgment is in the public interest. The parties have complied with the requirements of the Antitrust Procedures and Penalties Act, 15 U.S.C. 16, including making copies available to the public of this Final Judgment, the Competitive Impact Statement, and any comments thereon and the United States' responses to comments. Based upon the record before the Court, which includes the Competitive Impact Statement and any comments and response to comments filed with the Court, entry of this Final Judgment is in the public interest.
List of products and functionality included in “Divested Product,” as defined in Section II.L of this Final Judgment:
Notice of registration.
Unither Manufacturing, LLC applied to be registered as an importer of a certain basic class of controlled substance. The Drug Enforcement Administration (DEA) grants Unither Manufacturing, LLC registration as an importer of this controlled substance.
By notice dated April 14, 2015, and published in the
The DEA has considered the factors in 21 U.S.C. 823, 952(a) and 958(a) and determined that the registration of Unither Manufacturing, LLC to import the basic class of controlled substance is consistent with the public interest and with United States obligations under international treaties, conventions, or protocols in effect on May 1, 1971. The DEA investigated the company's maintenance of effective controls against diversion by inspecting and testing the company's physical security systems, verifying the company's compliance with state and local laws, and reviewing the company's background and history.
Therefore, pursuant to 21 U.S.C. 952(a) and 958(a), and in accordance with 21 CFR 1301.34, the above-named company is granted registration as an importer of methylphenidate (1724), a basic class of controlled substance listed in schedule II.
The company plans to import the listed substance as a raw material for updated testing purposes for EU customer requirements.
The company plans to import the listed controlled substances in finished dosage form (FDF) from foreign sources for analytical testing and clinical trials in which the foreign FDF will be compared to the company's own domestically-manufactured FDF. This analysis is required to allow the company to export domestically-manufactured FDF to foreign markets.
Notice of application.
Registered bulk manufacturers of the affected basic classes, and applicants therefore, may file written comments on or objections to the issuance of the proposed registration in accordance with 21 CFR 1301.33(a) on or before December 14, 2015.
Written comments should be sent to: Drug Enforcement Administration, Attention: DEA Federal Register Representative/ODXL, 8701 Morrissette Drive, Springfield, Virginia 22152. Request for hearings should be sent to: Drug Enforcement Administration, Attention: Hearing Clerk/LJ, 8701 Morrissette Drive, Springfield, Virginia 22152.
The Attorney General has delegated her authority under the Controlled Substances Act to the Administrator of the Drug Enforcement Administration (DEA), 28 CFR 0.100(b). Authority to exercise all necessary functions with respect to the promulgation and implementation of 21 CFR part 1301, incident to the registration of manufacturers, distributors, dispensers, importers, and exporters of controlled substances (other than final orders in connection with suspension, denial, or revocation of registration) has been redelegated to the Deputy Assistant Administrator of the DEA Office of Diversion Control (“Deputy Assistant Administrator”) pursuant to section 7 of 28 CFR part 0, appendix to subpart R.
In accordance with 21 CFR 1301.33(a), this is notice that on August 10, 2015, American Radiolabeled Chemicals, Inc., 101 Arc Drive, St. Louis, Missouri 63146 applied to be registered as a bulk manufacturer of the following basic classes of controlled substances:
The company plans to manufacture small quantities of the listed controlled substances as radiolabeled compounds for biochemical research.
Notice of application.
Registered bulk manufacturers of the affected basic class, and applicants therefore, may file written comments on or objections to the issuance of the proposed registration in accordance with 21 CFR 1301.33(a) on or before December 14, 2015.
Written comments should be sent to: Drug Enforcement Administration, Attention: DEA
The Attorney General has delegated her authority under the Controlled Substances Act to the Administrator of the Drug Enforcement Administration (DEA), 28 CFR 0.100(b). Authority to exercise all necessary functions with respect to the promulgation and implementation of 21 CFR part 1301, incident to the registration of manufacturers, distributors, dispensers, importers, and exporters of controlled substances (other than final orders in connection with suspension, denial, or revocation of registration) has been redelegated to the Deputy Assistant Administrator of the DEA Office of Diversion Control (“Deputy Assistant Administrator”) pursuant to section 7 of 28 CFR part 0, appendix to subpart R.
In accordance with 21 CFR 1301.33(a), this is notice that on August 7, 2015, Cambridge Isotope Lab, 50 Frontage Road, Andover, Massachusetts 01810 applied to be registered as a bulk manufacturer of morphine (9300), a basic class of controlled substance listed in schedule II.
The company plans to utilize small quantities of the listed controlled substance in the preparation of analytical standards.
Notice of application.
Registered bulk manufacturers of the affected basic classes, and applicants therefore, may file written comments on or objections to the issuance of the proposed registration in accordance with 21 CFR 1301.33(a) on or before December 14, 2015.
Written comments should be sent to: Drug Enforcement Administration, Attention: DEA
The Attorney General has delegated her authority under the Controlled Substances Act to the Administrator of the Drug Enforcement Administration (DEA), 28 CFR 0.100(b). Authority to exercise all necessary functions with respect to the promulgation and implementation of 21 CFR part 1301, incident to the registration of manufacturers, distributors, dispensers, importers, and exporters of controlled substances (other than final orders in connection with suspension, denial, or revocation of registration) has been redelegated to the Deputy Assistant Administrator of the DEA Office of Diversion Control (“Deputy Assistant Administrator”) pursuant to section 7 of 28 CFR part 0, appendix to subpart R.
In accordance with 21 CFR 1301.33(a), this is notice that on August 6, 2015, Apertus Pharmaceuticals, 331 Consort Drive, St. Louis, Missouri 63011 applied to be registered as a bulk manufacturer of the following basic classes of controlled substances:
The company plans to manufacture the above-listed controlled substances in bulk for distribution to its customers. In reference to drug codes 7360 marihuana and 7370 tetrahydrocannabinols the company plans to bulk manufacture both as synthetic substances.
No other activity for these drug codes is authorized for this registration.
Office for Victims of Crime, Department of Justice.
60-Day notice.
The Department of Justice (DOJ), Office of Justice Programs, Office for Victims of Crime, will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995. The following collections (1121-0336 and 1121-0342) will be discontinued and combined with this revision of 1121-0341.
Comments are encouraged and will be accepted for 60 days until December 14, 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 Shelby Jones Crawford, Program Manager, Office for Victims of Crime, Office of Justice Programs, Department of Justice, 810 7th Street NW., Washington, DC 20530.
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;
—Evaluate whether and if so how the quality, utility, and clarity of the information to be collected can be enhanced; 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:
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If additional information is required contact: Jerri Murray, Department Clearance Officer, United States Department of Justice, Justice Management Division, Policy and Planning Staff, Two Constitution Square, 145 N Street NE., 3E.405B, Washington, DC 20530.
Employment and Training Administration, Labor.
Renewal of the Native American Employment and Training Council (NAETC) Charter.
Notice is hereby given of the renewal of the Workforce Innovation and Opportunity Act (WIOA), section 166 Indian and Native American Programs Charter that is necessary and in the public interest. Accordingly, the U.S. Department of Labor (the Department), Employment and Training Administration (ETA) has renewed the NAETC Charter for two years with revisions. The revisions are not intended to change the purpose or the Council's original intent. The revisions include language regarding the use of proxies and changes to the membership balance plan. The Council Charter expired on September 9, 2015.
Athena Brown, Designated Federal Officer, Office of Workforce Investment, Employment and Training Administration, U.S. Department of Labor, Room S-4209, 200 Constitution Avenue NW., Washington, DC 20210. Telephone: (202) 693-3737, (this is not a toll-free number).
Occupational Safety and Health Administration (OSHA), Labor.
Notice.
In this notice, OSHA announces the application of SGS North America, Inc. for expansion of its scope of recognition as a Nationally Recognized Testing Laboratory (NRTL) and presents the Agency's preliminary finding to grant the application. Additionally, OSHA proposes incorporating one new test standard to the NRTL Program's list of appropriate test standards.
Submit comments, information, and documents in response to this notice, or requests for an extension of time to make a submission, on or before October 28, 2015.
Submit comments by any of the following methods:
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Information regarding this notice is available from the following sources:
The Occupational Safety and Health Administration is providing notice that SGS North America, Inc. (SGS), is applying for expansion of its current recognition as an NRTL. SGS requests the addition of five (5) recognized testing and certification sites, and fourteen (14) additional test standards to its NRTL scope of recognition.
OSHA recognition of an NRTL signifies that the organization meets the requirements specified in Title 29, Code of Federal Regulations, Section 1910.7 (29 CFR 1910.7). Recognition is an acknowledgment that the organization can perform independent safety testing and certification of the specific products covered within its scope of recognition and is not a delegation or grant of government authority. Recognition enables employers to use products approved by the NRTL to meet OSHA standards that require product testing and certification.
The Agency processes applications by an NRTL for initial recognition and for an expansion or renewal of this recognition, following requirements in Appendix A to 29 CFR 1910.7. This appendix requires that the Agency publish two notices in the
Each NRTL's scope of recognition has three elements: (1) The type of products the NRTL may test, with each type specified by its applicable test standard; (2) the recognized site(s) that has/have the technical capability to perform the product testing and product-certification activities for test standards within the NRTL's scope; and (3) the supplemental program(s) that the NRTL may use. Each of these elements allows the NRTL to rely on other parties to perform activities necessary for product testing and certification.
SGS currently has one facility (site) recognized by OSHA for product testing and certification, with its headquarters located at: SGS North America, Inc., 620 Old Peachtree Road, Suwanee, Georgia 30024. A complete list of SGS sites recognized by OSHA is available at
SGS submitted an application, dated October 1, 2014 (OSHA-2006-0040, Exhibit 15-1 SGS Expansion Application), to expand its recognition to include the addition of five recognized testing and certification sites located at: SGS-CSTC Standards Technical Services Co., Ltd. Guangzhou Branch, 198 Kezhu Road, Scientech Park Guangzhou Economic & Technology Development District, Guangzhou, Guangdong, China, 510663; SGS-CSTC Standards Technical Services Co., Ltd. Shunde Branch, 198 Kezhu Road, Scientech Park Building 1, European Industrial Park, No. 1, Shunde South Road, Wusha, Daliang, Shunde District, Foshan, Guangdong, China; SGS-CSTC Standards Technical Services Co., Ltd Ningbo Branch, 1-5/F., West of Building 4, Lingyun Industry Park, No. 1177, Lingyun Road, Ningbo National Hi-Tech Zone, Ningbo, Zhejiang, China; SGS-CSTC Standards Services Co., Ltd. Shenzhen Branch, No. 1 Workshop, M-10, Middle Section, Science & Technology Park, Nan Shan District, Shenzhen, China 518057; SGS-CSTC Standards Technical Services (Shanghai) Co., Ltd., No 588 West Jindu Road, Xinqiao Town, Songjiang District 201612, Shanghai, China. SGS's application also requested the addition of fourteen additional test standards to its scope of recognition. OSHA staff performed an on-site review of SGS's testing facilities on June 15, 2015 at SGS Shanghai, June 18, 2015 at SGS Ningbo, June 22, 2015 at SGS Shenzhen, June 24, 2015 at the two SGS Guangdong locations (Guangzhou and Shunde) in which the assessors found some nonconformances with the requirements of 29 CFR 1910.7. SGS addressed these issues sufficiently, and OSHA staff preliminarily determined that OSHA should grant the application.
Table 1 below lists the appropriate test standards found in SGS's application for expansion for testing and certification of products under the NRTL Program. One of these test standards, UL 60335-2-24, is new to the NRTL Program, and OSHA preliminarily determined that it is an “appropriate test standard” within the meaning of 29 CFR 1910.7(c).
1. SGS submitted an acceptable application for expansion of its scope of recognition. OSHA's review of the application file and its detailed on-site assessments indicate that SGS can meet the requirements prescribed by 29 CFR 1910.7 for expanding its recognition to include the addition of five sites and these fourteen test standards for NRTL testing and certification. This preliminary finding does not constitute an interim or temporary approval of SGS's application.
2. The UL 60335-2-24 standard is an appropriate test standard, and OSHA proposes to include this test standard in the NRTL Program's list of appropriate test standards.
OSHA welcomes public comment as to whether SGS meets the requirements of 29 CFR 1910.7 for expansion of its recognition as an NRTL. OSHA also seeks comments as to whether or not the UL 60335-2-24 test standard is an appropriate test standard under the NRTL Program. Comments should consist of pertinent written documents and exhibits. Commenters needing more time to comment must submit a request in writing, stating the reasons for the request. Commenters must submit the written request for an extension by the due date for comments. OSHA will limit any extension to 10 days unless the requester justifies a longer period. OSHA may deny a request for an extension if it is not adequately justified. To obtain or review copies of the exhibits identified in this notice, as well as comments submitted to the docket, contact the Docket Office, Room N-2625, Occupational Safety and Health Administration, U.S. Department of Labor, at the above address. These materials also are available online at
OSHA staff will review all comments to the docket submitted in a timely manner and, after addressing the issues raised by these comments, will recommend to the Assistant Secretary for Occupational Safety and Health whether to grant SGS's application for expansion of its scope of recognition. The Assistant Secretary will make the final decision on granting the application. In making this decision, the Assistant Secretary may undertake other proceedings prescribed in Appendix A to 29 CFR 1910.7.
OSHA will incorporate into its informational Web pages the modifications OSHA decides to make to its current list of NRTL test standards, as well as any changes to an NRTL's scope of recognition. Access to these Web pages is available at
OSHA will publish a public notice of this final decision in the
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, 200 Constitution Avenue NW., Washington, DC 20210, authorized the preparation of this notice. Accordingly, the Agency is issuing this notice pursuant to 29 U.S.C. 657(g)(2), Secretary of Labor's Order No. 1-2012 (77 FR 3912, Jan. 25, 2012), and 29 CFR 1910.7.
10:00 a.m., Thursday, October 15, 2015.
Board Room, 7th Floor, Room 7047, 1775 Duke Street (All visitors must use Diagonal Road Entrance), Alexandria, VA 22314-3428.
Open.
1. National Credit Union Share Insurance Fund Quarterly Report.
2. NCUA Rules and Regulations, Permissible Investment Activities—Bank Notes.
3. Delegations of Authority, Approval of Community Charter Requests.
4. NCUA Rules and Regulations, Prompt Corrective Action and Risk-Based Capital Measures.
11:15 a.m.
11:30 a.m., Thursday, October 15, 2015.
Board Room, 7th Floor, Room 7047, 1775 Duke Street, Alexandria, VA 22314-3428.
Closed.
1. Consideration of Supervisory Action. Closed pursuant to Exemptions (8), (9)(i)(B), and (9)(ii).
2. Review of Supervisory Action. Closed pursuant to Exemptions (8), (9)(i)(B), and (9)(ii).
3. Personnel. Closed pursuant to Exemptions (2) and (6).
Gerard Poliquin, Secretary of the Board, Telephone: 703-518-6304.
National Science Foundation.
Announcement of Membership of the National Science Foundation's Senior Executive Service Performance Review Board.
This announcement of the membership of the National Science Foundation's Senior Executive Service Performance Review Board is made in compliance with 5 U.S.C. 4314(c)(4).
Comments should be addressed to Division Director, Division of Human Resource Management, National Science Foundation, Room 315, 4201 Wilson Boulevard, Arlington, VA 22230.
Dr. Judith S. Sunley at the above address or (703) 292-8180.
The membership of the National Science Foundation's Senior Executive Service Performance Review Board is as follows:
The ACRS Subcommittee on Thermal-Hydraulic Phenomena will hold a meeting on October 20, 2015, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance with the exception of portions that may be closed to protect information that is propriety pursuant to 5 U.S.C. 552b(c)(4). The agenda for the subject meeting shall be as follows:
The Subcommittee will review Westinghouse report, WCAP-17788-P, Revision 0, “Comprehensive Analysis and Test Program for GSI-191 Closure (PA-SEE-1090).” The Subcommittee will hear presentations by and hold discussions with the NRC staff, industry, and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Weidong Wang (Telephone 301-415-6279 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
Revised director's decision under 10 CFR 2.206; issuance.
The U.S. Nuclear Regulatory Commission (NRC or the Commission) has issued a revised director's decision (DD) with regard to a petition dated June 18, 2012, filed by Mr. Richard Ayres, Counsel for Friends of the Earth (the petitioner), requesting that the NRC take action with regard to Southern California Edison (SCE or the licensee) at the San Onofre Nuclear Generating Station (SONGS). The petitioner's requests, the letter to the petitioner, the letter to the licensee, and the DD are included in the
Please refer to Docket ID NRC-2013-0083 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
• Federal Rulemaking Web site: Go to
• NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly-available documents online in the ADAMS Public Documents collection at
• NRC's PDR: You may examine and purchase copies of public documents at the NRC's PDR, Room O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852.
Thomas Wengert, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-4037, email:
Notice is hereby given that the Director, Office of Nuclear Reactor Regulation, has issued a revision to a DD dated July 28, 2015 (ADAMS Accession No. ML15183A164), on a portion of an intervention and hearing request petition filed by the petitioner on June 18, 2012 (ADAMS Accession No. ML12171A409), that was referred to the NRC's Office of the Executive Director for Operations by the Commission in its November 8, 2013, Memorandum and Order CLI-12-20 (ADAMS Accession No. ML12313A118), for consideration as a petition under section 2.206 of Title 10 of the
The petitioner requested that the NRC order SCE to submit a license amendment application for the design and installation of the SONGS, Units 2 and 3, replacement steam generators (SGs) and to suspend SCE's licenses until they are amended.
As the basis of the request, the petitioner asserted that the licensee violated 10 CFR 50.59, “Changes, tests, and experiments,” when the SGs for SONGS, Units 2 and 3, were replaced in 2010 and 2011 without a license amendment request.
The NRC sent a copy of the proposed DD to the petitioner and the licensee for comment on February 27, 2015 (ADAMS Accession Nos. ML15020A121 and ML15020A165, respectively). The petitioner and the licensee were asked to provide comments within 30 days on any part of the proposed DD that was considered to be erroneous or any issues in the petition that were not addressed. Comments were received from the petitioner and were addressed in an attachment to the final DD. The licensee had no comments on the proposed DD; however, the licensee did provide a response to the petitioner's comments. The NRC staff reviewed the response from the licensee and determined that because the licensee's comments are direct rebuttals to the petitioner's comments and raised no concerns with the proposed DD, that no changes to the final DD were required as a result of the licensee's comments.
On July 28, 2015, the NRC issued a DD regarding this matter. Subsequently, the NRC identified portions of this DD that required clarification regarding the scope of the petition and the decision. Accordingly, Section I of the DD is revised to clarify that the scope of the petition, which was referred by the Commission to the NRC staff in Memorandum and Order CLI-12-20, includes the underlying question of whether the licensee violated 10 CFR 50.59 when it replaced the SGs at SONGS, Units 2 and 3, without first obtaining a license amendment. Section II addresses the NRC staff's resolution of this underlying question; and the conclusion in Section III is updated to reflect the resolution of this underlying question. Section II is also revised to clarify additional NRC staff activities associated with the SONGS SG event that support the conclusion regarding whether the licensee violated 10 CFR 50.59 by replacing the SGs without a license amendment.
As stated in the DD, the Director of the Office of Nuclear Reactor Regulation has determined that the requests for the NRC to order the licensee to submit a license amendment application for the design and installation of the SONGS, Units 2 and 3, replacement SGs and to suspend SCE's licenses until they are amended be denied. The reasons for this decision are explained in the DD (DD-15-07; ADAMS Accession No. ML15267A158) pursuant to 10 CFR 2.206, “Requests for action under this subpart,” of the Commission's regulations.
The NRC will file a copy of the DD with the Secretary of the Commission for the Commission's review in accordance with 10 CFR 2.206. As provided by this regulation, the revised DD will constitute the final action of the Commission 25 days after the date of the decision unless the Commission, on its own motion, institutes a review of the DD in that time.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Biweekly notice.
Pursuant to Section 189a.(2) of the Atomic Energy Act of 1954, as amended (the Act), the U.S. Nuclear Regulatory Commission (NRC) is publishing this regular biweekly notice. The Act requires the Commission to publish notice of any amendments issued, or proposed to be issued, and grants the Commission the authority to issue and make immediately effective any amendment to an operating license or combined license, as applicable, upon a determination by the Commission that such amendment involves no significant hazards consideration, notwithstanding the pendency before the Commission of a request for a hearing from any person.
This biweekly notice includes all notices of amendments issued, or proposed to be issued from September 15 to September 28, 2015. The last biweekly notice was published on September 29, 2015.
Comments must be filed by November 12, 2015. A request for a hearing must be filed by December 14, 2015.
You may submit comments by any of the following methods (unless this document describes a different
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For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Janet Burkhardt, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; telephone: 301-415-1384, email:
Please refer to Docket ID NRC-2015-0236 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-2015-0236, facility name, unit number(s), application date, and subject in 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 posts all comment submissions at
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The Commission has made a proposed determination that the following amendment requests involve no significant hazards consideration. Under the Commission's regulations in § 50.92 of Title 10 of the
The Commission is seeking public comments on this proposed determination. Any comments received within 30 days after the date of publication of this notice will be considered in making any final determination.
Normally, the Commission will not issue the amendment until the expiration of 60 days after the date of publication of this notice. The Commission may issue the license amendment before expiration of the 60-day period provided that its final determination is that the amendment involves no significant hazards consideration. In addition, the Commission may issue the amendment prior to the expiration of the 30-day comment period should circumstances change during the 30-day comment period such that failure to act in a timely way would result, for example in derating or shutdown of the facility. Should the Commission take action prior to the expiration of either the comment period or the notice period, it will publish in the
Within 60 days after the date of publication of this notice, any person(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license or combined license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the NRC's PDR, located at One White Flint North, Room O1-F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852. The NRC's regulations are accessible electronically from the NRC Library on the NRC's Web site at
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert opinion which support the contention and on which the requestor/petitioner intends to rely in proving the contention at the hearing. The requestor/petitioner must also provide references to those specific sources and documents of which the petitioner is aware and on which the requestor/petitioner intends to rely to establish those facts or expert opinion. The petition must include sufficient information to show that a genuine dispute exists with the applicant on a material issue of law or fact. Contentions shall be limited to matters within the scope of the amendment under consideration. The contention must be one which, if proven, would entitle the requestor/petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing.
If a hearing is requested, the Commission will make a final determination on the issue of no significant hazards consideration. The final determination will serve to decide when the hearing is held. If the final determination is that the amendment request involves no significant hazards consideration, the Commission may issue the amendment and make it immediately effective, notwithstanding the request for a hearing. Any hearing held would take place after issuance of the amendment. If the final determination is that the amendment request involves a significant hazards consideration, then any hearing held would take place before the issuance of any amendment unless the Commission finds an imminent danger to the health or safety of the public, in which case it will issue an appropriate order or rule under 10 CFR part 2.
Petitions for leave to intervene must be filed no later than 60 days from the date of publication of this notice. Requests for hearing, petitions for leave to intervene, and motions for leave to file new or amended contentions that are filed after the 60-day deadline will not be entertained absent a determination by the presiding officer that the filing demonstrates good cause by satisfying the three factors in 10 CFR 2.309(c)(1)(i)-(iii).
For further details with respect to these license amendment applications, see the application for amendment which is available for public inspection in ADAMS and at the NRC's PDR. For additional direction on accessing information related to this document, see the “Obtaining Information and Submitting Comments” section of this document.
1. Does the proposed amendment involve a significant increase in the probability or consequences of any accident previously evaluated?
Response: No.
The post-modification configuration of the offsite 345 [kilovolt (kV)] transmission system (four lines separately supported and SLOD disabled) improves overall grid reliability and continues to meet the requirements for two independent sources of offsite power (GDC-17). Therefore, the post-modification configuration does not significantly increase the probability or consequences of a loss of offsite power event. Likewise, the associated proposed changes to the MPS2 and MPS3 FSARs to document the revised 345 kV transmission line tower design and disabling of SLOD, do not increase the probability or consequences of an accident previously evaluated in the FSARs.
The grid (offsite power) is by design, the preferred power source for the affected units. The grid provides a reliable source of power to MPS2 and MPS3 while the units are at power, in the event of unit trips, and when the units are shut down for maintenance. New TRM requirements are proposed that will maintain adequate defense in depth to ensure grid reliability and stability are preserved.
A loss of offsite power event is an anticipated operational occurrence. The proposed changes do not significantly increase the probability of this event. Additionally, as described in Chapter 14 (MPS2) and Chapter 15 (MPS3), several events are assumed to occur coincident with a loss of offsite power. Sufficient onsite power sources are available to mitigate these events and ensure the consequences of the existing analyses for these events remain bounding.
The proposed new TRM requirements for offsite line power sources will not change the plant design or design requirements. The design criteria for the offsite power system remain unchanged. Therefore, the safety analyses as documented in the MPS2 and MPS3 FSARs remain unchanged. Temporary reductions in the number of offsite lines from four to three, in accordance with the proposed TRM action requirements, will not adversely affect offsite power system availability in the event of a loss of either MPS2, MPS3, the largest other unit on the grid, or the most critical transmission line. Use of the proposed TRM requirements will not cause an accident to occur and will not change how accident mitigation equipment is operated. Allowing one offsite line to be nonfunctional for up to 14 days does not increase the probability of any previously evaluated accidents.
Therefore, the proposed changes to the offsite 345 kV transmission system (four lines separately supported and SLOD disabled) and proposed new TRM requirements does not significantly increase the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any previously evaluated?
Response: No.
The proposed amendments do not change the design function or operation of the offsite power system and do not affect the offsite power systems ability to perform its design function. The proposed amendments do not conflict with the design criteria, codes, or standards committed to in the licensing basis. The existing codes and standards, as they apply to the onsite emergency power systems, remain unchanged. The design criteria for the offsite power system remain unchanged. Therefore, the safety analyses as documented in the MPS2 and MPS3 FSARs remain unchanged.
No credible new failure mechanisms, malfunctions, or accident initiators not considered in the design and licensing basis are created by the proposed amendment. The offsite power system is assumed to be available during several FSAR Chapter 14 (MPS2) and Chapter 15 (MPS3) events. The new TRM requirements would allow 72 hours to restore a nonfunctional line, and up to 14 days to restore a nonfunctional line if specific TRM action requirements are met. Use of these TRM requirements does not impact offsite power availability and does not create the possibility for a new or different kind of accident from any previously evaluated. Temporary reductions in the number of offsite lines from four to three, in accordance with the proposed TRM requirements, will continue to ensure offsite power system availability in the event of a loss of either MPS2, MPS3, the largest other unit on the grid, or the most critical transmission line.
The proposed amendments have no adverse effect on plant operation or accident mitigation equipment. The response of the plants and the operators following a design basis accident will not be different. In addition, the proposed amendments do not create the possibility of a new failure mode associated with any equipment or personnel failures.
Therefore, the proposed amendments will not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in the margin of safety?
Response: No.
The post-modification configuration of the offsite 345 kV transmission system (four lines separately supported and SLOD disabled) improves overall grid reliability and continues to meet the requirements for two independent sources of offsite power (GDC-17). Likewise, the addition of TRM requirements that limit the unavailability of offsite lines provides acceptable assurance that line outages will not result in a significant reduction to grid stability and hence also to the margin of safety.
The offsite power systems are assumed to be available during several FSAR Chapter 14 (MPS2) and Chapter 15 (MPS3) events. The loss of the offsite power system is an anticipated operational occurrence.
Additionally, as described in Chapter 14 (MPS2) and Chapter 15 (MPS3), several events are assumed to occur coincident with a loss of offsite power. Sufficient onsite power sources are available to mitigate these events and ensure the consequences of the existing analyses for these events remain bounding.
The proposed amendments do not affect the assumptions in the safety analyses or the ability to safely shutdown the reactors and mitigate accident conditions. Station structures, systems, and components will continue to be able to mitigate the design basis accidents as assumed in the safety analyses and ensure proper operation of accident mitigation equipment. In addition, the proposed amendment will not affect equipment design or operation of station structures, systems, and components and there are no changes being made to the safety limits or safety system settings required by technical specifications.
Therefore, the proposed amendments will not result in a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed TS changes involve lowering the existing RCP under-voltage ALLOWABLE VALUE and adopting [Technical Specification Task Force (TSTF)-493] provisions for as-found and as-left calibration tolerances. The proposed TS changes serve to further ensure the Reactor Trip RCP under-frequency and under-voltage trip instrumentation will properly function as credited in the safety analyses. The proposed changes do not alter any assumptions previously made in the radiological consequences evaluations nor do they affect mitigation of the radiological consequences of an accident previously evaluated. The proposed TS changes do not affect the probability of accident initiation.
In summary, the proposed changes will not involve any increase in the probability or consequences of an accident previously evaluated
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed TS changes involve lowering the existing RCP under-voltage ALLOWABLE VALUE and adopting TSTF-493 provisions for as-found and as-left calibration tolerances. No new accident scenarios, failure mechanisms, or single failures are introduced as a result of any of the proposed changes.
The Reactor Trip System is not an accident initiator. No changes to the overall manner in which the plant is operated are being proposed.
Therefore, the proposed changes will not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
Margin of safety is related to the confidence in the ability of the fission product barriers to perform their intended functions. These barriers include the fuel cladding, the reactor coolant system pressure boundary, and the containment barriers. The proposed TS changes serve to ensure proper operation of the Reactor Trip RCP under-frequency and under-voltage trip instrumentation and that the instrumentation will properly function as credited in the safety analyses. The proposed TS changes will not have any effect on the margin of safety of fission product barriers. No accident mitigating equipment will be adversely impacted as a result of the modification.
Therefore, existing safety margins will be preserved. None of the proposed changes will involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change involves using gap release fractions for high-burnup fuel rods (
The changes proposed do not affect the precursors for fuel handling-type accidents analyzed in Chapter 15 of the CNS, MNS, or ONS UFSARs. The probability remains unchanged since the accident analyses performed and discussed in the basis for the UFSAR changes, involve no change to a system, structure, or component that affects initiating events for any UFSAR Chapter 15 accident evaluated.
Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously analyzed.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change involves using gap release fractions for high-burnup fuel rods (
The proposed change does not involve the addition or modification of any plant equipment. The proposed change has the potential to affect future core designs for CNS, MNS, and ONS. However, the impact will not be beyond the standard function capabilities of the equipment. The proposed change involves using gap release fractions that would allow high-burnup fuel rods (
Therefore, the proposed change does no create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in the margin of safety?
Response: No.
The proposed change involves using gap release fractions for high-burnup fuel rods (
The proposed change has the potential for an increased postulated accident dose at CNS, MNS or ONS. However, the analysis demonstrates that the resultant doses are within the appropriate acceptance criteria. The margin of safety, as described by 10 CFR 50.67 and Regulatory Guide 1.183, has been maintained. Furthermore, the assumptions and input used in the gap release and dose consequences calculations are conservative. These conservative assumptions ensure that the radiation doses calculated pursuant to Regulatory Guide 1.183 and cited in this license amendment requires are the upper bounds to radiological consequences of the fuel handling-type accidents analyzed. The analysis shows that with increased gap release fractions accounted for in the dose consequences calculations there is margin between the offsite radiation doses calculated and the dose limits of 10 CFR 50.67 and acceptance criteria of Regulatory Guide 1.183. The proposed change will not degrade the plant protective boundaries, will not cause a release of fission products to the public and will not degrade the performance of any structures, systems and components important to safety.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or
Response: No.
The proposed amendment to the TS involves the extension of the JAF Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The current Type A test interval of 120 months (10 years) would be extended on a permanent basis to no longer than 15 years from the last Type A test. The current Type C test interval of 60 months for selected components would be extended on a performance basis to no longer than 75 months. Extensions of up to nine months (total maximum interval of 84 months for Type C tests) are permissible only for non-routine emergent conditions. The proposed extension does not involve either a physical change to the plant or a change in the manner in which the plant is operated or controlled. The containment is designed to provide an essentially leak tight barrier against the uncontrolled release of radioactivity to the environment for postulated accidents. As such, the containment and the testing requirements invoked to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident, and do not involve the prevention or identification of any precursors of an accident. The change in dose risk for changing the Type A test frequency from three-per-ten years to once-per-fifteen-years, measured as an increase to the total integrated plant risk for those accident sequences influenced by Type A testing, is 0.0087 person-[roentgen equivalent man (rem)]/year. [Electric Power Research Institute (EPRI)] Report No. 1009325, Revision 2-A states that a very small population dose is defined as an increase of ≤ 1.0 person-rem per year, or ≤ 1% of the total population dose, whichever is less restrictive for the risk impact assessment of the extended ILRT intervals. The results of the risk assessment for this amendment meet these criteria. Moreover, the risk impact for the ILRT extension when compared to other severe accident risks is negligible. Therefore, this proposed extension does not involve a significant increase in the probability of an accident previously evaluated.
As documented in NUREG-1493 [“Performance Based Containment Leak-Test Program”], Type B and C tests have identified a very large percentage of containment leakage paths, and the percentage of containment leakage paths that are detected only by Type A testing is very small. The JAF Type A test history supports this conclusion.
The integrity of the containment is subject to two types of failure mechanisms that can be categorized as: (1) Activity based, and; (2) time based. Activity based failure mechanisms are defined as degradation due to system and/or component modifications or maintenance. Local leak rate test requirements and administrative controls such as configuration management and procedural requirements for system restoration ensure that containment integrity is not degraded by plant modifications or maintenance activities. The design and construction requirements of the containment combined with the containment inspections performed in accordance with [American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code] Section XI, the Maintenance Rule, and TS requirements serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by a Type A test. Based on the above, the proposed extensions do not significantly increase the consequences of an accident previously evaluated.
The proposed amendment also deletes exceptions previously granted to allow one-time extensions of the ILRT test frequency for JAF. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that has no effect on any component and no impact on how the unit is operated.
Therefore, the proposed change does not result in a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed amendment to the TS involves the extension of the JAF Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months. The containment and the testing requirements to periodically demonstrate the integrity of the containment exist to ensure the plant's ability to mitigate the consequences of an accident do not involve any accident precursors or initiators. The proposed change does not involve a physical change to the plant (
The proposed amendment also deletes exceptions previously granted to allow one-time extensions of the ILRT test frequency for JAF. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action that does not result in any change in how the unit is operated.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed amendment to TS 5.5.6 involves the extension of the JAF Type A containment test interval to 15 years and the extension of the Type C test interval to 75 months for selected components. This amendment does not alter the manner in which safety limits, limiting safety system set points, or limiting conditions for operation are determined. The specific requirements and conditions of the TS Containment Leak Rate Testing Program exist to ensure that the degree of containment structural integrity and leak-tightness that is considered in the plant safety analysis is maintained. The overall containment leak rate limit specified by TS is maintained.
The proposed change involves only the extension of the interval between Type A containment leak rate tests and Type C tests for JAF. The proposed surveillance interval extension is bounded by the 15-year ILRT Interval and the 75-month Type C test interval currently authorized within [Nuclear Energy Institute (NEI) 94-01, Revision 3-A [“Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J,” July 2012 (ADAMS Accession No. ML12221A202)]. Industry experience supports the conclusion that Type B and C testing detects a large percentage of containment leakage paths and that the percentage of containment leakage paths that are detected only by Type A testing is small. The containment inspections performed in accordance with ASME Section Xl, TS and the Maintenance Rule serve to provide a high degree of assurance that the containment would not degrade in a manner that is detectable only by Type A testing. The combination of these factors ensures that the margin of safety in the plant safety analysis is maintained. The design, operation, testing methods and acceptance criteria for Type A, B, and C containment leakage tests specified in applicable codes and standards would continue to be met, with the acceptance of this proposed change, since these are not affected by changes to the Type A and Type C test intervals.
The proposed amendment also deletes exceptions previously granted to allow one time extensions of the ILRT test frequency for JAF. These exceptions were for activities that would have already taken place by the time this amendment is approved; therefore, their deletion is solely an administrative action and does not change how the unit is operated and maintained. Thus, there is no reduction in any margin of safety.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change to the CSP Implementation Schedule is administrative in nature. This change does not alter accident analysis assumptions, add any initiators, or affect the function of plant systems or the manner in which systems are operated, maintained, modified, tested, or inspected. The proposed change does not require any plant modifications which affect the performance capability of the structures, systems and components relied upon to mitigate the consequences of postulated accidents and has no impact on the probability or consequences of an accident previously evaluated.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change to the CSP Implementation Schedule is administrative in nature. This proposed change does not alter accident analysis assumptions, add any initiators or affect the function of plant systems or the manner in which systems are operated, maintained, modified, tested, or inspected. The proposed change does not require any plant modifications which affect the performance capability of the structures, systems, and components relied upon to mitigate the consequences of postulated accidents and does not create the possibility of a new or different kind of accident from any accident previously evaluated.
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
Plant safety margins are established through limiting conditions for operation, limiting safety system settings, and safety limits specified in the technical specifications. The proposed change to the CSP Implementation Schedule is administrative in nature. In addition, the milestone date delay for full implementation of the CSP has no substantive impact because other measures have been taken which provide adequate protection during this period of time. Because there is no change to established safety margins as a result of this change, the proposed change does not involve a significant reduction in a margin of safety.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Do the proposed changes involve a significant increase in the probability or consequences of any accident previously evaluated?
Response: No.
The proposed changes relocate the specified frequencies for periodic surveillance requirements to licensee control under a new Surveillance Frequency Control Program [SFCP]. Surveillance frequencies are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased. The systems and components required by the technical specifications for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigation function assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.
Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
No new or different accidents result from utilizing the proposed changes. The changes do not involve a physical alteration of the plant (
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The design, operation, testing methods, and acceptance criteria for systems, structures, and components, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS), since these are not affected by changes to the surveillance frequencies. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. To evaluate a change in the relocated surveillance frequency, Exelon will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev. 1, in accordance with the TS SFCP. NEI 04-10, Rev. 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177 [“An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications”].
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed changes act to remove the current necessity of establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits and relocate the requirements to the UFSAR, which will have no impact on any safety related structures, systems or components. Once relocated to the UFSAR, changes to establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits will be controlled in accordance with 10 CFR 50.59.
The probability of occurrence of a previously evaluated accident is not increased because these changes do not introduce any new potential accident initiating conditions. The consequences of accidents previously evaluated in the UFSAR are not affected because the ability of the components to perform their required functions is not affected.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed changes act to remove the current necessity of establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits and relocate the requirements to the UFSAR, which will have no impact on any safety related structures, systems or components. Once relocated to the UFSAR, changes to establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits will be controlled in accordance with 10 CFR 50.59.
The proposed changes do not introduce new modes of plant operation and do not involve physical modifications to the plant (no new or different type of equipment will be installed). There are no changes in the method by which any safety related plant structure, system, or component (SSC) performs its specified safety function. As such, the plant conditions for which the design basis accident analyses were performed remain valid.
No new accident scenarios, transient precursors, failure mechanisms, or limiting single failures will be introduced as a result of the proposed changes. There will be no adverse effect or challenges imposed on any SSC as a result of the proposed changes.
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
Margin of safety is related to confidence in the ability of the fission product barriers to perform their accident mitigation functions. The proposed changes act to remove the current necessity of establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits and relocate the requirements to the UFSAR, which will have no impact on any safety related structures, systems or components. Once relocated to the UFSAR, changes to establishing and maintaining communications between the control room and the refueling station and the minimum load capacities and load limit controls required for the manipulator crane limits will be controlled in accordance with 10 CFR 50.59. The proposed changes do not physically alter any SSC. There will be no effect on those SSCs necessary to assure the accomplishment of protection functions. There will be no impact on the overpower limit, departure from nucleate boiling ratio (DNBR) limits, loss of cooling accident peak cladding temperature (LOCA PCT), or any other margin of safety. The applicable radiological dose consequence acceptance criteria will continue to be met.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change revises the TS SR for the purpose of restoring a value to be consistent with the licensing basis. The proposed TS change does not introduce new equipment or new equipment operating modes, nor does the proposed change alter existing system relationships. The proposed change does not affect plant operation[.] Further, the proposed change does not increase the likelihood of the malfunction of any SSC [structure, system or component] or impact any analyzed accident. Consequently, the probability of an accident previously evaluated is not affected and there is no significant increase in the consequences of any accident previously evaluated.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change revises the TS SR for the purpose of restoring a value to be consistent with the licensing basis. The
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed change revises the TS SR for the purpose of restoring a value to be consistent with the licensing basis. The proposed change does not alter the manner in which safety limits, limiting safety system settings, or limiting conditions for operation are determined. The safety analysis assumptions and acceptance criteria are not affected by this change.
Therefore, the proposed change does not involve a significant reduction in the margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change revises or adds Surveillance Requirements (SRs) that require verification that the Emergency Core Cooling Systems (ECCS), the Residual Heat Removal (RHR) System/Shutdown Cooling (SDC) System, the Containment Spray (CS) System, and the Reactor Core Isolation Cooling (RCIC) System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. Gas accumulation in the subject systems is not an initiator of any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased. The proposed SRs ensure that the subject systems continue to be capable to perform their assumed safety function and are not rendered inoperable due to gas accumulation. Thus, the consequences of any accident previously evaluated are not significantly increased.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change revises or adds SRs that require verification that the ECCS, the RHR/SDC System, the CS System, and the RCIC System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. The proposed change does not involve a physical alteration of the plant (
Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed change revises or adds SRs that require verification that the ECCS, the RHR/SDC System, the CS System, and the RCIC System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. The proposed change clarifies requirements for management of gas accumulation in order to ensure the subject systems are capable of performing their assumed safety functions. The proposed SRs are more comprehensive than the current SRs and will ensure that the assumptions of the safety analysis are protected. The proposed change does not adversely affect any current plant safety margins or the reliability of the equipment assumed in the safety analysis. Therefore, there are no changes being made to any safety analysis assumptions, safety limits or limiting safety system settings that would adversely affect plant safety as a result of the proposed change.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change revises or adds Surveillance Requirements (SRs) that require verification that the Emergency Core Cooling System (ECCS), the Residual Heat Removal (RHR) System, and the Containment Spray (CS) System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. Gas accumulation in the subject systems is not an initiator of any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased. The proposed SRs ensure that the subject systems continue to be capable to perform their assumed safety function and are not rendered inoperable due to gas accumulation. Thus, the consequences of any accident previously evaluated are not significantly increased.
Therefore, the proposed licensing basis change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change [revises or] adds SRs that require verification that the ECCS, the RHR System, and the CS System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. The proposed change does not involve a physical alteration of the plant (
Therefore, the proposed licensing basis change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The proposed change [revises or] adds SRs that require verification that the ECCS, the RHR System, and the CS System are not rendered inoperable due to accumulated gas and to provide allowances which permit performance of the revised verification. The proposed change adds new requirements to manage gas accumulation in order to ensure the subject systems are capable of performing their assumed safety functions. The proposed SRs will ensure that the assumptions of the safety analysis are protected. The proposed change does not adversely affect any current plant safety margins or the reliability of the equipment assumed in the safety analysis. Therefore, there are no changes being made to any safety analysis assumptions, safety limits[,] or limiting safety system settings that would adversely affect plant safety as a result of the proposed change.
Therefore, the proposed licensing basis change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change replaces an existing SR to operate the CRAFS for ten (10) continuous hours every month with heaters operating with a requirement to operate the system for 15 continuous minutes every month with heaters operating. The proposed change also replaces existing SRs to operate the SFPSAFS, the SIPRAFS, and the CACFS for ten (10) hours every month with a requirement to operate these systems for 15 continuous minutes every month.
These systems are not accident initiators and therefore, these changes do not involve a significant increase in the probability of an accident. The proposed system and filter testing changes are consistent with current regulatory guidance for these systems. The proposed changes continue to ensure that these systems perform their design function, which may include mitigating accidents. Thus, the change does not involve a significant increase in the consequences of an accident.
Therefore, it is concluded that this change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change replaces an existing SR to operate the CRAFS for ten (10) continuous hours every month with heaters operating with a requirement to operate the system for 15 continuous minutes every month with heaters operating. The proposed change also replaces existing SRs to operate the SFPSAFS, the SIPRAFS, and the CACFS for ten (10) hours every month with a requirement to operate these systems for 15 continuous minutes every month.
The change proposed for these ventilation systems does not change any system operations or maintenance activities. Testing requirements will be revised and will continue to demonstrate that the Limiting Conditions for Operation are met and/or the system components are capable of performing their intended safety functions. The change does not create new failure modes or mechanisms and no new accident precursors are generated.
Therefore, it is concluded that this change does not create the possibility of a new or
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
The proposed change replaces an existing SR to operate the CRAFS for ten (10) continuous hours every month with heaters operating with a requirement to operate the system for 15 continuous minutes every month with heaters operating. The proposed change also replaces existing SRs to operate the SFPSAFS, the SIPRAFS, and the CACFS for ten (10) hours every month with a requirement to operate these systems for 15 continuous minutes every month.
The design basis for the CRAFS heaters is to heat the incoming air, which reduces the relative humidity. The heater testing change proposed for the CRAFS will continue to demonstrate that the heaters are capable of heating the air and will perform their design function. The SFPSAFS, and the SIPRAFS are tested for adsorption at a relative humidity of [95 percent (%)] in accordance with RG [Regulatory Guide] 1.52, Revision 3, and do not require heaters for these systems to perform their specified safety function. The CACFS does not need to be tested similarly because the CACFS charcoal filters are not credited for the removal of radioiodines. The proposed change is consistent with regulatory guidance.
Therefore, it is concluded that this change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed changes are administrative in nature, involving changes to personnel and committee titles, deletion and or re-location of requirements redundant to regulations, and deletion of conditions controlling the first performance of testing that has since been completed. The proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated because: (1) the proposed amendment does not represent a change to the system design, (2) the proposed amendment does not alter, degrade, or prevent action described or assumed in any accident in the USAR from being performed, (3) the proposed amendment does not alter any assumptions previously made in evaluating radiological consequences, and [(4)] the proposed amendment does not affect the integrity of any fission product barrier. No other safety related equipment is affected by the proposed change.
Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed changes do not alter the physical design, safety limits, or safety analysis assumptions associated with the operation of the plant. Hence, the proposed changes do not introduce any new accident initiators, nor do these changes reduce or adversely affect the capabilities of any plant structure or system in the performance of their safety function.
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The proposed changes do not alter the manner in which safety limits or limiting safety system settings are determined. The safety analysis acceptance criteria are not affected by these proposed changes. Further, the proposed changes do not change the design function of any equipment assumed to operate in the event of an accident.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
This license amendment does not physically impact any system, structure, or component (SSC) that is a potential initiator of an accident. Therefore, implementation of AST, the AST assumptions and inputs, the proposed [Technical Specification (TS)] changes, and new χ/Q values have no impact on the probability for initiation of any design basis accident. Once the occurrence of an accident has been postulated, the new accident source term and [atmospheric dispersion factors (χ/Q)] values are inputs to analyses that evaluate the radiological consequences of the postulated events.
Reactor coolant specific activity, testing criteria of charcoal filters, and the accident induced primary-to-secondary system leakage performance criterion are not initiators for any accident previously evaluated. The proposed change to require the 48-inch containment purge valves to be sealed closed during operating MODES 1, 2, 3, and 4 is not an accident initiator for any
The change to the decay time prior to fuel movement is not an accident initiator. Decay time is used to determine the source term for the dose consequence calculation following a potential [fuel handling accident (FHA)] and has no effect on the probability of the accident. Likewise, the change to the Control Room radiation monitors setpoint cannot cause an accident and the operation of containment spray during the recirculation phase is used for mitigation of a [loss-of-coolant accident (LOCA)], and thus not an accident initiator.
As a result, there are no proposed changes to the parameters or conditions that could contribute to the initiation of an accident previously evaluated in Chapter 15 of the Updated Final Safety Analysis Report (UFSAR). As such, the AST cannot affect the probability of an accident previously evaluated.
Regarding accident consequences, equipment and components affected by the proposed changes are mitigative in nature and relied upon once the accident has been postulated. The license amendment implements a new calculation methodology for determining accident consequences and does not adversely affect any plant component or system that is credited to mitigate fuel damage. Subsequently, no conditions have been created that could significantly increase the consequences of any accidents previously evaluated.
Requiring that the 48-inch containment purge supply and exhaust valves be sealed closed during operating MODES 1, 2, 3, and 4 eliminates a potential path for radiological release following events that result in radioactive material releases to the containment, thus reducing potential consequences of the event. The steam generator tube inspection testing criterion for accident induced leakage is being changed, resulting in lower leakage rates, and thus less potential releases due to primary-to-secondary leakage. The auxiliary building ventilation system allowable methyl iodide penetration limit is being changed, which results in more stringent testing requirements, and thus higher filter efficiencies for reducing potential releases.
Changes to the operation of the containment spray system to require operation during the recirculation mode are also mitigative in nature. While the plant design basis has always included the ability to implement containment spray during recirculation, this license amendment now requires operation of containment spray in the recirculation mode for dose mitigation. DCPP is designed and licensed to operate using containment spray in the recirculation mode. As such, operation of containment spray in the recirculation mode has already been analyzed, evaluated, and is currently controlled by Emergency Operating Procedures. Usage of recirculation spray reduces the consequence of the postulated event. Likewise, the additional shielding to the Control Room and the addition of a [high-efficiency particulate air (HEPA)] filter to the [Technical Support Center (TSC)] ventilation system reduces the consequences of the postulated event to the Control Room and TSC personnel. Lowering the limit for [Dose Equivalent XE-133 (DEX)] lowers potential releases. By reclassifying a portion of the 40-inch Containment Penetration Area Ventilation line and a portion of the 2-inch gaseous radwaste system line to PG&E Design Class I, these lines will be seismically qualified, thus assuring that post-LOCA release points are the same as those used for determining χ/Q values.
The change to the decay time from 100 hours to 72 hours prior to fuel movement is an input to the FHA. Although less decay will result in higher released activity, the results of the FHA dose consequence analysis remain within the dose acceptance criteria of the event. Also, the radiation levels to an operator from a raised fuel assembly may increase due to a lower decay time, however, any exposure will continue to be maintained under 10 CFR 20 limits by the plant Radiation Protection Program.
Plant-specific radiological analyses have been performed using the AST methodology, assumption and inputs, as well as new χ/Q values. The results of the dose consequences analyses demonstrate that the regulatory acceptance criteria are met for each analyzed event. Implementing the AST involves no facility equipment, procedure, or process changes that could significantly affect the radioactive material actually released during an event. Subsequently, no conditions have been created that could significantly increase the consequences of any of the events being evaluated.
Based on the above discussion, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed change create the possibility of a new or different accident from any accident previously evaluated?
Response: No.
This license amendment does not alter or place any SSC in a configuration outside its design or analysis limits and does not create any new accident scenarios.
The AST methodology is not an accident initiator, as it is a method used to estimate resulting postulated design basis accident doses. The proposed TS changes reflect the plant configuration that supports implementation of the new methodology and supports reduction in dose consequences. DCPP is designed and licensed to operate using containment spray in the recirculation mode. This change will not affect any operational aspect of the system or any other system, thus no new modes of operation are introduced by the proposed change.
The function of the radiation monitors has not changed; only the setpoint has changed as a result of an assessment of all potential release pathways. The continued operation of containment spray and the radiation monitor setpoint change do not create any new failure modes, alter the nature of events postulated in the UFSAR, nor introduce any unique precursor mechanism.
Requiring the 48-inch containment purge valves to be sealed closed during operating MODES 1, 2, 3, and 4 does not introduce any new accident precursor. This change only eliminates a potential release path for radionuclides following a LOCA.
The proposed TS testing criteria for the auxiliary building ventilation system charcoal filters and the proposed performance criteria for steam generator tube integrity also cannot create an accident, but results in requiring more efficient filtration of potentially released iodine and less allowable primary-to-secondary leakage. The proposed changes to the DEX activity limit, the TS terminology, and the decay time of the fuel before movement are also unrelated to accident initiators.
The only physical changes to the plant being made in support of AST is the addition of Control Room shielding in an area previously modified, the addition of a HEPA filter at the intake of the TSC normal ventilation system, and the upgrade to the damper actuators, pressure switches, and damper solenoid valves to support reclassifying a portion of the Containment Penetration Area Ventilation line to PG&E Design Class I. Both Control Room shielding and HEPA filtration are mitigative in nature and do not have any impact on plant operation or system response following an accident. The Control Room modification for adding the shielding will meet applicable loading limits, so the addition of the shielding cannot initiate a failure. Upgrading damper actuators, pressure switches, and damper solenoid valves involve replacing existing components with components that are PG&E Design Class I. Therefore, the addition of shielding, a HEPA filter, and upgrading components cannot create a new or different kind of accident.
Since the function of the SSCs has not changed for AST implementation, no new failure modes are created by this proposed change. The AST change itself does not have the capability to initiate accidents.
Therefore, the proposed change does not create the possibility of a new or different type of accident from any accident previously evaluated.
3. Does the proposed change involve a significant reduction in a margin of safety?
Response: No.
Implementing the AST is relevant only to calculated dose consequences of potential design basis accidents evaluated in Chapter 15 of the UFSAR. The changes proposed in this license amendment involve the use of a new analysis methodology and related regulatory acceptance criteria. New atmospheric dispersion factors, which are based on site specific meteorological data, were calculated in accordance with regulatory guidelines. The proposed TS, TS Bases, and UFSAR changes reflect the plant configuration that will support implementation of the new methodology and result in operation in accordance with regulatory guidelines that support the revisions to the radiological analyses of the limiting design basis accidents. Conservative
The change to the minimum decay time prior to fuel movement results in higher fission product releases after a FHA. However, the results of the FHA dose consequence analysis remain within the dose acceptance criteria of the event.
The proposed changes continue to ensure that the dose consequences of design basis accidents at the exclusion area, low population zone boundaries, in the TSC, and in the Control Room are within the corresponding acceptance criteria presented in RG 1.183 and 10 CFR 50.67. The margin of safety for the radiological consequences of these accidents is provided by meeting the applicable regulatory limits, which are set at or below the 10 CFR 50.67 limits. An acceptable margin of safety is inherent in these limits.
Therefore, the proposed change does not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment requests involve no significant hazards consideration.
1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The design functions of the VES for the main control room (MCR) are to provide breathable air, maintain positive pressurization relative to the outside, provide cooling of MCR equipment and facilities, and provide passive air filtration within the MCR boundary. The VES is designed to satisfy these functions for up to 72 hours following a design basis accident.
The proposed changes to the ASME [American Society of Mechanical Engineers] safety classification of components, equipment orientation and configuration, addition and deletion of components, and correction to the number of emergency air storage tanks would not adversely affect any design function. The proposed changes maintain the design function of the VES with safety-related equipment and system configuration consistent with the descriptions in UFSAR [Updated Final Safety Analysis Report] Subsection 6.4.2. The proposed changes do not affect the support or operation of mechanical and fluid systems. There is no change to the response of systems to postulated accident conditions. There is no change to the predicted radioactive releases due to postulated accident conditions. The plant response to previously evaluated accidents or external events is not adversely affected, nor do the proposed changes described create any new accident precursors.
Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.
2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed changes to revise the VES design related to the ASME safety classification, equipment orientation and configuration, addition and deletion of components, and correction to the number of emergency air storage tanks maintains consistency with the design function information in the USFAR. The proposed changes do not create a new fault or sequence of events that could result in a radioactive release. The proposed changes would not affect any safety-related accident mitigating function.
Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.
3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The proposed changes do not affect the ability of the VES to maintain the safety-related functions to the MCR. The VES continues to meet the requirements for which it was designed and continues to meet the regulations. No safety analysis or design basis acceptance limit/criterion is challenged or exceeded by the proposed changes, and no margin of safety is reduced.
Therefore, the proposed changes do not involve a significant reduction in a margin of safety.
The NRC staff has reviewed the licensee's analysis and, based on this review, it appears that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff proposes to determine that the amendment request involves no significant hazards consideration.
The following notices were previously published as separate individual notices. The notice content was the same as above. They were published as individual notices either because time did not allow the Commission to wait for this biweekly notice or because the action involved exigent circumstances. They are repeated here because the biweekly notice lists all amendments issued or proposed to be issued involving no significant hazards consideration.
For details, see the individual notice in the
During the period since publication of the last biweekly notice, the Commission has issued the following amendments. The Commission has determined for each of these amendments that the application complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
A notice of consideration of issuance of amendment to facility operating license or combined license, as applicable, proposed no significant hazards consideration determination, and opportunity for a hearing in connection with these actions, was published in the
Unless otherwise indicated, the Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments. If the Commission has prepared an environmental assessment under the special circumstances provision in 10 CFR 51.22(b) and has made a determination based on that assessment, it is so indicated.
For further details with respect to the action see (1) the applications for amendment, (2) the amendment, and (3) the Commission's related letter, Safety Evaluation and/or Environmental Assessment as indicated. All of these items can be accessed as described in the “Obtaining Information and Submitting Comments” section of this document.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated September 24, 2015.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated September 22, 2015.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated September 21, 2015.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated September 15, 2015.
The Commission's related evaluation of the amendment is contained in a Safety Evaluation dated September 10, 2015.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated September 22, 2015.
The Commission's related evaluation of the amendments is contained in a Safety Evaluation dated September 17, 2015.
During the period since publication of the last biweekly notice, the Commission has issued the following amendments. The Commission has determined for each of these amendments that the application for the amendment complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations. The Commission has made appropriate findings as required by the Act and the Commission's rules and regulations in 10 CFR Chapter I, which are set forth in the license amendment.
Because of exigent or emergency circumstances associated with the date the amendment was needed, there was not time for the Commission to publish, for public comment before issuance, its usual notice of consideration of issuance of amendment, proposed no significant hazards consideration determination, and opportunity for a hearing.
For exigent circumstances, the Commission has either issued a
In circumstances where failure to act in a timely way would have resulted, for example, in derating or shutdown of a nuclear power plant or in prevention of either resumption of operation or of increase in power output up to the plant's licensed power level, the Commission may not have had an opportunity to provide for public comment on its no significant hazards consideration determination. In such case, the license amendment has been issued without opportunity for comment. If there has been some time for public comment but less than 30 days, the Commission may provide an opportunity for public comment. If comments have been requested, it is so stated. In either event, the State has been consulted by telephone whenever possible.
Under its regulations, the Commission may issue and make an amendment immediately effective, notwithstanding the pendency before it of a request for a hearing from any person, in advance of the holding and completion of any required hearing, where it has determined that no significant hazards consideration is involved.
The Commission has applied the standards of 10 CFR 50.92 and has made a final determination that the amendment involves no significant hazards consideration. The basis for this determination is contained in the documents related to this action. Accordingly, the amendments have been issued and made effective as indicated.
Unless otherwise indicated, the Commission has determined that these amendments satisfy the criteria for categorical exclusion in accordance with 10 CFR 51.22. Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared for these amendments. If the Commission has prepared an environmental assessment under the special circumstances provision in 10 CFR 51.12(b) and has made a determination based on that assessment, it is so indicated.
For further details with respect to the action see (1) the application for amendment, (2) the amendment to Facility Operating License or Combined License, as applicable, and (3) the Commission's related letter, Safety Evaluation and/or Environmental Assessment, as indicated. All of these items can be accessed as described in the “Obtaining Information and Submitting Comments” section of this document.
The Commission is also offering an opportunity for a hearing with respect to the issuance of the amendment. Within 60 days after the date of publication of this notice, any person(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license or combined license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the NRC's PDR, located at One White Flint North, Room O1-F21, 11555 Rockville Pike (first floor), Rockville, Maryland 20852, and electronically on the Internet at the NRC's Web site,
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth with particularity the interest of the petitioner in the proceeding, and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (4) the possible effect of any decision or order which may be entered in the proceeding on the
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert opinion which support the contention and on which the petitioner intends to rely in proving the contention at the hearing. The petitioner must also provide references to those specific sources and documents of which the petitioner is aware and on which the petitioner intends to rely to establish those facts or expert opinion. The petition must include sufficient information to show that a genuine dispute exists with the applicant on a material issue of law or fact. Contentions shall be limited to matters within the scope of the amendment under consideration. The contention must be one which, if proven, would entitle the petitioner to relief. A requestor/petitioner who fails to satisfy these requirements with respect to at least one contention will not be permitted to participate as a party.
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing. Since the Commission has made a final determination that the amendment involves no significant hazards consideration, if a hearing is requested, it will not stay the effectiveness of the amendment. Any hearing held would take place while the amendment is in effect.
The Commission's related evaluation of the amendment, finding of exigent circumstances, state consultation, and final NSHC determination are contained in a Safety Evaluation dated September 25, 2015.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Notice of hearing.
The U.S. Nuclear Regulatory Commission (NRC or the Commission) will convene an evidentiary session to receive testimony and exhibits in the uncontested portion of this proceeding regarding the application of Nuclear Innovation North America LLC (NINA) for combined licenses (COLs) to construct and operate two additional units (Units 3 and 4) at the South Texas Project (STP) Electric Generating Station site in Matagorda County near Bay City, Texas. This mandatory hearing will concern safety and environmental matters relating to the requested COLs.
The hearing will be held on November 19, 2015, beginning at 8:30 a.m. Eastern Time. For the schedule for submitting pre-filed documents and deadlines affecting Interested Government Participants, see Section VI of the
Please refer to Docket IDs 52-012 and 52-013 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
• NRC's Electronic Hearing Docket: You may obtain publicly available documents related to this hearing online at
• NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly available documents online in the ADAMS Public Documents collection at
• NRC's PDR: You may examine and purchase copies of public documents at the NRC's PDR, Room O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852.
Glenn Ellmers, Office of the Secretary, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, telephone: 301-415-0442; email:
The Commission hereby gives notice that, pursuant to section 189a of the Atomic Energy Act of 1954, as amended (the Act), it will convene an evidentiary session to receive testimony and exhibits in the uncontested portion of this proceeding regarding NINA's September 20, 2007, application for COLs under part 52 of title 10 of the
The Commission will conduct this hearing beginning at 8:30 a.m., Eastern Time on November 19, 2015, at the Commission's headquarters in Rockville, Maryland. The hearing on these issues will continue on subsequent days, if necessary.
The Commission is the presiding officer for this proceeding.
The matter at issue in this proceeding is whether the review of the application by the Commission's staff has been adequate to support the findings found in 10 CFR 52.97 and 10 CFR 51.107. Those findings that must be made for each COL are as follows:
The Commission will determine whether (1) the applicable standards and requirements of the Act and the Commission's regulations have been met; (2) any required notifications to other agencies or bodies have been duly made; (3) there is reasonable assurance that the facility will be constructed and will operate in conformity with the license, the provisions of the Act, and the Commission's regulations; (4) the applicant is technically and financially qualified to engage in the activities authorized; and (5) issuance of the license will not be inimical to the common defense and security or the health and safety of the public.
The Commission will (1) determine whether the requirements of sections 102(2)(A), (C), and (E) of NEPA and the applicable regulations in 10 CFR part 51 have been met; (2) independently consider the final balance among conflicting factors contained in the record of the proceeding with a view to determining the appropriate action to be taken; (3) determine, after weighing the environmental, economic, technical, and other benefits against environmental and other costs, and considering reasonable alternatives, whether the combined licenses should be issued, denied, or appropriately conditioned to protect environmental values; and (4) determine whether the NEPA review conducted by the NRC staff has been adequate.
No later than October 29, 2015, unless the Commission directs otherwise, the staff and the applicant shall submit a list of its anticipated witnesses for the hearing.
No later than October 29, 2015, unless the Commission directs otherwise, the applicant shall submit its pre-filed written testimony. The staff previously submitted its testimony on September 30, 2015.
The Commission may issue written questions to the applicant or the staff before the hearing. If such questions are issued, an order containing such questions will be issued no later than October 16, 2015. Responses to such questions are due October 29, 2015, unless the Commission directs otherwise.
No later than October 14, 2015, any interested State, local government body, or affected, Federally-recognized Indian tribe may file with the Commission a statement of any issues or questions to which the State, local government body, or Indian tribe wishes the Commission to give particular attention as part of the uncontested hearing process. Such statement may be accompanied by any supporting documentation that the State, local government body, or Indian tribe sees fit to provide. Any statements and supporting documentation (if any) received by the Commission using the agency's E-filing system
States, local governments, or Indian Tribes should be aware that this evidentiary hearing is separate and distinct from the NRC's contested hearing process. Issues within the scope of contentions that have been admitted or contested issues pending before the Atomic Safety and Licensing Board or the Commission in a contested proceeding for a COL application are outside the scope of the uncontested proceeding for that COL application. In addition, although States, local governments, or Indian tribes participating as described above may take any position they wish, or no position at all, with respect to issues regarding the COL application or the NRC staff's associated environmental review that do fall within the scope of the uncontested proceeding (
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Notice of submission to the Office of Management and Budget; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) has recently submitted a request for renewal of an existing collection of information to the Office of Management and Budget (OMB) for review. The information collection is entitled, “NRC Form 748, National Source Tracking Transaction Report.”
Submit comments by November 12, 2015.
Submit comments directly to the OMB reviewer at: Vlad Dorjets, Desk Officer, Office of Information and Regulatory Affairs (3150-0202) NEOB-10202, Office of Management and Budget, Washington, DC 20503; telephone: 202-395-1741, email:
Tremaine Donnell, NRC Clearance Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-41-6258; email:
Please refer to Docket ID NRC-2015-0005 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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The NRC cautions you not to include identifying or contact information in comment submissions that you do not want to be publicly disclosed in your comment submission. All comment submissions are posted at
If you are requesting or aggregating comments from other persons for submission to the OMB, 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 comment submissions are not routinely edited to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
Under the provisions of the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the NRC recently submitted a request for renewal of an existing collection of information to OMB for review entitled, “NRC Form 748, National Source Tracking Transaction Report.” The NRC hereby informs potential respondents that an agency may not conduct or sponsor, and that a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
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For the Nuclear Regulatory Commission.
The ACRS Subcommittee on AP1000 will hold a meeting on October 21-22, 2015, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The entire meeting will be open.
The agenda for the subject meeting shall be as follows:
The Subcommittee will review the draft Safety Evaluation Report associated with combined license application (COLA) for the William States Lee Nuclear Station Units 1 and 2. The Subcommittee will hear presentations by and hold discussions with the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Mr. Peter Wen (Telephone 301-415-2832 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
Confirmatory order; issuance.
The U.S. Nuclear Regulatory Commission (NRC) and Energy Northwest engaged in mediation as part of the NRC's Alternative Dispute Resolution Program which resulted in a settlement agreement as reflected in the confirmatory order relating to Columbia Generating Station.
The confirmatory order was issued to the licensee on September 28, 2015. The effective date is October 28, 2015.
Please refer to Docket ID NRC-2015-0228 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
• Federal Rulemaking Web site: Go to
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• NRC's PDR: You may examine and purchase copies of public documents at the NRC's PDR, Room O1-F21, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852.
Richard Guzman, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-1030, email:
The text of the Order is attached.
For the Nuclear Regulatory Commission.
Energy Northwest (Licensee) is the holder of Reactor Operating License NPF-21 issued by the U.S. Nuclear Regulatory Commission (NRC or Commission) pursuant to Title 10 of the
This Confirmatory Order is the result of an agreement reached during an alternative dispute resolution (ADR) mediation session conducted on August 6, 2015, and subsequent discussions completed on August 25, 2015.
On December 11, 2013, the NRC's Office of Investigations (OI), Region IV Field Office, initiated an investigation to determine whether nuclear security officers (NSOs) assigned to Energy Northwest's CGS were willfully inattentive while on duty. The investigation was completed on March 11, 2015, and was documented in OI Report 4-2014-009, dated December 18, 2014. Based on the results of the investigation, the NRC concluded that, on multiple occasions in 2012, 2013, and 2014, two security officers willfully violated 10 CFR 73.55(k)(5)(iii), in that they were not available at all times inside the protected area for their assigned response duties.
On August 6, 2015, Energy Northwest and the NRC met in an ADR session mediated by a professional mediator, arranged through the Cornell University Scheinman Institute on Conflict Resolution. ADR is a process in which a neutral mediator with no decision-making authority assists the parties in reaching an agreement on resolving any differences regarding the dispute. This Confirmatory Order is issued pursuant to the agreement reached during the ADR process.
In response to the NRC's offer, Energy Northwest requested use of the NRC ADR process to resolve differences it had with the NRC. On August 25, 2015, a preliminary settlement agreement was reached.
The NRC recognizes the corrective actions that Energy Northwest has already implemented associated with the events that formed the basis of this matter. These actions at CGS include:
• Informational briefings to NSOs on all shifts regarding the severity and the consequences of the incidents that formed the basis for this violation; and the reinforcement of using mitigation tools to avoid inattentiveness;
• Discussions with NSOs regarding regulatory requirements and the overall role security plays in the nuclear industry;
• Review of professionalism standards and expectations, as well as a code of ethics with NSOs and supervisors on each shift;
• Installation and use of surveillance cameras in bullet resistant enclosures (BREs);
• Increased frequency of radio checks to all posts and patrols; and
• Increased supervisory checks of posts and patrols;
The elements of the agreement, as signed by both parties, consist of the following:
A. The NRC has concluded that a willful violation of Title 10 of the
B. Within 3 months of the date of this Confirmatory Order, Energy Northwest will conduct a common cause evaluation related to the events that formed the basis of this matter.
1. The common cause evaluation will be conducted by a trained individual outside of the Emergency Services organization at CGS.
2. The results will be incorporated into Energy Northwest's corrective action program at CGS, as appropriate.
3. A copy of the completed evaluation will be made available for NRC review.
C. Within 18 months of the date of this Confirmatory Order, Energy Northwest will install wide-angle cameras in BREs to monitor the availability of nuclear security officers.
1. The cameras will be monitored by security supervisors (
2. When the cameras are not functional, security supervisors (
3. Until cameras are installed in the BREs, Energy Northwest security management will continue to perform a minimum of two post checks per shift, provided there is adequate staffing (
4. Use of cameras to monitor the availability of NSOs inside BREs will be documented.
D. Within 6 months of the date of this Confirmatory Order, Energy Northwest will revise its annual compliance and ethics computer-based training to address deliberate misconduct (10 CFR 50.5), compliance therewith, and consequences for non-compliance.
1. Prior to conducting the training, Energy Northwest will provide its proposed training plan to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the plan within 30 days of submittal for resolution in a manner acceptable to both parties.
2. Energy Northwest will complete administration of this training within 6 months of the date of this Confirmatory Order.
E. Energy Northwest will ensure its NSOs understand the need to comply with regulations and the consequences for non-compliance by having NSOs sign a statement affirming the same. This statement will be signed by current NSOs within 6 months of the date of this Confirmatory Order and within 30 days of hire for new NSOs, subject to collective bargaining.
F. Energy Northwest will prepare a “lessons learned” presentation derived from the common cause evaluation to be delivered to Energy Northwest's nuclear security department at CGS concerning the incidents that formed the basis for this violation and the consequences.
1. Prior to offering this presentation, Energy Northwest will provide its proposed presentation to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the presentation within 30 days of submittal for resolution in a manner acceptable to both parties.
2. Energy Northwest will deliver the presentation to the nuclear security department at CGS within 6 months of the date of this Confirmatory Order.
G. Energy Northwest will incorporate the lessons learned, derived from the common cause evaluation referenced in Condition B, and revise procedures at CGS as appropriate. A copy of the revised procedures will be made available for NRC review.
H. Within 12 months of the date of this Confirmatory Order, Energy Northwest will prepare a presentation communicating the incidents that formed the basis for this violation to be delivered to an appropriate industry forum (
1. This presentation will include, among other things, the significance of the incidents that formed the basis for this violation; the consequences of the
2. Prior to making the presentation, Energy Northwest will provide its proposed presentation to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the presentation within 30 days of submittal for resolution in a manner acceptable to both parties.
3. Energy Northwest will deliver the presentation within 12 months of the date of this Confirmatory Order.
I. Within 6 months of the date of this Confirmatory Order, Energy Northwest will ensure that an independent third party will conduct a targeted nuclear safety culture assessment of the security organization at CGS.
1. Based on the results of the assessment, Energy Northwest will incorporate recommended actions from the assessment into its corrective action program, as appropriate.
2. A copy of the completed assessment will be made available for NRC review within 30 days of the completion of the assessment.
J. Within 4 months of the date of this Confirmatory Order, Energy Northwest will revise its investigatory procedures to incorporate lessons learned from this matter (
K. Notification to NRC When Actions Are Completed
1. Unless otherwise specified, Energy Northwest will submit written notification to the Director, Division of Reactor Safety, U.S. NRC Region IV, 1600 East Lamar Blvd., Arlington, Texas 76011-4511, at intervals not to exceed 3 months until the terms of the Confirmatory Order are completed, providing a status of each item in the Order.
2. Energy Northwest will provide its basis for concluding that the terms of the Confirmatory Order have been satisfied, to the NRC, in writing.
L. Inspection Follow-up
Based on the corrective actions and enhancements described above, the NRC will conduct follow-up inspections using NRC Inspection Procedure 92702, “Followup on Corrective Actions for Violations and Deviations,” to confirm, among other things, the thoroughness and adequacy of the above-referenced actions.
M. Administrative Items
1. The NRC and Energy Northwest agree that the above elements will be incorporated into a Confirmatory Order and that the NRC will consider the order an escalated enforcement action with respect to any future enforcement actions.
2. The NRC agrees to provide Energy Northwest with copies of the correspondence issued to the two nuclear security officers involved, and associated with the incidents that formed the basis for this violation.
3. In consideration of the commitments delineated above, the NRC agrees to refrain from issuing a Notice of Violation for the violation discussed in NRC Inspection Report and Investigation Report to Energy Northwest of June 25, 2015 (EA-14-240).
4. This agreement is binding upon successors and assigns of Energy Northwest.
N. Within 30 days of the date of the Confirmatory Order, Energy Northwest shall pay a civil penalty of $35,000.
On September 21, 2015, Energy Northwest consented to issuing this Confirmatory Order with the commitments, as described in Section V below. Energy Northwest further agreed that this Confirmatory Order is to be effective 30 days after its issuance and that Energy Northwest has waived its right to a hearing.
Since the licensee has agreed to take additional actions to address NRC concerns, as set forth in Item III above, the NRC has concluded that its concerns can be resolved through issuance of this Confirmatory Order.
I find that Energy Northwest's commitments as set forth in Section V are acceptable and necessary, and conclude that with these commitments, the public health and safety are reasonably assured. In view of the foregoing, I have determined that public health and safety require that Energy Northwest's commitments be confirmed by this Confirmatory Order. Based on the above and Energy Northwest's consent, this Confirmatory Order is effective 30 days after its issuance.
Accordingly, pursuant to Sections 104b, 161b, 161i, 161o, 182, and 186 of the Atomic Energy Act of 1954, as amended, and the Commission's regulations in 10 CFR 2.202 and 10 CFR part 50, IT IS HEREBY ORDERED, THAT THE ACTIONS DESCRIBED BELOW WILL BE TAKEN AT COLUMBIA GENERATING STATION AND THAT LICENSE NO. NPF-21 IS MODIFIED AS FOLLOWS WITH RESPECT TO THE ACTIONS TO BE TAKEN AT THE COLUMBIA GENERATING STATION:
A. Within 3 months of the date of this Confirmatory Order, Energy Northwest will conduct a common cause evaluation related to the events that formed the basis of this matter.
1. The common cause evaluation will be conducted by a trained individual outside of the Emergency Services organization at CGS.
2. The results will be incorporated into Energy Northwest's corrective action program at CGS, as appropriate.
3. A copy of the completed evaluation will be made available for NRC review.
B. Within 18 months of the date of this Confirmatory Order, Energy Northwest will install wide-angle cameras in BREs to monitor the availability of nuclear security officers.
1. The cameras will be monitored by security supervisors (
2. When the cameras are not functional, security supervisors (
3. Until cameras are installed in the BREs, Energy Northwest security management will continue to perform a minimum of two post checks per shift, provided there is adequate staffing (
4. Use of cameras to monitor the availability of NSOs inside BREs will be documented.
C. Within 6 months of the date of this Confirmatory Order, Energy Northwest will revise its annual compliance and ethics computer-based training to address deliberate misconduct (10 CFR 50.5), compliance therewith, and consequences for non-compliance.
1. Prior to conducting the training, Energy Northwest will provide its proposed training plan to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the plan within 30 days of submittal for resolution in a manner acceptable to both parties.
2. Energy Northwest will complete administration of this training within 6 months of the date of this Confirmatory Order.
D. Energy Northwest will ensure its NSOs understand the need to comply with regulations and the consequences for non-compliance by having NSOs sign a statement affirming the same. This statement will be signed by current NSOs within 6 months of the date of this Confirmatory Order and within 30
E. Energy Northwest will prepare a “lessons learned” presentation, derived from the common cause evaluation, to be delivered to Energy Northwest's nuclear security department at CGS concerning the incidents that formed the basis for this violation and the consequences.
1. Prior to offering this presentation, Energy Northwest will provide its proposed presentation to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the presentation within 30 days of submittal for resolution in a manner acceptable to both parties.
2. Energy Northwest will deliver the presentation to the nuclear security department at CGS within 6 months of the date of this Confirmatory Order.
F. Energy Northwest will incorporate the lessons learned, derived from the common cause evaluation referenced in Condition B, and revise procedures at CGS as appropriate. A copy of the revised procedures will be made available for NRC review.
G. Within 12 months of the date of this Confirmatory Order, Energy Northwest will prepare a presentation communicating the incidents that formed the basis for this violation to be delivered to an appropriate industry forum (
1. This presentation will include, among other things, the significance of the incidents that formed the basis for this violation; the consequences of the actions; and the significant responsibilities of NSOs.
2. Prior to making the presentation, Energy Northwest will provide its proposed presentation to the NRC for its review. The NRC will communicate to the licensee any concerns regarding the presentation within 30 days of submittal for resolution in a manner acceptable to both parties.
3. Energy Northwest will deliver the presentation within 12 months of the date of this Confirmatory Order.
H. Within 6 months of the date of this Confirmatory Order, Energy Northwest will ensure that an independent third party will conduct a targeted nuclear safety culture assessment of the security organization at CGS.
1. Based on the results of the assessment, Energy Northwest will incorporate recommended actions from the assessment into its corrective action program, as appropriate.
2. A copy of the completed assessment will be made available for NRC review within 30 days of the completion of the assessment.
I. Within 4 months of the date of this Confirmatory Order, Energy Northwest will revise its investigatory procedures to incorporate lessons learned from this matter (
J. Notification to NRC When Actions Are Completed
1. Unless otherwise specified, Energy Northwest will submit written notification to the Director, Division of Reactor Safety, U. S. NRC Region IV, 1600 East Lamar Blvd., Arlington, Texas 76011-4511, at intervals not to exceed 3 months until the terms of this Confirmatory Order are completed, providing a status of each item in the Confirmatory Order.
2. Energy Northwest will provide its basis for concluding that the terms of this Confirmatory Order have been satisfied, to the NRC, in writing.
K. Within 30 days of the date of this Confirmatory Order, Energy Northwest shall pay a civil penalty of $35,000.
The Regional Administrator, Region IV, may, in writing, relax or rescind any of the above conditions upon demonstration by Energy Northwest of good cause.
Any person adversely affected by this Confirmatory Order, other than Energy Northwest may request a hearing within 30 days of the issuance date of this Confirmatory Order. Where good cause is shown, consideration will be given to extending the time to request a hearing. A request for extension of time must be directed to the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555, and include a statement of good cause for the extension.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC E-Filing rule (72 FR 49139, August 28, 2007, as amended at 77 FR 46562, August 3, 2012), which is codified in pertinent part at 10 CFR part 2, subpart C. The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least ten (10) days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. Further information on the Web-based submission form is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with NRC guidance available on the NRC's public Web site at
A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC Electronic Filing Help Desk through the “Contact Us” link located on the NRC's Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) first class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, Maryland, 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by first-class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service upon depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in NRC's electronic hearing docket, which is available to the public at
If a person other the Energy Northwest requests a hearing, that person shall set forth with particularity the manner in which his interest is adversely affected by this Confirmatory Order and shall address the criteria set forth in 10 CFR 2.309(d) and (f).
If a hearing is requested by a person whose interest is adversely affected, the Commission will issue a separate order designating the time and place of any hearings, as appropriate. If a hearing is held, the issue to be considered at such hearing shall be whether this Confirmatory Order should be sustained.
In the absence of any request for hearing, or written approval of an extension of time in which to request a hearing, the provisions specified in Section V above shall be effective and final 30 days after the issuance date of this Confirmatory Order without further order or proceedings. If an extension of time for requesting a hearing has been approved, the provisions specified in Section V shall be final when the extension expires if a hearing request has not been received.
Dated this 28th day of September 2015.
For the Nuclear Regulatory Commission.
Marc L. Dapas
The ACRS Subcommittee on Structural Analysis will hold a meeting on October 23, 2015, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The entire meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will review and discuss treatment of uncertainties in probabilistic seismic hazard analysis. The Subcommittee will hear presentations by and hold discussions with the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Christopher Brown (Telephone 301-415-7111 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, MD. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
Nuclear Regulatory Commission.
License amendment request; opportunity to request a hearing and to petition for leave to intervene.
The U.S. Nuclear Regulatory Commission (NRC) has received an application from Virginia Electric and Power Company (Dominion) requesting an amendment, in the form of changes to the Technical Specifications to Materials License Number SNM-2507 for the North Anna Power Station (NAPS) Independent Spent Fuel Storage Installation (ISFSI).
A request for a hearing or petition for leave to intervene must be filed by December 14, 2015.
Please refer to Docket ID NRC-2015-0237 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
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• NRC's Agencywide Documents Access and Management System (ADAMS): You may obtain publicly-available documents online in the ADAMS Public Documents collection at
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John-Chau Nguyen, Office of Nuclear Material Safety and Safeguards, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-0262; email:
By letter dated August 24, 2015 (ADAMS Accession No. ML15239B260), Dominion requested a revision to the Technical Specifications to License Number SNM-2507 for NAPS ISFSI located in Louisa County, Virginia. The proposed changes would allow storage of spent fuel in a modified TN-32B bolted lid cask as part pf the High Burn-up Dry Storage Cask Research and Development Project sponsored by the Department of Energy and the Electric Power Research Institute. Data gathered from the cask will be used to confirm the effects of long-term dry storage on high burn-up assemblies. License No. SNM-2507 authorizes the licensee to receive, store, and transfer spent fuel from NAPS, Units 1 and 2.
An NRC administrative completeness review found the application acceptable for a technical review (ADAMS Accession No. ML15271A044). Prior to approving the amendment, the NRC will need to make the findings required by the Atomic Energy Act of 1954, as amended (the Act), and the NRC's regulations. The NRC's findings will be documented in a safety evaluation report and an environmental assessment. The environmental assessment will be the subject of a subsequent notice in the
Within 60 days after the date of publication of this notice, any person(s) whose interest may be affected by this action may file a request for a hearing and a petition to intervene with respect to issuance of the amendment to the subject facility operating license or combined license. Requests for a hearing and a petition for leave to intervene shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested person(s) should consult a current copy of 10 CFR 2.309, which is available at the NRC's PDR, located in One White Flint North, Room O1-F21 (first floor), 11555 Rockville Pike, Rockville, Maryland 20852. The NRC's regulations are accessible electronically from the NRC Library on the NRC's Web site at
As required by 10 CFR 2.309, a petition for leave to intervene shall set forth, with particularity, the interest of the petitioner in the proceeding and how that interest may be affected by the results of the proceeding. The petition should specifically explain the reasons why intervention should be permitted, with particular reference to the following general requirements: (1) The name, address, and telephone number of the requestor or petitioner; (2) the nature of the requestor's/petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the requestor's/petitioner's property, financial, or other interest in the proceeding; and (4) the possible effect of any decision or order which may be entered in the proceeding on the requestor's/petitioner's interest. The petition must also set forth the specific contentions which the requestor/petitioner seeks to have litigated at the proceeding.
Each contention must consist of a specific statement of the issue of law or fact to be raised or controverted. In addition, the requestor/petitioner shall provide a brief explanation of the bases for the contention and a concise statement of the alleged facts or expert
Those permitted to intervene become parties to the proceeding, subject to any limitations in the order granting leave to intervene, and have the opportunity to participate fully in the conduct of the hearing with respect to resolution of that person's admitted contentions, including the opportunity to present evidence and to submit a cross-examination plan for cross-examination of witnesses, consistent with NRC regulations, policies, and procedures. The Atomic Safety and Licensing Board will set the time and place for any prehearing conferences and evidentiary hearings, and the appropriate notices will be provided.
Petitions for leave to intervene must be filed no later than 60 days from the date of publication of this notice. Requests for hearing, petitions for leave to intervene, and motions for leave to file new or amended contentions that are filed after the 60-day deadline will not be entertained absent a determination by the presiding officer that the filing demonstrates good cause by satisfying the three factors in 10 CFR 2.309(c)(1)(i)-(iii).
A State, local governmental body, Federally-recognized Indian tribe, or agency thereof, may submit a petition to the Commission to participate as a party under 10 CFR 2.309(h)(1). The petition should state the nature and extent of the petitioner's interest in the proceeding. The petition should be submitted to the Commission by December 14, 2015. The petition must be filed in accordance with the filing instructions in the “Electronic Submissions (E-Filing)” section of this document, and should meet the requirements for petitions for leave to intervene set forth in this section, except that under § 2.309(h)(2) a State, local governmental body, or Federally-recognized Indian tribe, or agency thereof does not need to address the standing requirements in 10 CFR 2.309(d) if the facility is located within its boundaries. A State, local governmental body, Federally-recognized Indian tribe, or agency thereof may also have the opportunity to participate under 10 CFR 2.315(c).
If a hearing is granted, any person who does not wish, or is not qualified, to become a party to the proceeding may, in the discretion of the presiding officer, be permitted to make a limited appearance pursuant to the provisions of 10 CFR 2.315(a). A person making a limited appearance may make an oral or written statement of position on the issues, but may not otherwise participate in the proceeding. A limited appearance may be made at any session of the hearing or at any prehearing conference, subject to the limits and conditions as may be imposed by the presiding officer. Persons desiring to make a limited appearance are requested to inform the Secretary of the Commission by December 14, 2015.
All documents filed in NRC adjudicatory proceedings, including a request for hearing, a petition for leave to intervene, any motion or other document filed in the proceeding prior to the submission of a request for hearing or petition to intervene, and documents filed by interested governmental entities participating under 10 CFR 2.315(c), must be filed in accordance with the NRC's E-Filing rule (72 FR 49139; August 28, 2007). The E-Filing process requires participants to submit and serve all adjudicatory documents over the internet, or in some cases to mail copies on electronic storage media. Participants may not submit paper copies of their filings unless they seek an exemption in accordance with the procedures described below.
To comply with the procedural requirements of E-Filing, at least 10 days prior to the filing deadline, the participant should contact the Office of the Secretary by email at
Information about applying for a digital ID certificate is available on the NRC's public Web site at
If a participant is electronically submitting a document to the NRC in accordance with the E-Filing rule, the participant must file the document using the NRC's online, Web-based submission form. In order to serve documents through the Electronic Information Exchange System, users will be required to install a Web browser plug-in from the NRC's Web site. Further information on the Web-based submission form, including the installation of the Web browser plug-in, is available on the NRC's public Web site at
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a request for hearing or petition for leave to intervene. Submissions should be in Portable Document Format (PDF) in accordance with NRC guidance available on the NRC's public Web site at
A person filing electronically using the NRC's adjudicatory E-Filing system may seek assistance by contacting the NRC Meta System Help Desk through the “Contact Us” link located on the NRC's public Web site at
Participants who believe that they have a good cause for not submitting documents electronically must file an exemption request, in accordance with 10 CFR 2.302(g), with their initial paper filing requesting authorization to continue to submit documents in paper format. Such filings must be submitted by: (1) First class mail addressed to the Office of the Secretary of the Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, Attention: Rulemaking and Adjudications Staff; or (2) courier, express mail, or expedited delivery service to the Office of the Secretary, Sixteenth Floor, One White Flint North, 11555 Rockville Pike, Rockville, Maryland 20852, Attention: Rulemaking and Adjudications Staff. Participants filing a document in this manner are responsible for serving the document on all other participants. Filing is considered complete by first-class mail as of the time of deposit in the mail, or by courier, express mail, or expedited delivery service upon depositing the document with the provider of the service. A presiding officer, having granted an exemption request from using E-Filing, may require a participant or party to use E-Filing if the presiding officer subsequently determines that the reason for granting the exemption from use of E-Filing no longer exists.
Documents submitted in adjudicatory proceedings will appear in the NRC's electronic hearing docket which is available to the public at
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Environmental assessment and finding of no significant impact; issuance.
The U.S. Nuclear Regulatory Commission (NRC) has prepared an Environmental Assessment (EA) to evaluate the potential environmental impacts that may arise as a result of additional geologic field work for a paleoliquefaction research project. The NRC has determined that there will be no adverse effects to any historic or cultural resources that may be located in the paleoliquefaction study's area of potential effects. The NRC has also concluded that a Finding of No Significant Impact (FONSI) is appropriate.
October 13, 2015.
Please refer to Docket ID NRC-2012-0271 when contacting the NRC about the availability of information regarding this document. You may obtain publicly-available information related to this document using any of the following methods:
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Thomas Weaver, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-2383; email:
On November 2, 2012, the NRC issued a FONSI for field work to support paleoliquifaction studies along certain river segments located in Kentucky, Missouri, Tennessee, Arkansas, Mississippi, and Virginia. The NRC provided notice of the FONSI and the supporting EA upon which the FONSI was based, in a
The NRC has prepared an EA to evaluate the potential environmental impacts that may arise as a result of this research project in accordance with the requirements of 10 CFR part 51, the NRC's regulations that implement Section 102(2) of the National Environmental Policy Act of 1969, as amended. Based on the EA, and in accordance with 10 CFR 51.31(a), the NRC has concluded that a FONSI is appropriate. Field work for this project will commence following publication of this Notice.
The NRC has prepared the EA to evaluate the potential environmental impacts of the field work to be performed along select river segments for this project. In accordance with Section 7 of the Endangered Species Act of 1973, as amended (16 U.S.C. 1531
Similarly, the NRC determined that there will be no adverse effects to any historic or cultural resources that may be located in the paleoliquefaction study's area of potential effects within the states of Arkansas, Missouri and Mississippi. The Arkansas, Mississippi, and Missouri State Historic Preservation Officers have concurred with this finding.
Finally, the NRC has determined that there will be no significant impacts to any other resource areas (
On the basis of the EA and as further described in the FONSI, the NRC has concluded that there are no significant environmental impacts from the proposed field work and has determined not to prepare an environmental impact statement.
For the Nuclear Regulatory Commission.
The ACRS Subcommittee on Reliability and PRA will hold a meeting on October 19, 2015, Room T-2B1, 11545 Rockville Pike, Rockville, Maryland.
The meeting will be open to public attendance.
The agenda for the subject meeting shall be as follows:
The Subcommittee will discuss a draft SECY Paper on possible implementation of a Risk Management Regulatory Framework (RMRF). The Subcommittee will hear presentations by and hold discussions with the NRC staff and other interested persons regarding this matter. The Subcommittee will gather information, analyze relevant issues and facts, and formulate proposed positions and actions, as appropriate, for deliberation by the Full Committee.
Members of the public desiring to provide oral statements and/or written comments should notify the Designated Federal Official (DFO), Mike Snodderly (Telephone 301-415-2241 or Email:
Detailed meeting agendas and meeting transcripts are available on the NRC Web site at
If attending this meeting, please enter through the One White Flint North building, 11555 Rockville Pike, Rockville, Maryland. After registering with security, please contact Mr. Theron Brown (Telephone 240-888-9835) to be escorted to the meeting room.
October 12, 19, 26, November 2, 9, 16, 2015.
Commissioners' Conference Room, 11555 Rockville Pike, Rockville, Maryland.
Public and Closed.
There are no meetings scheduled for the week of October 12, 2015.
9:30 a.m. Briefing on Security Issues (Closed—Ex. 1)
9:00 a.m. Joint Meeting of the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC) (Part 1) (Public Meeting)To be held at FERC Headquarters, 888 First Street NE. Washington, DC. (Contact: Tania Martinez-Navedo: 301-415-6561).
This meeting will be webcast live at the Web address—
11:20 a.m. Joint Meeting of the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory
There are no meetings scheduled for the week of October 26, 2015.
There are no meetings scheduled for the week of November 2, 2015.
There are no meetings scheduled for the week of November 9, 2015.
9:00 a.m. Briefing on the Status of Lessons Learned from the Fukushima Dia-Ichi Accident (Public Meeting) (Contact: Gregory Bowman: 301-415-2939).
This meeting will be webcast live at the Web address—
9:00 a.m. Hearing on Combined Licenses for South Texas Project, Units 3 and 4: Section 189a. of the Atomic Energy Act Proceeding (Public Meeting) (Contact: Tom Tai: 301-415-8484).
This meeting will be webcast live at the Web address—
The schedule for Commission meetings is subject to change on short notice. For more information or to verify the status of meetings, contact Glenn Ellmers at 301-415-0442 or via email at
The NRC Commission Meeting Schedule can be found on the Internet at:
The NRC provides reasonable accommodation to individuals with disabilities where appropriate. If you need a reasonable accommodation to participate in these public meetings, or need this meeting notice or the transcript or other information from the public meetings in another format (
Members of the public may request to receive this information electronically. If you would like to be added to the distribution, please contact the Nuclear Regulatory Commission, Office of the Secretary, Washington, DC 20555 (301-415-1969), or email
U.S. Office of Personnel Management (OPM).
Notice.
This notice identifies Schedule A, B, and C appointing authorities applicable to a single agency that were established or revoked from June 1, 2015, to June 30, 2015.
Senior Executive Resources Services, Senior Executive Services and Performance Management, Employee Services, 202-606-2246.
In accordance with 5 CFR 213.103, Schedule A, B, and C appointing authorities available for use by all agencies are codified in the Code of Federal Regulations (CFR). Schedule A, B, and C appointing authorities applicable to a single agency are not codified in the CFR, but the Office of Personnel Management (OPM) publishes a notice of agency-specific authorities established or revoked each month in the
(a) One Asian Studies Program Administrator, one International Security Studies Program Administrator, one Latin American Program Administrator, one Russian Studies Program Administrator, two Social Science Program Administrators, one Middle East Studies Program Administrator, one African Studies Program Administrator, one Global Sustainability and Resilience Program Administrator, one Canadian Studies Program Administrator; one China Studies Program Administrator, one Science, Technology and Innovation Program Administrator, and one Population, Environmental Change, and Security Administrator.
No Schedule B Authorities to report during June 2015.
The following Schedule C appointing authorities were approved during June 2015.
The following Schedule C appointing authorities were revoked during June 2015.
5 U.S.C. 3301 and 3302; E.O. 10577, 3 CFR, 1954-1958 Comp., p. 218.
U.S. Office of Personnel Management (OPM).
Notice.
This notice identifies Schedule A, B, and C appointing authorities applicable to a single agency that were established or revoked from July 1, 2015, to July 31, 2015.
Senior Executive Resources Services, Senior Executive Services and
In accordance with 5 CFR 213.103, Schedule A, B, and C appointing authorities available for use by all agencies are codified in the Code of Federal Regulations (CFR). Schedule A, B, and C appointing authorities applicable to a single agency are not codified in the CFR, but the Office of Personnel Management (OPM) publishes a notice of agency-specific authorities established or revoked each month in the
No Schedule A Authorities to report during July 2015.
No Schedule B Authorities to report during July 2015.
The following Schedule C appointing authorities were approved during July 2015.
The following Schedule C appointing authorities were revoked during July 2015
5 U.S.C. 3301 and 3302; E.O. 10577, 3 CFR, 1954-1958 Comp., p. 218.
Postal Regulatory Commission.
Notice.
The Commission is noticing a recent Postal Service filing concerning a revised model agreement for the International Merchandise Return Service Agreements with Foreign Postal Operators product. This notice informs the public of the filing, invites public comment, and takes other administrative steps.
Submit comments electronically via the Commission's Filing Online system at
David A. Trissell, General Counsel, at 202-789-6820.
On August 4, 2015, the Commission conditionally approved the proposed International Merchandise Return Service Agreements with Foreign Postal Operators (IMRS-FPO) product.
On October 1, 2015, the Postal Service filed a revised model agreement for the proposed IMRS-FPO product.
In Order No. 2639, the Commission stated that once the Postal Service filed a revised model agreement it would “notice that filing for comment.” Order No. 2639 at 8. Accordingly, the Commission invites comments on whether the Postal Service's revised model agreement is consistent with the Commission's directive. Interested persons, including the Public Representative, may submit comments on the information in the Postal Service's Response no later than October 15, 2015. James F. Callow will continue to serve as Public Representative in these proceedings.
Article 9 of the revised model agreement states that, in the event that the prices in the agreement no longer fall within the range most recently approved by the Commission, the agreement “shall expire sixty (60) days after the effective date of the new rate range. . . .” Response, Attachment 1 at 3. The Commission requests that the Postal Service explain why IMRS-FPO agreements cannot terminate sooner than sixty days after the effective date of a new rate range. The Postal Service's response is due no later than October 13, 2015.
1. Comments on the information in the Postal Service's Response are due no later than October 15, 2015.
2. The Postal Service's response to the request for supplemental information is due no later than October 13, 2015.
3. James F. Callow will continue to serve as an officer of the Commission (Public Representative) to represent the interests of the general public in these proceedings.
4. The Secretary shall arrange for publication of this order in the
By the Commission.
Notice is hereby given that, pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The Investment Company Act of 1940 (“Investment Company Act”) (15 U.S.C. 80a-1
Based on recent filings of notifications of registration on Form N-8A, we estimate that about 92 investment companies file such notifications each year. An investment company must only file a notification of registration on Form N-8A once. The currently approved average hour burden per investment company of preparing and filing a notification of registration on Form N-8A is one hour. Based on the Commission staff's experience with the requirements of Form N-8A and with disclosure documents generally—and considering that investment companies that are filing notifications of registration on Form N-8A simultaneously with the registration statement under the Investment Company Act are only required by Form N-8A to file a signed cover page—we continue to believe that this estimate is appropriate. Therefore, we estimate that the total annual hour burden to prepare and file notifications of registration on Form N-8A is 92 hours. The currently approved cost burden of Form N-8A is $443 per filing. We are updating the estimated cost burden to $449 to account for the effects of inflation. Therefore, we estimate that the total annual cost burden to associated with preparing and filing notifications of registration on Form N-8A is about $41,308.
Estimates of average burden hours and costs are made solely for the purposes of the Paperwork Reduction Act, and are not derived from a comprehensive or even representative survey or study of the costs of Commission rules and forms. Compliance with the collection of information requirements of Form N-8A is mandatory. Responses to the collection of information will not be kept confidential. 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.
The public may view the background documentation for this information collection at the following Web site,
Pursuant to Section 19(b)(1)
The Exchange proposes new equity trading rules relating to auctions for Pillar, the Exchange's new trading technology platform. The text of the proposed rule change is available on the Exchange's Web site at
In its filing with the Commission, the self-regulatory organization 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 those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
On April 30, 2015, the Exchange filed its first rule filing relating to the implementation of Pillar, which is an integrated trading technology platform designed to use a single specification for connecting to the equities and options markets operated by NYSE Arca and its affiliates, New York Stock Exchange LLC (“NYSE”) and NYSE MKT LLC (“NYSE MKT”).
This filing is the fourth and final set of proposed rule changes to support Pillar implementation and is intended to be read together with the rules approved in the Pillar I Filing, and the proposed rule changes in the Pillar II Filing and the Pillar III Filing. As described in the Pillar I Filing, new rules to govern trading on Pillar will have the same numbering as current rules, but with the modifier “P” appended to the rule number. For example, Rule 7.35, governing auctions, would remain unchanged and continue to apply to any trading in symbols on the current trading platform. Proposed Rule 7.35P would govern auctions for trading in symbols migrated to the Pillar platform. In addition, the proposed new rules to support Pillar in this filing would use the terms and definitions approved in the Pillar I Filing and proposed in the Pillar II Filing and Pillar III Filing.
In this filing, the Exchange proposes new Pillar Rule 7.35P relating to auctions. The Exchange also proposes to change definitions in Rule 1.1.
Rule 1.1 sets forth definitions. In the Pillar I Filing, the Exchange amended specified definitions and, in the Pillar II Filing and the Pillar III Filing, proposed additional amendments to Rule 1.1.
Current Rule 1.1(r) defines an Imbalance for the purposes of the Opening Auction, the Market Order Auction, the Closing Auction, and the Trading Halt Auction. Current Rule 1.1(s) defines the Indicative Match Price for the Opening Auction, the Market Order Auction, the Closing Auction, and the Trading Halt Auction. As discussed below, the Exchange proposes to define the terms “Imbalance” and “Indicative Match Price” for Pillar in Rule 7.35P, and therefore would not use these terms as defined in current Rules 1.1(r) and (s).
In order to specify that the current Rules 1.1(r) and (s) definitions would be applicable only to trading on the current trading platform, the Exchange proposes to specify that each definition is for purposes of Rule 7.35 and delete the clause in each definition that provides “the Opening Auction, the Market Order Auction, the Closing Auction, and the trading Auction, as the case may be.” Because Rule 7.35 governs auctions on the current trading platform, by specifying that these definitions are for purposes of Rule 7.35, these definitions would not be applicable to Rule 7.35P, which will govern auctions on Pillar.
The Exchange proposes new Rule 7.35P to describe auctions on the Pillar trading platform and is based on current Rule 7.35 and Rules 1.1(r) and (s). Auctions in Pillar would function
For example, consistent with Rule 7.34P, in proposed Rule 7.35P, the Exchange would use Pillar terminology, including the terms “Early Open Auction” instead of “Opening Auction,” “Core Open Auction” instead of “Market Order Auction,” and the terms Early Trading Session, Core Trading Session, and Late Trading Session. In addition, proposed Rule 7.35P would use terms defined in Rule 7.36P, including terms relating to the priority ranking of orders in Pillar. Further, the Exchange proposes to include in Rule 7.35P the definitions that are used for auctions rather than have them be set forth in Rule 1.1.
The Exchange also proposes the following substantive differences for auctions in Pillar:
• Consistent with the substantive difference proposed in the Pillar II Filing that MOO Orders would participate in Trading Halt Auctions, the term “Market Orders” in proposed Rule 7.35P would also mean MOO Orders for the Trading Halt Auction, unless otherwise specified. In addition, because in Pillar, unexecuted Market Orders would participate in the Closing Auction, for the Closing Auction, the term “Market Orders” would include MOC Orders, unless otherwise specified.
• The securities eligible to participate in an auction,
• The Exchange would consolidate existing definitions relating to auctions in proposed Rule 7.35P and would create new definitions for Pillar for the terms Auction Processing Period, Auction Imbalance Freeze, Auction NBBO, Auction Ranking, and Auction Reference Price.
• Auction Imbalance Information would be updated at least every second, rather than on a real-time basis, both for the proprietary data feed dissemination and for determining order entry eligibility during the applicable Auction Imbalance Freeze period.
• The Exchange is proposing a new term, “Auction NBBO,” which would be used as the basis for pricing the Core Open Auction and the Indicative Match Price for the Closing Auction when that auction consists only of Market Orders.
• The Exchange would allocate orders on the side of the Imbalance the same for all auctions and would consolidate the description of such ranking in the new defined term “Auction Ranking.” MOO and MOC Orders would be ranked Priority 1—Market Orders, LOO Orders and LOC Orders would be ranked as Priority 2—Display Orders, and the limit price of an order would be used for ranking purposes,
• During a Short Sale Period, for purposes of pricing an auction and ranking orders for allocation in an auction, sell short orders that have been adjusted to a Permitted Price would be processed as Limit Orders ranked Priority 2—Display Orders. In addition, for Auction Imbalance Information, sell short orders that are not yet eligible to trade would be adjusted to a Permitted Price as the NBB moves up and down.
• The Market Imbalance would be Market Orders not matched for trading in an auction against any interest, and not just Market Orders not matched for trading against other Market Orders.
• To attract interest for an auction, the Exchange would publish an Indicative Match Price value when there is no Matched Volume but there is a published BBO.
• The Indicative Match Price would be determined for all securities in the same manner regardless of whether the Exchange is the primary listing market for a security or the security is a UTP Security.
• The Auction Reference Price for purposes of determining the Indicative Match Price and Auction Collars for the Core Open Auction would be based on the midpoint of an Auction NBBO and would use the prior trading day's Official Closing Price if there is no Auction NBBO.
• The Exchange would conduct a Closing Auction if there are only Market Orders on both sides of the market, in which case, the Indicative Match Price would be the midpoint of the Auction NBBO. For the Core Open Auction, if there are only Market Orders, the Indicative Match Price would also be the midpoint of the Auction NBBO.
• An Indicative Match Price that is outside the Auction Collars would be adjusted to be one MPV inside the Auction Collars, rather than to the Auction Collar.
• As specified in Rule 7.34P, because the Core Open Auction would be conducted in the Core Trading Session and not the Early Trading Session, orders designated for the Early Trading Session would not be eligible to participate in the Core Open Auction.
• There would not be any order entry or cancellation restrictions during the one-minute Auction Imbalance Freeze before the Early Open Auction.
• The Core Open Auction Imbalance Freeze would be five seconds, instead of one minute, and during this period, MOO Orders and LOO Orders would be rejected regardless of the Imbalance. In addition, during the Core Open Auction Imbalance Freeze, the Exchange would accept Market Orders and Limit Orders designated for the Core Trading Session only on both sides of the market, but such orders would be eligible to participate in the auction only to offset the Imbalance as of the time of the scheduled Auction, and requests to cancel such orders would not be processed until after the Core Open Auction concludes. All other order instructions would be accepted during the Core Open Auction Imbalance Freeze. As with the current trading platform, requests to cancel MOO Orders and LOO Orders entered beginning one minute before the scheduled time for the Core Open Auction would be rejected.
Rule 7.35P(a) would provide that for purposes of proposed Rule 7.35P, unless otherwise specified, the term “Market Orders” includes MOO Orders (for the Core Open Auction and Trading Halt Auction) and MOC Orders (for the Closing Auction). With respect to the Core Open Auction, this text is based on the last clause of current Rule 7.35(c), which provides that unless stated otherwise, for the Market Order Auction, reference to Market Orders shall include MOO Orders.
With respect to the Trading Halt Auction, the Exchange proposes a
The Exchange further proposes to include in Rule 7.35P(a) that for the Closing Auction, Market Orders would include MOC Orders. Current Rule 7.35(e) refers only to MOC Orders for Closing Auctions. However, because unexecuted Market Orders that are held at a Trading Collar or NBBO would be eligible to participate in the Closing Auction and would be included in Closing Auction Imbalance Information, the Exchange proposes that Rule 7.35P would refer to Market Orders generally for the Closing Auction, which would include MOC Orders.
The Exchange proposes the following definitions for purposes of Rule 7.35P:
As with the current rule, all securities for which the Exchange is the primary listing market would be Auction-Eligible Securities. The Exchange proposes a substantive difference for Pillar to provide that the Exchange would designate UTP Securities that would be Auction-Eligible Securities. This proposed rule text would allow, as under the current rules, for the Exchange to conduct auctions in UTP Derivative Securities Products. It would also allow the Exchange to designate Tape A, B, or C securities that are not UTP Derivative Securities Products as being auction eligible. The Exchange believes this proposed rule change would support the initiatives of the Exchange, NYSE, and the NASDAQ Stock Market LLC (“Nasdaq”) to increase resiliency by having auctions on NYSE Arca serve as a back-up to either NYSE or Nasdaq if one of those markets is unable to conduct an auction.
Proposed Rule 7.35P(a)(1)(B) would define Auction-Eligible Securities for the Trading Halt Auction as securities for which NYSE Arca is the primary listing market. This proposed rule text is consistent with the substantive difference proposed in the Pillar III Filing that the Exchange would not conduct a Trading Halt Auction in a UTP Security.
Proposed Rule 7.35P(a)(4)(A) would provide that Auction Imbalance Information would be updated at least every second, unless there is no change to the information. The frequency of how often Auction Imbalance Information would be updated is based on rule text from Rules 7.35(a)(3) (imbalance information before the Opening Auction will be published at “various times . . . as determined from time to time by the Corporation”), 7.35(c)(1)(A)(1) (imbalance information before the Market Order Auction will be “updated real-time”), 7.35(e)(1) (imbalance information before the Closing Auction will be “updated real-time”), and 7.35(f)(2)(A) (imbalance information before a Trading Halt Auction will be “updated real-time”).
The Exchange proposes a substantive difference in Pillar that Auction Imbalance Information would be updated at least every second, unless there is no change to the information. To reflect that order entry eligibility would be based on the Imbalance that is updated on this schedule, if applicable for the respective auction as described below, proposed Rule 7.35P(a)(4)(B) would provide that order entry eligibility during an Auction Imbalance Freeze would be based on the most recently-updated Auction Imbalance Information.
In addition, to reflect that in Pillar the Exchange would disseminate Auction Imbalance Information via a proprietary market data feed, proposed Rule
• There is an NBB above zero and NBO for the security; and
• The NBBO is not crossed
In addition, for the Core Open Auction, the Exchange proposes that an NBBO would be an Auction NBBO when the midpoint of the NBBO when multiplied by the designated percentage, is greater than or equal to the spread of that NBBO. As further proposed, the designated percentage would be determined by the Corporation from time to time upon prior notice to ETP Holders. The proposed method for determining an Auction NBBO for the Core Open Auction is designed to validate whether an NBBO bears a relation to the value of the applicable security.
The proposed definition of Auction NBBO is based in part on BATS Exchange, Inc. (“Bats”) Rule 11.23(a)(23), which defines a “Valid NBBO” as when there is both an NBB and NBO for a security, the NBBO is not crossed, and the midpoint of the NBBO is less than the Maximum Percentage way from both the NBB and the NBO. The Exchange proposes to include greater specificity than the Bats rule to describe that the requirement to have both an NBB and an NBO means that the NBB cannot be zero.
In addition to requiring an NBB that is above zero and an NBBO that is not crossed, for the Core Open Auction, the Exchange proposes to validate whether an NBBO bears a relation to the value of the security. Similar to Bats, the Exchange would compare the midpoint price to the NBBO. However, unlike Bats, the Exchange proposes to multiply the midpoint by a designated percentage and compare this value to the spread of the NBBO. If the value of the midpoint when multiplied by the designated percentage is greater than or equal to the spread of the NBBO, the Exchange would use the NBBO as an Auction NBBO. The Exchange believes that if the NBBO spread is greater than the value of the midpoint as multiplied by the designated percentage, it would indicate that the spread is too wide, and therefore may not be representative of the value of the security. In such scenario, the NBBO would not be considered an Auction NBBO and therefore would not be used as an Auction Reference Price for the Core Open Auction.
Bats determines the Maximum Percentage for determining its Valid NBBO and publishes that percentage to its members via a Circular. The Exchange proposes to similarly specify the designated percentage used for determining the Auction NBBO for the Core Open Auction via Trader Update. The Exchange believes that it is consistent with a fair and orderly market and the protection of investors and the public to be able to change the designated percentage on notice to ETP Holders because such flexibility would provide the Exchange with the ability to respond quickly to market-wide events that may warrant use of a different designated percentage.
The Exchange proposes a substantive difference in Pillar to allocate orders on the side of the Imbalance the same for all auctions and therefore would consolidate the description of how orders would be allocated in a single definition of Auction Ranking in new Rule 7.35P(a)(6). As proposed, orders on the side of an Imbalance would be ranked in price-time priority under Rule 7.36P(c)-(g) consistent with the priority ranking associated with each order.
• As proposed in Rule 7.35P(a)(6)(A), Limit Orders, LOO Orders, and LOC Orders would be ranked based on their limit price and not the price at which they would participate in the auction.
• As proposed in Rule 7.35P(a)(6)(B), MOO Orders and MOC Orders would be ranked Priority 1—Market Orders. This priority is based on current Rule 7.35(c), which provides that Market Orders includes MOO Orders, and then provides that Market Orders are executed first, but uses Pillar terminology to specify the priority ranking for MOO Orders and MOC Orders.
• As proposed in Rule 7.35P(a)(6)(C), LOO Orders and LOC Orders would be ranked in time priority with Limit Orders ranked Priority 2—Display Orders. For the Core Open Auction, this proposed ranking of LOO Orders would be a substantive difference in Pillar and differs from the ranking set forth in current Rule 7.35(c)(2)(1)(ii)-(iv), which provides priority to Limit Orders eligible for the Opening Session first, then Limit Orders designated for the
• As proposed in Rule 7.35P(a)(6)(D), orders on the side of the Imbalance would not be guaranteed to participate in an auction. This proposed rule text would be new in Pillar and makes explicit that the reason why orders are ranked for an auction is because not all orders on the side of the Imbalance are guaranteed to participate in an auction.
The Exchange proposes a substantive difference in Pillar regarding how it would calculate the Market Imbalance. As proposed, the Market Imbalance would be the volume of Market Orders that are not paired off with any interest, including Limit Orders. By contrast, under current rules, the Market Imbalance only shows the Market Orders that are not paired off with other Market Orders. The Exchange believes that this proposed substantive difference would provide transparency regarding the volume of Market Orders that are not paired up against any interest. The Exchange also proposes a non-substantive difference to use the term “Market Orders” generally for all applicable auctions, and not use the term “Market-on-Close Orders” for the Closing Auction. As discussed above, unless stated otherwise, the term “Market Orders” in Rule 7.35P would include MOO Orders or MOC Orders, as applicable.
Proposed Rule 7.35P(a)(8)(A)-(E) would provide greater specificity regarding how the Indicative Match Price in Pillar would be determined in different scenarios.
Proposed Rule 7.35P(a)(8)(A) would provide that if there are two or more prices at which the maximum volume of shares is tradable, the Indicative Match Price would be the price closest to the Auction Reference Price, which would be specified in the rule text as follows:
This rule text is based on current Rule 1.1(s), which provides that if there are two or more prices at which the maximum volume of shares are executable, the price that is closest to the closing price of the previous trading day's normal market hours (or, in the case of a Closing Auction or a Trading Halt Auction, the last sale during normal market hours), as determined by the consolidated tape will establish the opening price (or the closing price in the case of a Closing Auction). The Exchange proposes in Rule 7.35P(a)(8)(A) to add a new defined
• For the Early Open Auction, the Exchange proposes that the Auction Reference Price would be the prior trading day's Official Closing Price. This proposed rule text is based on current rule text in Rule 1.1(s) that the Opening Auction uses the closing price of the previous trading day's normal market hours, with a non-substantive difference to use the term “Official Closing Price,” which would be a new defined term in Pillar.
• For the Core Open Auction, the Exchange proposes a substantive difference in Pillar that the Auction Reference Price would be the midpoint of the Auction NBBO or, if the Auction NBBO is locked, the locked price. The Exchange further proposes that if there is no Auction NBBO,
• For the Trading Halt Auction and Closing Auction, the Exchange proposes that the Auction Reference Price would be the last consolidated round-lot price of that trading day and, if none, the prior trading day's Official Closing Price. This Auction Reference Price would be based on current rule text in Rule 1.1(s), with non-substantive differences to provide more specificity that it would be a last consolidated round-lot price of that trading day, and to provide specificity regarding which reference price to use if there were no last consolidated round lot trades that day.
• For an IPO Auction, the Exchange proposes that the Auction Reference Price would be zero unless the Corporation is provided with a price for the security. This proposed rule text would be new for Pillar. As is currently used for an IPO Auction, the Exchange proposes to use zero as the Auction Reference Price if there are two prices at which the maximum volume of shares can be traded because there would not be any prior trading in that security. In Pillar, the Exchange proposes to add the ability to use a value other than zero in such cases if, for example, on the first day of trading of a new listing of a Derivative Securities Product, the Exchange is provided with a deal price for such Derivative Securities Product. In such a case, the deal price would be used as the Auction Reference Price in lieu of the default of zero.
Proposed Rule 7.35P(a)(8)(A) would further provide that the Indicative Match Price would not be lower (higher) than the price of an order to buy (sell) ranked Priority 2—Display Orders that was eligible to participate in the applicable auction. This rule text is based on current rule text in Rule 1.1(s) that provides that if the Indicative Match price would trade through eligible Limited Price Order designated for such auction, then the auction price will occur at the best price level available where no trade through occurs. The Exchange proposes non-substantive differences in Rule 7.35P(a)(8)(A) to use Pillar terminology, including reference to priority ranking defined in Rule 7.36P, to describe how the Indicative Match Price would not trade through an order that was eligible to participate in the auction. Rather than use the phrase “trade through,” the Exchange proposes a non-substantive difference to describe that the Indicative Match Price would not be lower (higher) than the price of an order to buy (sell).
Proposed Rule 7.35P(a)(8)(B) would provide that if there are two prices at which the maximum volume of shares is tradable and both prices are equidistant to the Auction Reference Price, the Indicative Match Price would be the Auction Reference Price. This proposed rule text is based in part on rule text in current Rule 1.1(s), but is more specific regarding the price that would be used if the two prices at which the maximum volume of tradable shares are equidistant to the Auction Reference Price.
Proposed Rule 7.35P(a)(8)(C) would specify the Indicative Match Price if the Matched Volume for an auction consists of buy and sell Market Orders only.
• For the Core Open Auction, the Indicative Match Price would be the Auction Reference Price, which as described above, would be the midpoint of the Auction NBBO and, if no Auction NBBO, the last Official Closing Price for that security. Matching Market Orders at the Auction Reference Price would be a substantive difference in Pillar. Accordingly, the Exchange would not include in Rule 7.35P the current rule text in Rule 7.35(c)(3)(A)(2)(i) and (ii), which describes how the Exchange currently determines the Market Order Auction price if there are no limit orders eligible for execution in the Market Order Auction.
The Exchange proposes a substantive difference in Pillar that the Exchange would use the Auction Reference Price for all Auction-Eligible Securities, regardless of where the security is listed.
• For the Closing Auction, the Indicative Match Price would be the midpoint of the Auction NBBO as of the time the auction is conducted, provided that if the Auction NBBO is locked, it would be the locked price, and if there is no Auction NBBO, it would be the Auction Reference Price.
This proposed rule text represents a substantive difference because in Pillar, the Exchange would conduct a Closing Auction if there are only buy and sell Market Orders, and would price such auction based on the Auction NBBO. The Exchange, therefore, is not proposing to include in the Pillar rule, text in current Rule 7.35(e)(3)(B) that provides that if there are no Limit Orders eligible for execution in the Closing Auction, MOC Orders would be rejected.
• For the Trading Halt Auction, the Indicative Match Price would be the Auction Reference Price. This rule text is based in part on current Rule 7.35(f)(4)(A), which provides that if equilibrium exists between buy and sell Market Orders, the match price shall be the last Corporation sale price in the security regardless of the trading session. In Pillar, by using the Auction Reference Price as the Indicative Match Price for a Trading Halt Auction, the Exchange would be using the last consolidated round lot trading price during that trading day, which could include an Early Trading Session trade, just as under current rules.
Proposed Rule 7.35P(a)(8)(D) would provide that if there is a BBO, but no Matched Volume (
Proposed Rule 7.35P(a)(8)(E) would provide that, if there is no Matched Volume and Market Orders on only one side of the market, the Indicative Match Price for the Auction Imbalance Information would be zero. This proposed rule text would be new for Pillar and provides specificity regarding the price that would be disseminated as part of the Auction Imbalance Information if there is no Matched Volume and Market Orders on only one side of the market.
Because of the additional level of specificity in proposed Rule 7.35P regarding how the Exchange would determine the Indicative Match Price, as well as the substantive differences of how these values would be determined in Pillar, the Exchange proposes that Rule 7.35P would not include the examples of Indicative Match Price and Imbalance calculations set forth in current Rules 7.35(c)(1)(A) and 7.35(e)(1)(A). Rather, the Exchange believes that the detailed rule text provides transparency regarding how the Indicative Match Price and Imbalances are determined without the need for examples.
The Exchange proposes a non-substantive difference in Pillar to provide that the Auction Collars would be applicable to the “Core Open Auction” instead of the “Market Order Auction.” The Exchange also proposes in Pillar to refer to it as a price collar threshold for the Indicative Match Price, rather than a price collar threshold for the Limit Orders eligible for determining the Indicative Match Price. Both manners of describing Auction Collars result in orders participating in an auction being priced within price collar thresholds. However, in Pillar, the Exchange has proposed new terminology to describe the limit price of an order being the highest (lowest) specified price at which a Limit Orders to buy (sell) is eligible to trade.
Proposed Rule 7.35P(a)(10)(A) would provide that the Auction Collar would be based on a price that is a specified percentage away from the Auction Reference Price for the applicable auction and that the Corporation would set and modify such thresholds from time to time upon prior notice to ETP Holders. The rule would further provide that the upper (lower) boundary of the Auction Collar would be the Auction Reference Price increased (decreased) by the specified percentage, truncated to the MPV. This proposed rule text specifies in detail how Auction Collars would be set in Pillar, except for the specified percentage. As provided for in current Rule 1.1(s)(A), the Exchange would continue to set and modify the thresholds from time to time upon prior notice to ETP Holders.
Proposed Rule 7.35P(a)(10)(B) would provide that an Indicative Match Price that is equal to or higher (lower) than the upper (lower) boundary of the Auction Collar would be adjusted to one MPV below (above) the upper (lower) boundary of the Auction Collar and orders eligible to participate in the applicable auction would trade at the collared Indicative Match Price. This proposed rule text uses Pillar terminology to provide specificity regarding how the Auction Collars would function and is based on current functionality. The Exchange proposes a substantive difference in Pillar that the Indicative Match Price would be at least one MPV inside the Auction Collars, and could not be equal to the Auction Collar.
Proposed Rule 7.35P(a)(10)(C) would provide that Limit Orders to buy (sell) with a limit price at or above (below) the upper (lower) Auction Collar would be included in the Auction Imbalance Information at the collared Indicative Match Price and would be eligible to trade at the Indicative Match Price. Proposed Rule 7.35P(a)(10)(D) would further provide that Limit Orders to buy (sell) with a limit price below (above) the lower (upper) Auction Collar would not be included in the Auction Imbalance Information and would not participate in the applicable auction. This proposed rule text uses Pillar terminology to provide specificity regarding how Limit Orders would participate in an auction that is subject to Auction Collars and is based on current functionality.
Proposed Rule 7.35P(b) would further provide that only Limit Orders in Auction-Eligible Securities would be eligible to participate in the Early Open Auction. This text is based on current Rule 7.35(a)(2), which provides that only Limit Orders designated for the Opening Session will be eligible for the Opening Auction.
Proposed Rule 7.35P(b)(1) would provide that thirty minutes before the Early Trading Session begins, the NYSE Arca Marketplace would begin disseminating the Early Open Auction Imbalance Information. This proposed rule text is based on current Rule 7.35(a)(3), which provides that, beginning 30 minutes prior to the Opening Session, and various times thereafter as determined from time to time by the Corporation, the Indicative Match Price of the Opening Auction and any Imbalance associated therewith, shall be published by electronic means as determined from time to time by the Corporation. Proposed Rule 7.35P(b)(1) would further provide that the non-displayed quantity of Reserve Orders eligible to participate in the Early Open Auction would not be included in the Matched Volume or Total Imbalance until the Early Open Auction Freeze begins, which would be new in Pillar. In addition, the Exchange proposes non-substantive differences for proposed Rule 7.35P(b)(1) to use Pillar terminology that is defined in proposed Rule 7.35P(a) to describe the same functionality as Rule 7.35(a)(3).
Proposed Rule 7.35P(b)(2) would provide that the Early Open Auction Imbalance Freeze would begin one minute before the scheduled time for the Early Open Auction. This proposed rule text is based on rule text in Rule 7.35(a)(4), which describes the one minute period prior to the Opening Auction as when orders may not be cancelled.
In Pillar, the Exchange proposes a substantive difference that during the Early Open Auction Imbalance Freeze, there would be no restrictions on order entry or cancellation. Accordingly, the Exchange would not include in Rule 7.35P rule text from current Rule 7.35(a)(4), which provides that orders that are eligible for the Opening Auction may not be cancelled one minute prior to the Opening Session until the conclusion of the Opening Auction.
Proposed Rule 7.35P(b)(3) would provide that Limit Orders eligible to trade in the Early Open Auction would be matched and traded in the Early Open Auction at the Indicative Match Price following Auction Ranking as of the time of the Early Open Auction. This proposed rule text is based on current Rule 7.35(b)(2), which provides that the orders in the Opening Auction shall be executed at the Indicative Match Price as of the time of the Opening Auction.
Proposed Rule 7.35P(b)(4) would provide that the Early Open Auction trade would be designated with a modifier to identify it as an extended hour .T trade. This rule text is based on current Rule 7.34(f), which provides that trades on the NYSE Arca Marketplace executed and reported outside of the Core Trading Session shall be designated as .T trades. The Exchange proposes to include this text in Rule 7.35P to provide specificity that an auction that occurs outside the Core Trading Session would also be designated as a .T trade.
Proposed Rule 7.35P(c) would further provide that orders in Auction-Eligible Securities that include a designation for the Core Trading Session and that are eligible to participate in an auction would be eligible to participate in the Core Open Auction. The Exchange has proposed in new Rule 7.31P to define which orders and modifiers are not eligible to participate in an auction.
Proposed Rule 7.35P(c)(1) would provide that the NYSE Arca Marketplace would begin publishing Core Open Auction Imbalance Information at 8:00 a.m. Eastern Time. This rule text is based on current Rule 7.35(c)(1), which provides that beginning at 5:00 a.m. (Pacific Time), and updated real-time thereafter, the Indicative Match Price of the Market Order Auction and the volume of Market Orders and Limit Orders available to trade at such price, and the Market Imbalance and Total Imbalance, if any, shall be published via electronic means and that Market Orders shall be included for purposes of calculating the Total Imbalance and Market Imbalance. The Exchange proposes non-substantive differences to use Eastern Time rather than Pacific Time, and to use new Pillar terminology, as proposed in Rule 7.35P(a)(7) above, to describe which information would be disseminated.
Proposed Rule 7.35P(c)(1) would further provide that the non-displayed quantity of Reserve Orders that are eligible to participate in the Core Open Auction would not be included in the Matched Volume, Total Imbalance, or Market Imbalance until the Core Open
Proposed Rule 7.35P(c)(3) would specify that the Core Open Auction Imbalance Freeze would begin five seconds before the scheduled time for the Core Open Auction. This proposed time frame would be a substantive difference for Pillar because on the current trading platform, order entry and cancellation restrictions begin one minute before the Market Order Auction. The Exchange also proposes substantive differences to how order entry and cancellation would be processed before the Core Open Auction. Accordingly, rule text in current Rule 7.35(c) and (d), which describe the order entry and cancellation requirements during the period between 6:29 a.m. (Pacific Time) and the conclusion of the Market Order Auction, would not be included in proposed Rule 7.35P.
The Exchange proposes a shorter Auction Imbalance Freeze period in order to provide additional time for market participants to enter orders for the Core Open Auction without restriction. As further proposed, in Pillar, the Exchange would not validate order entry during the freeze period based on whether an order offsets the real-time Imbalance. Rather, because of the shorter freeze period, MOO Orders and LOO Orders entered during the Core Open Auction Imbalance Freeze would be rejected, regardless of the side of the market. Market Orders and Limit Orders designated for the Core Trading Session only would be accepted during the Auction Imbalance Freeze without validating them on entry against the published Imbalance. Such orders would be eligible to participate in the Core Open Auction only to offset the Imbalance for the auction. The Exchange also proposes to retain the current functionality that MOO Orders and LOO Orders may not be cancelled beginning one minute before the scheduled time of the Core Open Auction.
Specifically, the Exchange proposes to process order entry and cancellation of orders before and during the Core Open Auction Imbalance Freeze as follows:
• Proposed Rule 7.35P(c)(2) would provide that beginning one minute before the scheduled time for the Core Open Auction, requests to cancel and requests to cancel and replace MOO Orders and LOO Orders would be rejected. This is based on current Rule 7.35(c)(2)(A)(2), which provides that beginning at 6:29 a.m. (Pacific Time) Market Orders (which include MOO Orders) and Limit Orders designated for the Core Trading Session may not be cancelled. The Exchange proposes a non-substantive difference to specify that such requests to cancel or cancel and replace would be rejected.
• Proposed Rule 7.35P(c)(3)(A) would provide that during the Core Open Auction Imbalance Freeze, MOO Orders and LOO Orders would be rejected. This proposed rule text would be a substantive difference in Pillar because currently, under Rule 7.35(c)(2)(A)(3), MOO Orders and LOO Orders may be entered to offset an Imbalance. Because the proposed Core Auction Imbalance Freeze period would be shorter in Pillar, the Exchange proposes instead to reject new MOO or LOO Orders, regardless of the side of the order.
• Proposed Rule 7.35P(c)(3)(B) would provide that Market Orders (other than MOO Orders) and Limit Orders designated for the Core Trading Session only would be accepted but would not be included in the calculation of the Indicative Match Price or the Core Open Auction Imbalance Information and that such orders would participate in the Core Open Auction only to offset the Imbalance that would remain after all orders entered before the Core Open Auction Imbalance Freeze, including the non-display quantity of Reserve Orders, are allocated in the Core Open Auction. The proposed rule would further provide that these offsetting orders would be allocated in price-time priority under Rule 7.36P(c)-(g) consistent with the priority ranking associated with each order.
This proposed rule text would be similar to current Rules 7.35(c)(2)(A)(3) 7.35(d)(2) in that Market Orders and Limit Orders designated for the Core Trading Session would participate in the auction only to reduce the Imbalance. The Exchange proposes a substantive difference in Pillar because the Exchange would not validate such orders on entry against the published Imbalance. Rather, such orders would be accepted but would only participate in the Core Open Auction if they were to offset the final Imbalance for the auction. As interest of last resort, such orders would be ranked in price-time priority after all other orders have been allocated.
The Exchange proposes to process Market Orders and Limit Orders differently from MOO Orders and LOO Orders because such orders would not expire at the end of the Core Open Auction. Rather than rejecting Market Orders and Limit Orders upon entry, they would be accepted and would be eligible to be offsetting interest for the auction. If these orders do not participate in the Core Open Auction, they would become eligible to participate in the Core Trading Session.
• Proposed Rule 7.35P(c)(3)(C) would provide that requests to cancel and requests to cancel and replace Market Orders (other than MOO Orders) and Limit Orders designated for the Core Trading Session only would be accepted but not processed until after the Core Open Auction concludes. This proposed rule text is based on current Rule 7.35(c)(2)(A)(2), but with a proposed substantive difference that order entry restrictions would be during a five-second rather than a one-minute period. The proposed Pillar rule would function similarly to the current rule in that requests to cancel pending Market Orders and Limit Orders would not be permitted during the Core Open Auction Imbalance Freeze period.
• Proposed Rule 7.35P(c)(3)(D) would provide that all other order instructions would be accepted. Proposed Rule 7.35P(c)(3)(D) would therefore include that requests to cancel Limit Orders designated for both the Early Trading Session and Core Trading Session would be accepted, which is based on current Rule 7.35(c)(2)(A)(2).
Proposed Rule 7.35P(c)(4) would provide that all orders eligible to trade in the Core Open Auction would be matched and traded at the Indicative Match Price following Auction Ranking as of the time of the Core Open Auction. This rule text is based on current Rule 7.35(c)(3), which specifies how the Market Order Auction Price is determined. As discussed above, in
Proposed Rule 7.35P(c)(5) would provide that the Core Open Auction trade would be designated with a modifier to identify it as a Core Open Auction trade. This rule text is based on current Rule 7.35(c)(4), with non-substantive differences to use Pillar terminology.
Proposed Rule 7.35P(d) would further provide that orders in Auction-Eligible Securities that include a designation for the Core Trading Session and that are eligible to participate in an auction would be eligible to participate in the Closing Auction. As discussed above, proposed Rule 7.31P would specify which orders are eligible to participate in an auction.
Proposed Rule 7.35P(d)(1) would provide that the NYSE Arca Marketplace would begin publishing Closing Auction Imbalance Information one hour before the scheduled time for the Closing Auction. This proposed rule text is based on current Rule 7.35(e)(1)(A), which provides that beginning at 12:00 p.m. (Pacific Time), and updated real-time thereafter, the Indicative Match Price of the Closing Auction and volume available to trade at such price, and the Total Imbalance and Market Imbalance associated with the Closing Auction, if any, will be published via electronic means. The Exchange proposes non-substantive differences to specify that the information would begin being published one hour before the scheduled time for the Closing Auction, rather than specifying 12:00 p.m. Pacific Time. This proposed difference would address those days when the Exchange has an early scheduled close, in which case, Closing Auction Imbalance Information would be disseminated beginning at 12:00 p.m. Eastern Time, which is one hour before the early scheduled close of 1:00 p.m. Eastern Time. The Exchange also proposes non-substantive differences to use new Pillar terminology, as proposed in Rule 7.35P(a)(4) above, to describe which information would be disseminated. Proposed Rule 7.35P(d)(1) would further provide that the non-displayed quantity of Reserve Orders that would be eligible to participate in the Closing Auction would not be included in the Matched Volume, Total Imbalance, or Market Imbalance until the Closing Auction Imbalance Freeze would begin. This would be new rule text in Pillar.
Proposed Rule 7.35P(d)(2) would specify that the Closing Auction Imbalance Freeze would begin one minute before the scheduled time for the Closing Auction. This proposed time frame is based on rule text in current Rule 7.35(e)(2)(B) and (C), which describe the order entry and cancellation requirements during the period between 12:59 p.m. (Pacific Time) and the conclusion of the Closing Auction.
The Exchange proposes non-substantive differences in Pillar regarding how order entry and cancellation would be handled during the Closing Auction Imbalance Freeze. The Exchange proposes to process order entry and cancellation of orders during the Closing Auction Imbalance Freeze as follows:
• Proposed Rule 7.35P(d)(2)(A) would provide that LOC Orders and MOC Orders that are on the same side of the Imbalance, would flip the Imbalance, or would create a new Imbalance would be rejected. This proposed rule text is based on the first and third sentences of current Rule 7.35(e)(2)(C), which provides that MOC Orders and LOC Orders may not be entered on the same side as the Imbalance and that MOC Orders and LOC Orders that create equilibrium and thereafter convert the Imbalance from a buy to a sell (or convert the Imbalance from a sell to a buy) Imbalance will be rejected. The Exchange proposes non-substantive differences in Rule 7.35P to use Pillar terminology and to specify that such orders would be rejected. The Exchange would not include the examples set forth in current Rule 7.35(e)(2)(C)(1) and (2) in the Pillar rule because the Exchange believes that the proposed Pillar rule describes which orders would be rejected without the need for examples.
• Proposed Rule 7.35P(d)(2)(B) would provide that requests to cancel and requests to cancel and replace MOC Orders and LOC Orders would be rejected. This proposed rule text is based on current Rule 7.35(e)(2)(B), which provides that MOC Orders and LOC Orders may not be cancelled. The Exchange proposes a non-substantive difference to specify that any such requests would be rejected.
• Proposed Rule 7.35P(d)(2)(C) would provide that all other order instructions would be accepted. Because the Exchange would continue to accept requests to cancel Limit Orders, rule text set forth in Rule 7.35(e)(2)(B), which provides that Limit Orders (except LOC Orders) may be cancelled, would not be included in proposed Rule 7.35P(d)(2). Similarly, because MOC Orders and LOC Orders, other than those specified in proposed Rule 7.35P(d)(2)(A), would be accepted during the Closing Auction Imbalance Freeze, the Exchange would not include text from the second sentence of Rule 7.35(e)(2)(C), which provides that MOC Orders and LOC Orders that reduce the Imbalance may be entered on the opposite side of the Imbalance any time before the conclusion of the Closing Auction, in the Pillar rule.
Proposed Rule 7.35P(d)(3) would provide that all orders eligible to trade in the Closing Auction would be matched and traded at the Indicative Match Price following Auction Ranking as of the time of the Closing Auction. This rule text is based on current Rule 7.35(e)(3), which specifies how the Closing Auction Price is determined. As discussed above, in Pillar, the Exchange proposes to describe how the Indicative Match Price would be determined in proposed Rule 7.35P(a)(6)(A)-(E), and therefore would not duplicate the text currently set forth in Rule 7.35(e)(3)(A)-(B) in the Pillar rule.
Proposed Rule 7.35P(d)(4) would provide that the Closing Auction trade would be designated with a modifier to identify it as a Closing Auction trade. This rule text is based on current Rule 7.35(e)(3)(D), with non-substantive differences to use Pillar terminology.
Proposed Rule 7.35P(e)(1) would provide that immediately after trading in an Auction-Eligible Security is halted or paused, the NYSE Arca Marketplace would begin publishing Trading Halt Auction Imbalance Information. This proposed rule text is based on current Rule 7.35(f)(2)(A) and (B), which provides that immediately after trading is halted in a security, and updated real-time thereafter, the Indicative Match Price of the Trading Halt Auction and the volume available to trade at such price, as well as the Market and Total Imbalance information, shall be published via electronic means and that if such a price does not exist, the NYSE Arca Marketplace shall indicate via electronic means that an Indicative Match Price does not exist. The Exchange proposes non-substantive differences to use new Pillar terminology, as proposed in Rule 7.35P(a)(4) above, to describe which information would be disseminated. The Exchange also proposes to specify that Trading Halt Auction Imbalance Information would be disseminated during a trading pause, which is current functionality.
Proposed Rule 7.35P(e)(2) would provide that after trading in a security has been halted or paused, the NYSE Arca Marketplace would disseminate the estimated time at which trading in that security would re-open, which would be defined as the “Re-Opening Time.” This proposed rule text is based on current Rule 7.35(f)(1), which provides that after trading in a security has been halted, the NYSE Arca Marketplace shall disseminate the estimated time at which trading in that security will re-open (the “Re-Opening Time”). The Exchange proposes non-substantive differences in the Pillar rule to specify that a Re-Opening Time would be disseminated during a trading pause and to use the term “will” instead of “shall.”
Proposed Rule 7.35P(e)(3) would provide that during a trading halt or pause in an Auction-Eligible Security, entry and cancellations of orders eligible to participate in the Trading Halt Auction would be processed as provided for in Rule 7.18P(c).
Proposed Rule 7.35P(e)(4) would provide that all orders eligible to trade in a Trading Halt Auction would be matched and traded at the Indicative Match Price following Auction Ranking as of the Re-Opening Time. This rule text is based on the first sentence of current Rule 7.35(f)(4)(A), which provides that for those issues for which the Corporation is the primary market, Orders will be executed at the Indicative Match Price at the Re-Opening Time. As discussed above, in Pillar, the Exchange proposes to describe how the Indicative Match Price would be determined in proposed Rule 7.35P(a)(6)(A)-(E), and therefore would not duplicate the remaining text currently set forth in Rule 7.35(f)(4) in the Pillar rule.
Proposed Rule 7.35P(e)(5) would provide that a Trading Halt Auction that occurs during the Early Trading Session or the Late Trading Session would be designated with a modifier to identify it as an extended hour .T trade. A Trading Halt Auction that occurs during the Core Trading Session would be designated with a modifier to identify it as a halt auction. This would be new rule text in Pillar, but represents how trades are currently reported.
In Pillar, the Exchange would not have a Trading Halt Auction Imbalance Freeze. Accordingly, rule text in current Rule 7.35(f)(3)(C), which provides that the Corporation, if it deems such action necessary, will disseminate the time, prior to the time that orders are matched pursuant to the Trading Halt Auction, at which orders may no longer be cancelled, would not be included in Rule 7.35P.
As further proposed, an IPO Auction would follow the processing rules of a Core Open Auction, provided that:
• As provided for in proposed Rule 7.35P(f)(1), the NYSE Arca Marketplace would specify the time that an IPO Auction would be conducted. While an IPO Auction would occur during the Core Trading Session, the Exchange proposes to provide the Exchange with discretion to designate the time for the IPO Auction.
• As provided for in proposed Rule 7.35P(f)(2), there would be no Auction Imbalance Freeze, Auction Collars, or restrictions on the entry or cancellation of orders for an IPO Auction. Because an IPO Auction would not be set at a specific time, nor would there be any trading in the security before the IPO Auction, the Exchange does not believe that an Auction Imbalance Freeze or Auction Collars would assist in the price discovery process. Similarly, because the time of an IPO Auction may change, the Exchange does not believe that there needs to be any restrictions on the entry or cancellation of orders, including cancellation of MOO Orders and LOO Orders, before an IPO Auction. Accordingly, an IPO Auction would not be subject to these requirements.
• As provided for in proposed Rule 7.35P(f)(3), an IPO Auction would not
As proposed in Rule 7.35P(h)(1), after auction processing concludes, orders that are no longer eligible to trade, either because they are Auction-Only Orders or not eligible for the next trading session, would expire. This proposed rule text is based on current Rule 7.35(e)(3)(C), which provides that MOC Orders that are eligible for, but not executed in, the Closing Auction, shall be cancelled immediately upon conclusion of the Closing Auction. The Exchange proposes non-substantive differences to specify that any order that is not eligible for the next trading session, and not just MOC Orders, would expire after the respective auction concludes.
As proposed in Rule 7.35P(h)(2), orders that are designated for the trading session following an auction and that were received before the auction or during the Auction Processing Period, and that did not participate in the auction, would become eligible to trade. This proposed rule text is based on the following rules:
• Rule 7.35(b)(3), which provides that orders that are eligible for, but not executed in, the Opening Auction shall become eligible for the Opening Session immediately upon conclusion of the Opening Auction;
• Rule 7.35(c)(3)(A)(3), which provides that the Market Orders that are eligible for both the Market Order Auction and the Core Trading Session, but which are not executed in the Market Order Auction, shall become eligible for execution in the Core Trading Session immediately upon conclusion of the Market Order Auction;
• Rule 7.35(d)(1) and (2), which provide that Limit and Market Orders entered after 6:29 a.m. (Pacific Time) become eligible for execution at 6:30 a.m. (Pacific Time) or the conclusion of the Market Order Auction, whichever is later; and
• Rule 7.35(f)(5), which provides that if any orders are not executed in their entirety during the Trading Halt Auction, then such orders shall be executed in accordance with Rule 7.37 after the completion of the Trading Halt Auction.
The Exchange proposes non-substantive differences in proposed Rule 7.35P(h)(2) to consolidate the text of Rules 7.35(b)(3), 7.35(c)(3)(A)(3), 7.35(d)(1) and (2), and 7.35(f)(5) into a single rule that uses Pillar terminology to describe that orders that do not participate in an auction and that are eligible for the trading session following such auction would become eligible to trade.
Proposed Rule 7.35P(h)(3) would provide that before continuous trading in the Trading Session following the applicable auction begins, the Exchange would process orders as follows:
• As provided for in proposed Rule 7.35P(h)(3)(A), any order instructions received during either the Auction Imbalance Freeze or Auction Processing Period that were not processed will be processed. For example, a request to cancel a Limit Order designated for the Core Trading Session only and that was entered during the Core Open Auction Imbalance Freeze would be processed after the auction processing concludes. This rule text would be new in Pillar and uses Pillar terminology to specify when order instructions would be processed.
• As provided for in proposed Rule 7.35P(h)(3)(B), the working price of orders would be adjusted based on the PBBO or NBBO, as provided for in proposed Rule 7.31P. Before becoming eligible to trade in the next trading session, orders would have their working prices adjusted as provided for in proposed Rule 7.31P and consistent with the terms of the respective orders. This rule text would be new in Pillar and uses Pillar terminology regarding when an order would receive a new working price.
• As provided for in proposed Rule 7.35P(h)(3)(C), if orders that become eligible to trade would be marketable, such orders would trade and/or route based on price-time priority of individual orders as provided for in Rule 7.37P. This rule text would be new in Pillar and uses Pillar terminology to describe that following an auction, orders that are marketable would trade or route, as provided for in Rule 7.37P, before the Exchange would disseminate its first quote following an auction. The Exchange proposes that following an auction, if orders that did not trade in an auction, or were not eligible to trade in an auction, are marketable, these orders should trade or route, as applicable, rather than publishing a locked or crossed quote from the NYSE Arca Book.
• As provided for in proposed Rule 7.35P(h)(3)(D), after marketable orders have been routed or traded, the NYSE Arca Marketplace would publish a quote for the next trading session. This rule text would be new in Pillar.
This proposed treatment of sell short Market Orders would be applicable only for purposes of auctions because once adjusted to a Permitted Price, a sell short Market Order has a price and such price would be used for purposes of determining the price of an auction. For example, if there are only buy Market Orders and sell short Market Orders for an auction, the Permitted Price at which sell short Market Orders are priced to a Permitted Price would be the basis for determining the Indicative Match Price for that auction, instead of the applicable Auction Reference Price, as described above. Because the Permitted Price of sell short Market Orders would be used for purposes of determining the Indicative Match Price, the Exchange proposes that for purposes of order allocation during an auction, sell short Market Orders that have been adjusted to a Permitted Price would be ranked as Priority 2—Display Orders.
Proposed Commentary .01(b) to Rule 7.35P would further provide that, during a Short Sale Period, sell short orders that would be included in Auction Imbalance Information, but which would not be eligible for continuous trading before the applicable auction, would be adjusted to a Permitted Price as the NBB moves both up and down. The Exchange believes this proposed rule text provides clarity that for purposes of calculating Auction Imbalance Information before each applicable auction, orders that are not eligible for continuous trading (
As discussed in the Pillar I Filing, because of the technology changes associated with the migration to the Pillar trading platform, the Exchange will announce by Trader Update when rules with a “P” modifier will become operative and for which symbols. The Exchange believes that keeping existing rules pending the full migration of Pillar is necessary because they would continue to govern trading on the current trading platform pending the full migration.
The proposed rule change is consistent with Section 6(b) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange believes that new Rule 7.35P, together with the rules adopted in the Pillar I Filing and the rules proposed in the Pillar II Filing and Pillar III Filing, would remove impediments to and perfect the mechanism of a free and open market because they would promote transparency by using consistent terminology for rules governing equities trading, thereby ensuring that members, regulators, and the public can more easily navigate the Exchange's rulebook and better understand how equity trading would be conducted on the Pillar trading platform. Adding new rules with the modifier “P” to denote those rules that would be operative for the Pillar trading platform would remove impediments to and perfect the mechanism of a free and open market by providing transparency of which rules govern trading once a symbol has been migrated to the Pillar platform. In addition, the proposed use of new Pillar terminology would promote consistency in the Exchange's rulebook regarding how the Exchange would process orders during an auction.
The Exchange believes that the proposed amendments to existing definitions in Rule 1.1 would remove impediments to and perfect the mechanism of a fair and orderly market because they would not make any substantive changes to Exchange rules, but rather are designed to reduce confusion by specifying that Rules 1.1(r) and (s) would be applicable to auctions on the current trading platform only, and would not be applicable to symbols trading on the Pillar platform.
The Exchange believes that proposed Rule 7.35P, which would govern auctions in Pillar, would remove impediments to and perfect the mechanism of a fair and orderly market because it would set forth in a single rule the requirements for auctions in Pillar in both UTP Securities and Exchange-listed securities, which are currently described in Rules 1.1(r) and (s) and Rule 7.35. The proposed new definitions for new Rule 7.35P, including the new terms Auction Processing Period, Auction Imbalance Freeze, Auction NBBO, Auction Ranking, and Auction Reference Price, would promote transparency by using common definitions that incorporate Pillar terminology to describe how auctions would function in Pillar.
The Exchange believes that the proposed substantive differences for Rule 7.35P as compared to the current rules would remove impediments to and perfect the mechanism of a fair and orderly market for the following reasons:
• The proposed substantive difference to add that Market Orders would include not only MOO Orders for the Core Open Auction, but also MOO Orders for a Trading Halt Auction and MOC Orders for the Closing Auction, and use Pillar terminology to specify that all such orders would be ranked Priority 1—Market Orders, would promote transparency in Exchange rules regarding how Market Orders, MOO Orders, and MOC Orders would be processed during an auction.
• The proposed substantive difference to define the term “Auction-Eligible Securities,” to provide the Exchange with the ability to conduct auctions in all securities that trade on the Exchange, including UTP Securities, would support the initiatives of the Exchange, NYSE, and Nasdaq to increase resiliency by having auctions on the Exchange serve as a back-up to
• The proposed substantive difference to update Auction Imbalance Information at least every second, rather than on a real-time basis, both for the proprietary data feed dissemination and for determining order entry eligibility during the applicable Auction Imbalance Freeze period would promote transparency in Exchange rules regarding which Imbalance would be used to determine order entry eligibility during specified Auction Imbalance Freeze periods.
• The proposed substantive difference to define a new term, “Auction NBBO,” to use as the basis for pricing the Core Open Auction and the Indicative Match Price for the Closing Auction when that auction consists only of Market Orders would promote transparency regarding how the Exchange would determine pricing for such auctions. Further to this point, the Exchange believes that creating a process to validate the Auction NBBO for the Core Open Auction by comparing the midpoint value to the spread of the NBBO, and if the NBBO is not valid, to use the prior day's Official Closing Price, would ensure that the NBBO is sufficiently tight to guarantee that the midpoint of the NBBO would be a meaningful and accurate basis for pricing the Core Open Auction.
• The proposed substantive difference to allocate orders on the side of the Imbalance the same for all auctions and describe such ranking in the new defined term “Auction Ranking” would promote transparency in Exchange rules by consolidating into a single location how orders would be ranked for auctions. In addition, using the same methodology to rank and allocate orders on the side of the Imbalance for all auctions based on the priority ranking described in Rule 7.36P would promote consistency in how the Exchange would rank orders on the Pillar trading platform, whether for continuous trading or for auctions.
• The proposed substantive difference that during a Short Sale Period, processing sell short Market Orders that have been adjusted to a Permitted Price as Limit Orders ranked Priority 2—Display Orders for purposes of pricing an auction and ranking orders for allocation in an auction would ensure that such orders would not trade at or below the NBB. In addition, processing such re-priced sell short Market Orders as Limit Orders would promote transparency by processing all orders that have a price similarly in an auction.
• The proposed substantive difference that the Market Imbalance would be Market Orders not matched for trading in an auction against any interest, and not just Market Orders not matched for trading against other Market Orders, would promote transparency regarding the volume of Market Orders that have not been paired against any interest for an auction.
• The proposed substantive difference to publish an Indicative Match Price based on a published BBO when there is no Matched Volume, and more specifically, if the BB equals the BO volume, to use the BB as the Indicative Match Price, would serve as a benchmark price to attract additional interest for an auction, thereby promoting price discovery.
• The proposed substantive difference to determine the Indicative Match Price for all securities in the same manner regardless of whether the Exchange is the primary listing market for a security or the security is a UTP Security would promote clarity and transparency in Exchange rules and streamline how auctions would be processed.
• The proposed substantive difference to conduct a Closing Auction if there are only Market Orders on both sides of the market and use the midpoint of the Auction NBBO to price such auction would increase the potential for market participants that have entered MOC Orders to receive an execution in an auction that is priced based on the prevailing value of the security. Specifically, pricing such auction based on the midpoint of the Auction NBBO in effect as of the scheduled time of the Closing Auction would reflect the most recent quoting activity in a stock and therefore the market's view of the value of the security. If there is no Auction NBBO, which would indicate that there is not a good quote in a security, the Exchange would instead price the auction based on the last consolidated round lot sale, which, in the absence of an Auction NBBO, would reflect the most recent price for the security.
• The proposed substantive difference to adjust an Indicative Match Price that is outside the Auction Collars to be one MPV inside the Auction Collars, rather than to the Auction Collar, would reduce the potential for an auction to be priced at the Auction Collar. More specifically, if the Auction Collars are based on the clearly erroneous execution thresholds (which is currently the case for the Core Open Auction), pricing an auction one MPV inside the Auction Collar would potentially prevent an auction from being a clearly erroneous execution.
• The proposed substantive difference not to have any order entry or cancellation restrictions during the one-minute Auction Imbalance Freeze before the Early Open Auction reflects that there is not any trading occurring before the Early Open Auction, and therefore the risk to manipulate market prices before the Early Open Auction is minimal.
• The proposed substantive difference to have a Core Open Auction Imbalance Freeze of five seconds instead of one minute would increase the period during which orders may be entered to participate in the Core Open Auction, thereby promoting price discovery for the auction. To reduce the potential to manipulate pricing for the auction, the Exchange proposes to retain the current functionality that MOO Orders and LOO Orders may not be cancelled beginning one minute before the scheduled time for the auction.
With respect to order entry and cancellation during the Core Open Auction Imbalance Freeze, the Exchange believes that rejecting all MOO Orders and LOO Orders during this period would remove the potential for such orders to impact the Imbalance. The Exchange further believes that accepting Market Orders and Limit Orders designated for the Core Trading Session only on both sides of the market during the Core Open Auction Freeze and then allowing such orders to participate in the Core Open Auction only if they offset the Imbalance in effect at the scheduled time of the Core Open Auction would eliminate the possibility for these orders to create an Imbalance or increase an Imbalance.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed change is not designed to address any competitive issue but rather to adopt new rules to support the Exchange's new Pillar trading platform. As discussed in detail above, the Exchange proposes a new rule for auctions in Pillar, which would be based on current rules with both substantive and non-substantive differences. The proposed substantive differences would promote competition because the Exchange would be offering functionality that would promote price discovery and liquidity on the primary listing market for auctions, thereby supporting competition. The proposed
No written comments were solicited or received with respect to the proposed rule change.
Within 45 days of the date of publication of this notice in the
(A) By order approve or disapprove the proposed rule change, or
(B) institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change 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 (the “Act”),
The Exchange proposes to amend Rule 7270 (Block Trades). The text of the proposed rule change is available from the principal office of the Exchange, at the Commission's Public Reference Room and also on the Exchange's Internet Web site at
In its filing with the Commission, the self-regulatory organization 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 self-regulatory organization has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The purpose of the proposed rule change is to amend Rule 7270 (Block Trades) to permit an Order Flow Provider (“OFP”) initiating a Facilitation Auction, at its option, to designate a lower amount for which it will retain certain priority and trade allocation privileges upon the conclusion of the Facilitation Auction.
The Facilitation Auction mechanism allows OFPs to enter crossing transactions where the OFP represents a block-size order as agent (“Agency Order”) and (1) is trading against the Agency Order as principal (
OFPs must be willing to execute the entire size of the Agency Orders entered into the Facilitation Auction through the submission of a contra “Facilitation Order.” Upon the entry of an Agency
Unless there is sufficient size to execute the entire Agency Order at a better price, Public Customer bids (offers) and Public Customer responses at the time the Agency Order is executed that are priced higher (lower) than the facilitation price are executed at the facilitation price. Non-Public Customer and Market Maker bids (offers) and Non-Public Customer and Market Maker responses at the time the Agency Order is executed that are priced higher (lower) than the facilitation price are executed against the Agency Order at their stated price, which provides Agency Order execution at a better price for the number of contracts associated with such higher bids (lower offers) and responses.
The facilitating OFP is allocated priority for at least forty percent (40%) of the original size of the Facilitation Order, but only after better-priced bids (offers) and responses, as well as Public Customer bids (offers) and responses at the facilitation price, are executed in full. After the facilitating OFP has executed his forty percent (40%), Non-Public Customer and Market Maker bids (offers) and responses at the facilitation price will participate in the execution of the Agency Order based upon price and time priority.
The Exchange is now proposing to amend the Facilitation Auction to permit an OFP to designate a lower amount for which it will retain certain priority and trade allocation privileges at the conclusion of the Facilitation Auction. Specifically, this proposal will permit an OFP, when starting a Facilitation Auction, to submit the Facilitation Order to BOX with a designation to identify the total size of the Agency Order that the OFP is willing to “surrender” to other Participants (“Surrender Quantity”), resulting in the OFP potentially being allocated less than the forty percent (40%) to which it is entitled.
The proposed rule change further provides that in no case shall the OFP's use of the Surrender Quantity function result in an allocation to the OFP that would be greater than the maximum allowable allocation the OFP would otherwise receive in accordance with the Facilitation allocation procedures set forth in Rule 7270(a).
The proposed rule change will modify the Trading Host's
The Exchange will provide Participants with notice, via Information Circular, about the implementation date of the Surrender Quantity prior to its implementation in the trading system.
The Exchange believes that the proposal is consistent with the requirements of section 6(b) of the Act,
The Exchange believes that the proposed rule change will benefit investors and Participants by allowing an OFP the flexibility to designate a lower amount for which it will retain certain priority and trade allocation privileges upon the conclusion of the Facilitation Auction, thereby providing other Participants with the opportunity to receive increased trade allocations. The proposed rule change is designed to promote just and equitable principles of trade by assuring that an OFP cannot use the Surrender Quantity to receive an allocation greater than the maximum allowable percentage. The proposed rule change will protect investors and the public interest because Public Customer orders will still receive the same priority during the allocation process.
The proposed changes are similar to Exchange rules applicable to other auctions offered by the Exchange. Specifically, the Exchange allows Participants to submit a surrender quantity when submitting orders to the Price Improvement Period (“PIP”) and Solicitation Auction.
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. In this regard and as indicated above, the Exchange notes that the rule change is similar to rules of the Exchange's PIP and Solicitation Auction. The Exchange believes that the propose rule change should incent OFPs to continue submitting block trades to the Facilitation Auction to the benefit of the Exchange and its Participants and public customers. The Exchange believes that the proposal will enhance competition by providing an opportunity for Participants to receive a greater allocation at the end of the Facilitation Auction.
The Exchange has neither solicited nor received comments on the proposed rule change.
Because the proposed rule change does not (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate if consistent with the protection of investors and the public interest, the proposed rule change 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 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 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)
The Exchange proposes to amend the NYSE Arca Equities Schedule of Fees and Charges for Exchange Services (“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 self-regulatory organization 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 those statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries,
The Exchange proposes to amend the Fee Schedule to (i) change certain rebate and volume thresholds applicable to Lead Market Makers (“LMMs”)
The Exchange proposes to amend the Fee Schedule to modify the structure of the transaction credits it provides to LMMs for providing displayed liquidity in the NYSE Arca Marketplace
• $0.0035 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month greater than 5,000,000 shares
• $0.004 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month of between 1,000,000 and 5,000,000 shares
• $0.0045 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month of less than 1,000,000 shares
The Exchange proposes to lower the credit for the tier requiring a CADV in the previous month greater than 5,000,000 shares from $0.0035 per share to $0.0033 per share. The Exchange is not proposing any change to the credits provided for the other two tiers. The Exchange also proposes to lower the volume threshold for the tier requiring a CADV in the previous month greater than 5,000,000 million shares from 5,000,000 shares to 3,000,000 shares, and lower the volume threshold for the tier requiring a CADV in the previous month of between 1,000,000 shares and 5,000,000 to 1,000,000 shares and 3,000,000 shares. The Exchange is not proposing any change to the volume threshold for the remaining tier.
As proposed, the transaction credits and volume thresholds would be as follows:
• $0.0033 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month greater than 3,000,000 shares
• $0.004 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month of between 1,000,000 and 3,000,000 shares
• $0.0045 per share (credit) for orders that provide displayed liquidity to the Book in securities for which they are registered as the LMM and which have a CADV in the previous month of less than 1,000,000 shares
The Exchange proposes to adopt tier-based incremental credits for orders that provide displayed liquidity to the NYSE Arca Book in Tape B Securities. Specifically, LMMs that are registered as the LMM in Tape B securities that have a CADV in the previous month of less than 100,000 shares (“Less Active ETP Securities”), and the ETP Holders and Market Makers affiliated with such LMMs, would receive an additional credit for orders that provide displayed liquidity to the Book in any Tape B Securities that trade on the Exchange.
• An additional credit of $0.0004 per share if an LMM is registered as the LMM in at least 300 Less Active ETP Securities
• An additional credit of $0.0003 per share if an LMM is registered as the LMM in at least 200 but less than 300 Less Active ETP Securities
• An additional credit of $0.0002 per share if an LMM is registered as the LMM in at least 100 but less than 200 Less Active ETP Securities
The number of Less Active ETP Securities for the billing month would be based on the number of Less Active ETP Securities in which an LMM is registered as the LMM on the last business day of the previous month. As noted above, the proposed incremental credits would also apply to ETP Holders and Market Makers affiliated with the LMM whose orders in Tape B Securities provide displayed liquidity to the NYSE Arca Book.
For example, a LMM that provides liquidity to the NYSE Arca Book in a security for which the LMM is registered as the LMM which has a CADV in the previous month of at least 1,000,000 shares would receive a credit of $0.0045 per share. If that LMM is a Tier 1 firm that is also registered as an LMM in 250 Less Active ETP Securities, the LMM would receive an incremental credit of $0.0003 per share under the proposed new rebate structure, for a total credit of $0.0048 per share. Additionally, affiliated ETP Holders and Market Makers of such LMM that provide displayed liquidity in Tape B Securities would receive a total credit of $0.0026 per share,
With this pricing incentive, the Exchange hopes to provide incentives for increased trading in Less Active ETP Securities for market participants.
The Exchange currently charges a fee of $0.0025 per share to LMMs for orders in primary listed securities that remove liquidity from the NYSE Arca Book. The Exchange proposes to increase this fee to $0.0028 per share.
Currently, ETP Holders and Market Makers qualify for Tier 1 fees and
The Exchange proposes to simplify this pricing tier by removing the second requirement. As proposed, ETP Holders and Market Makers will qualify for Tier 1 fees and credits if they provide liquidity an average daily share volume per month of 0.70% or more of the US CADV. Additionally, the Exchange proposes distinct fees and credits applicable to Tape A and Tape C Securities. As proposed, ETP Holders and Market Makers would receive an increased credit of $0.0031 per share for orders that provide liquidity to the Book in Tape A Securities and will continue to pay a fee of $0.0030 per share for orders that take liquidity from the Book in Tape A Securities. ETP Holders and Market Makers would receive an increased credit of $0.0033 per share for orders that provide liquidity to the Book in Tape C Securities and would pay a lower fee of $0.0029 per share for orders that take liquidity from the Book in Tape C Securities. The Exchange is not proposing any change to the per share credit provided to ETP Holders and Market Makers in Tape B Securities.
Currently, ETP Holders and Market Makers receive a credit of $0.0030 per share in Tape A, Tape B and Tape C Securities when such participants (1) provide liquidity of 0.40% or more of the US CADV per month, and (2) are affiliated with an OTP Holder or OTP Firm that provides an ADV of electronic posted Customer executions in Penny Pilot issues on NYSE Arca Options (excluding mini options) of at least 0.95% of total Customer equity and ETF option ADV as reported by OCC, or when such participants (1) provide liquidity of 0.30% or more of the US CADV per month, (2) are affiliated with an OTP Holder or OTP Firm that provides an ADV of electronic posted Customer executions in all issues on NYSE Arca Options (excluding mini options) of at least 0.80% of total Customer equity and ETF option ADV as reported by OCC, and (3) execute an ADV of Retail Orders that provide liquidity during the month that is 0.10% or more of the US CADV. Under the current tier, participants receive a credit of $0.0030 per share for providing liquidity to the order book in Tape A, Tape B and Tape C Securities.
The Exchange proposes to simplify this pricing tier by removing the first requirement. As proposed, ETP Holders and Market Makers would receive a per share credit when such participants (a) provide liquidity of 0.30% or more of the US CADV per month, (b) are affiliated with an OTP Holder or OTP Firm that provides an ADV of electronic posted Customer executions in all issues on NYSE Arca Options (excluding mini options) of at least 0.80% of total Customer equity and ETF option ADV as reported by OCC, and (c) execute an ADV of Retail Orders that provide liquidity during the month that is 0.10% or more of the US CADV. The Exchange is not proposing any change to the amount of the credit in Tape A, Tape B and Tape C Securities, which will remain at $0.0030 per share. The Exchange also proposes to rename the current tier to Cross Asset Tier 1 to distinguish this pricing tier from Cross Asset Tier 2, which the Exchange is proposing to adopt with this proposed rule change.
The Exchange proposes a new pricing tier—Cross Asset Tier 2—for securities with a per share price above $1.00.
As proposed, the Cross Asset Tier 2 would apply to ETP Holders and Market Makers that (a) provide liquidity an average daily volume share per month of 0.30% or more of the US CADV and (b) are affiliated with an OTP Holder or OTP Firm that provides an ADV of electronic posted executions for the account of a market maker in Penny Pilot issues on NYSE Arca Options (excluding mini options) of at least 90,000 contracts. Such ETP Holders and Market Makers would receive a credit of $0.0031 per share for orders that provide liquidity to the order book in Tape A Securities; a credit of $0.0030 per share for providing liquidity to the order book and a fee of $0.0028 per share for taking liquidity from the order book in Tape B Securities; and a credit of $0.0033 per share for providing liquidity to the order book and a fee of $0.0029 per share for taking liquidity from the order book in Tape C Securities.
The Exchange proposes to introduce two new pricing tier levels—Tape B Tier 1 and Tape B Tier 2—for securities with a per share price above $1.00.
As proposed, a new Tape B Tier 1 credit of $0.0030 per share
Additionally, a new Tape B Tier 2 credit of $0.0028 per share
The Fee Schedule currently includes several pricing tiers that have not encouraged ETP Holders and Market Makers to increase their activity to qualify for the tiers as significantly as the Exchange anticipated they would. These tiers are as follows: (i) Step Up Tier 1, (ii) Step Up Tier 2, (iii) Step Up Tier 3, (iv) Tape B Step Up Tier, (v) Tape C Step Up Tier, (vi) Tape C Step Up Tier 2, and (vii) Routable Order Tier. The Exchange proposes to remove these pricing tiers from the Fee Schedule as well as any related cross references.
The Exchange currently makes ports available that provide connectivity to the Exchange's trading systems (
The Exchange proposes to standardize the port fee and charge $550 per port per month, regardless of the number of users and whether the port is used for order/quote entry or for drop copies. The Exchange believes standardizing the port fees will permit the Exchange to offset, in part, its infrastructure costs associated with making such ports available. The proposed change would also encourage users to become more efficient with their usage of the ports thereby resulting in a corresponding increase in the efficiency that the Exchange would be able to realize with respect to managing its own infrastructure. In this regard, as users decrease the number of ports that they utilize, the Exchange would similarly be able to decrease the amount of its hardware that it is required to support to interface with such ports.
The proposed changes are not otherwise intended to address any other issues, and the Exchange is not aware of any problems that ETP Holders would have in complying with the proposed changes.
The Exchange believes that the proposed rule change is consistent with section 6(b) of the Act,
The Exchange believes the proposed new incremental tiered-rebates will provide a further incentive for LMMs to quote and trade a greater number of securities on the Exchange and will generally allow the Exchange and LMMs to better compete for order flow and thus enhance competition. Specifically, the Exchange believes that its proposal, which among other things, adjusts the CADV and credits for LMMs based on the CADV of the security in primary listed securities in which they are registered as the LMM, is reasonable as it is still the highest credit in securities with a CADV greater than 3,000,000 shares. The Exchange also believes that the rebate for providing displayed liquidity is equitable because it would uniformly apply to all LMMs.
The proposed fee change is intended to encourage ETP Holders to promote price discovery and market quality in Less Active ETP Securities for the benefit of all market participants. The Exchange believes the proposed credits are reasonable and appropriate in that they are based on the amount of business transacted on the Exchange. The Exchange notes that the proposed fee change is similar to market quality incentive programs already in place on other markets, such as the Qualified Market Maker incentive on the NASDAQ Stock Market LLC (“NASDAQ”), which requires a member on that exchange to provide meaningful and consistent support to market quality and price discovery by quoting at the National Best Bid and Offer in a large number of securities. In return, NASDAQ provides such member with an incremental rebate.
The Exchange believes the proposed incremental credits are equitable and not unfairly discriminatory because they are open to all ETP Holders and Market Makers affiliated with a LMM on an equal basis and provide discounts that are reasonably related to the value to the Exchange's market quality associated with higher volumes. The Exchange further believes that the proposed incremental rebate is not unfairly discriminatory because it is consistent with the market quality and
The Exchange believes that it is reasonable to increase the fee charged to LMMs for orders in primary listed securities that remove liquidity from the NYSE Arca Book as this fee is same as the fee charged by the Exchange to Tier 1, Tier 2 and Tier 3 ETP Holders and Market Makers that take liquidity in Tape B securities.
The Exchange believes that the amendments to Tier 1 is reasonable, equitable and not unfairly discriminatory because the proposed amendment would apply uniformly to all similarly situated ETP Holders and Market Makers that send orders to the Exchange. The Exchange believes providing increased credits and charging lower fees for orders in Tape A and Tape C Securities will incentivize ETP Holders to increase the orders sent to the Exchange and therefore provide liquidity that supports the quality of price discovery and promotes market transparency. The Exchange believes that by recalibrating the fees for taking liquidity and credits for providing liquidity will attract additional order flow and liquidity to the Exchange, thereby contributing to price discovery on the Exchange and benefiting investors generally. The Exchange also believes it is reasonable to remove one of the two current requirements for ETP Holders and Market Makers to qualify for Tier 1 fees and credits. The proposed change will simplify the tier by removing a multi-prong requirement. The Exchange believes that the proposed change is equitable and not unfairly discriminatory because the requirement would be eliminated entirely—no ETP Holders would remain able to qualify for the eliminated prong.
The Exchange believes that the amendments to the Cross Asset Tier is reasonable, equitable and not unfairly discriminatory because the proposed amendment would continue to directly relate to the activity of an ETP Holder and the activity of an affiliated OTP Holder or OTP Firm on NYSE Arca Options, thereby encouraging increased trading activity on both the NYSE Arca equity and option markets. In this regard, the proposal is designed to bring additional posted order flow to NYSE Arca Options, so as to provide additional opportunities for all OTP Holders and OTP Firms to trade on NYSE Arca Options. Furthermore, similar to the revised Cross Asset Tier, the NYSE Arca Options Fee Schedule includes a credit for OTP Holders and OTP Firms that is based on both equity and options volume. Additionally, ETP Holders that are not affiliated with an NYSE Arca Options OTP Holder or OTP Firm are still eligible for fees and credits by means other than the Cross Asset Tier. NASDAQ similarly charges certain fees based on both equity and options volume.
The Exchange believes the proposed Cross Asset Tier 2 is reasonable and equitably allocated because it would apply to ETP Holders and Market Makers that provide liquidity to the Exchange and is designed to incentivize these market participants to increase the orders sent directly to the Exchange and therefore provide liquidity that supports the quality of price discovery and promotes market transparency. The Exchange believes the new Cross Asset Tier 2 is equitable because it would be available to all similarly situated ETP Holders and Market Makers on an equal basis and would provide credits that are reasonably related to the value of an exchange's market quality associated with higher volumes. The Exchange further believes that the proposed Cross Asset Tier 2 is reasonable, equitable and not unfairly discriminatory because the Exchange has previously implemented cross asset tiers, including the current Cross Asset Tier.
The Exchange believes the proposed Tape B Tiers are reasonable and equitably allocated because they apply to ETP Holders and Market Makers that provide liquidity to the Exchange and are designed to incentivize these market participants to increase the orders sent directly to the Exchange and therefore provide liquidity that supports the quality of price discovery and promotes market transparency. The Exchange believes the new Tape B Tiers are equitable because they are open to all similarly situated ETP Holders and Market Makers on an equal basis and provide credits that are reasonably related to the value of an exchange's market quality associated with higher volumes. The Exchange further believes
The Exchange believes that it is reasonable to eliminate the obsolete pricing tiers from the Fee Schedule because ETP Holders have not increased their activity to qualify for these tiers as significantly as the Exchange anticipated they would. The Exchange believes that it is equitable and not unfairly discriminatory to eliminate these tiers because they would be eliminated entirely—no ETP Holders would remain able to qualify for the eliminated tiers. This aspect of the proposed change would therefore result in a more streamlined Fee Schedule, including with respect to removal of related cross references.
The Exchange believes that the proposal to amend the port fees constitutes an equitable allocation of fees because all similarly situated ETP Holders and other market participants would be charged the same amount. The Exchange believes that the proposed change to the monthly rates is reasonable because the proposed port fees are expected to permit the Exchange to offset, in part, its infrastructure costs associated with making such ports available, including costs based on gateway software and hardware enhancements and resources dedicated to gateway development, quality assurance, and support. In this regard, the Exchange believes that the proposed fees are competitive with those charged by other exchanges.
Finally, the Exchange believes that it is subject to significant competitive forces, as described below in the Exchange's statement regarding the burden on competition. For these reasons, the Exchange believes that the proposal is consistent with the Act.
In accordance with section 6(b)(8) of the Act,
Further, the proposal to amend the requirements to qualify for Tier 1 and the Cross Asset Tier will not place an undue burden on competition because both pricing tiers would remain available for all ETP Holders to satisfy, except, with respect to the Cross Asset Tier which would not be available for those ETP Holders that are not affiliated with an NYSE Arca Options OTP Holder or OTP Firm. ETP Holders that are not affiliated with an NYSE Arca Options OTP Holder or OTP Firm are eligible for fees and credits by others means than the Cross Asset Tier. The Exchange believes that the proposed change to adopt the Tape B Tiers will encourage competition by attracting additional liquidity to the Exchange, which will make the Exchange a more competitive venue for, among other things, order execution and price discovery. An ETP Holder could qualify for the proposed new Tape B Tiers by providing sufficient adding liquidity to satisfy the applicable proposed volume requirements. The Exchange also notes that the proposed Tape B Tiers would be similar to existing pricing tiers and applicable credits on the Exchange. Also, the Exchange does not believe that the proposed change will impair the ability of ETP Holders or competing order execution venues to maintain their competitive standing in the financial markets. In this regard, the Exchange notes that existing pricing tiers of other exchanges similarly provide for credits for market participants that provide certain levels of liquidity on those exchanges.
The removal of obsolete pricing tiers is not competitive in nature, but would result in a more streamlined Fee Schedule.
The Exchange believes the proposed change to the port fees sets the fees that are competitive with those charges by other exchanges,
The Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues. In such an environment, the Exchange must continually review, and consider adjusting, its fees and credits to remain competitive with other exchanges. For the reasons described above, the Exchange believes that this proposal promotes a competitive environment.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change is effective upon filing pursuant to section 19(b)(3)(A)
At any time within 60 days of the filing of such 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 under section 19(b)(2)(B)
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.
Notice is hereby given that, under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520), the Securities and Exchange Commission (the “Commission”) has submitted to the Office of Management and Budget a request for extension of the previously approved collection of information discussed below.
Section 22(e) of the Investment Company Act [15 U.S.C. 80a-22(e)] (“Act”) generally prohibits funds, including money market funds, from suspending the right of redemption, and from postponing the payment or satisfaction upon redemption of any redeemable security for more than seven days. The provision was designed to prevent funds and their investment advisers from interfering with the redemption rights of shareholders for improper purposes, such as the preservation of management fees. Although section 22(e) permits funds to postpone the date of payment or satisfaction upon redemption for up to seven days, it does not permit funds to suspend the right of redemption for any amount of time, absent certain specified circumstances or a Commission order.
Rule 22e-3 under the Act [17 CFR 270.22e-3] exempts money market funds from section 22(e) to permit them to suspend redemptions in order to facilitate an orderly liquidation of the fund. Specifically, rule 22e-3 permits a money market fund to suspend redemptions and postpone the payment of proceeds pending board-approved liquidation proceedings if: (i) The fund's board of directors, including a majority of disinterested directors, determines pursuant to § 270.2a-7(c)(8)(ii)(C) that the extent of the deviation between the fund's amortized cost price per share and its current net asset value per share calculated using available market quotations (or an appropriate substitute that reflects current market conditions) may result in material dilution or other unfair results to investors or existing shareholders; (ii) the fund's board of directors, including a majority of disinterested directors, irrevocably approves the liquidation of the fund; and (iii) the fund, prior to suspending redemptions, notifies the Commission of its decision to liquidate and suspend redemptions. Rule 22e-3 also provides an exemption from section 22(e) for registered investment companies that own shares of a money market fund pursuant to section 12(d)(1)(E) of the Act (“conduit funds”), if the underlying money market fund has suspended redemptions pursuant to the rule. A conduit fund that suspends redemptions in reliance on the exemption provided by rule 22e-3 is required to provide prompt notice of the suspension of redemptions to the Commission. Notices required by the rule must be provided by electronic mail, directed to the attention of the Director of the Division of Investment Management or the Director's designee.
Commission staff estimates that, on average, one money market fund would break the buck and liquidate every six years.
The estimate of average burden hours is made solely for the purposes of the Paperwork Reduction Act, and is not derived from a comprehensive or even a representative survey or study of the costs of Commission rules and forms.
Compliance with the collection of information requirements of the rule is necessary to obtain the benefit of relying on the rule. 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 control number.
The public may view the background documentation for this information collection at the following Web site,
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Rule 17Ad-4(b) & (c) (17 CFR 240.17Ad-4) is used to document when transfer agents are exempt, or no longer exempt, from the minimum performance standards and certain recordkeeping provisions of the Commission's transfer agent rules. Pursuant to Rule 17Ad-4(b), if the Commission or the Office of the Comptroller of the Currency (“OCC”) is the appropriate regulatory agency (“ARA”) for an exempt transfer agent, that transfer agent is required to prepare and maintain in its possession a notice certifying that it is exempt from certain performance standards and recordkeeping and record retention provisions of the Commission's transfer agent rules. This notice need not be filed with the Commission or OCC. If the Board of Governors of the Federal Reserve System (“Fed”) or the Federal Deposit Insurance Corporation (“FDIC”) is the transfer agent's ARA, that transfer agent must prepare a notice and file it with the Fed or FDIC.
Rule 17Ad-4(c) sets forth the conditions under which a registered transfer agent loses its exempt status. Once the conditions for exemption no longer exist, the transfer agent, to keep the appropriate regulatory authority (“ARA”) apprised of its current status, must prepare, and file if the ARA for the transfer agent is the Board of Governors of the Federal Reserve System (“BGFRS”) or the Federal Deposit Insurance Corporation (“FDIC”), a notice of loss of exempt status under paragraph (c). The transfer agent then cannot claim exempt status under Rule 17Ad-4(b) again until it remains subject to the minimum performance standards for non-exempt transfer agents for six consecutive months.
ARAs use the information contained in the notices required by Rules 17Ad-4(b) and 17Ad-4(c) to determine whether a registered transfer agent qualifies for the exemption, to determine when a registered transfer agent no longer qualifies for the exemption, and to determine the extent to which that transfer agent is subject to regulation.
The Commission estimates that approximately 10 registered transfer agents each year prepare or file notices in compliance with Rules 17Ad-4(b) and 17Ad-4(c). The Commission estimates that each such registered transfer agent spends approximately 1.5 hours to prepare or file such notices for an aggregate total annual burden of 15 hours (1.5 hours times 10 transfer agents). The Commission staff estimates that compliance staff work at registered transfer agents results in an internal cost of compliance, at an estimated hourly wage of $283, of $424.5 per year per transfer agent (1.5 hours × $283 per hour = $424.5 per year). Therefore, the aggregate annual internal cost of compliance for the approximate 10 transfer agents annually preparing or filing notices pursuant to Rules 17Ad-4(b) and 17Ad-4(c) is approximately $4,245 ($424.5 × 10 = $4,245).
This rule does not involve the collection of confidential information.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information under the PRA unless it displays a currently valid OMB control number.
The public may view background documentation for this information collection at the following Web site:
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes to refund Specialists
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 refund Specialists and Market Makers a certain portion of the variable Active SQF Port Fee that was effective and operative in the month of April 2015 and paid by these Exchange members. The fees proposed to be refunded (the “Refund”) represent the difference between the variable Active SQF Port Fees that were in place in Section VII B. of the Pricing Schedule during the month of April 2015 (“variable Active SQF Port Fees”), and the current one price Active SQF Fee with the operative date of May 1, 2015 (“Active SQF Port Fee”). The Refund is unique to April 2015 only, and arose when a filing to delete the monthly variable Active SQF Port Fee operative on April 1, 2015 was rejected for reasons unrelated to the changes proposed in this filing, and was re-filed with the operative date of May 1, 2015.
SQF is an interface that enables Specialists, Streaming Quote Traders (“SQTs”)
The variable Active SQF Port Fees became operative on April 1, 2015. The proposal to replace the variable Active SQF Port Fee with the current Active SQF Port Fee operative April 1, 2015 was rejected and was refiled with the operative date of May 1, 2015.
The variable Active SQF Fee was implemented in December of last year with a delayed operative date of April 1, 2015, in large measure to encourage members and member organizations to work through the now-completed technology refresh (“technology refresh” or “refresh”).
Currently, per Section VII B. of the Pricing Schedule all Specialists and Market Makers on the Exchange are subject to an Active SQF Port Fee of $1,250 per port per month. Per note 26 in Section VII B., which is applicable to this section, the Active SQF Port Fee is capped at $42,000 per month. During the April billing period, all Specialists and Market Makers on the Exchange were subject to the following variable Active SQF Port Fee:
The proposed Refund of overages paid by Specialists and Market Makers to the Exchange is, as discussed, uniquely applicable only to the April billing period. The Exchange believes that its proposal is reasonable and proper under the circumstances, and is consistent with the Act.
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
During the April billing period of April 1 to April 30, 2015 the Exchange had in place a variable Active SQF Port Fee applicable to Specialists and Market Makers that exceeded the current Active SQF Port Fee, which became operative on May 1, 2015. This created the overages that are proposed to be refunded to eligible Specialists and Market Makers. That is, Specialists and Market Makers paid more in April than was anticipated by the Exchange and members, as compared to the one price Active SQF Port Fee that has been operative since May 1, 2015, and the Exchange proposes to refund the difference. Only those Specialists and Market Makers that were assessed and in fact paid an overage are eligible for the Refund. For example, if Specialist A was assessed and paid a variable Active SQF Port Fee of $16,000 for the month of April 2015 (4 ports at $4000 per port) whereas he would have paid only a $5,000 Active SQF Port Fee if this fee had been operative in April (4 ports at $1250 per port), his Refund amount would be $11,000. Or, if Market Maker B was assessed and paid a variable Active SQF Port Fee of $42,000 for the month of April 2015 (8 ports at $15,000 per port for an uncapped total of $120,000, to which the cap is applied) whereas he would have paid only a $10,000 Active SQF Port Fee if this fee had been operative in April (8 ports at $1,250 per port), his Refund amount would be $32,000.
The Exchange believes it is reasonable to refund eligible Specialists and Market Makers that were assessed per the Pricing Schedule and actually paid an overage. The Exchange's intention was to delete the variable Active SQF Port Fee and institute the Active SQF Port Fee operative April 1; however, the proposal to do so was rejected. The Exchange then filed a proposal that was in fact instituted to be operative on May 1, 2015 since the fees regarding the Active SQF Ports are monthly. The Exchange believes that it is reasonable and equitable to assess all firms the same Active SQF Port Fee as opposed to a variable fee and refund the overage to eligible Specialists and Market Makers because, as discussed, the variable Active SQF Port Fee is more expensive for the great majority of Specialists and Market Makers; this was not the expected outcome of the technology refresh. In addition, Specialists and Market Makers have, as a group, successfully worked with the Exchange through the technology refresh and as a result most such members need, and use, fewer ports to connect to the Exchange's matching engine.
The Exchange believes that its proposal to refund Specialists and Market Makers as discussed is equitable and not unfairly discriminatory because the Exchange will refund all Specialists and Market Makers that are eligible for such Refunds. A few Specialists and Market Makers hit the cap of $42,000 for the variable Active SQF Port Fee and the cap of $42,000 for the fixed Active SQF Port Fee. As a result, they did not, in fact, pay any overage and are not eligible for a Refund.
The Exchange does not believe that the proposed rule change will impose an undue burden on competition not necessary or appropriate in furtherance of the purposes of the Act.
The Exchange believes that offering Specialists and Market Makers the opportunity to utilize certain Active SQF Ports and returning to eligible Specialists and Market Makers the overages between the variable Active SQF Port Fee and fixed Active SQF Port Fee for the April billing period does not burden competition. The Exchange continues to charge all Specialists and Market Makers the Active SQF Port Fee.
The Exchange operates in a highly competitive market, comprised of twelve options exchanges, in which market participants can easily and readily direct order flow to competing venues if they deem fee levels at a particular venue to be excessive or rebates to be inadequate. Accordingly, the fees that are assessed by the Exchange are influenced by these robust market forces and therefore must remain competitive with fees charged and rebates paid by other venues and therefore must continue to be reasonable and equitably allocated to those members that opt to direct orders to the Exchange rather than competing venues.
Finally, in establishing the pricing structure for Active SQF Ports, the Exchange has considered the competitive nature of the market and believes that it has considered all relevant factors and has not considered irrelevant factors in order to establish fair, reasonable, and not unreasonably discriminatory fees and an equitable allocation of fees among all users. The Exchange believes that its proposal to return the overages from the April billing period complement this process.
No written comments were either solicited or 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 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.
Notice is hereby given that pursuant to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Rule 17f-2(a) (Fingerprinting Requirements for Securities Professionals) requires that securities professionals be fingerprinted. This requirement serves to identify security- risk personnel, to allow an employer to make fully informed employment decisions, and to deter possible wrongdoers from seeking employment in the securities industry. Partners, directors, officers, and employees of exchanges, brokers, dealers, transfer agents, and clearing agencies are included.
The Commission staff estimates that approximately 4,500 respondents will submit an aggregate total 300,700 new fingerprint cards each year or approximately 67 fingerprint cards per year per registrant. The staff estimates that the average number of hours necessary to complete a fingerprint card is one-half hour. Thus, the total estimated annual burden is 150,350 hours for all respondents (300,700 times one-half hour). The average internal labor cost of compliance per hour is approximately $283. Therefore, the total estimated annual internal labor cost of compliance for all respondents is $42,549,050 (150,350 times $283).
This rule does not involve the collection of confidential information.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information under the PRA unless it displays a currently valid OMB control number.
The public may view background documentation for this information collection at the following Web site:
On June 23, 2015, the Chicago Stock Exchange, Inc. (“CHX” or “Exchange”) filed with the Securities and Exchange Commission (“Commission”), pursuant to section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
This order approves the proposed rule change, as modified by Amendment No. 1, on an accelerated basis.
The Exchange proposes to adopt and implement a new auction, titled the Sub-second Non-displayed Auction Process (“SNAP”), that is designed to facilitate the bulk trading
During the stages of a SNAP (the “SNAP Cycle”), the Exchange temporarily suspends automated trading on the Exchange for the security subject to the SNAP. At the conclusion of the SNAP Cycle, the Exchange transitions back to automated trading on the Exchange for the subject security.
The Exchange also proposes amendments to the following CHX Rules in order to facilitate the SNAP Cycle:
(1) Article 1, Rule 1 (Definitions);
(2) Article 2, Rule 2 (Order Types, Modifiers, and Related Terms;
(3) Article 4, Rule 1 (CHX Book Feed);
(4) Article 16, Rule 8 (CHX Market Maker Responsibilities);
(5) Article 19, Rule 3 (Order Routing Events);
(6) Article 20, Rules 1 (Trading Sessions) and 2A (Limit Up-Limit Down (“LULD”) Plan and Trading Pauses in Individual Securities Due to Extraordinary Market Volatility);
(7) Article 20, Rule 8(b) (Ranking and Display of Orders);
(8) Article 20, Rule 8(d)(4) (Rule 201 of Regulation SHO);
(9) Article 20 Rule 8(e) (Execution of Certain Orders and Order Types).
In particular, the Exchange proposes to add the following new limit order modifiers related to SNAP:
(1) Start SNAP;
(2) Cancel on SNAP;
(3) SNAP Auction Only (SNAP AOO), which is subcategorized as SNAP AOO—Day, SNAP AOO—One and Done, or SNAP AOO—Pegged.
A limit order marked Start SNAP will either: (1) Initiate a SNAP Cycle in a specified security if it meets certain requirements;
SNAP AOOs will be accepted only from the beginning of the CHX early session
The first stage of a SNAP Cycle is titled Initiating the SNAP.
(1)
(2)
(3)
(4)
Upon acceptance of a valid limit order market Start SNAP, the Matching System would begin the SNAP Cycle in the subject security by taking the following actions: (1) Immediately suspending automatic execution of orders in the subject security; (2) removing the Exchange's Protected Quotation(s) in the subject security, if any; (3) notifying the market that a SNAP Cycle in the subject security has begun; (4) disseminating messages through the CHX Book Feed indicating that precedent orders on the CHX book in the subject security are no longer automatically executable; and (5) suspending dissemination of any other order information concerning the subject security through the CHX Book Feed.
Upon initiation of the SNAP Cycle, the SNAP Order Acceptance Period begins.
During the SNAP Order Acceptance Period, the CHX Matching System will establish the SNAP CHX book
First, pursuant to proposed CHX Article 18, Rule 1(b)(2)(A), the CHX Matching System will rank or cancel “precedent orders,” which are: (1) SNAP Eligible Orders in the subject security resting on the CHX Book and SNAP AOO Queue
Second, the CHX Matching System would rank incoming SNAP Eligible Orders received during the SNAP Order Acceptance Period on the CHX SNAP Book. Incoming SNAP Eligible Orders would be immediately ranked on the SNAP CHX book pursuant to proposed Article 20, Rule 8(b)(3)(E),
During the SNAP Cycle, the following incoming messages would be queued in the proposed First In/First Out (“FIFO”) Queue for later processing: (1) Cancel and cancel/replace messages for resting or queued orders; (2) cancel messages from away markets for routed orders received after the SNAP Order Acceptance Period; (3) SNAP Eligible Orders received after the SNAP Order Acceptance Period; and (4) cross orders. The Exchange asserts that the FIFO Queue is necessary because the immediate processing of most messages would be suspended during the SNAP Cycle.
Upon the conclusion of the Order Acceptance Period, the Matching System will take a snapshot of the Protected Quotation(s) of external market(s) in the subject security and determine whether or not the CHX Routing Services are available. If the snapshot of the Protected Quotation(s) of external market(s) in the subject security shows that a two-sided NBBO exists and the CHX Routing Services are available, the SNAP Cycle will continue to stage three, the Pricing and Satisfaction Period; if the market snapshot shows that a two-sided NBBO does not exist or the CHX Routing Services are unavailable, the SNAP Cycle will abort without any executions, and the Matching System will take another snapshot of the Protected Quotation(s) of external market(s) in the subject security and immediately transition to stage five, Transition to the Open Trading State.
Using the market snapshot taken at the conclusion of the Order Acceptance Period, the Matching System will initiate the Pricing and Satisfaction Period.
After SNAP AOOs marked SNAP AOO—Pegged are priced, the Matching System will determine the SNAP Price. Under proposed Article 1, Rule 1(rr), the SNAP Price is the single price at which the greatest number of shares may be executed during a SNAP Cycle without trading-through any more aggressively priced orders on either side of the market, in compliance with all CHX Rules and relevant securities laws and regulations, including Regulation NMS and Rule 201 of Regulation SHO, and any applicable exemptive relief therefrom.
If the SNAP Price cannot be determined, the Matching System will take a snapshot of the Protected Quotation(s) of external market(s) in the subject security and the SNAP Cycle will transition to stage five, Transition to the Open Trading State.
During the Satisfaction Period, the Exchange's routing systems will route away the necessary SNAP Eligible Orders, or portions thereof, based on the execution priority rules set forth in proposed CHX Article 18, Rule 1(b)(4)(A).
Upon conclusion of the stage three Pricing and Satisfaction Period, orders remaining on the SNAP CHX book if any, will be matched at the SNAP Price in accordance with the execution priority provisions set forth in proposed CHX Article 18, Rule 1(b)(4), and after those orders are matched, the Matching System will take another snapshot of the Protected Quotation(s) of external market(s) in the subject security.
During stage five, the Transition to Open Trading State, the Matching System will use the relevant market snapshot to transition trading in the subject security to the Open Trading State.
Once these processes have finished, all messages queued on the FIFO Queue during the SNAP Cycle will be processed as incoming messages in the order in which they were received. As the final step of the SNAP Cycle, the Exchange will: (1) notify the market that the SNAP Cycle has concluded; (2) publish Protected Quotation(s) in the subject security, if any; and (3) begin the dissemination of relevant order information concerning orders resting on the CHX book.
After careful review and consideration, the Commission finds that the proposed rule change, as modified by Amendment No. 1, is consistent with the requirements of the Act and the rules and regulations thereunder that are applicable to a national securities exchange.
The Commission believes that the proposal is reasonably designed to facilitate the auction trading of securities on CHX in a fair and orderly manner, and could improve market quality for market participants seeking to execute bulk trading interests and for other market participants submitting orders in response to that interest. The Commission believes that the SNAP may promote liquidity while minimizing potential information leakage that could disadvantage market participants whose orders are participating in the SNAP Cycle. At the initiation of the SNAP Cycle, the Exchange will broadcast to the market that an aggressively priced trading interest
The Exchange has included functionalities in SNAP that the Exchange states are designed to deemphasize speed as a key for trading success. A SNAP Cycle will never be scheduled ahead of time, and the length of the SNAP Order Acceptance Period would be randomized.
For the above reasons, the Commission finds that the proposed rule change, as modified by Amendment No. 1, is consistent with the requirements of the Act.
The Commission finds good cause to approve the proposed rule change, as modified by Amendment No. 1, prior to the 30th day after the date of publication of notice of Amendment No. 1 in the
The Exchange states that it received feedback from certain Participants indicating that the original tier-based minimum size requirements were counter-intuitive and would unnecessarily complicate the programming of those Participants' respective systems to automatically initiate and participate in SNAP Cycles, and that the proposed simplification of the minimum size requirements is designed to address those concerns.
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”)
FINRA is proposing to merge its dispute resolution subsidiary, FINRA Dispute Resolution, Inc. (“FINRA Dispute Resolution”) into and with its regulatory subsidiary, FINRA Regulation, Inc. (“FINRA Regulation”). To implement the merger, FINRA would make conforming amendments to the Plan of Allocation and Delegation of Functions by NASD to Subsidiaries (“Delegation Plan”); amend the By-Laws of FINRA Regulation (“FINRA Regulation By-Laws”) to make relevant conforming amendments and to incorporate substantive provisions from the By-Laws of FINRA Dispute Resolution (“FINRA Dispute Resolution By-Laws”) that apply to the dispute resolution forum only; delete the FINRA Dispute Resolution By-Laws in their entirety; and make conforming amendments to FINRA rules.
The text of the proposed rule change is available on FINRA's Web site at
In its filing with the Commission, FINRA included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. FINRA has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
FINRA is proposing to merge FINRA Dispute Resolution into FINRA Regulation. To undertake the merger, FINRA would make conforming amendments to the Delegation Plan, amend the FINRA Regulation By-Laws to incorporate substantive and unique provisions from the FINRA Dispute Resolution By-Laws and to make other conforming amendments, delete the FINRA Dispute Resolution By-Laws in their entirety, and make conforming amendments to FINRA rules. The proposed rule change would also amend the FINRA Regulation By-Laws to increase the total number of directors who could serve on the FINRA Regulation board in order to provide additional flexibility to meet the compositional requirements under the FINRA Regulation By-Laws.
Prior to 1996, the National Association of Securities Dealers, Inc. (“NASD”) Arbitration Department operated the NASD's arbitration and mediation programs. In 1996, upon the combined recommendations of two committees (the “Ruder Task Force” and the “Rudman Committee”) formed by the NASD of individuals with significant securities industry and NASD governance experience,
In 1999, NASD decided to move ODR into a separate subsidiary, NASD Dispute Resolution, Inc., that would focus solely on administering its dispute resolution program, which it believed would further strengthen the independence and credibility of the arbitration and mediation functions. NASD believed that the new dispute resolution subsidiary would benefit from the perception that it was separate and distinct from other corporate entities.
FINRA
The proposed merger would align the legal structure with the public's perception of FINRA as well as its operational realities. From the public's perspective, FINRA, Inc., FINRA Regulation and FINRA Dispute Resolution have the appearance of a single organization. FINRA's Annual Report is a consolidated report that includes all FINRA operations, and all press releases and communications are issued by FINRA.
Operationally, the three corporate entities largely function as a single organization. The entities share many administrative and support functions including, for example, Corporate Communications and Government Relations, Corporate Real Estate and Corporate Security, Finance and Purchasing, Human Resources, Internal Audit, Legal, Meetings and Travel, Office of the Corporate Secretary, Office of the Ombudsman and Technology. These integrated functions promote efficient operations and conserve financial resources. In addition, the operational cohesiveness furthers FINRA's mission of protecting investors. FINRA Dispute Resolution staff, for example, works with the Department of Enforcement to identify misconduct by individuals or firms involved in arbitration cases that could justify further action.
There are also significant shared resources across entities in the areas of corporate governance and funding. With respect to governance, members of the FINRA Board's Regulatory Policy Committee currently serve as the directors of the boards of both FINRA Regulation and FINRA Dispute Resolution.
In addition to aligning the corporate structure with operational realities, the proposed merger would reduce the considerable administrative duplication associated with maintaining the three distinct corporate entities. From a regulatory perspective, the three corporate entities have separate reporting requirements and Federal and state taxes, and are, therefore, treated as individual entities.
Although a merger between FINRA Dispute Resolution and FINRA Regulation would change FINRA Dispute Resolution's corporate status, it would not affect the services and benefits provided by or the costs to use the dispute resolution forum, its corporate governance or oversight. Over the past 15 years, FINRA, as a single organization, has operated the largest securities dispute resolution forum in the world—through its arbitration and mediation services—to assist in the resolution of monetary and business disputes between and among investors, brokerage firms and individual brokers. FINRA's Dispute Resolution program provides investors and markets with a fair, efficient and economical alternative to costly and complex litigation programs, which are often cost-prohibitive for investors with small claims.
The FINRA Dispute Resolution program has several features that distinguish it from other private arbitration forums and further promote investor protection and market integrity. For example, the forum charges significantly lower arbitration fees for investors, gives investors the choice of an all-public arbitrator panel, uses an investor-friendly discovery guide, and offers 71 hearing locations, including at least one in every state, Puerto Rico and London, United Kingdom. Also, FINRA has the authority to suspend or cancel the membership of firms and suspend registered representatives who fail to pay arbitration awards or agreed-upon settlements.
Similarly, the merger would not have a practical impact on corporate governance involving FINRA Dispute Resolution. Members of the FINRA Board's Regulatory Policy Committee currently serve as the directors of both the FINRA Regulation and FINRA Dispute Resolution boards.
Moreover, the dispute resolution forum would continue to be subject to the same SEC oversight as other departments of FINRA, which would include the requirement to file all By-Law and rule changes with the SEC. Thus, the arbitration program and services would continue to be governed by the Codes of Arbitration Procedure,
FINRA is proposing to merge FINRA Dispute Resolution into FINRA Regulation. FINRA would make conforming amendments to the Delegation Plan, amend the FINRA Regulation By-Laws to incorporate substantive and unique provisions from the FINRA Dispute Resolution By-Laws and to make other conforming amendments, delete the FINRA Dispute Resolution By-Laws, and make conforming amendments to FINRA rules. The proposed rule change would also amend the FINRA Regulation By-Laws to increase the total number of directors who could serve on the FINRA Regulation board.
FINRA is proposing to make conforming amendments throughout the Delegation Plan to remove references to “NASD” and “Rules of the Association” and replace them with references to “FINRA” and “FINRA rules,” respectively.
Section I of the Delegation Plan provides responsibility for the rules and regulations of the Association and its operation and administration to FINRA, Inc. Under section I(B), the proposed rule change would remove subsections 5 and 6 because they refer to actions taken between FINRA Regulation and FINRA Dispute Resolution. The remaining subsections would be re-numbered. In re-numbered subsection 5, FINRA is proposing to remove the word “common,” as FINRA Regulation would no longer share overhead and technology with FINRA Dispute Resolution as a separate subsidiary. In re-numbered subsection 6, FINRA is proposing to change the reference to the Office of Internal Review to the Office of Internal Audit to reflect a name change.
In section I(D), the proposed rule change would replace the reference to “4000A” with “6200,” to reflect the transfer and re-numbering of the rule
Section II of the Delegation Plan delegates responsibilities and functions to FINRA Regulation. FINRA is proposing to transfer several provisions from section III, which pertains to FINRA Dispute Resolution, into section II.
First, under section II(A)(1), FINRA is proposing to amend subsection (a) to add “and dispute resolution programs,” so that the function of establishing and interpreting rules and regulations would also apply to dispute resolution programs.
Second, the proposed rule change would amend subsection (b) to add “arbitration, mediation or other resolution of disputes among and between FINRA members, associated persons and customers,” so that FINRA Regulation would have the authority to develop and adopt appropriate and necessary rule changes related to the dispute resolution forum.
Third, FINRA is proposing to amend section II(A)(1) to add the function that would permit FINRA Regulation to “conduct arbitrations, mediations, and other dispute resolution programs.” The provision would be labeled as subsection (n). The remaining subsections would be re-numbered.
Fourth, the proposed rule change would amend re-numbered subsection (q), which addresses the function of establishing and assessing fees and other charges on FINRA members, persons associated with members, and others using the services or facilities of FINRA or FINRA Regulation, to add “which includes the dispute resolution forum.”
Fifth, the proposed rule change would amend re-numbered subsection (r) to explicitly add “dispute resolution” to the list of areas in which FINRA Regulation may manage external relations.
Finally, FINRA is proposing to transfer in its entirety current section III(C)(1) of the Delegation Plan, which governs the NAMC, into section II(C) of the Delegation Plan. Currently, section III(C)(1) of the Delegation Plan delegates authority to the NAMC to advise the FINRA Dispute Resolution board on issues relating to dispute resolution.
Under section II(C)(2)(a)(iii), FINRA is proposing to replace the reference to “Rule 11890” with “the Rule 11000 Series.” The Rule 11000 Series refers to the Uniform Practice Code and includes the new Rule 11890 Series governing clearly erroneous transactions that FINRA moved into the Consolidated FINRA Rulebook.
FINRA is proposing to delete section III of the Delegation Plan because, as discussed above, the provisions that apply to dispute resolution only would be incorporated into amended section II of the Delegation Plan.
FINRA is proposing to amend the FINRA Regulation By-Laws to incorporate substantive and unique provisions from the FINRA Dispute Resolution By-Laws. Where differences exist in the FINRA Dispute Resolution By-Laws that would not be incorporated into the FINRA Regulation By-Laws under the proposed rule change, such differences are non-substantive in nature or would not otherwise affect the governance or operation of the dispute resolution program.
FINRA is proposing to add the term “electronic transmission” to Article I of the By-Laws of FINRA Regulation in light of the common usage of electronic transmission as a means of communication and references to such term in the By-Laws of FINRA Regulation.
FINRA is proposing to expand the term “FINRA member” in Article I(s) of the By-Laws of FINRA Regulation to incorporate a definition that applies to the dispute resolution forum. Specifically, the added language would further define a “FINRA member” as “any broker or dealer admitted to membership in FINRA, whether or not the membership has been terminated or cancelled; and any broker or dealer admitted to membership in a self-regulatory organization that, with FINRA consent, has required its members to arbitrate pursuant to the Code of Arbitration Procedure for Customer Disputes or the Code of Arbitration Procedure for Industry Disputes and/or to be treated as members of FINRA for purposes of the Codes of Arbitration Procedure, whether or not the membership has been terminated or cancelled.” The SEC
The proposed rule change would also amend the definitions of Industry Member
Second, Article I(x)(5) of the By-Laws defines an Industry Member as a NAC or committee member who provides professional services to a director, officer, or employee of a broker, dealer, or corporation that owns 50 percent or more of the voting stock of a broker or dealer, and such services relate to the director's, officer's, or employee's professional capacity and constitute 20 percent or more of the professional revenues received by the member or 20 percent or more of the gross revenues received by the member's firm or partnership. Similar to the change in Article I(x)(4) described in the paragraph above, FINRA proposes to amend the definition to clarify that, for purposes of determining membership on the NAMC, services provided in the capacity as a mediator of disputes involving a director, officer, or employee as described in this definition and not representing any party in such mediations would not be considered professional services provided to such individuals.
The proposed rule change would also amend the definition of Public Member. The FINRA Regulation By-Laws define a Public Member as a NAC or committee member who has no material business relationship with a broker or dealer or a self-regulatory organization registered under the Act (other than serving as a public director or public member on a committee of such a self-regulatory organization). The proposed rule change would amend the definition by adding language to the parenthetical to clarify that, for the purposes of determining membership on the NAMC, acting in the capacity as a mediator of disputes involving a broker or dealer and not representing any party in such mediations is not considered a material business relationship with a broker or dealer.
The proposed rule change would amend the definitions of Industry Director and Public Director in Article I(w) and Article I(gg), respectively, to clarify that a director is a member of the board of directors of FINRA Regulation. The proposed rule change would also delete Article I(r) to eliminate the reference to FINRA Dispute Resolution, Inc.
The proposed rule change would amend the FINRA Regulation By-Laws to reflect a change in the address of FINRA Regulation's registered office and its registered agent from Corporate Creations Network Inc., 3411 Silverside Road, Rodney Building #104, Wilmington, Delaware 19810, to Corporation Service Company, 2711 Centerville Road, Suite 400, Wilmington, New Castle County, Delaware 19808. The FINRA Board approved this change at its February 2015 meeting.
With respect to governance, as noted above, members of the FINRA Board's Regulatory Policy Committee currently serve as the directors of the board of FINRA Regulation.
Currently, the number of FINRA Regulation directors may not exceed 15.
FINRA would amend section 4.10 of the FINRA Regulation By-Laws to insert a reference to the Delegation Plan as another governing document with which the board must comply when adopting rules, regulations, and requirements for the conduct of the business and management of FINRA Regulation. This change would conform the language in this section to that of
Under the proposed rule change, FINRA would amend section 4.14(b) to remove a reference to FINRA Dispute Resolution.
FINRA is proposing to amend section 11.3(b) to insert the word “stock” in the sentence to clarify the type of certificate to which the section refers. This change would conform the language in this section of the FINRA Regulation By-Laws to that of section 8.3(b) of the FINRA Dispute Resolution By-Laws.
As discussed under section II(B), amendments to the FINRA Regulation By-Laws, above, FINRA would incorporate substantive and unique provisions of the FINRA Dispute Resolution By-Laws into the FINRA Regulation By-Laws. As discussed above, where differences exist in the FINRA Dispute Resolution By-Laws that would not be incorporated into the FINRA Regulation By-Laws under the proposed rule change, such differences are non-substantive in nature or would not otherwise affect the governance or operation of the dispute resolution program.
FINRA is also proposing to amend several FINRA rules to reflect the proposed merger. The proposed rule change would amend Rules 0160 (Definitions) and 0170 (Delegation, Authority and Access) to delete references to FINRA Dispute Resolution. In addition, the proposed rule change would amend Rule 0160 to add paragraphs (b)(7) and (b)(11) to define “FINRA Regulation” and “Office of Dispute Resolution,” respectively, and re-number subparagraphs accordingly. The term “Office of Dispute Resolution” would mean the office within FINRA Regulation that assumes the responsibilities and functions relating to dispute resolution programs including, but not limited to, the arbitration, mediation, or other resolution of disputes among and between members, associated persons and customers. Thus, if the proposed rule change is approved, FINRA's existing dispute resolution programs would continue to operate as a separate department within FINRA Regulation, under the name of the Office of Dispute Resolution.
The proposed rule change would also amend Rules 0170 (Delegation, Authority and Access), 6250 (Quote and Order Access Requirements), 6740 (Termination of TRACE Service), 7180 (Termination of Access), 7280A (Termination of Access), 7280B (Termination of Access), 7380 (Termination of Access), 7530 (Other Services), 9710 (Purpose), 11892 (Clearly Erroneous Transactions in Exchange-Listed Securities) and 11893 (Clearly Erroneous Transactions in OTC Equity Securities) to change references to “subsidiaries” or “subsidiary” to “FINRA Regulation.”
In addition, the proposed rule change would amend Rules 12102 (National Arbitration and Mediation Committee), 13102 (National Arbitration and Mediation Committee) and 14102 (National Arbitration and Mediation Committee) to remove references to the section of the Delegation Plan that pertains to FINRA Dispute Resolution and to change the language to reference FINRA Regulation.
Because the position of President of FINRA Dispute Resolution would no longer exist upon completion of the merger, FINRA is proposing to delete references to the President of FINRA Dispute Resolution in Rules 10312 (Disclosures Required of Arbitrators and Director's Authority to Disqualify), 12103 (Director of Dispute Resolution), 12104 (Effect of Arbitration on FINRA Regulatory Activities; Arbitrator Referral During or at Conclusion of Case), 12203 (Denial of FINRA Forum), 12407 (Removal of Arbitrator by Director), 13103 (Director of Dispute Resolution), 13104 (Effect of Arbitration on FINRA Regulatory Activities; Arbitrator Referral During or at Conclusion of Case), 13203 (Denial of FINRA Forum) and 13410 (Removal of Arbitrator by Director). Any authority formerly granted by those rules to the President of FINRA Dispute Resolution would be granted to the Director of the Office of Dispute Resolution in light of that position's responsibility for overseeing the dispute resolution programs, except that in amended Rules 12103 (Director of Dispute Resolution) and 13103 (Director of Dispute Resolution), as proposed, the authority to appoint an interim Director if the Director is unable to perform his or her duties would be granted to the President of FINRA Regulation.
Similarly, FINRA is proposing to amend Rule 10103 (Director of Arbitration) to provide that the President of FINRA Regulation would have the authority to appoint an interim Director of Arbitration if the Director becomes incapacitated, resigned, is removed, or if the Director becomes permanently or indefinitely incapable of performing the duties and responsibilities of the Director. References to the President or Executive Vice President of FINRA Dispute Resolution would be removed from the Rule.
FINRA is proposing to rename FINRA Dispute Resolution as the Office of Dispute Resolution. The Office of Dispute Resolution would become a separate department within FINRA Regulation that would continue to administer independently FINRA's existing dispute resolution programs. Accordingly, the proposed rule change would amend Rules 10314 (Initiation of Proceedings), 12100(k) (Definitions), 12103 (Director of Dispute Resolution), 12701 (Settlement), 13100(k) (Definitions), 13103 (Director of Dispute Resolution), 13701 (Settlement) and 14100(c) (Definitions) to replace any remaining references to “Dispute Resolution” with “Office of Dispute Resolution.”
Finally, FINRA is proposing to amend Rules 10102 (National Arbitration and Mediation Committee), 12100(c) (Definitions), 13100(c) (Definitions), 14100(a) and (f) (Definitions) to replace references to “Dispute Resolution” with “Regulation.”
As noted in Item 2 of this filing, if the Commission approves the proposed rule change, FINRA anticipates the effective date will be December 20, 2015. FINRA will announce the effective date of the proposed rule change in a
FINRA believes that the proposed rule change is consistent with the provisions of section 15A(b)(6) of the Act,
FINRA believes that the proposed reorganization would align FINRA's corporate organizational structure with its current organizational practice, and,
FINRA emphasizes that the proposed rule change would not affect the benefits and services provided to public investors by the dispute resolution forum or the costs of any party to use the dispute resolution forum. FINRA believes that the proposed rule change reflects its continued commitment to providing an effective forum for the resolution of disputes, claims, and controversies arising out of or in connection with the business of FINRA members, or arising out of the employment or termination of employment of associated persons with any member. In addition, FINRA believes that increasing the maximum number of FINRA Regulation board seats from 15 to 17 would provide it with additional flexibility to manage its board committee assignments and meet the compositional requirements under the FINRA Regulation By-Laws, continuing to assure fair representation of FINRA's members and maintaining the numerical dominance of public directors. Thus, FINRA believes that the reorganization and its continued commitment to dispute resolution would ensure that FINRA continues to protect investors and the public interest in an efficient manner.
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. FINRA believes that the proposed merger of its two subsidiaries would align FINRA's corporate organizational structure with its current organizational practice. The proposed rule change would allow FINRA to eliminate duplicative tax and regulatory filings, which, in turn, would reduce its administrative costs and the resources spent generating and submitting these filings. Moreover, the proposed rule change would allow FINRA to streamline its procedures and re-allocate staff and financial resources to other areas, thereby enhancing the efficient operation of the corporation.
While the proposed rule change would alter FINRA Dispute Resolution's corporate status, it would not affect the dispute resolution program in any substantive way. As discussed above, it would not affect the services and benefits provided by or the costs to use the dispute resolution forum. FINRA believes that the proposed rule change demonstrates its commitment to providing a dispute resolution forum that remains accessible to investors, because the benefits and services provided by the dispute resolution forum would continue unabated.
Written comments were neither solicited nor received.
Within 45 days of the date of publication of this notice in the
(A) by order approve or disapprove such proposed rule change, or
(B) institute proceedings to determine whether the proposed rule change should be disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change 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.
30-Day notice of submission of information collection approval from the Office of Management and Budget and request for comments.
As part of a Federal Government-wide effort to streamline the process to seek feedback from the public on service delivery, the Securities and Exchange Commission has submitted a Generic Information Collection Request (Generic ICR): “Generic Clearance for the Collection of Qualitative Feedback on Agency Service Delivery” to OMB for approval under the Paperwork Reduction Act (PRA) (44 U.S.C. 3501
Feedback collected under this generic clearance will provide useful information, but it will not yield data that can be generalized to the overall population. This type of generic clearance for qualitative information will not be used for quantitative information collections that are designed to yield reliably actionable results, such as monitoring trends over time or documenting program performance. Such data uses require more rigorous designs that address: The target population to which generalizations will be made, the sampling frame, the sample design (including stratification and clustering), the precision requirements or power calculations that justify the proposed sample size, the expected response rate, methods for assessing potential non-response bias, the protocols for data collection, and any testing procedures that were or will be undertaken prior fielding the study. Depending on the degree of influence the results are likely to have, such collections may still be eligible for submission for other generic mechanisms that are designed to yield quantitative results.
Below is the projected average estimates for the next three years:
Written comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the Commission, including whether the information shall have practical utility; (b) the accuracy of the Commission's estimates of the burden 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. 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.
The public may view the background documentation for this information collection at the following Web site,
Department of State.
Notice.
This public notice provides information on how to apply for the DV-2017 Program and is issued pursuant to 22 CFR 42.33(b)(3), implementing sections 201(a)(3), 201(e), 203(c), and 204(a)(1)(I) of the Immigration and Nationality Act, as amended, (8 U.S.C. 1151, 1153, and 1154(a)(1)(I)).
The Congressionally-mandated Diversity Immigrant Visa Program is administered annually by the Department of State. Section 203(c) of the Immigration and Nationality Act (INA) provides for a class of immigrants known as “diversity immigrants” from countries with historically low rates of immigration to the United States. For Fiscal Year 2017, 50,000 Diversity Visas (DVs) will be available. There is no cost to register for the DV program.
Applicants who are selected in the program (“selectees”) must meet simple, but strict, eligibility requirements in order to qualify for a Diversity Visa. Selectees are chosen through a randomized computer drawing. Diversity Visas are distributed among six geographic regions and no single country may receive more than seven percent of the available DVs in any one year.
For DV-2017, natives of the following countries are not eligible to apply, because more than 50,000 natives of these countries immigrated to the United States in the previous five years:
Bangladesh, Brazil, Canada, China (mainland-born), Colombia, Dominican Republic, Ecuador, El Salvador, Haiti, India, Jamaica, Mexico, Nigeria, Pakistan, Peru, Philippines, South Korea, United Kingdom (except Northern Ireland) and its dependent territories, and Vietnam.
Persons born in Hong Kong SAR, Macau SAR, and Taiwan are eligible.
Changes in eligibility this year: None.
If you were not born in an eligible country, there are two other ways you might be able to qualify.
• Was your spouse born in a country whose natives are eligible? If yes, you can claim your spouse's country of birth—provided that both you and your spouse are named on the selected entry, are issued diversity visas, and enter the United States simultaneously.
• Were you born in a country whose natives are ineligible, but in which neither of your parents was born or legally resident at the time of your birth? If yes, you may claim the country of birth of one of your parents if it is a country whose natives are eligible for the DV-2017 program. For more details on what this means, see the Frequently Asked Questions.
• At least a high school education or its equivalent, defined as successful completion of a 12-year course of formal elementary and secondary education;
OR
• two years of work experience within the past five years in an occupation requiring at least two years of training or experience to perform. The U.S. Department of Labor's O*Net Online database will be used to determine qualifying work experience.
For more information about qualifying work experience for the principal DV applicant, see the Frequently Asked Questions.
Entries for the DV-2017 DV program must be submitted electronically at
Submit your Electronic Diversity Visa Entry Form (E-DV Entry Form or DS-5501), online at
You are strongly encouraged to complete the entry form yourself, without a “visa consultant,” “visa agent,” or other facilitator who offers to help. If someone helps you, you should be present when your entry is prepared so that you can provide the correct answers to the questions and retain the confirmation page and your unique confirmation number. It is extremely important that you retain your confirmation page and unique confirmation number. Without this information, you will not be able to access the online system that will inform you of your entry status. Be wary if someone offers to keep this information for you. You also should retain access to the email account listed in your E-DV entry. See the Frequently Asked Questions for more information about Diversity Visa program scams.
After you submit a complete entry, you will see a confirmation screen containing your name and a unique confirmation number. Print this confirmation screen for your records. Starting May 3, 2016, you will be able to check the status of your entry by returning to
You must provide the following information to complete your entry:
1. Name—last/family name, first name, middle name—exactly as on your passport.
2. Gender—male or female.
3. Birth date—day, month, year.
4. City where you were born.
5. Country where you were born—Use the name of the country currently used for the place where you were born.
6. Country of eligibility for the DV program—Your country of eligibility will normally be the same as your country of birth. Your country of eligibility is not related to where you live. If you were born in a country that is not eligible, please review the Frequently Asked Questions to see if there is another way you may be eligible.
7. Entrant photograph(s)—Recent photographs (taken within 6 months) of yourself, your spouse, and all your children listed on your entry. See Submitting a Digital Photograph for compositional and technical specifications. You do not need to include a photograph for a spouse or child who is already a U.S. citizen or a Lawful Permanent Resident, but you will not be penalized if you do.
Group photographs will not be accepted; you must submit a photograph for each individual. Your entry may be disqualified or visa application refused if the photographs are not recent, have been manipulated in any way, or do not meet the specifications explained below. See Submitting a Digital Photograph for more information.
8. Mailing Address—In Care of
9. Country where you live today.
10. Phone number (optional).
11. Email address—An email address to which you have direct access. If your entry is selected and you respond to the notification of your selection through the
12. Highest level of education you have achieved, as of today: (1) Primary school only, (2) Some high school, no diploma, (3) High school diploma, (4) Vocational school, (5) Some university courses, (6) University degree, (7) Some graduate-level courses, (8) Master's degree, (9) Some doctoral-level courses, and (10) Doctorate. See the Frequently Asked Questions for more information about educational requirements.
13. Current marital status—Unmarried, married and my spouse is NOT a U.S. citizen or U.S. Lawful Permanent Resident (LPR), married and my spouse IS a U.S. citizen or U.S. LPR, divorced, widowed, or legally separated. Enter the name, date of birth, gender, city/town of birth, country of birth of your spouse, and a photograph of your spouse meeting the same technical specifications as your photo.
Failure to list your eligible spouse will result in your disqualification as the Diversity Visa principal applicant and refusal of all visa applications in your case at the time of the visa interview. You must list your spouse even if you plan to be divorced before you apply for a visa. A spouse who is already a U.S. citizen or LPR will not require or be issued a visa, though you will not be penalized if you list them on your entry form. See the Frequently Asked Questions for more information about family members.
14. Number of children—List the name, date of birth, gender, city/town of birth, and country of birth for all living unmarried children under 21 years of age, regardless of whether or not they are living with you or intend to accompany or follow to join you, should you immigrate to the United States. Submit individual photographs of each of your children using the same technical specifications as your own photograph.
Be sure to include:
• All living natural children;
• all living children legally adopted by you; and,
• all living step-children who are unmarried and under the age of 21 on the date of your electronic entry, even if you are no longer legally married to the child's parent, and even if the child does not currently reside with you and/or will not immigrate with you.
Married children and children over the age of 21 are not eligible for the DV. However, the Child Status Protection Act protects children from “aging out” in certain circumstances. If your DV entry is made before your unmarried child turns 21, and the child turns 21 before visa issuance, he/she may be treated as though he/she were under 21 for visa-processing purposes.
A child who is already a U.S. citizen or LPR is not eligible for a Diversity Visa, and you will not be penalized for either including or omitting such family members from your entry.
Failure to list all children who are eligible will result in disqualification of the principal applicant and refusal of all visa applications in the case at the time of the visa interview. See the Frequently Asked Questions for more information about family members.
See the Frequently Asked Questions for more information about completing your Electronic Entry for the DV-2017 Program.
Based on the allocation of available visas in each region and country, individuals will be randomly selected by computer from among qualified entries. All DV-2017 entrants will be required to go to the
If your entry is selected, you will be directed to a confirmation page that will provide further instructions, including information about fees connected with immigrating to the United States.
If you are selected, in order to receive a Diversity Visa to immigrate to the United States, you still must meet all eligibility requirements under U.S. law. These requirements may significantly increase the level of scrutiny required and time necessary for processing for visa applications of natives of some countries listed in this notice including, but not limited to, countries identified as state sponsors of terrorism.
All processing of entries and issuance of DVs to selectees meeting eligibility requirements and their eligible family members must be completed by midnight on September 30, 2017. Under no circumstances can DVs be issued or adjustments approved after this date, nor can family members obtain DVs to follow-to-join the principal applicant in the United States after this date. See the Frequently Asked Questions for more information about the selection process.
You can take a new digital photograph or scan a recent photographic print with a digital scanner, as long as it meets the compositional and technical specifications listed below. Test your photos through the photo validation link on the E-DV Web site, which provides additional technical advice on photo composition and examples of acceptable and unacceptable photos.
Photographs must be in 24-bit color depth. If you are using a scanner, the settings must be for True Color or 24-bit color mode. See the additional scanning requirements below.
• Head Position: The subject must directly face the camera. The subject's head should not be tilted up, down, or to the side. The head height or facial region size (measured from the top of the head, including the hair, to the bottom of the chin) must be between 50 percent and 69 percent of the image's total height. The eye height (measured from the bottom of the image to the level of the eyes) should be between 56 percent and 69 percent of the image's height.
• Light-colored Background: The subject should be in front of a neutral, light-colored background.
• Focus: The photograph must be in focus.
• No Decorative Items: The subject must not wear sunglasses or other items that detract from the face.
• No Head Coverings or Hats: Head coverings or hats worn for religious reasons are acceptable, but the head covering may not obscure any portion of the face. Tribal or other headgear not religious in nature may not be worn. Photographs of military, airline, or other personnel wearing hats will not be accepted.
“Native” ordinarily means someone born in a particular country, regardless of the individual's current country of residence or nationality. “Native” also can mean someone who is entitled to be “charged” to a country other than the one in which he/she was born under the provisions of Section 202(b) of the Immigration and Nationality Act.
Because a numerical limitation is placed on immigrants entering from a country or geographic region, each
Listing an incorrect country of eligibility or chargeability (
There are two circumstances in which you still might be eligible to apply. First, if your derivative spouse was born in an eligible country, you may claim chargeability to that country. As your eligibility is based on your spouse, you only will be issued a DV-1 immigrant visa if your spouse also is eligible for and issued a DV-2 visa. Both of you must enter the United States together using your DVs. Similarly, your minor dependent child can be “charged” to a parent's country of birth.
Second, you can be “charged” to the country of birth of either of your parents as long as neither of your parents was born in or a resident in your country of birth at the time of your birth. People are not generally considered residents in a country in which they were not born or legally naturalized, if they were only visiting, studying in the country temporarily, or stationed temporarily for business or professional reasons on behalf of a company or government of a different country other than the one in which you were born.
If you claim alternate chargeability through either of the above, you must provide an explanation on the E-DV Entry Form, in question #6.
Listing an incorrect country of eligibility or chargeability (
DVs are intended to provide an immigration opportunity for persons who are not from “high admission” countries. The law defines “high admission countries” as those from which a total of 50,000 persons in the Family-Sponsored and Employment-Based visa categories immigrated to the United States during the previous five years. Each year, U.S. Citizenship and Immigration Services (USCIS) tallies the family and employment immigrant admission and adjustment of status figures for the previous five years to identify the countries that are considered “high admission” and whose natives will therefore be ineligible for the annual Diversity Visa program. Since this calculation is made annually, the list of countries whose natives are eligible or not eligible may change from one year to the next.
United States Citizenship and Immigration Services (USCIS) determines the regional DV limits for each year according to a formula specified in Section 203(c) of the INA. The number of visas that eventually will be issued to natives of each country will depend on the regional limits established, how many entrants come from each country, and how many of the selected entrants are found eligible for the visa. No more than seven percent of the total visas available can go to natives of any one country.
U.S. immigration law and regulations require that every DV entrant must have at least a high school education or its equivalent or have two years of work experience within the past five years in an occupation requiring at least two years of training or experience. A “high school education or equivalent” is defined as successful completion of a 12-year course of elementary and secondary education in the United States OR the successful completion in another country of a formal course of elementary and secondary education comparable to a high school education in the United States. Only formal courses of study meet this requirement; correspondence programs or equivalency certificates (such as the General Equivalency Diploma G.E.D.) are not acceptable. Documentary proof of education or work experience must be presented to the consular officer at the time of the visa interview.
If you do not meet the requirements for education or work experience, your entry will be disqualified at the time of your visa interview, and no visas will be issued to you or any of your family members.
The U.S. Department of Labor's (DOL) O*Net OnLine database will be used to determine qualifying work experience. The O*Net Online database groups job experience into five “job zones.” While many occupations are listed on the DOL Web site, not all occupations qualify for the DV program. To qualify for a DV on the basis of your work experience, you must have, within the past five years, two years of experience in an occupation that is classified in a Specific Vocational Preparation (SVP) range of 7.0 or higher.
If you do not meet the requirements for education or work experience, your entry will be disqualified at the time of your visa interview, and no visas will be issued to you or any of your family members.
When you are in O*Net OnLine, follow these steps to determine if your occupation qualifies:
1. Under “Find Occupations” select “Job Family” from the pull down;
2. Browse by “Job Family”, make your selection, and click “GO”;
3. Click on the link for your specific occupation.
4. Select the tab “Job Zone” to find the designated Job Zone number and Specific Vocational Preparation (SVP) rating range.
As an example, select Aerospace Engineers. At the bottom of the Summary Report for Aerospace Engineers, under the Job Zone section, you will find the designated Job Zone 4, SVP Range, 7.0 to <8.0. Using this example, Aerospace Engineering is a qualifying occupation.
For additional information, see the Diversity Visa—List of Occupations Web page (
There is no minimum age to apply, but the requirement of a high school education or work experience for each principal applicant at the time of application will effectively disqualify most persons who are under age 18.
The DV-2017 entry period will run from 12:00 p.m. (noon), Eastern Daylight Time (EDT) (GMT-4), Thursday, October 1, 2015, until 12:00 p.m. (noon), Eastern Standard Time (EST) (GMT-5), Tuesday, November 3, 2015. Each year,
You are strongly encouraged to enter early during the registration period. Excessive demand at the end of the registration period may slow the system down. No entries will be accepted after noon EST Tuesday, November 3, 2015.
Yes, an entrant may be in the United States or in another country, and the entry may be submitted from anywhere.
Yes, the law allows only one entry by or for each person during each registration period. The Department of State uses sophisticated technology to detect multiple entries.
Yes, spouses may each submit one entry if each meets the eligibility requirements. If either spouse is selected, the other is entitled to apply as a derivative dependent.
Parents and siblings of the entrant are ineligible to receive DV visas as dependents, and should not be included in your entry.
If you list family members on your entry, they are not required to apply for a visa or to immigrate or travel with you. However, if you fail to include an eligible dependent on your original entry and later list them on your visa application forms, your case will be disqualified at the time of your visa interview and no visas will be issued to you or any of your family members. This only applies to those who were family members at the time the original application was submitted, not those acquired at a later date. Your spouse, if eligible to enter, may still submit a separate entry even though he or she is listed on your entry, as long as both entries include details about all dependents in your family (see FAQ #12 above).
You are encouraged to prepare and submit your own entry, but you may have someone submit the entry for you. Regardless of whether you submit your own entry, or an attorney, friend, relative, or someone else submits it on your behalf, only one entry may be submitted in your name. You, as the entrant, are responsible for ensuring that information in the entry is correct and complete; entries that are not correct or complete may be disqualified. Entrants should keep their own confirmation number so that they are able to independently check the status of their entry using
Yes.
You can enter online during the registration period beginning at 12:00 p.m. (noon) Eastern Daylight Time (EDT) (GMT-4) on Thursday, October 1, 2015, and ending at 12:00 p.m. (noon) Eastern Standard Time (EST) (GMT-5) on Tuesday, November 3, 2015.
No, you will not be able to save the form into another program for completion and submission later. The E-DV Entry Form is a web-form only. You must fill in the information and submit it while online.
No. The E-DV Entry Form is designed to be completed and submitted at one time. You will have 60 minutes starting from when you download the form to complete and submit your entry through the E-DV Web site. If you exceed the sixty minute limit and have not electronically submitted your complete entry, any information already entered is discarded. The system deletes any partial entries so that they are not accidentally identified as duplicates of a later, complete entry. Read the DV instructions completely before you start to complete the form online, so that you know exactly what information you will need.
Yes, as long as the photograph meets the requirements in the instructions and is electronically submitted with, and at the same time as, the E-DV online entry. You must already have the scanned photograph file when you submit the entry online; it cannot be submitted separately from the online application. The entire entry (photograph and application together) can be submitted electronically from the United States or from overseas.
Yes. If your photo(s) did not meet the specifications, your entry will not be accepted by the E-DV Web site, so you will not receive a confirmation notice. However, given the unpredictable nature of the Internet, you may not receive the rejection notice immediately. If you can correct the photo(s) and re-send the Form Part One or Two within 60 minutes, you may be able to successfully submit the entry. Otherwise, you will have to restart the entire entry process. You can try to submit an application as many times as is necessary until a complete application is received and the confirmation notice sent. Once you have
You should receive the confirmation notice immediately, including a confirmation number that you must record and keep. However, the unpredictable nature of the Internet can result in delays. You can hit the “Submit” button as many times as is necessary until a complete application is received and the confirmation notice sent. However, once you receive a confirmation notice, do not resubmit your information.
You must use your confirmation number to access the Entrant Status Check available on the E-DV Web site at
You may check the status of your DV-2017 entry through the Entrant Status Check on the E-DV Web site at
You must have your confirmation number to access Entrant Status Check. A tool is now available in Entrant Status Check on the E-DV Web site that will allow you to retrieve your confirmation number via the email address you registered with by entering certain personal information to confirm your identity.
U.S. embassies and consulates and the Kentucky Consular Center are unable to check your selection status for you or provide your confirmation number to you directly (other than through the ESC retrieval tool). The Department of State is NOT able to provide a list of those selected to continue the visa process.
The Department of State will not send you a notification letter. The U.S. government has never sent emails to notify individuals that they have been selected, and there are no plans to use email for this purpose for the DV-2017 program. If you are a selectee, you will only receive email communications regarding your visa appointment
Only internet sites that end with the “.gov” domain suffix are official U.S. government Web sites. Many other Web sites (
You may receive emails from Web sites trying to trick you into sending money or providing your personal information. You may be asked to pay for forms and information about immigration procedures, all of which are available free on the Department of State Web site or through U.S. embassy or consulate Web sites. Additionally, organizations or Web sites may try to steal your money by charging fees for DV-related services. If you send money to one of these scams, you will likely never see it again. Also, do not send personal information to these Web sites, as it may be used for identity fraud/theft.
For DV-2017, 50,000 Diversity Visa are available. Because it is likely that some of the first 50,000 persons who are selected will not qualify for visas or pursue their cases to visa issuance, more than 50,000 entries will be selected to ensure that all of the available DV visas are issued. However, this also means that there will not be a sufficient number of visas for all those who are initially selected.
You can check the E-DV Web site's Entrant Status Check to see if you have been selected for further processing and your place on the list. Interviews for the DV-2017 program will begin in October 2016 for selectees who have submitted all pre-interview paperwork and other information as requested in the notification instructions. Selectees who provide all required information will be informed of their visa interview appointment through the E-DV Web site's Entrant Status Check four to six weeks before the scheduled interviews with U.S. consular officers overseas.
Each month, visas will be issued to those applicants who are ready for issuance during that month, as long as visas are available. Once all of the 50,000 DV visas have been issued, the program will end. Visa numbers could be finished before September 2017. Selected applicants who wish to receive visas must be prepared to act promptly on their cases.
Official notifications of selection will be made through Entrant Status Check, available May 3, 2016, through at least September 30, 2017, on the E-DV Web site
All entries received from each region are individually numbered, and at the end of the entry period, a computer will randomly select entries from among all the entries received for each geographic region. Within each region, the first entry randomly selected will be the first case registered; the second entry selected will be the second case registered, etc. All entries received within each region during the entry
Yes, provided you are otherwise eligible to adjust status under the terms of Section 245 of the Immigration and Nationality Act, you may apply to USCIS for adjustment of status to permanent resident. You must ensure that USCIS can complete action on your case, including processing of any overseas applications for a spouse or for children under 21 years of age, before September 30, 2017, since on that date your eligibility for the DV-2017 program expires. No visa numbers or adjustments of status for the DV-2017 program will be approved after midnight EDT on September 30, 2017, under any circumstances.
If you are selected in the DV-2017 program, you are entitled to apply for visa issuance only during U.S. government Fiscal Year 2017, which spans from October 1, 2016, through September 30, 2017. Selectees are encouraged to apply for visas as early as possible, once their program rank numbers become eligible for further processing.
If a DV selectee dies at any point before he or she has traveled to the United States, the DV case is automatically closed. Any derivative spouse and/or children of the deceased selectee will no longer be entitled to a DV visa. Any visas that were issued to them will be revoked.
If you are a randomly selected entrant, you will receive instructions for the DV visa application process through Entrant Status Check at
If you are selected and you are already present in the United States and plan to file for adjustment of status with USCIS, the instructions page accessible through Entrant Status Check at
No. Visa fees cannot be refunded. You must meet all qualifications for the visa as detailed in these instructions. If a consular officer determines you do not meet requirements for the visa, or you are otherwise ineligible for the DV under U.S. law, the officer cannot issue a visa and you will forfeit all fees paid.
DV applicants are subject to all grounds of ineligibility for immigrant visas specified in the Immigration and Nationality Act (INA). There are no special provisions for the waiver of any ground of visa ineligibility aside from those ordinarily provided in the Immigration and Nationality Act (INA), nor is there special processing for waiver requests. Some general waiver provisions for people with close relatives who are U.S. Citizens or Lawful Permanent Resident aliens may be available to DV applicants in some cases, but the time constraints in the DV program may make it difficult for applicants to benefit from such provisions.
Please visit the
By law, a maximum of 55,000 visas are available each year to eligible persons. However, in November 1997, the U.S. Congress passed the Nicaraguan Adjustment and Central American Relief Act (NACARA), which stipulates that beginning as early as DV-1999, and for as long as necessary, up to 5,000 of the 55,000 annually-allocated DVs will be made available for use under the NACARA program. The actual reduction of the limit began with DV-2000 and will remain in effect through the DV-2017 program, so 50,000 visas remain for the DV program described in these instructions.
No. The U.S. government will not provide any of these services to you if
The list below shows the countries whose natives are eligible for DV-2017, grouped by geographic region. Dependent areas overseas are included within the region of the governing country. The countries whose natives are not eligible for the DV-2017 program were identified by USCIS, according to the formula in Section 203(c) of the INA. The countries whose natives are not eligible for the DV program (because they are the principal source countries of Family-Sponsored and Employment-Based immigration or “high-admission” countries) are noted after the respective regional lists.
In Africa, natives of Nigeria are not eligible for this year's Diversity Program.
Macau S.A.R. does qualify and is listed above.
In North America, natives of Canada and Mexico are not eligible for this year's Diversity Program.
Countries in this region whose natives are not eligible for this year's diversity program: Brazil, Colombia, Dominican Republic, Ecuador, El Salvador, Haiti, Jamaica, Mexico, and Peru.
Notice of request for public comments.
The Department of State is seeking Office of Management and Budget (OMB) approval for the information collections described below. In accordance with the Paperwork Reduction Act of 1995, we are requesting comments on these collections from all interested individuals and organizations. The purpose of this notice is to allow 30 days for public comment preceding submission of the collections to OMB.
The Department will accept comments from the public until November 12, 2015.
Direct comments to the Department of State Desk Officer in the Office of Information and Regulatory Affairs at the Office of Management and Budget (OMB). You may submit comments by the following methods:
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Direct requests for additional information to Mr. Glenn Smith, PM/DDTC, SA-1, 12th Floor, Directorate of Defense Trade Controls, Bureau of Political-Military Affairs, U.S. Department of State, Washington, DC 20522-0112, who may be reached via phone at (202) 663-2737, or via email at
• Title of Information Collection:
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 12,500.
• Estimated Number of Responses: 12,500.
• Average Hours Per Response: 1 hour.
• Total Estimated Burden: 12,500 hours.
• Frequency: Annually.
• Obligation to Respond: Required in Order to Obtain or Retain Benefits.
• Title of Information Collection:
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 1,057.
• Estimated Number of Responses: 1,057.
• Average Hours Per Response: 2 hours.
• Total Estimated Burden: 2,114 hours.
• Frequency: Annually.
• Obligation to Respond: Required in Order to Obtain or Retain Benefits.
• Title of Information Collection:
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 100.
• Estimated Number of Responses: 100.
• Average Hours Per Response: 2 hours.
• Total Estimated Burden: 200 hours.
• Frequency: On Occasion.
• Obligation to Respond: Voluntary.
• Title of Information Collection:
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 3,000.
• Estimated Number of Responses: 3,000.
• Average Hours Per Response: 1 hour.
• Total Estimated Burden: 3,000 hours.
• Frequency: On Occasion.
• Obligation to Respond: Voluntary.
• Title of Information Collection:
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 150.
• Estimated Number of Responses: 166.
• Average Hours Per Response: 1 hour.
• Total Estimated Burden: 166 hours.
• Frequency: On Occasion.
• Obligation to Respond: Voluntary.
• Title of Information Collection: Voluntary Disclosures.
• OMB Control Number:
• Type of Request:
• Originating Office:
• Form Number:
• Respondents:
• Estimated Number of Respondents: 750.
• Estimated Number of Responses: 1,300.
• Average Hours Per Response: 10 hours.
• Total Estimated Burden: 13,000 hours.
• Frequency: On Occasion.
• Obligation to Respond: Voluntary.
We are soliciting public comments to permit the Department to:
• Evaluate whether the proposed information collection is necessary for the proper functions of the Department.
• Evaluate the accuracy of our estimate of the time and cost burden for this proposed collection, including the validity of the methodology and assumptions used.
• Enhance the quality, utility, and clarity of the information to be collected.
• Minimize the reporting burden on those who are to respond, including the use of automated collection techniques or other forms of information technology.
Please note that comments submitted in response to this Notice are public record. Before including any detailed personal information, you should be aware that your comments as submitted, including your personal information, will be available for public review.
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Federal Aviation Administration (FAA), U.S. Department of Transportation (DOT).
Notice of Twentieth RTCA Special Committee 225 Meeting.
The FAA is issuing this notice to advise the public of the Twentieth RTCA Special Committee 225 meeting.
The meeting will be held November 3rd from 9 a.m.-1 p.m.
This is a WebEx Meeting. For in-person attendees, the meeting will be held at RTCA, Inc., 1150 18th Street NW., Suite 910, Washington, DC 20036, Tel: (202) 330-0662.
The RTCA Secretariat, 1150 18th Street NW., Suite 910, Washington, DC 20036, or by telephone at (202) 833-9339, fax at (202) 833-9434, or Web site at
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., App.), notice is hereby given for a meeting of RTCA Special Committee 225. The agenda will include the following:
Attendance is open to the interested public but limited to space availability. With the approval of the chairman, members of the public may present oral statements at the meeting. This Plenary
Federal Aviation Administration (FAA), U.S. Department of Transportation (DOT).
Notice of sixty-fourth Special Committee 186 meeting.
The FAA is issuing this notice to advise the public of the sixty-fourth Special Committee 186 meeting.
The meeting will be held October 27th-30th from 9:00 a.m.-1:00 p.m.
The meeting will be held at RTCA, Inc., 1150 18th Street NW., Suite 910, Washington, DC 20036, Tel: (202) 330-0663.
The RTCA Secretariat, 1150 18th Street NW., Suite 910, Washington, DC 20036, or by telephone at (202) 833-9339, fax at (202) 833-9434, or Web site at
Pursuant to section 10(a)(2) of the Federal Advisory Committee Act (Pub. L. 92-463, 5 U.S.C., App.), notice is hereby given for a meeting of Special Committee 186. The agenda will include the following:
Attendance is open to the interested public but limited to space availability. With the approval of the chairman, members of the public may present oral statements at the meeting. Persons wishing to present statements or obtain information should contact the person listed in the
Federal Transit Administration, DOT.
Rescind the Record of Decision.
The Federal Transit Administration (FTA), in cooperation with the Maryland Transit Administration (MTA), is issuing this notice to advise the public that the Record of Decision (ROD) for the proposed Red Line Project in Baltimore County and City in Maryland is being rescinded.
Ms. Kathleen Zubrzycki, Community Planner, Federal Transit Administration Region III, 1760 Market St., Suite 500, Philadelphia, PA, 19103-4124 phone 215-656-7262 email
The FTA, as the lead federal agency, in cooperation with MTA published a ROD on February 28, 2013 for the Red Line project, a 14-miles light rail transit line from the Centers of Medicare & Medicaid Services in Baltimore County to the Johns Hopkins Bayview Medical Center campus in Baltimore City. The transitway proposed a combination of surface, tunnel and aerial segments with 19 stations (14 surface and 5 underground); three new park-and-ride facilities, and other ancillary facilities. Since issuance of the ROD, MTA notified FTA that federal funds will not be pursued and that the project is cancelled as directed by the Governor of Maryland. Therefore, FTA has determined that the ROD for the Final Environmental Impact Statement dated December 4, 2012 will be rescinded since there will be no federal action, and the requirements of the National Environmental Policy Act pursuant to 42 U.S.C. 4321,
Surface Transportation Board, DOT.
Notice of extension of OMB approval of information collection.
Pursuant to the Paperwork Reduction Act, 44 U.S.C. 3501-3521 (PRA), and Office of Management and Budget (OMB) regulations at 5 CFR 1320.11, the Surface Transportation Board has obtained OMB approval of an extension of the information collection—Notifications of Trails Act Agreement and Substitute Sponsorship.
This collection, which is codified at 49 CFR 1152.29, has been assigned OMB Control No. 2140-0017. Unless renewed, OMB approval expires on July 31, 2018. The display of a currently valid OMB control number for this collection is required by law. Under the PRA and 5 CFR 1320.8, an agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection displays a currently valid OMB control number.
Office of the Secretary, DOT.
Notice.
The Department of Transportation (DOT) issued a decision and order under the Procedures for Transportation Workplace Drug and Alcohol Testing Programs excluding a service agent, Michael R. Bennett, Workplace Compliance, Inc. in North Carolina, Texas, and all other places it is incorporated, franchised, or otherwise doing business, and all other individuals who are officers, employees, directors, shareholders, partners, or other individuals associated with Workplace Compliance, Inc., from providing drug and alcohol testing services in any capacity to any DOT-regulated employer for a period of 5 years. Mr. Bennett and his company provided Medical Review Officer services to DOT-regulated employers directly and through other service agents when Mr. Bennett was not qualified to act as a Medical Review Officer. The 5-year period has ended and Mr. Bennett, et al., has been removed from the list of excluded service agents.
This notice is effective as of July 31, 2014.
Patrice M. Kelly, Acting Director, U.S. Department of Transportation, Office of Drug and Alcohol Policy and Compliance, 1200 New Jersey Avenue SE., Washington, DC 20590; (202) 366-3784 (voice), (202) 366-3897 (fax), or
The Department published notice of the Public Interest Exclusion for Michael R. Bennett,
Office of Foreign Assets Control, Treasury.
Notice.
The U.S. Department of the Treasury's Office of Foreign Assets Control (OFAC) is publishing the name of three individuals and seven entities whose property and interests in property have been blocked pursuant to the Foreign Narcotics Kingpin Designation Act (Kingpin Act) (21 U.S.C. 1901-1908, 8 U.S.C. 1182). In addition, OFAC is publishing the name of three U.S. entities that have been identified as blocked property pursuant to the Kingpin Act.
The designation by the Acting Director of OFAC of the three individuals and seven entities and the identification of three U.S. entities as blocked property listed in the notice pursuant to section 805(b) of the Kingpin Act on October 5, 2015.
Assistant Director, Sanctions Compliance & Evaluation, Office of Foreign Assets Control, U.S. Department of the Treasury, Washington, DC 20220, Tel: (202) 622-2490.
This document and additional information concerning OFAC are available on OFAC's Web site at
The Kingpin Act became law on December 3, 1999. The Kingpin Act establishes a program targeting the activities of significant foreign narcotics traffickers and their organizations on a worldwide basis. It provides a statutory framework for the imposition of sanctions against significant foreign narcotics traffickers and their organizations on a worldwide basis, with the objective of denying their businesses and agents access to the U.S. financial system and the benefits of trade and transactions involving U.S. companies and individuals.
The Kingpin Act blocks all property and interests in property, subject to U.S. jurisdiction, owned or controlled by significant foreign narcotics traffickers as identified by the President. In addition, the Secretary of the Treasury, in consultation with the Attorney General, the Director of the Central Intelligence Agency, the Director of the Federal Bureau of Investigation, the Administrator of the Drug Enforcement Administration, the Secretary of Defense, the Secretary of State, and the Secretary of Homeland Security, may designate and block the property and interests in property, subject to U.S. jurisdiction, of persons who are found to be: (1) Materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of a person designated pursuant to the Kingpin Act; (2) owned, controlled, or directed by, or acting for or on behalf of, a person designated pursuant to the Kingpin Act; or (3) playing a significant role in international narcotics trafficking.
On October 5, 2015, the Acting Director of OFAC designated the following three individuals and seven entities whose property and interests in property are blocked pursuant to section 805(b) of the Kingpin Act. In addition, the Acting Director of OFAC also identified three U.S. entities as blocked property pursuant to section 805(b) of the Kingpin Act.
1. ROSENTHAL COELLO, Yankel Antonio, Contiguo Rio Santa Ana, Lote Residencial Fina Vieja, San Pedro Sula, Cortes, Honduras; Blvd. Santa Ana, Residencial Fina Vieja No 5, San Pedro Sula, Cortes, Honduras; 1395 Brickell Ave. 3404, Miami, FL 33131, United States; DOB 31 Oct 1968; POB Honduras; Passport B139300 (Honduras); National ID No. 0501196808151 (Honduras); RTN 05011968081512 (Honduras) (individual) [SDNTK] (Linked To: SHELIMAR INVESTMENTS, LTD.; Linked To: SHELIMAR REAL ESTATE HOLDINGS II, INC.; Linked To: SHELIMAR REAL ESTATE HOLDINGS III, INC.; Linked To: DESLAND OVERSEAS, LTD.; Linked To: PREYDEN INVESTMENTS, LTD. Designated for materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of multiple previously designated SDNTKs, and/or for playing a significant role in international narcotics trafficking, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (4) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (4).
2. ROSENTHAL HIDALGO, Yani Benjamin, 5 Calle, 24 Avenida S.O. #226, San Pedro Sula, Honduras; DOB 14 Jul 1965; POB Honduras; Passport B255530 (Honduras); National ID No. 0501196506001 (Honduras); RTN 05011965060013 (Honduras) (individual) [SDNTK] (Linked To: INVERSIONES CONTINENTAL (PANAMA), S.A. DE C.V.; Linked To: INVERSIONES CONTINENTAL, S.A. DE C.V.; Linked To: EMPACADORA CONTINENTAL, S.A. DE C.V.; Linked To: BANCO CONTINENTAL, S.A.). Designated for materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of multiple previously designated SDNTKs, and/or for playing a significant role in international narcotics trafficking, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (4) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (4).
3. ROSENTHAL OLIVA, Jaime Rolando, Barrio Rio Piedras, Calle 26, Ave 45, San Pedro Sula, Honduras; DOB 05 May 1936; POB San Pedro Sula, Cortes, Honduras; Passport E337842 (Honduras); National ID No. 0501193600600 (Honduras); RTN 05011936006000 (Honduras) (individual) [SDNTK] (Linked To: INVERSIONES CONTINENTAL (PANAMA), S.A. DE C.V.; Linked To: INVERSIONES CONTINENTAL, S.A. DE C.V.; Linked To: EMPACADORA CONTINENTAL, S.A. DE C.V.; Linked To: BANCO CONTINENTAL, S.A.; Linked To: INVERCIONES CONTINENTAL, U.S.A., CORP.). Designated for materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of multiple previously designated SDNTKs, and/or for playing a significant role in international narcotics trafficking, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (4) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (4).
1. BANCO CONTINENTAL, S.A., Centro Comercial Nova Prisa 390, San Pedro Sula, Cortes, Honduras; 9-10 Avenida NO, Boulevard Morazan, San Pedro Sula, Cortes, Honduras; SWIFT/BIC CSPSHNTE; RTN 08019003077544 (Honduras); All branches in Honduras. [SDNTK]. Designated for materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of multiple previously designated SDNTKs, and/or being owned, controlled or directed by, or acting for or on behalf of, Jaime Rolando ROSENTHAL OLIVA and/or Yani Benjamin ROSENTHAL HIDALGO, who are also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
2. DESLAND OVERSEAS, LTD., 3rd Floor, Geneva Place, Waterfront Drive, Road Town, Tortola, Virgin Islands, British [SDNTK]. Designated for being owned, controlled or directed by, or acting for or on behalf of, Yankel Antonio ROSENTHAL COELLO, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
3. EMPACADORA CONTINENTAL, S.A. DE C.V. (a.k.a. ALIMENTOS CONTINENTAL, S.A. DE C.V.), Carretera Campo 2, San Pedro Sula, Cortes, Honduras; P.O. Box 605, San Pedro Sula, Cortes, Honduras; Zona Industrial Continental, La Lima, San Pedro Sula, Cortes, Honduras; Lomas del Toncontin, Carretera Hacia Villeda Morales a 150 metros de Tipicos La Costa, Tegucigalpa, Honduras; National ID No. 08011900307609 (Honduras); RTN 080119003076090 (Honduras) [SDNTK]. Designated for materially assisting in, or providing financial or technological support for or to, or providing goods or services in support of, the international narcotics trafficking activities of multiple previously designated SDNTKs, and/or being owned, controlled or directed by, or acting for or on behalf of, Jaime Rolando ROSENTHAL OLIVA and/or Yani Benjamin ROSENTHAL HIDALGO, who are also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
4. INVERSIONES CONTINENTAL (PANAMA), S.A. DE C.V. (a.k.a. HOLDING INVERSIONES CONTINENTAL (PANAMA), S.A.; a.k.a. “GRUPO CONTINENTAL”), Calle 50 con Aquilino de la Guardia, Plaza Blanco General, Piso 20, Panama, Panama; RUC # 25882543162 (Panama) [SDNTK]. Designated for being owned, controlled or directed by, or acting for or on behalf of, Jaime Rolando ROSENTHAL OLIVA and/or Yani Benjamin ROSENTHAL HIDALGO, who are also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
5. INVERSIONES CONTINENTAL, S.A. DE C.V. (a.k.a. GRUPO FINANCIERO CONTINENTAL; a.k.a. “GRUPO FINANCIERO”), Entre la 9 y 10 Avenida, 1ra Calle, Boulevard Morazan, CC Nova, San Pedro Sula, Honduras; National ID No. 0101999501331 (Honduras); RTN 01019995013319 (Honduras) [SDNTK]. Designated for being owned, controlled or directed by, or acting for or on behalf of, Jaime Rolando ROSENTHAL OLIVA and/or Yani Benjamin ROSENTHAL HIDALGO, who are also being
6. PREYDEN INVESTMENTS, LTD., 3rd Floor, Geneva Place, Waterfront Drive, Road Town, Tortola, Virgin Islands, British [SDNTK]. Designated for being owned, controlled or directed by, or acting for or on behalf of, Yankel Antonio ROSENTHAL COELLO, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
7. SHELIMAR INVESTMENTS, LTD., Vanterpool Plaza 2nd Floor, Wickhams Cay, Road Town, Tortola, Virgin Islands, British [SDNTK]. Designated for being owned, controlled or directed by, or acting for or on behalf of, Yankel Antonio ROSENTHAL COELLO, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
1. INVERCIONES CONTINENTAL, U.S.A., CORP., Plantation, Florida, United States; Apartado 390, San Pedro Sula, Cortes, Honduras; P.O. Box 390, San Pedro Sula, Cortes, Honduras; Tax ID No. 650018270 (United States) [SDNTK]. Blocked for being owned, controlled or directed by, or acting for or on behalf of, Jaime Rolando ROSENTHAL OLIVA, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
2. SHELIMAR REAL ESTATE HOLDINGS II, INC., Miami, FL, United States [SDNTK].Blocked for being owned, controlled or directed by, or acting for or on behalf of, Yankel Antonio ROSENTHAL COELLO, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
3. SHELIMAR REAL ESTATE HOLDINGS III, INC., Golden Beach, FL, United States; Tax ID No. 270800357 (United States) [SDNTK]. Blocked for being owned, controlled or directed by, or acting for or on behalf of, Yankel Antonio ROSENTHAL COELLO, who is also being designated, and therefore meets the statutory criteria for designation as a SDNT pursuant to sections 805(b)(2) and/or (3) of the Kingpin Act, 21 U.S.C. 1904(b)(2) and/or (3).
Department of the Treasury.
Notice of members of the Legal Division Performance Review Board (PRB).
Pursuant to 5 U.S.C. 4314(c)(4), this notice announces the appointment of members of the Legal Division PRB. The purpose of this Board is to review and make recommendations concerning proposed performance appraisals, ratings, bonuses, and other appropriate personnel actions for incumbents of SES positions in the Legal Division.
Office of the General Counsel, Department of the Treasury, 1500 Pennsylvania Avenue NW, Room 3000, Washington, DC 20220, Telephone: (202) 622-0283 (this is not a toll-free number).
The Board shall consist of at least three members. In the case of an appraisal of a career appointee, more than half the members shall consist of career appointees. Composition of the specific PRBs will be determined on an ad hoc basis from among the individuals listed in this notice.
The names and titles of the PRB members are as follows: Paul Ahern, Assistant General Counsel (Enforcement & Intelligence); Peter A. Bieger, Assistant General Counsel (Banking and Finance); Himamauli Das, Assistant General Counsel (International Affairs); Eric Froman, Deputy Assistant General Counsel (Financial Stability Oversight Council); Anthony Gledhill, Chief Counsel, Alcohol Tobacco, Tax, and Trade Bureau; Rochelle F. Granat, Assistant General Counsel (General Law, Ethics and Regulation); Carlton Greene, Chief Counsel, Financial Crimes Enforcement Network; Laura Hildner, Deputy General Counsel; Elizabeth Horton, Deputy Assistant General Counsel (Ethics); Mark S. Kaizen, Associate Chief Counsel (General Legal Services), Internal Revenue Service; Jeffrey Klein, Deputy Assistant General Counsel (International Affairs); Steven D. Laughton, Deputy Assistant General Counsel (Banking and Finance); Robert Neis, Benefits Tax Counsel; Douglas Poms, Deputy International Tax Counsel; Sidney Rocke, Chief Counsel, Bureau of Engraving and Printing; Danielle Rolfes, International Tax Counsel; Bradley Smith, Chief Counsel, Office of Foreign Assets Control; Brian Sonfield, Deputy Assistant General Counsel (General Law and Regulation); Dustin M. Starbuck, Associate Chief Counsel (Finance and Management), Internal Revenue Service; Thomas West, Tax Legislative Counsel and; Paul Wolfteich, Deputy Chief Counsel, Bureau of the Fiscal Service.
(1) The authority under section 506(a)(1) of the Foreign Assistance Act of 1961 (FAA) to direct the drawdown of up to $20 million in defense articles and services of the Department of Defense and military education and training to provide assistance for the Government of Ukraine, and to make the determinations required under such section to direct such a drawdown; and
(2) The authority under section 552(c)(2) of the FAA to direct the drawdown of up to $1.5 million in nonlethal commodities and services from any agency of the United States Government to provide assistance for the Government of Ukraine, and to make the determinations required under such section to direct such a drawdown.
Fish and Wildlife Service, Interior.
Proposed rule.
We, the U.S. Fish and Wildlife Service (Service), propose to list as endangered species two endemic American Samoan land snails, the American Samoa distinct population segment of the friendly ground-dove, the Pacific sheath-tailed bat, (South Pacific subspecies), and the mao, under the Endangered Species Act (Act). If we finalize this rule as proposed, it would extend the Act's protections to these species. The effect of this regulation will be to add these species to the List of Endangered and Threatened Wildlife.
We will accept comments received or postmarked on or before December 14, 2015. Comments submitted electronically using the Federal eRulemaking Portal (see
You may submit comments by one of the following methods:
(1)
(2)
We request that you send comments only by the methods described above. We will post all comments on
Mary Abrams, Field Supervisor, Pacific Islands Fish and Wildlife Office, 300 Ala Moana Boulevard, Honolulu, HI 96850, by telephone 808-792-9400 or by facsimile 808-792-9581. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Information Relay Service (FIRS) at 800-877-8339.
• Habitat loss and fragmentation or degradation due to agriculture and urban development, nonnative ungulates, and nonnative plants.
• Collection for commercial purposes (snails only).
• Predation by feral cats, rats, nonnative snails, and nonnative flatworms.
• Inadequate existing regulatory mechanisms.
• Small numbers of individuals and populations.
We intend that any final action resulting from this proposed rule will be based on the best scientific and commercial data available and be as accurate and as effective as possible. Therefore, we request comments or information from the public, other concerned governmental agencies, the American Samoa Government (ASG), the scientific community, industry, or any other interested parties concerning this proposed rule. For the Pacific sheath-tailed bat and the mao, we also request comments or information from the CITES (Convention on International Trade in Endangered Species of Wild Fauna and Flora) management and scientific authorities or authority competent to issue comparable documentation in the countries of Samoa, Fiji, Tonga, and Vanuatu. We particularly seek comments concerning:
(1) The species' biology, range, and population trends, including:
(a) Biological or ecological requirements of the species, including habitat requirements for feeding, breeding, and sheltering;
(b) Genetics and taxonomy;
(c) Historical and current range including distribution patterns;
(d) Historical and current population levels, and current and projected trends; and
(e) Past and ongoing conservation measures for these species, their habitats, or both.
(2) Factors that that may affect the continued existence of these species, which may include habitat modification or destruction, overutilization, disease, predation, the inadequacy of existing regulatory mechanisms, or other natural or manmade factors.
(3) Biological, commercial trade, or other relevant data concerning any threats (or lack thereof) to these species and existing regulations that may be addressing those threats.
(4) Empirical data or other scientific information describing the specific impacts of climate change on the habitat, life history, and/or ecology of these species, for example, the species' biological response, or likely response, to changes in habitat resulting from climate-change related changes in ambient temperature, precipitation, drought, or storm severity.
(5) Additional information concerning the historical and current status, ranges, distributions, and population sizes of these species, including the locations of any additional populations of these species.
(6) Although we are not proposing to designate critical habitat at this time, we request information about the quality and extent of areas within U.S. jurisdiction (
Please include sufficient information with your submission (such as scientific journal articles or other publications) to allow us to verify any scientific or commercial information you include.
Please note that submissions merely stating support for or opposition to the action under consideration without providing supporting information, although noted, will not be considered in making a determination, as section 4(b)(1)(A) of the Act directs that determinations as to whether any species is a threatened or endangered species must be made “solely on the basis of the best scientific and commercial data available.”
You may submit your comments and materials concerning this proposed rule by one of the methods listed in the
If you submit information via
Comments and materials we receive, as well as supporting documentation we used in preparing this proposed rule, will be available for public inspection on
Section 4(b)(5) of the Act provides for one or more public hearings on this proposal, if requested. Requests must be received within 45 days after the date of publication of this proposed rule in the
All five species proposed for listing are candidate species. Candidate species are those taxa for which the Service has sufficient information on their biological status and threats to propose them for listing under the Act, but for which the development of a listing regulation has been precluded to date by other higher priority listing activities. The species addressed in this proposed rule are the Pacific sheath-tailed bat, the mao, the American Samoa DPS of the friendly ground-dove, and two American Samoa land snails,
On May 4, 2004, the Center for Biological Diversity petitioned the Secretary of the Interior to list 225 species of plants and animals, including four of the five candidate species listed above, as endangered or threatened under the provisions of the Act. Since then, we have published our annual findings on the May 4, 2004, petition (including our findings on the candidate species listed above) in the CNORs dated May 11, 2005 (70 FR 24870), September 12, 2006 (71 FR 53756), December 6, 2007 (72 FR 69034), December 10, 2008 (73 FR 75176), November 9, 2009 (74 FR 57804), November 10, 2010 (75 FR 69222), October 26, 2011 (76 FR 66370), November 21, 2012 (77 FR 69994), November 22, 2013 (78 FR 70104), and December 4, 2014 (79 FR 72450). This proposed rule constitutes a further response to the 2004 petition.
In 2014, the Service evaluated the status and threats for the fifth candidate species, the mao. We determined that
The table below (Table 1) provides the common name, scientific name, listing priority, and range for the species that are the subjects of this proposed rule.
The Samoan Archipelago consists of a remote chain of 13 islands and 2 atolls in the Pacific Ocean south of the equator. These islands extend more than 298 miles (mi) (480 kilometers (km)) in an east-west orientation between 13 and 15 degrees south latitude, and 168 to 172 degrees west longitude (Goldin 2002, p. 4). The islands date to the early Pleistocene and were formed as hot-spot shield volcanoes, with the older islands located on the western end of the chain (Thornberry-Ehrlich 2008, pp. 16, 28). The archipelago is divided into two political entities, American Samoa, an unincorporated territory of the United States, and the independent nation of Samoa (Craig 2009, p. 5). American Samoa consists of five high islands and two atolls: Tutuila (the largest island; 54 square (sq) mi (140 sq km)); Aunuu (1 sq mi (2 sq km)) off the southeast end of Tutuila; Ofu and Olosega (3.5 sq mi (9 sq km)) separated by a narrow channel now spanned by a bridge; Tau (15 sq mi (39 sq km)); Rose Atoll (1.5 sq mi (4 sq km)), a National Wildlife Refuge) with two uninhabited islands, Rose and Sand; and Swains Island (0.6 sq mi (1.5 sq km)), which is politically part of American Samoa, but geologically and biologically part of the Tokelau archipelago (Goldin 2002, pp. 5-6). These islands and atolls range in elevation from the high peak of Mt. Lata on Tau at 3,170 ft (966 meters (m)) to 4 to 6 ft (1 to 2 m) above sea level (asl) at Rose Atoll.
American Samoa lies within the tropics, where it is hot, humid, and rainy year-round. The wet season is from October to May, with a slightly cooler and drier season from June through September. Temperatures average about 81.5 degrees Fahrenheit (F) (27 degrees Celsius (C)). Rainfall averages 125 inches (in) (318 centimeters (cm)) annually at lower elevations, but can vary greatly depending upon topography, reaching 300 in (750 cm) or greater annually in the mountain areas. Hurricanes are a common natural disturbance in the Samoan Archipelago, and occur at intervals of 1 to 13 years (Goldin 2002, p. 7).
In 2010, the population of American Samoa totaled 55,519 individuals (U.S. Census 2011, in litt.). Because of the steep topography, most areas of the northern coastline of Tutuila are uninhabited, and most people live on the narrow coastal plain on the southern shore, within several hundred yards of the shoreline. The islanders practice extensive small-scale agriculture on plots inland of villages and in lowland rainforest on slopes that sometimes exceed 45 degrees (Atkinson and Medeiros 2006, p. 4). Before the arrival of Polynesians approximately 3,000 years ago, the whole archipelago, except for recent lava flows or poorly drained areas, was likely covered by rain forest or cloud forest (Mueller-Dombois and Fosberg 1998, p. 360).
The independent nation of Samoa (Samoa) is located less than 100 mi (160 km) west of Tutuila Island, American Samoa, and consists of two large inhabited islands, Upolu (424 sq mi (1,100 sq km)) and Savaii (703 sq mi (1,820 sq km)), and 8 small offshore islets, several of which are inhabited. Samoa lies between 13 to 14 degrees south latitude and 170 to 173 degrees west longitude and has a total land area of approximately 1,133 sq mi (2,934 sq km)) (Watling 2001, p. 26). The highest point in Samoa is Mt. Silisili on Savaii at 6,093 ft (1,857 m) asl. As discussed above, the Samoan archipelago is volcanic in origin with the islands sequentially formed in a generally eastern direction by a series of “hot spot” eruptions, starting with Savaii approximately at 2 million years of age (Keating 1992, p. 131).
The Kingdom of Tonga (Tonga) is located in the western South Pacific Ocean, approximately 560 mi (900 km) southwest of the Tutuila Island, American Samoa. The archipelago is spread over 500 mi (800 km) in a north-south direction between 15 to 23.5 degrees south latitude and 173 to 177 west degrees longitude (Australian Bureau of Meteorology (BOM) and Commonwealth Scientific and Industrial Research Organization (CSIRO) Australian BOM and CSIRO 2011, Vol. 2, p. 217). Tonga consists of four groups of islands: Tongatapu and Eua in the south, Haapai in the middle, Vavau in the north, and Niaufoou and Niua Toputapu in the far north. The 172 named islands have an area of 289 sq mi (748 sq km). The islands include high volcanic islands (maximum elevation 3,389 ft (1,033 m) asl), elevated limestone islands and low-lying
The Republic of Fiji (Fiji) is located in the western South Pacific Ocean approximately 777 mi (1250 km) west of Tutuila Island, American Samoa, between 16 to 20 degrees south latitude and 177 degrees east to 178 degrees west longitude. Fiji consists of 322 islands (105 inhabited) and a total land area of 7,078 sq mi (18,333 sq km) (Watling 2001, p. 22). The two largest islands, Viti Levu (4,026 sq mi (10,429 sq km)) and Vanua Levu (2,145 sq mi (5,556 sq km)), account for 87 percent of the total land area and are mountainous and of volcanic origin with peaks up to 4,265 ft (1,300 m) asl (Australian BOM and CSIRO 2011, Vol. 2, p. 77). The other islands consist of small volcanic islands, low-lying atolls, and elevated reefs in the Northern and Southern Lau groups in the east, the centrally located Lomaiviti group, and the Yasawa group in the northwest (Watling 2001, p. 23).
The Republic of Vanuatu (Vanuatu) is an archipelago located in the western South Pacific Ocean, approximately 1,500 mi (2,400 km) west of Tutuila Island, American Samoa. Vanuatu lies between 13 to 21 south degrees latitude and 166 to 171 degrees east longitude and includes over 80 islands (about 65 of which are inhabited) with a total land area of 4,707 sq mi (12,190 sq km) (Central Intelligence Agency (CIA) 2013). Larger islands in general are characterized by rugged volcanic peaks and tropical rainforests. The largest island is Espiritu Santo (1,527 sq mi (3,955 sq km)), which also contains the highest peak, Mount Tabwemasana (6,158 ft (1,877 m) asl) (Australia BOM and CSIRO 2011, Vol. 2, p. 245).
The Territory of the Wallis and Futuna Islands (Wallis and Futuna) is an overseas territory of France located approximately 496 mi (799 km) west of Tutuila Island, American Samoa. Wallis and Futuna consists of three main islands (Wallis or Uvea, Futuna, and Alofi) and more than 20 smaller islands, which lie between 13 to 14 south degrees latitude and 176 to 178 west degrees longitude (Watling 2001, pp. 36-37). The land area totals approximately 98 sq mi (255 sq km). Uvea is a low volcanic island with gentle relief, while Futuna and Alofi (uninhabited) are rugged mountainous islands with uplifted coral tiers (Dupon and Beaudou 1986, p. 1; Watling 2001, p. 36). The islands have experienced extensive deforestation due to the continued use of wood as the main fuel source (CIA 2009).
The Pacific sheath-tailed bat is a member of the Emballonuridae, an Old World bat family that has an extensive distribution primarily in the tropics (Nowak 1994, pp. 90-91). A Samoan specimen was first described by Peale in 1848 as
Four subspecies of Pacific sheath-tailed bats are currently recognized:
All subspecies of the Pacific sheath-tailed bat appear to be cave-dependent, roosting during the day in a wide range of cave types, including overhanging cliffs, crevices, lava tubes, and limestone caves (Grant 1993, p. 51; Grant
In American Samoa, Amerson
In Samoa, the Pacific sheath-tailed bat is known from the two main islands of Upolu and Savaii, but the species has experienced a severe decline over the last several decades, and has been observed only rarely since Cyclones Ofa (1990) and Val (1991) (Lovegrove
In Tonga, the distribution of the Pacific sheath-tailed bat is not well known. It has been recorded on the island of Eua and Niaufoou (Rinke 1991, p. 134; Koopman and Steadman 1995, p. 7), and is probably absent from Ata and Late (Rinke 1991, pp. 132-133). In 2007, ten nights of acoustic surveys on Tongatapu and Eua failed to record any detections of this species (M. Pennay pers. comm. in Scanlon
In Fiji, the Pacific sheath-tailed bat is distributed throughout the archipelago, on large islands such as Vanua Levu and Taveuni, medium-sized islands in the Lau group (Lakeba, Nayau, Cicia, Vanua Balavu), and small islets such as Yaqeta in the Yasawa group and Vatu Vara and Aiwa in the Lau group (Palmeirim
The species is predicted to be extirpated or nearly so on Kadavu, Vanua Levu, and Fiji's largest island, Viti Levu, where it was known to be widespread until the 1970s (Palmeirim
In Vanuatu, the Pacific sheath-tailed bat is known from two museum specimens, one collected in 1929 and one collected before 1878, both on the main island of Espiritu Santo (Helgen and Flannery 2002, pp. 210-211). No subsequent expeditions have recorded sheath-tailed bats, suggesting that this species was either extirpated or perhaps never actually occurred in Vanuatu (Medway and Marshall 1975, pp. 32-33; Hill 1983, pp. 140-142; Flannery 1995, p. 326; Helgen and Flannery 2002, pp. 210-211; Palmeirim
In summary, the Pacific sheath-tailed bat, once widely distributed across the southwest Pacific islands of American Samoa, Samoa, Tonga, and Fiji, has undergone a significant decline in numbers and contraction of its range. Reports of possible extirpation or extremely low numbers in American Samoa and Samoa, steep population declines in Fiji, and the lack of detections in Tonga and Vanuatu, suggest that the Pacific sheath-tailed bat is vulnerable to extinction throughout its range. The remaining populations of the Pacific sheath-tailed bat continue to experience habitat loss from deforestation and development, predation by introduced mammals, and human disturbance of roosting caves, all of which are likely to be exacerbated in the future by the effects of climate change (see Summary of Factors Affecting the Species discussion below). In addition, low population numbers and the breakdown of the metapopulation equilibrium across its range render the remaining populations of Pacific sheath-tailed bat more vulnerable to chance occurrences such as hurricanes.
Deforestation can cause the destruction and modification of foraging habitat of the Pacific sheath-tailed bat as a result of the loss of cover and reduction of available insect prey. The loss of native plant diversity associated with the conversion of native forests to agriculture and other uses can result in a corresponding reduction in the diversity and number of flying insects (Hespenheide 1975, pp. 84, 96; Waugh and Hails 1983, p. 212; Tarburton 2002, p. 107). Deforestation results from logging, agriculture, and development (Government of Samoa 2001, p. 59; Wiles and Worthington 2002, p. 18) and from hurricanes. Based on the preference of the Mariana subspecies for foraging in forested habitats near their roost caves, Wiles
Deforestation has been extensive and is ongoing across the range of the Pacific sheath-tailed bat. On the island of Tutuila, American Samoa, agriculture and development cover approximately 24 percent of the island and are concentrated in the coastal plain and low-elevation areas where loss of forest is likely to have modified foraging habitat for sheath-tailed bats (American Samoa Community College (ASCC) 2010, p. 13). In Samoa, the amount of forested area declined from 74 to 46 percent of total land area between 1954 and 1990 (Food and Agricultural Organization (FAO) 2005 in litt.). Between 1978 and 1990, 20 percent of all forest losses in Samoa were attributable to logging, with 97 percent of the logging having occurred on Savaii (Government of Samoa 1998 in Whistler 2002, p. 132). Forested land area in Samoa continued to decline at a rate of roughly 2.1 percent or 7,400 ac (3,000 ha) annually from 1990 to 2000 (FAO 2005 in litt.). As a result, there is very little undisturbed, mature forest left in Samoa (Watling 2001, p. 175; FAO 2005 in litt.). Today, only 360 ac (146 ha) of native lowland rainforests (below 2,000 ft or 600 m) remain on Savaii and Upolu as a result of logging, agricultural clearing, residential clearing (including relocation due to tsunami), and natural causes such as rising sea level and hurricanes (Ministry of Natural Resources and Environment (MNRE) 2013, p. 47). On Upolu, direct or indirect human influence has caused extensive damage to native forest habitat (above 2,000 ft or 600 m) (MNRE 2013, p. 13). Although forested, almost all upland forests on Upolu are largely dominated by introduced species today. Savaii still has extensive upland forests, which are for the most part undisturbed and composed of native species (MNRE 2013, p. 40). Although the large Fijian islands still have some areas of native forest, much of it has been lost (
Climate change may have impacts to the habitat of the Pacific sheath-tailed bat. Discussion of these impacts is included in our complete discussion of climate change in the section “E. Other Natural or Manmade Factors Affecting Their Continued Existence,” below.
The National Park of American Samoa (NPSA) was established to preserve and protect the tropical forest and archaeological and cultural resources, to maintain the habitat of flying foxes, to preserve the ecological balance of the Samoan tropical forest, and, consistent with the preservation of these resources, to provide for the enjoyment of the unique resources of the Samoan tropical forest by visitors from around the world (Pub. L. 100-571, Pub. L. 100-336). Under a 50-year lease agreement between local villages, the American Samoa Government, and the Federal Government, approximately 8,000 ac (3,240 ha) of forested habitat on the islands of Tutuila, Tau, and Ofu are protected and managed, including suitable foraging habitat for the Pacific sheath-tailed bat (NPSA Lease Agreement 1993).
As of 2014, a total of approximately 58,176 ac (23,543 ha), roughly 8 percent of the total land area of Samoa (285,000 ha) was enlisted in terrestrial protected areas, with the majority located in five national parks covering a total of 50,629 ac (20,489 ha), overlapping several sites known to be previously occupied by the bat (Tarburton 2002, pp. 105-107; Tarburton 2011, pp. 43-46).
Fiji currently has 23 terrestrial protected areas covering 188 sq mi (488 sq km) or 2.7 percent of the nation's land area (Fiji Department of Environment 2014, pp. 20-21). Most notably, on Taveuni Island, the Bouma
Based on our review of the best available scientific and commercial information, habitat destruction and degradation by deforestation, as a result of logging and land-clearing for agriculture and other land-uses, is occurring throughout the range of the Pacific sheath-tailed bat. Habitat destruction and modification and range curtailment are current threats to the Pacific sheath-tailed bat that are likely to persist in the future.
The best available information does not indicate that the Pacific sheath-tailed bat is used for any commercial, recreational, scientific, or educational purpose. As a result, we do not find overutilization for commercial, recreational, scientific, or educational purposes to be a threat to the Pacific sheath-tailed bat.
Predation by nonnative mammals (mammals that occur as a result of introduction by humans) is a factor in the decline of the Pacific sheath-tailed bat throughout its range. Terrestrial predators may be able to take the bat directly from its roosts, which are often in exposed sites such as shallow caves, rock overhangs or cave entrances. Domestic and feral cats (
Of the predators introduced to Fiji, cats are the most likely to prey on bats (Palmeirim
Rats may also prey on the Pacific sheath-tailed bat. Rats are omnivores and opportunistic feeders and have a widely varied diet consisting of nuts, seeds, grains, vegetables, fruits, insects, worms, snails, eggs, frogs, fish, reptiles, birds, and mammals (Fellers 2000, p. 525; Global Invasive Species Database (GISD) 2011). Rats are known to prey on non-volant (young that have not developed the ability to fly) bats at roosting sites and can be a major threat to bat colonies (Wiles
In summary, nonnative mammalian predators such as rats and feral cats are present throughout the range of the Pacific sheath-tailed bat. Predation of related subspecies and other cave-roosting bats by rats and feral cats strongly suggests a high probability of predation of the Pacific sheath-tailed bat. Based on the above information, we conclude that predation by rats and feral cats is a current and future threat to the Pacific sheath-tailed bat throughout its range.
Disease may contribute to the decline of the Pacific sheath-tailed bat, especially because of the bat's communal roosting habit (Wiles and Worthington 2002, p. 13). Microchiropterans have been severely affected by certain diseases, such as white nose syndrome in North America; therefore, the possibility exists that an undetected disease has led or contributed to the extirpation of this species on several islands (Malotaux 2012a in litt.). However, disease has not been observed either in the Mariana or South Pacific subspecies of Pacific sheath-tailed bat (Palmeirim
We are unaware of any conservation actions planned or implemented at this time to abate the threats of predation by feral cats or rats to the Pacific sheath-tailed bat.
In summary, based on the best available scientific and commercial information, we consider predation by nonnative mammals to be an ongoing threat to the Pacific sheath-tailed bat that will continue into the future. We do not find that disease is a threat to the Pacific sheath-tailed bat, or that it is likely to become one in the future.
The Act requires that the Secretary assess available regulatory mechanisms in order to determine whether existing regulatory mechanisms may be inadequate as designed to address
In American Samoa no existing Federal laws, treaties, or regulations specify protection of the Pacific sheath-tailed bat's foraging habitat from the threats of agriculture and development, protect its known roosting caves from disturbance, or address the threat of predation by nonnative mammals such as rats and feral cats. However, some existing Territorial laws and regulations have the potential to afford the species some protection but their implementation does not achieve that result. The DMWR is given statutory authority to “manage, protect, preserve, and perpetuate marine and wildlife resources” and to promulgate rules and regulations to this end (American Samoa Code Annotated (ASCA), title 24, chapter 3). This agency conducts monitoring surveys, conservation activities, and community outreach and education about conservation concerns. However, to our knowledge, DMWR has not used this authority to undertake conservation efforts for the Pacific sheath-tailed bat such as habitat protection and control of nonnative predators (DMWR 2006, pp. 79-80).
The Territorial Endangered Species Act provides for appointment of a Commission with the authority to nominate species as either endangered or threatened (ASCA, title 24, chapter 7). Regulations adopted under the Coastal Management Act (ASCA § 24.0501
Commercial hunting and exportation of the Pacific sheath-tailed bat is prohibited under ASCA, title 24, chapter 23, “Conservation of Flying Foxes),” which also authorizes and directs the ASG DMWR to monitor flying fox populations, protect roosting areas from disturbance, and conduct other activities to manage and protect the species. This law identifies the Pacific sheath-tailed bat as a “flying fox species” (ASCA § 24.2302), but it has not led to measures implemented to protect the Pacific sheath-tailed bat or its habitat from known threats. The sale and purchase of all native bats is prohibited, and the take, attempt to take, and hunting of all native bats are prohibited unless explicitly allowed during an officially proclaimed hunting season (ASAC § 24.1106); take is defined as harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect or to attempt to engage in such conduct (ASAC § 24.1101 (f)). However, we do not consider hunting or other forms of utilization to be a threat to the Pacific sheath-tailed bat.
Under a 50-year lease agreement between local villages, the American Samoa Government, and the Federal Government, approximately 8,000 ac (3,240 ha) of forested habitat on the islands of Tutuila, Tau, and Ofu are protected and managed in the National Park of American Samoa (NPSA Lease Agreement 1993). There is the potential for development surrounding park in-holdings, but such forest clearing would be isolated and small in scale compared to the large tracts of forested areas protected.
Under ASCA, title 24, chapter 08 (Noxious Weeds), the Territorial DOA has the authority to ban, confiscate, and destroy species of plants harmful to the agricultural economy. This authority was expanded by executive regulation so that the governor can ban the use or importation of any plant (ASCA § 24.0801). A permit from the director of the DOA is likewise required before plants may be imported to American Samoa (ASAC § 24.0328). These regulations are promulgated without consultation with the DMWR (DMWR 2006, p. 80). Although these regulations provide some protection against the introduction of nonnative plant species, some imports permitted by the DOA, or that escape detection, could prove harmful to native species and their habitats in American Samoa. These regulations do not require any measures to control invasive nonnative plants that already are established and proving harmful to native species and their habitats.
Similarly, under ASCA, title 24, chapter 06 (Quarantine), the director of DOA has the authority to promulgate agriculture quarantine restrictions concerning animals. Using this authority, the DOA has restricted the importation of insects, farm animals, and “domestic pets,” including exotic animals, to entry by permit only (See ASAC § 24.0305
The Territorial Coastal Management Act establishes a land use permit (LUP) system for development projects and a Project Notification Review System (PNRS) for multi-agency review and approval of LUP applications (ASAC § 26.0206). The standards and criteria for review of LUP applications includes requirements to protect Special Management Areas (SMA), Unique Areas, and “critical habitats” where “sustaining the natural characteristics is important or essential to the productivity of plant and animal species, especially those that are threatened or endangered” on all lands and in coastal waters in the territory not under federal management authority (ASCA § 24.0501
In summary, some existing Territorial laws and regulatory mechanisms have the potential to offer some level of protection for the Pacific sheath-tailed bat and its habitat but are not currently implemented in a manner that would do so. The DMWR has not has not exercised its statutory authority to address threats to the bat such has nonnative species. The bat is not listed pursuant to the Territorial Endangered Species Act. The Coastal Management Act and its implementing regulations have the potential to address this threat more substantively, but are inadequately implemented. Therefore, we conclude that regulatory mechanisms in American Samoa do not address threats to the Pacific sheath-tailed bat.
In Samoa, the Animals Ordinance 1960 and the Protection of Wildlife Regulations 2004 regulate the protection, conservation, and utilization of terrestrial or land-dwelling species (MNRE and the Secretariat of the Pacific Regional Environment Programme (SPREP) 2012, p. 5). These laws and regulations prohibit, and establish penalties for committing, the following activities: (1) The take, keep, or kill of protected and partially protected animal species; (2) harm of flying species endemic to Samoa; and (3) the export of any bird from Samoa (MNRE and SPREP 2012, pp. 5-6). As described above, the Pacific sheath-tailed bat is neither endemic to the Samoan archipelago, nor is it listed as a “flying species endemic to Samoa” under the Protection of Wildlife Regulations 2004. Therefore, it is not protected by the current regulations.
The Planning and Urban Management Act 2004 (PUMA) and PUMA Environmental Impact Assessment (EIA) Regulation (2007) were enacted to ensure all development initiatives are properly evaluated for adverse environmental impacts (MNRE 2013, p. 93). The information required under PUMA for Sustainable Management Plans (Para. 18, Consultation) and Environmental Impact Assessments (Para. 46, Matters the Agency shall consider) does not include specific consideration for species or their habitat (PUMA 2004, as amended). Other similar approval frameworks mandated under other legislation address specific stressors and activities. These include the permit system under the Lands Surveys and Environment Act 1989 for sand mining and coastal reclamation, and ground water exploration and abstraction permits under the Water Resources Act 2008 (MNRE 2013, p. 93). The PUMA process has been gaining in acceptance and use; however, information is lacking on its effectiveness in preventing adverse impacts to species or their habitats (MNRE 2013, p. 93).
The Forestry Management Act 2011 aims to provide for the effective and sustainable management and utilization of forest resources. This law creates the requirement for a permit or license for commercial logging or harvesting of native, agro-forestry, or plantation forest resources (MNRE and SPREP 2012, p. 18). Permitted and licensed activities must follow approved Codes of Practice, forestry harvesting plans, and other requirements set by the Ministry of Natural Resources and Environment. Certain restrictions apply to actions on protected lands such as national parks and reserves. Permits or licenses may designate certain areas for the protection of the biodiversity, endangered species, implementation of international conventions, water resources, or area determined to be of significance on which no forestry activities may be undertaken (Forestry Management Act 2011, Para. 57). Although this law includes these general considerations for managing forest resources, it does not specifically provide protection to habitat for the Pacific sheath-tailed bat.
In Fiji, the Endangered and Protected Species Act (2002) regulates the international trade, domestic trade, possession, and transportation of species protected under CITES and other species identified as threatened or endangered under this act. Under the law, the Pacific sheath-tailed bat is recognized as an “indigenous species not listed under CITES.” Its recognition under the law can garner public recognition of the importance of conserving the bat and its habitat (Tuiwawa 2015, in litt.); however, because the focus of the legislation is the regulation of foreign and domestic trade, and the bat is not a species in trade, this law is not intended to provide protection for the bat or its habitat within Fiji. The best available information does not identify any laws or regulations protecting the habitat of the Pacific sheath-tailed bat in Fiji.
In Tonga, the Birds and Fish Preservation (Amendment) Act 1989, is a law to “make provision for the preservation of wild birds and fish.” The law protects birds and fish, and provides for the establishment of protected areas, but it does not specifically protect the Pacific sheath-tailed bat or its habitat (Kingdom of Tonga 1988, 1989).
In Vanuatu, the Environment Management and Conservation Act (2002) provides for conservation, sustainable development, and management of the environment of Vanuatu. Areas of the law that may apply to species protection are the Environmental Impact Assessment process, which includes an assessment of protected, rare, threatened, or endangered species or their habitats in project areas, laws on bioprospecting, and the creation of Community Conservation Areas for the management of unique genetic, cultural, geological, or biological resources (Environmental Management and Conservation Act, Part 3, Environmental Impact Assessment). The Wild Bird Protection law (Republic of Vanuatu 2006) is limited to birds and does not offer protection to the Pacific sheath-tailed bat or its habitat.
Based on the best available information, some existing regulatory mechanisms have the potential to offer protection, but their implementation does not reduce or remove threats to the Pacific sheath-tailed bat. In American Samoa the DMWR has not exercised its statutory authority to address threats to the bat such as predation by nonnative species, the bat is not listed pursuant to the Territorial Endangered Species Act, and the Coastal Management Act's land use permitting process is implemented inadequately to reduce or remove the threat of habitat destruction or
Disturbance of roosting caves has contributed to the decline of the Pacific sheath-tailed bat throughout its range. Disturbance of roost caves by humans is likely to have occurred as a result of recreation, harvesting of co-occurring bat species, and, more commonly, guano mining (Grant
In American Samoa, human disturbance at the two caves known to be historical roost sites for the bat is likely to be minimal. Guano mining occurred in the Anapeapea caves in the 1960s (Amerson
Goats are certain to enter caves for shelter from the sun and consequently can disturb roosting bats, although the extent of this disturbance is unknown (Scanlon 2015b, in litt.). Feral goats have been observed entering caves on Aguiguan Island for shelter, which disrupts colonies of the endangered swiftlet and is believed to disturb the Mariana subspecies of the Pacific sheath-tailed bat (Wiles and Worthington 2002, p. 17; Cruz
Populations of the Pacific sheath-tailed bat are concentrated in the caves where they roost, and chronic disturbance of these sites can result in the loss of populations, as described above. Because so few populations of this bat remain, loss of additional populations to roost disturbance further erodes its diminished abundance and distribution. Based on the above information, roost disturbance at caves accessible to humans and animals such as feral goats is a current threat and will likely continue to be a threat into the future.
The use of pesticides may negatively affect the Pacific sheath-tailed bat as a result of direct toxicity and a reduction in the availability of insect prey. Pesticides are known to adversely affect bat populations, either by secondary poisoning when bats consume contaminated insects or by reducing the availability of insect prey (Hutson
In American Samoa and Samoa, current levels of pesticide use are likely lower than several decades ago when their use, particularly during the years in which taro was grown on large scales for export (1975-1985), coincided with the decline of bats in both places and has been implicated as the cause (Tarburton 2002, p. 107). However, Grant
Although severe storms are a natural disturbance with which the Pacific sheath-tailed bat has coexisted for millennia, such storms exacerbate other threats to the species by adversely affecting habitat and food resources and pose a particular threat to its small and isolated remaining populations. American Samoa, Samoa, Fiji, Tonga, and Vanuatu are irregularly affected by hurricanes (Australian BOM and CSIRO 2011 Vol. 1, p. 41). Located in the Southern Hemisphere, these countries experience most hurricanes during the November to April wet season, with the maximum occurrence between January and March (Australian BOM and CSIRO 2011 Vol. 1, p. 47). In the 41-year period ending in 2010, more than 280 hurricanes passed within 250 mi (400 km) of Samoa (52 storms), Tonga (71), Fiji (70), and Vanuatu (94) (Australian BOM and CSIRO 2011, pp. 76, 186, 216, 244). In recent decades, several major (named) storms have hit American Samoa and Samoa (Tusi in 1987, Ofa in 1990, Val in 1991, Heta in 2004, and Olaf in 2005 (MNRE 2013, pp. 31-32; Federal Emergency Management Agency 2015, in litt.)); Tonga (Waka in 2001 and Ian in 2014 (Tonga Meteorological Service 2006, in litt.; World Bank 2014, in litt.)); Fiji (Tomas in 2010 (Digital Journal 2010, in litt.)); and, most recently, Vanuatu (Pam in 2015 (BBC 2015, in litt.)).
The high winds, waves, strong storm surges, high rainfall, and flooding associated with hurricanes, particularly severe hurricanes (with sustained winds of at least 150 mi per hour or 65 m per second) cause direct mortality of the Pacific sheath-tailed bat. Cyclones Ofa (1990) and Val (1991) removed the dense vegetation that had obscured the
Hurricanes also cause direct mortality of the Pacific sheath-tailed bat as a result of the bats' inability to forage during extended periods of high wind or rain, during which they may starve. Cyclone Val (December 1991) remained stationary over the Samoan archipelago for four days, and Pacific sheath-tailed bats likely were unable to feed during this time (Grant
Hurricanes may also cause modification of the roosting habitat of the Pacific sheath-tailed bat by modifying vegetation in and around cave entrances and altering climate conditions within roosting caves as a result. Microchiropterans, such as the Pacific sheath-tailed bat, can spend over half their lives in their roosts; consequently, the microclimate of these habitats can exert a strong influence over their heat-energy balance (Campbell
Loss of forest cover and associated insect prey for bats as a result of hurricanes can reduce foraging opportunities. Following Cyclones Ofa (1990) and Val (1991), about 90 percent of the forests on Upolu and Savaii were blown over or defoliated (Park
The low numbers of individuals and populations of this subspecies place the Pacific sheath-tailed bat at great risk of extinction from inbreeding and stochastic events such as storms. The threat is significant for cave-dwelling species whose populations are often highly localized with few numbers of animals that can easily be lost in a severe storm, disease outbreak, or disturbance to the roost caves (Wiles and Worthington 2002, p. 20).
Species that undergo significant habitat loss and degradation and face other threats resulting in decline in numbers and range reduction are inherently highly vulnerable to extinction resulting from localized catastrophes such as severe storms or disease outbreaks, climate change effects, and demographic stochasticity (Shaffer 1981, p. 131; Gilpin and Soulé 1986, pp. 24-34; Pimm
The Pacific sheath-tailed bat is thought to have a metapopulation structure (Palmeirim
Our analyses under the Act include consideration of ongoing and projected changes in climate. The terms “climate” and “climate change” are defined by the Intergovernmental Panel on Climate Change (IPCC). “Climate” refers to the mean and variability of different types of weather conditions over time, with 30 years being a typical period for such measurements, although shorter or longer periods also may be used (IPCC 2013, p. 1,450). The term “climate change” thus refers to a change in the mean or variability of one or more measures of climate (
In our analyses, we reference the scientific assessment and climate change predictions for the western Pacific region prepared by the Pacific Climate Change Science Program (PCCSP), a collaborative research partnership between the Australian Government and 14 Pacific Island countries, including Samoa, Tonga, Fiji, and Vanuatu (Australian BOM and CSIRO 2011 Vol. 1, p. 15). The assessment builds on the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), and presents regional predictions for the area roughly between 25° S. to 20° N. and 120° E. to 150° W. (excluding the Australian region south of 10° S. and west of 155° E.) (Australian BOM and CSIRO 2011 Vol. 1, pp. 14, 20). The findings for Samoa (13° S. and 171° E.) may be used as a proxy for American Samoa (14° S. and 170° W.).
The annual average air temperatures and sea surface temperatures are projected to increase in American Samoa, Samoa, Fiji, Tonga, and Vanuatu, as well as throughout the western Pacific region (Australian BOM and CSIRO 2011 Vol. 2, pp. 91, 198, 228, 258). The projected regional warming is around 0.5-1.0 °C by 2030, regardless of the emissions scenario. By 2055, the warming is generally 1.0-1.5 °C with regional differences depending on the emissions scenario. Projected changes associated with increases in temperature include, but are not limited to, changes in mean precipitation with unpredictable effects on local environments (including ecosystem processes such as nutrient cycling), increased occurrence of drought cycles, increases in the intensity and number of severe storms, sea-level rise, a shift in vegetation zones upslope, and shifts in in the ranges and lifecycles of individual species (Loope and Giambelluca 1998, pp. 514-515; Pounds
In the western Pacific region, increased ambient temperatures is projected to lead to increases in annual mean rainfall, the number of heavy rain days (20-50 mm), and extreme rainfall events in American Samoa, Samoa Fiji, Tonga, and Vanuatu (Australian BOM and CSIRO 2011 Vol. 1, p. 178; Australian BOM and CSIRO 2011 Vol. 2, pp. 87-88, 194-195, 224-225, 254-255). Impacts of increased precipitation on the Pacific sheath-tailed bat are unknown.
Hurricanes are projected to decrease in frequency in this part of the Pacific but increase in severity as a result of global warming (Australian BOM and CSIRO 2011 Vol. 2, pp. 88, 195, 225, 255). The high winds, waves, strong storm surges, high rainfall, and flooding associated with hurricanes, particularly severe hurricanes (with sustained winds of 150 mi (240 km) per hour), have periodically caused great damage to roosting habitat of Pacific sheath-tailed bats and to native forests that provide their foraging habitat (Craig
In the western Pacific region, sea level is projected to rise 1.18 to 6.3 in (30 to 160 mm) by 2030, 2.6 to 12.2 in (70 to 310 mm) by 2055, and 8.3 in to 2 ft (210 to 620 mm) by 2090 under the high-emissions scenario (Australian BOM and CSIRO 2011 Vol. 2, pp. 91, 198, 228, 258). The Pacific sheath-tailed bat is known to roost in areas close to the coast and forage in the adjacent forested areas at or near sea-level, as well as inland and at elevations up to 2,500 ft (762 m). The impacts of projected sea-level rise on low-elevation and coastal roosting and foraging habitat are likely to reduce and fragment the bat's habitat on individual high islands.
In summary, although we lack information about the specific effects of projected climate change on the Pacific sheath-tailed bat, we anticipate that increased ambient temperature, precipitation, hurricane intensity, and sea-level rise and inundation would create additional stresses on the bat and on its roosting and foraging habitat because it is vulnerable to these disturbances. The risk of extinction as a result of the effects of climate change increases when a species' range and habitat requirements are restricted, its habitat decreases, and its numbers and number of populations decline (IPCC 2007, pp. 8-11). In addition, the fragmented range, diminished number of populations, and low total number of individuals have caused the Pacific sheath-tailed bat to lose redundancy and resilience rangewide. Therefore, we would expect the Pacific sheath-tailed bat to be particularly vulnerable to the habitat impacts of projected environmental effects of climate change (Loope and Giambelluca 1998, pp. 504-505; Pounds
We are unaware of any conservation actions planned or implemented at this time to abate the threats of roost disturbance, low numbers, hurricanes, or breakdown of the metapopulation equilibrium that negatively impact the Pacific sheath-tailed bat.
In summary, based on the best scientific and commercial information available, we consider other natural and manmade factors to be current and ongoing threats to the Pacific sheath-tailed bat. Roost disturbance, small population size, and breakdown of the metapopulation dynamic are threats to the Pacific sheath-tailed bat and are likely to continue in the future. The bat's small and isolated remaining populations are vulnerable to natural environmental catastrophes such as hurricanes, and the threats of small population size and hurricanes are likely to continue into the future. Due to reduced levels of pesticide use and the uncertainty regarding impacts to this species, we do not consider the use of pesticides to be a threat to the Pacific sheath-tailed bat. Although we do not consider climate change to be a current threat to the Pacific sheath-tailed bat, we anticipate that climate change is likely to exacerbate other threats to the species and to become a threat in the future.
In our analysis of the five factors, we found that the Pacific sheath-tailed bat is likely to be affected by loss of forest
Section 4 of the Act (16 U.S.C. 1533), and its implementing regulations at 50 CFR part 424, set forth the procedures for adding species to the Federal Lists of Endangered and Threatened Wildlife and Plants. Under section 4(a)(1) of the Act, we may list a species based on (A) The present or threatened destruction, modification, or curtailment of its habitat or range; (B) Overutilization for commercial, recreational, scientific, or educational purposes; (C) Disease or predation; (D) The inadequacy of existing regulatory mechanisms; or (E) Other natural or manmade factors affecting its continued existence. Listing actions may be warranted based on any of the above threat factors, singly or in combination.
We have carefully assessed the best scientific and commercial information available regarding the past, present, and future threats to the Pacific sheath-tailed bat. We find that the Pacific sheath-tailed bat is presently in danger of extinction throughout its entire range based on the severity and immediacy of the ongoing and projected threats described above. Habitat loss and degradation due to deforestation, predation by nonnative mammals, human disturbance of roost caves, and stochastic events such as hurricanes, floods, or disease outbreaks, which all pose a particular threat to the small and isolated remaining populations and probable low total abundance throughout its range, render the Pacific sheath-tailed bat in its entirety highly susceptible to extinction as a consequence of these imminent threats. The vulnerability of the species and its cave habitat to the impacts of predation and human disturbance is exacerbated by hurricanes and likely to be further exacerbated in the future by the effects of climate change, such as sea level rise, extreme rain events, and increased storm severity. The breakdown of the Pacific sheath-tailed bat's metapopulation structure is expected to reduce opportunities for repopulation following local extirpations of dwindling populations due to stochastic events. In addition, the continued decline of the last relatively large population of this species in Fiji further diminishes the probability of persistence throughout the remainder of its range where it is currently considered to be extirpated or nearly extirpated. In addition, the continued decline of the last relatively large population of this species in Fiji further diminishes the probability of persistence throughout the remainder of its range where it is currently considered to be extirpated or nearly extirpated.
In summary, habitat destruction and modification from deforestation is a threat to the Pacific sheath-tailed bat that is occurring throughout its range (Factor A). The threat of predation by nonnative predators such as rats and feral cats is ongoing (Factor C). Existing regulatory mechanisms do not address the threats to the Pacific sheath-tailed bat (Factor D). Human disturbance of roost caves, low numbers of individuals and populations and their concomitant vulnerability to catastrophic events such as hurricanes, and the breakdown of the metapopulation structure all are current threats to the bat as well (Factor E). All of these factors pose threats to the Pacific sheath-tailed bat, whether we consider their effects individually or cumulatively, and all of these threats will continue in the future.
The Act defines an endangered species as any species that is “in danger of extinction throughout all or a significant portion of its range” and a threatened species as any species “that is likely to become endangered throughout all or a significant portion of its range within the foreseeable future.” We find that the Pacific sheath-tailed bat is presently in danger of extinction throughout its entire range based on the severity and immediacy of threats currently impacting the species. Therefore, On the basis of the best available scientific and commercial information, we propose listing Pacific sheath-tailed bat as endangered in accordance with sections 3(6) and 4(a)(1) of the Act.
Under the Act and our implementing regulations, a species may warrant listing if it is in danger of extinction or likely to become so throughout all or a significant portion of its range. Because we have determined that the Pacific sheath-tailed bat is endangered throughout all of its range, no portion of its range can be “significant” for purposes of the definitions of “endangered species” and “threatened species.” See the Final Policy on Interpretation of the Phrase “Significant Portion of Its Range” in the Endangered Species Act's Definitions of “Endangered Species” and “Threatened Species” (79 FR 37577, July 1, 2014).
The genus
The mao is a large (approximately 11 in (28 cm)), “very dark-looking honeyeater . . . uniformly olive-black with a brown suffusion, except for an olive stripe beneath the eye. The “slender, down-curved bill and feet are black” (Watling 2001, p. 174). Butler and Stirnemann (2013, p. 25) report that male mao have blue eyes and are larger, while females are smaller with brown eyes. Juveniles have a shorter bill than adults, and eye color changes 2 months post-fledging (Butler and Stirnemann 2013, p. 25). The mao is a very vocal species and makes a variety of loud distinctive calls with bouts of calling lasting up to a minute (Watling 2001, p. 174). Calls differ between sexes (Butler and Stirnemann 2013, p. 25).
The mao is endemic to the Samoan archipelago. The species was thought to be primarily restricted to mature, well-developed, moist, mossy forests at upper elevations (Watling 2001, p. 175; Engbring and Ramsey 1989, p. 68), but has recently been observed at elevations ranging from 932 to 5,075 ft (284 to 1,547 m) and in ecosystems including lowland rainforest, disturbed secondary forest, and montane rainforest (MNRE 2006, pp. 9-10). The birds use the mid- to upper-canopy levels of the forest and
Butler and Stirnemann (2013, p. 30) provide the following information about the mao's habitat use. The birds only occur in forested areas with a canopy layer, including modified habitat such as plantations where large trees also are present. They do not occur in logged areas with no large trees or canopy. Mao are primarily found in the high canopy layer, but also spend considerable time foraging on the trunks of trees and feeding on nectar sources near the ground (such as ginger (family Zingiberaceae)) and in low bushes (such as
Butler and Stirnemann (2013, pp. 19-32) provide the following information about mao life history and breeding behavior. Based on a study of 15 nests, the mao nests once a year, between June and October, and produces one egg per clutch (Butler and Stirnemann 2013, pp. 19-32). The nest consists of young branches of various trees and contains little lining (Butler and Stirnemann 2013, p. 25). Incubation lasts 19 days, and chicks fledge 21-22 days after hatching. Juveniles are dependent on adults for approximately 8 to 10 weeks post-fledging. The female is almost exclusively responsible for incubation and feeding the chick, and both adults defend the nest. The mao will re-nest if the first nest fails, but not if the first nesting attempt produces a chick. Pairs are highly territorial with high site fidelity.
The mao's diet consists primarily of nectar, and also includes some invertebrates and fruit (MNRE 2006, p. 11). Nectar is an especially important food source during the breeding season, and the mao will defend nectar patches (Butler and Stirnemann 2013, p. 30). The mao eats invertebrates by probing dead material and moss, and by gleaning from emerging leaves (Butler and Stirnemann 2013, p. 30). Females forage for invertebrates under dead leaves on the forest floor to feed their fledglings (Butler and Stirnemann 2013, p. 30). Fledglings solicit food from the female by begging continually from the forest floor (Butler and Stirnemann 2013, p. 28).
The mao was once found throughout Savaii and Upolu (Samoa) likely in forests ranging from the coast to mountain tops (MNRE 2006, p. 2). It is endemic to the islands of Savaii and Upolu, Samoa, and Tutuila Island, American Samoa (Engbring and Ramsey 1989, p. 68; Watling 2001, p. 174). The mao was observed during an 1839 expedition on Tutuila (Amerson
The mao is currently found only on the islands of Savaii and Upolu in Samoa (Amerson
The mao is likely extirpated from Tutuila Island in American Samoa (Freifeld 1999, p. 1,208). Surveys conducted on Tutuila Island in 1982 and 1986 and from 1992 to 1996 did not detect the mao (Amerson
The mao is listed as Endangered in the 2014 IUCN Red List (Birdlife International 2012). Endangered is IUCN's second most severe category of extinction assessment, which equates to a very high risk of extinction in the wild. IUCN criteria include the rate of decline, population size, area of geographic distribution, and degree of population and distribution fragmentation; however, IUCN rankings do not confer any actual protection or management.
Several thousand years of subsistence agriculture and more recent commercial agriculture has resulted in the alteration and great reduction in area of forests at lower elevations in the Samoan archipelago (Whistler 1994, p. 40; Mueller-Dombois and Fosberg 1998, p. 361; Whistler 2002, pp. 130-131). In American Samoa, forest clearing for agriculture has contributed to habitat loss and degradation of forests in the lowland areas on Tutuila, and has the potential to spread into higher elevations and previously undisturbed forest; however, owing to limits on the feasibility of land-clearing imposed by the island's extreme topography, large areas of mature native rainforest have persisted. Deforestation, therefore, is unlikely to have been a cause of the mao's extirpation on this island in American Samoa.
The loss of forested habitat in Samoa is a primary threat to the mao (MNRE 2006, p. 5). Between 1954 and 1990, the amount of forested area declined from 74 to 46 percent of total land area in Samoa (Food and Agricultural Organization (FAO) 2005 in litt.). Between 1978 and 1990, 20 percent of all forest losses in Samoa were attributable to logging, with 97 percent of the logging having occurred on Savaii (Government of Samoa 1998 in Whistler 2002, p. 132). Forested land area in Samoa continued to decline at a rate of
The clearing of land for commercial agriculture has been the leading cause of deforestation in Samoa—more so than plantations or logging (Whistler 2002, p. 131). The transition from subsistence agriculture to developing cash crops for export (
Habitat quality has also degraded with the loss of closed forest space (MNRE 2006, p. 5; Butler and Stirnemann 2013, p. 22). An analysis in 1999 identified 32 percent of the total forest cover as “open” forest (less than 40 percent tree cover) and less than 0.05 percent as “closed” forest, largely as a result of damage from Cyclones Ofa and Val (Butler and Stirnemann 2013, p. 22). An additional 24 percent of the forest cover is classified as secondary re-growth forest. As a result, the montane forest in Samoa is now extremely open and patchy with fewer food resources for birds, including the mao (Butler and Stirnemann 2013, p. 22). The montane forests are also increasingly vulnerable to invasion by nonnative trees and other plants (Butler and Stirnemann 2013, p. 22), which adversely affect native forests through competition for light, nutrients, and water; chemical inhibition; and prevention of reproduction. Loss of forest is likely to affect the mao by reducing breeding, nesting, and foraging habitat, increasing forest fragmentation, and increasing the abundance and diversity of invasive species (Butler and Stirnemann 2013, p. 22).
On the island of Tutuila, American Samoa, agriculture and urban development covers approximately 24 percent of the island, and up to 60 percent of the island contains slopes of less than 30 percent where additional land clearing is feasible (ASCC 2010, p. 13; DWMR 2006, p. 25). Farmers are increasingly encroaching into some of the steep forested areas as a result of suitable flat lands already being occupied with urban development and agriculture (ASCC 2010, p. 13). Consequently, agricultural plots have spread from low elevations up to middle and some high elevations on Tutuila.
In summary, deforestation by land-clearing for agriculture has been the major contributing factor in the loss and degradation of forested habitat for the mao throughout its range in Samoa and American Samoa, and logging has been an additional major factor in loss and degradation of forest habitat in Samoa. The majority of the lowland forests have either been lost or fragmented by land-clearing for agriculture. Upland areas in Samoa have suffered extensive deforestation from logging and are increasingly at risk as agriculture and development expand into these areas. Based on the above information, we conclude that the threat of habitat destruction and modification by agriculture and development is a current threat to the mao and will continue into the future.
Nonnative plant species can degrade the habitat of native species and their impacts to native forest often are facilitated or exacerbated by the impacts of other threats such as hurricanes, agriculture and development, and feral ungulates.
The native flora of the Samoan archipelago (plant species that were present before humans arrived) consisted of approximately 550 taxa, 30 percent of which were endemic (species that occur only in the American Samoa and Samoa) (Whistler 2002, p. 8). An additional 250 plant species have been intentionally or accidentally introduced and have become naturalized with 20 or more of these considered invasive or potentially invasive in American Samoa (Whistler 2002, p. 8; Space and Flynn 2000, pp. 23-24). Of these approximately 20 or more nonnative pest plant species, at least 10 have altered or have the potential to alter the habitat of the mao and the other four species proposed for listing (Atkinson and Medeiros 2006, p. 18; Craig 2009, pp. 94, 97-98; ASCC 2010, p. 15).
Nonnative plants can degrade native habitat in Pacific island environments by: (1) Modifying the availability of light through alterations of the canopy structure; (2) altering soil-water regimes; (3) modifying nutrient cycling; (4) ultimately converting native-dominated plant communities to nonnative plant communities; and (5) increasing the frequency of landslides and erosion (Smith 1985, pp. 217-218; Cuddihy and Stone, 1990, p. 74; Matson 1990, p. 245; D'Antonio and Vitousek 1992, p. 73; Vitousek
The invasive vines
The following list provides a brief description of the nonnative plants that have the greatest negative impacts to the native forest habitat for the mao in American Samoa (Space and Flynn 2000, pp. 23-24; Craig 2009, pp. 94, 96-98; ASCC 2010, p. 15):
The shrub
Feral pigs (
Feral pigs are known to cause deleterious impacts to ecosystem processes and functions throughout their worldwide distribution (Aplet
In American Samoa, feral pigs continue to negatively affect forested habitats. Feral pigs have been present in American Samoa since antiquity (American Samoa Historic Preservation Office 2015, in litt.). In the past, hunting pressure kept their numbers down, however, increasing urbanization and increasing availability of material goods has resulted in the decline in the practice of pig hunting to almost nothing (Whistler 1992, p. 21; 1994, p. 41). Feral pigs are moderately common to abundant in many forested areas, where they spread invasive plants, damage understory vegetation, and destroy riparian areas by their feeding and wallowing behavior (DMWR 2006, p. 23; ASCC 2010, p. 15). Feral pigs are a serious problem in the NPSA because of the damage they cause to native vegetation through their rooting and wallowing (Whistler 1992, p. 21; 1994, p. 41; Hoshide 1996, p. 2; Cowie and Cook 1999, p. 48; Togia pers. comm. in Loope
In Samoa, feral pigs are present throughout lowland and upland areas on Savaii, and are considered to have a negative impact on the ecological integrity of upland forests of Savaii, an important conservation area for the mao and other rare species (Atherton and Jeffries 2012, p. 17). During recent surveys, feral pig activity was common at most sites in upland forests on Savaii, and was even detected at the upper range of the mao at an elevation of 4,921 ft (1,500 m) (Atherton and Jefferies 2012, pp. 103, 146). Significant numbers of feral cattle were present in an upland site where their trampling had kept open grassy areas within forested flats, and where mao had previously been observed (Atherton and Jeffries 2012, pp. 103-105). Trampling in forested areas damages understory vegetation and is likely to reduce foraging opportunities for mao as well as provide vectors for invasion by nonnative plants. In summary, the widespread disturbance caused by feral ungulates is likely to continue to negatively impact the habitat of the mao. Based on the above information, we conclude that habitat destruction and modification by feral ungulates is a threat to the mao.
The National Park of American Samoa (NPSA) was established to preserve and protect the tropical forest and archaeological and cultural resources, to maintain the habitat of flying foxes, to preserve the ecological balance of the Samoan tropical forest, and, consistent with the preservation of these resources, to provide for the enjoyment of the unique resources of the Samoan tropical forest by visitors from around the world (Public Law 100-571, Public Law 100-336). Under a 50-year lease agreement between local villages, the American Samoa Government, and the Federal Government, approximately 8,000 ac (3,240 ha) of forested habitat on the islands of Tutuila, Tau, and Ofu are protected and managed (NPSA Lease Agreement 1993).
Several programs and partnerships to address the threat of nonnative plant species have been established and are ongoing in American Samoa. Since 2000, the NPSA has implemented an invasive plant management program that has focused on monitoring and removal of nonnative plant threats. The nonnative plant species prioritized for removal include the following:
The thrip
In 2004, the American Samoa Invasive Species Team (ASIST) was established as an inter-agency team of nine local government and Federal agencies. The mission of ASIST is to reduce the rate of invasion and impact of invasive species in American Samoa with the goals of promoting education and awareness on invasive species and preventing, controlling, and eradicating invasive species. In 2010, the U.S. Forest Service conducted an invasive plant management workshop for Territorial and Federal agencies, and local partners (Nagle 2010 in litt.). More recently, the NPSA produced a field guide of 15 invasive plants that the park and its partners target for early detection and response (NPSA 2012, in litt.).
In 1996, the NPSA initiated a feral pig control program that includes fencing and removal of pigs using snares in the Tutuila Island and Tau Island Units. Two fences have been constructed and several hundred pigs have been removed since 2007 (Togia 2015, in litt.). The program is ongoing and includes monitoring feral pig activity twice per year and additional removal actions as needed (Togia 2015, in litt.).
In 2006, the Government of Samoa developed a recovery plan for the mao. The recovery plan identifies goals of securing the mao, maintaining its existing populations on Upolu and Savaii, and reestablishing populations at former sites (MNRE 2006). The plan has eight objectives: (1) Manage key forest areas on Upolu and Savaii where significant populations of the mao remain; (2) carry out detailed surveys to identify the numbers of pairs and establish monitoring; (3) increase understanding of the breeding and
The Mt. Vaea Ecological Restoration Project surveyed and mapped the presence of native bird and plant species and invasive plant species within lowland forest habitat of the 454-ac (183-ha) Mt. Vaea Scenic Reserve on Upolu, Samoa (Bonin 2008, pp. 2-5). The project was envisioned as the first demonstration project of invasive species management and forest restoration in Samoa. Phase I of the project resulted in the development of a restoration plan recommending removal of five priority invasive plant species and planting of native tree species (Bonin 2008, pp. viii, 24). Phase 2 of the project resulted in identifying techniques for treatment of two problematic rubber species (
The Two Samoas Environmental Collaboration Initiative brings together government agencies, nongovernmental organizations and institutions from American Samoa and Samoa and provides a platform for a single concerted effort to manage threats to environmental resources such as the management of fisheries, land-based sources of pollution, climate change, invasive species, and key or endangered species (MNRE 2014, p. 67). In 2010, a Memorandum of Understanding establishing the collaborative effort between the two countries was signed by the two agencies responsible for conservation of species and their habitats, MNRE (Samoa) and DMWR (American Samoa). This initiative establishes a framework for efforts to recover the mao in American Samoa and Samoa.
In summary, based on the best available scientific and commercial information, we conclude that the destruction, modification, and curtailment of the mao's habitat and range are ongoing threats and these threats will continue into the future. The destruction and modification of habitat for the mao is caused by agriculture, logging, feral ungulates, and nonnative plant species, the impacts of all of which are exacerbated by hurricanes (see Factor E). The most serious threat identified has been the loss of forested habitat caused by forest clearing for agriculture, and logging. All of the above threats are ongoing and interact to exacerbate the negative impacts and increase the vulnerability of extinction of the mao.
In Samoa, there is anecdotal information suggesting that the mao has been shot by people who were afraid of their calls (MNRE 2006, p. 8). In addition, one individual reported that mao are eaten, or were eaten in the past, but it seems more likely these birds were shot accidentally by hunters who were targeting pigeons (MNRE 2006, p. 8). The mao has been protected under regulations enacted by the Government of Samoa in 1993 and revised in 2004 (MNRE 2006, p. 8). The best available information does not indicate overutilization for commercial, recreation, scientific, or educational purposes in American Samoa. Based on the above information, we conclude that hunting of the mao is unintentional or accidental; therefore, we do not consider the overutilization for commercial, recreational, scientific, or educational purposes to be a threat to the mao.
Nest predation by rats has negative impacts on many island birds, including the mao (Atkinson 1977, p. 129; 1985, pp. 55-70; Butler and Stirnemann 2013, p. 29; O'Donnell
Butler and Stirnemann (2013, p. 29) captured footage of one nest depredation event by a black rat, which took a mao egg. The rat gained access to the egg by jumping on the incubating female's back from the branch above, driving the female off the nest. Combined with the disappearance of two females during the breeding season, this footage suggests that adult females are potentially vulnerable to predation on the nest at night, while they are incubating (Butler and Stirnemann 2013, p. 31), a phenomenon documented or suspected in other island bird species, which lack innate behavioral defenses against nonnative mammalian predators (see for example Robertson
The location of mao nests affects their vulnerability to predation by rats; nests in close proximity to plantation habitats, where rats are most abundant, are particularly susceptible and experience low reproductive success (Butler and Stirnemann 2013, p. 31). Nests within 50 meters of a plantation are 40 percent more likely to be depredated than nests in forested areas farther from plantations (Butler and Stirnemann 2013, p. 31). Because good-quality, closed-canopy forest habitat remains in American Samoa, factors in addition to deforestation are likely responsible for the extirpation of the mao from American Samoa (MNRE 2006, p. 8), including predation by rats (Stirnemann 2015, in litt.). Habitat loss from clearing of native forest combined with an expansion of plantations in Samoa may lead to an increase in rat populations (which find ample food in plantation habitats) and a potential for an increase in the mao nest predation rate. In addition, the mao's low reproductive rate (one juvenile per year) and extended breeding season increase the likelihood of population-level effects of predation (Butler and Stirnemann 2013, p. 22).
Predation by feral cats has been directly responsible for the extinction of numerous birds on oceanic islands (Medina
Recent investigations suggest that avian malaria may be indigenous and non-pathogenic in American Samoa and, therefore, is unlikely to affect bird populations (Jarvi
A project to restore habitat for the mao and other priority species by removing the threat of predation by the Polynesian rat (
In summary, based on the best available scientific and commercial information, we conclude that disease is not a current threat to the mao, nor is it likely to become a threat in the future. Because of its low reproductive rate (1 egg per clutch) and vulnerability to predation at multiple life-history stages (eggs, chicks, fledglings, and adults), we conclude that the threat of predation by rats and feral cats is an ongoing threat to the mao that will continue into the future.
The Act requires that the Secretary assess available regulatory mechanisms in order to determine whether existing regulatory mechanisms may be inadequate as designed to address threats to the species being evaluated (Factor D). Under this factor, we examine whether existing regulatory mechanisms are inadequate to address the potential threats to the mao discussed under other factors. In determining whether the inadequacy of regulatory mechanisms constitutes a threat to the mao, we analyzed the existing Federal, Territorial, and international laws and regulations that may address the threats to this species or contain relevant protective measures. Regulatory mechanisms, if they exist, may preclude the need for listing if we determine that such mechanisms adequately address the threats to the species such that listing is not warranted.
The Government of Samoa has enacted numerous laws and regulations and has signed on to various international agreements that address a wide range of activities such as land tenure and development, biodiversity, wildlife protection, forestry management, national parks, biosecurity, and the extraction of water resources (MNRE 2013, pp. 148-149; MNRE 2014, p. 57).
The Protection of Wildlife Regulations 2004 regulates the protection, conservation, and utilization of terrestrial or land-dwelling species (MNRE and SPREP 2012, p. 5). These regulations prohibit, and establish penalties for committing, the following activities: (1) The take, keep, or kill of protected and partially protected animal species; (2) harm of flying species endemic to Samoa; and (3) the export of any bird from Samoa (MNRE and SPREP 2012, pp. 5-6). The mao is endemic to the Samoan archipelago, but it is not listed as a “flying species endemic to Samoa” under these regulations.
The Planning and Urban Management Act 2004 (PUMA) and PUMA Environmental Impact Assessment (EIA) Regulation (2007) were enacted to ensure all development initiatives are properly evaluated for adverse environmental impacts (MNRE 2013, p. 93). The information required for Sustainable Management Plans and Environmental Impact Assessments does not include specific consideration for species or their habitat (Planning and Urban Management Act 2004, as amended). Other similar approval frameworks mandated under other legislation address specific threats and activities. These include the permit system under the Lands Surveys and Environment Act 1989 for sand mining and coastal reclamation, and ground water exploration and abstraction permits under the Water Resources Act 2008 (MNRE 2013, p. 93). The PUMA process has been gaining in acceptance and use, however, information on its effectiveness in preventing adverse impacts to species or their habitats is lacking (MNRE 2013, p. 93).
The Forestry Management Act 2011 regulates the effective and sustainable management and utilization of forest resources. This law creates the requirement for a permit or license for commercial logging or harvesting of native, agro-forestry, or plantation forest resources (MNRE and SPREP 2012, p. 18). Permitted and licensed activities must follow approved Codes of Practice, forestry harvesting plans, and other requirements set by the Ministry of Natural Resources and Environment. License or permit holders must also follow laws relating to national parks and reserves, and all provisions of management plans for any national park or reserve. Under this act, lands designated as protected areas for the purposes of the protection of biodiversity and endangered species prohibit any clearing for cultivation or removal of forest items from protected areas without prior consent of the MNRE (Forestry Management Act 2011, Para. 57). Although this law includes these general considerations for managing forest resources, it does not specifically provide protection to habitat for the mao.
The Quarantine (Biosecurity) Act 2005 forms part of the system to combat the introduction of invasive species and manage existing invasions. It is the main legal instrument to manage the deliberate or accidental importation of invasive species, pests, and pathogens and also to deal with such species should they be found in Samoa (MNRE and SPREP 2012, p. 38). This legislation also provides a risk assessment procedure for imported animals, plants and living modified organisms. Although this law provides for management of invasive species, including those that degrade or destroy native forest habitat for the mao, we do not have information indicating the degree to which it has been implemented or effectiveness of such efforts.
In Samoa, there are several regulatory and nonregulatory protected area systems currently in place that protect and manage terrestrial species and their habitats; these include national parks, nature reserves, conservation areas, and village agreements. The National Parks and Reserves Act (1974) created the
Conservation International (CI) and the Secretariat of the Pacific Regional Environment Programme (SPREP) in collaboration with the Ministry of Natural Resources Environment identified eight terrestrial Key Biodiversity Areas (KBAs) intended to ensure representative coverage of all native ecosystems with high biodiversity values, five of which are targeted to benefit the conservation of the mao (CI
In 2006, the Government of Samoa developed a recovery plan for the mao. The recovery plan identifies goals of securing the mao, maintaining its existing populations on Upolu and Savaii, and reestablishing populations at former sites (MNRE 2006). This plan is nonregulatory in nature.
In summary, existing regulatory mechanisms have the potential to address the threat of habitat destruction and degradation to the mao in Samoa. However, these policies and legislation may not provide the protection necessary for the conservation of the mao in Samoa.
In American Samoa no existing Federal laws, treaties, or regulations specify protection of the mao's habitat from the threat of deforestation, or address the threat of predation by nonnative mammals such as rats and feral cats. However, some existing Territorial laws and regulations have the potential to afford the species some protection but their implementation does not achieve that result. The DMWR is given statutory authority to “manage, protect, preserve, and perpetuate marine and wildlife resources” and to promulgate rules and regulations to that end (American Samoa Code Annotated (ASCA), title 24, chapter 3). This agency conducts monitoring surveys, conservation activities, and community outreach and education about conservation concerns. However, to our knowledge, the DMWR has not used this authority to undertake conservation efforts for the mao such as habitat protection and control of nonnative predators such as rats and cats (DMWR 2006, pp. 79-80).
The Territorial Endangered Species Act provides for appointment of a Commission with the authority to nominate species as either endangered or threatened (ASCA, title 24, chapter 7). Regulations adopted under the Coastal Management Act (ASCA § 24.0501
Under ASCA, title 24, chapter 08 (Noxious Weeds), the Territorial DOA has the authority to ban, confiscate, and destroy species of plants harmful to the agricultural economy. Similarly, under ASCA, title 24, chapter 06 (Quarantine), the director of DOA has the authority to promulgate agriculture quarantine restrictions concerning animals. These laws may provide some protection against the introduction of new nonnative species that may have negative effects on the mao's habitat or become predators of the mao, but these regulations do not require any measures to control invasive nonnative plants or animals that already are established and proving harmful to native species and their habitats (DMWR 2006, p. 80) (see Factor D for the Pacific sheath-tailed bat, above).
As described above, the Territorial Coastal Management Act establishes a land use permit (LUP) system for development projects and a Project Notification Review System (PNRS) for multi-agency review and approval of LUP applications (ASAC § 26.0206). The standards and criteria for review of LUP applications include requirements to protect Special Management Areas (SMA), Unique Areas, and “critical habitats” (ASCA § 24.0501
In summary, existing Territorial laws and regulatory mechanisms have the potential to offer some level of protection for the mao and its habitat if it were to be reintroduced to American Samoa but are not currently implemented in a manner that would do so. The DMWR has not exercised its statutory authority to address threats to the mao such as predation by nonnative predators, the mao is not listed pursuant
Based on the best available information, no existing Federal regulatory mechanisms address the threats to the mao. Some existing regulatory mechanisms in Samoa and American Samoa have the potential to offer some protection of the mao and its habitat, but their implementation does not reduce or remove threats to the species such as habitat destruction or modification or predation by nonnative species. For these reasons, we conclude that existing regulatory mechanisms do not address the threats to the mao.
Hurricanes are a common natural disturbance in the tropical Pacific and have occurred in the Samoan archipelago with varying frequency and intensity (see Factor E discussion for the Pacific sheath-tailed bat). Catastrophic events such as hurricanes can be a major threat to the persistence of species already experiencing population-level impacts of other stressors (MNRE 2006, p. 8). Two storms in the 1990s, Cyclones Ofa (1990) and Val (1991), severely damaged much of the remaining forested habitat in Samoa, reducing forest canopy cover by 73 percent (MNRE 2006, pp. 5, 7). In addition, Cyclone Evan struck Samoa in 2012 causing severe and widespread forest damage, including defoliation and downed trees in 80 to 90 percent of the Reserves and National Parks on Upolu (Butler and Stirnemann 2013, p. 41). Secondary forests also were severely damaged by the storm, and most trees in the known mao locations were stripped of their leaves, fruits, and flowers (Butler and Stirnemann 2013, p. 41). Hurricanes thus exacerbate forest fragmentation and invasion of native forests by nonnative species, stressors that reduce breeding, nesting, and foraging habitat for the mao (see Factor A, above). Although severe storms are a natural disturbance with which the mao has coexisted for millennia, such storms exacerbate the threats to its remaining small, isolated populations by at least temporarily damaging or redistributing habitat and food resources for the birds and causing direct mortality of individuals (Wiley and Wunderle 1993, pp. 340-341; Wunderle and Wiley 1996, p. 261). If the mao was widely distributed, had ample habitat and sufficient numbers, and were not under chronic pressure from anthropogenic threats such as introduced predators, it might recover from hurricane-related mortality and the temporary loss or redistribution of resources in the wake of severe storms. However, this species' current status makes it highly vulnerable to catastrophic chance events, such as hurricanes, which occur frequently throughout its range in Samoa and American Samoa.
Species with low numbers of individuals, restricted distributions, and small, isolated populations are often more susceptible to extinction as a result of natural catastrophes such as hurricanes or disease outbreaks, demographic fluctuations, or inbreeding depression (Shaffer 1981, p. 131; see Factor E discussion for the Pacific sheath-tailed bat, above). These problems associated with small population size are further magnified by interactions with each other and with other threats, such as habitat loss and predation (Lacy 2000, pp. 45-47; see Factor A and Factor C, above).
We consider the mao to be vulnerable to extinction because of threats associated with its low number of individuals—perhaps not more than a few hundred birds—and low numbers of populations. These threats include environmental catastrophes, such as hurricanes, which could immediately extinguish some or all of the remaining populations; demographic stochasticity that could leave the species without sufficient males or females to be viable; and inbreeding depression or loss of adaptive potential that can be associated with loss of genetic diversity and result in eventual extinction (Shaffer 1981, p. 131; Lacy 2000, pp. 40, 44-46). Combined with ongoing habitat destruction and modification by logging, agriculture, development, nonnative plant species, and feral ungulates (Factor A) and predation by rats and feral cats (Factor C), the effects of these threats to small populations further increases the risk of extinction of the mao.
Our analyses under the Act include consideration of ongoing and projected changes in climate (see Factor E discussion for the Pacific sheath-tailed bat). The magnitude and intensity of the impacts of global climate change and increasing temperatures on western tropical Pacific island ecosystems currently are unknown. In addition, there are no climate change studies that address impacts to the specific habitats of the mao. The scientific assessment completed by the Pacific Science Climate Science Program provides general projections or trends for predicted changes in climate and associated changes in ambient temperature, precipitation, hurricanes, and sea level rise for countries in the western tropical Pacific region including Samoa (used also as a proxy for American Samoa) (Australian BOM and CSIRO 2011, Vol. 1 & Vol. 2; see Factor E discussion for the Pacific sheath-tailed bat for summary).
Although we do not have specific information on the impacts of the effects of climate change to the mao, increased ambient temperature and precipitation, and increased severity of hurricanes, would likely exacerbate other threats to this species as well as provide additional stresses on its habitat. The probability of species extinction as a result of climate change impacts increases when its range is restricted, habitat decreases, and numbers of populations decline (IPCC 2007, p. 48). The mao is limited by its restricted range and low numbers of individuals. Therefore, we expect this species to be particularly vulnerable to the environmental effects of climate change and subsequent impacts to its habitat, even though the specific and cumulative effects of climate change on the mao are presently unknown and we are not able to determine the magnitude of this future threat with confidence. Based on the above information, we conclude that habitat impacts resulting from the effects of climate change are not a current threat but are likely to become a threat to the mao in the future.
We are unaware of any conservation actions planned or implemented at this time to abate the threats of hurricanes and low numbers of individuals that negatively impact the mao. However, the completion of a recovery plan, basic research on the mao's life-history requirements, population monitoring, and cooperation between the governments of American Samoa and Samoa contribute to the conservation of the mao.
We have carefully assessed the best scientific and commercial information available regarding the past, present, and future threats to mao. This large honeyeater endemic to the Samoan archipelago is vulnerable to extinction
The threat of habitat destruction and modification from agriculture, logging, and development, nonnative plants, and nonnative ungulates is occurring throughout the range of the mao, and is not likely to be reduced in the future (Factor A). The threat of predation from nonnative predators such as rats and feral cats is ongoing and likely to continue in the future (Factor C). Existing regulatory mechanisms do not address the threats to this species (Factor D). Additionally, the low numbers of individuals and populations of the mao render the species vulnerable to environmental catastrophes such as hurricanes, demographic stochasticity, and inbreeding depression (Factor E). These factors pose threats to the mao whether we consider their effects individually or cumulatively. All of these threats are likely to continue in the future.
The Act defines an endangered species as any species that is “in danger of extinction throughout all or a significant portion of its range” and a threatened species as any species “that is likely to become endangered throughout all or a significant portion of its range within the foreseeable future.” We find that the mao is presently in danger of extinction throughout its entire range based on the severity and immediacy of threats currently impacting the species.
Therefore, on the basis of the best available scientific and commercial information, we propose listing mao as endangered in accordance with sections 3(6) and 4(a)(1) of the Act. We find that the mao is presently in danger of extinction throughout its entire range based on the severity and immediacy of the ongoing and projected threats described above. The loss and degradation of its forested habitat, predation by nonnative mammals, limited distribution, the effects of small population size, and stochastic events such as hurricanes render this species in its entirety highly susceptible to extinction as a consequence of these imminent threats; the species' low reproductive rate reduces its ability to recover from impacts of multiple threats and their cumulative effects.
Under the Act and our implementing regulations, a species may warrant listing if it is in danger of extinction or likely to become so throughout all or a significant portion of its range. Because we have determined that the mao is endangered throughout all of its range, no portion of its range can be “significant” for purposes of the definitions of “endangered species” and “threatened species.” See the Final Policy on Interpretation of the Phrase “Significant Portion of Its Range” in the Endangered Species Act's Definitions of “Endangered Species” and “Threatened Species” (79 FR 37577, July 1, 2014).
The genus
We accept the current taxonomic treatment of the friendly ground-dove as
The friendly ground-dove is a medium-sized dove, approximately 10 in (26 cm) long. Males have rufous-brown upperparts with a bronze-green iridescence, the crown and nape are grey, the wings rufous with a purplish luster, and the tail is dark brown. The abdomen and belly are dark brown-olive, while the breast shield is dark pink with a white border. Immature birds are similar to adults but are uniformly brown. Females are dimorphic in Fiji and Tonga, where a brown phase (tawny underparts and no breast shield) and pale phase (similar to males but duller) occur. In Samoa and American Samoa, only the pale phase is known to occur (Watling 2001, p. 117).
In American Samoa, the friendly ground-dove is typically found on or near steep, forested slopes, particularly those with an open understory and fine scree or exposed soil (Tulafono 2006, in litt.). Elsewhere the species is known to inhabit brushy vegetation or native forest on offshore islands, native limestone forest (Tonga), and forest habitats on large, high islands (Steadman and Freifeld 1998, p. 617; Clunie 1999, pp. 42-43; Freifeld
The friendly ground-dove is uncommon or rare throughout its range in Fiji, Tonga, Wallis and Futuna, Samoa, and American Samoa (Steadman and Freifeld 1998, p. 626; Schuster
In American Samoa, the species was first reported on Ofu in 1976 (Amerson
Under the Act, we have the authority to consider for listing any species, subspecies, or for vertebrates, any distinct population segment (DPS) of these taxa if there is sufficient information to indicate that such action may be warranted. To guide the implementation of the DPS provisions of the Act, we and the National Marine Fisheries Service (National Oceanic and Atmospheric Administration—Fisheries), published the Policy Regarding the Recognition of Distinct Vertebrate Population Segments Under the Endangered Species Act (DPS Policy) in the
Under our DPS Policy, a population segment of a vertebrate taxon may be considered discrete if it satisfies either one of the following conditions: (1) It is markedly separated from other populations of the same taxon as a consequence of physical, physiological, ecological, or behavioral factors. Quantitative measures of genetic or morphological discontinuity may provide evidence of this separation; (2) It is delimited by international governmental boundaries within which differences in control of exploitation, management of habitat, conservation status, or regulatory mechanisms exist that are significant in light of section 4(a)(1)(D) of the Act.
The American Samoa population of the friendly ground-dove, a cryptic, understory-dwelling dove not noted for long-distance dispersal, is markedly separate from other populations of the species. The genus
Based on the our review of the available information, we have determined that the American Samoa population of the friendly ground-dove is markedly separate from other populations of the species due to geographic (physical) isolation from friendly ground-dove populations in Samoa, Tonga, and Fiji (Fig. 1). The geographic distance between the American Samoa population and other populations coupled with the low likelihood of frequent long-distance exchange between populations further separate the American Samoa population from other populations of this species throughout its range. Therefore, we have determined that the American Samoa population of friendly ground-dove meets a condition of our DPS policy for discreteness.
Under our DPS Policy, once we have determined that a population segment is discrete, we consider its biological and ecological significance to the larger taxon to which it belongs. This consideration may include, but is not limited to: (1) Evidence of the persistence of the discrete population segment in an ecological setting that is unusual or unique for the taxon, (2) evidence that loss of the population segment would result in a significant gap in the range of the taxon, (3) evidence that the population segment represents the only surviving natural occurrence of a taxon that may be more abundant elsewhere as an introduced population outside its historical range, or (4) evidence that the discrete population segment differs markedly from other populations of the species in its genetic characteristics. One of these criteria is met. We have found substantial evidence that loss of the American Samoa population of the friendly ground-dove would constitute a
The American Samoa population of the friendly ground-dove represents the easternmost distribution of this species. The loss of this population would truncate the species' range by approximately 100 mi (161 km), or approximately 15 percent of the linear extent of its range, which trends southwest-to-northeast from Fiji to Tonga to Wallis and Futuna, Samoa, and American Samoa. Unlike other Pacific Island columbids, this species does not fly high above the canopy; it is an understory species that forages largely on the ground and nests near the ground (Watling 2001, p. 118). Because of its flight limitations, the friendly ground-dove is unlikely to disperse over the long distances between American Samoa and the nearest surrounding populations. Therefore, the loss of the American Samoa population coupled with the low likelihood of recolonization from the nearest source populations in Samoa, Fiji, and Tonga, would create a significant gap in the range of the friendly ground-dove.
Given that both the discreteness and the significance elements of the DPS policy are met for the American Samoa population of the friendly ground-dove, we find that the American Samoa population of the friendly ground-dove is a valid DPS. Therefore, the American Samoa DPS of friendly ground-dove is a listable entity under the Act, and we now assess this DPS's conservation status in relation to the Act's standards for listing, (
The loss or modification of lowland and coastal forests has been implicated as a limiting factor for populations of the friendly ground-dove and has likely pushed this species into more disturbed areas or forested habitat at higher elevations (Watling 2001, p. 118). Several thousand years of subsistence agriculture and more recent, larger-scale agriculture has resulted in the alteration and great reduction in area of forests at lower elevations in American Samoa (see Factor A discussion for the mao). On Ofu, the coastal forest where the ground-dove has been recorded, and which may be the preferred habitat for this species range-wide (Watling 2001, p. 118), largely has been converted to villages, grasslands, or coconut plantations (Whistler 1994, p. 127). However, none of the land-clearing or development projects proposed for Ofu or Olosega in recent years has been approved or initiated in areas known to be frequented by friendly ground-doves (Tulafono 2006, in litt.; Stein
The National Park of American Samoa (NPSA) was established to preserve and protect the tropical forest and archaeological and cultural resources, to maintain the habitat of flying foxes, to preserve the ecological balance of the Samoan tropical forest, and, consistent with the preservation of these resources, to provide for the enjoyment of the unique resources of the Samoan tropical forest by visitors from around the world (Public Law 100-571, Public Law 100-336). Under a 50-year lease agreement between local villages, the American Samoa Government, and the Federal Government, approximately 73 ac (30 ha) on Ofu Island are located within park boundaries (NPSA Lease Agreement 1993). While the majority of the park's land area on Ofu consists of coastal and beach habitat, approximately 30 ac (12 ha) in the vicinity of Sunuitao Peak may provide forested habitat for the friendly ground-dove.
Past clearing for agriculture and development has resulted in the significant destruction and modification of coastal forest habitat for the American Samoa DPS of the friendly ground-dove. Land-clearing for agriculture is expected to continue in the future, but likely at a low rate. However, the degraded and fragmented status of the remaining habitat for the ground-dove is likely to be exacerbated by hurricanes. Therefore, we consider habitat destruction and modification to be a threat to this DPS.
Pigeon-catching was a traditional practice in ancient Samoan society (Craig 2009, p. 104). Hunting of terrestrial birds and bats in American Samoa primarily for subsistence purposes continued until the documented decline of wildlife populations led to the enactment of a hunting ban and formal hunting regulations (Craig
Research suggests that avian malaria may be indigenous and non-pathogenic in American Samoa, and, therefore, is unlikely to limit populations of the friendly ground-dove (Jarvi
Depredation by introduced mammalian predators is the likely cause of widespread extirpation of the friendly ground-dove throughout portions of its range (Steadman and Freifeld 1998, p. 617; Watling 2001, p. 118). Three species of rats occur in American Samoa and are likely to be present on the islands of Ofu and Olosega: the Polynesian rat, Norway rat, and black rat (Atkinson 1985, p. 38; DMWR 2006, p. 22; Caruso 2015b, in litt.). Domestic cats are widespread on Ofu and have been observed in the proximity of areas where friendly ground-doves have been detected (Arcilla 2015, in litt.). Feral cats are likely to occur on Olosega because of its physical connection to Ofu.
Predation by rats is well known to have caused population decline and extirpation in many island bird species (Atkinson 1977, p. 129; 1985, pp. 55-70; O'Donnell
Predation by cats has been directly responsible for the extinction of numerous birds on oceanic islands (Medina
In summary, based on the best available scientific and commercial information, we conclude that disease is not a factor in the continued existence of the friendly ground-dove. Because island birds such as the friendly ground-dove are extremely vulnerable to predation by nonnative predators, the threat of predation by rats and feral cats is likely to continue and is considered a threat to the continued existence of this DPS.
The Act requires that the Secretary assess available regulatory mechanisms in order to determine whether existing regulatory mechanisms may be inadequate as designed to address threats to the species being evaluated (Factor D). Under this factor, we examine whether existing regulatory mechanisms are inadequate to address the potential threats to the American Samoa DPS of the friendly ground-dove discussed under other factors. In determining whether the inadequacy of regulatory mechanisms constitutes a threat to the friendly ground-dove, we analyzed the existing Federal and Territorial laws and regulations that may address the threats to this species or contain relevant protective measures. Regulatory mechanisms, if they exist, may preclude the need for listing if we determine that such mechanisms adequately address the threats to the species such that listing is not warranted.
In American Samoa no existing Federal laws, treaties, or regulations specify protection of the friendly ground-dove's habitat from the threat of deforestation, or address the threat of predation by nonnative mammals such as rats and feral cats. However, some existing Territorial laws and regulations have the potential to afford the species some protection but their implementation does not achieve that result. The DMWR is given statutory authority to “manage, protect, preserve, and perpetuate marine and wildlife resources” and to promulgate rules and regulations to that end (American Samoa Code Annotated (ASCA), title 24, chapter 3). This agency conducts monitoring surveys, conservation activities, and community outreach and education about conservation concerns. However, to our knowledge, the DMWR has not used this authority to undertake conservation efforts for the friendly ground-dove such as habitat protection and control of nonnative predators such as rats and cats (DMWR 2006, pp. 79-80).
The Territorial Endangered Species Act provides for appointment of a Commission with the authority to nominate species as either endangered or threatened (ASCA, title 24, chapter 7). Regulations adopted under the Coastal Management Act (ASCA § 24.0501
Under ASCA, title 24, chapter 08 (Noxious Weeds), the Territorial DOA has the authority to ban, confiscate, and destroy species of plants harmful to the agricultural economy. Similarly, under ASCA, title 24, chapter 06 (Quarantine), the director of DOA has the authority to promulgate agriculture quarantine restrictions concerning animals. These laws may provide some protection against the introduction of new nonnative species that may have negative effects on the friendly ground-dove's habitat or become predators of the species, but these regulations do not require any measures to control invasive nonnative plants or animals that already are established and proving harmful to native species and their habitats (DMWR 2006, p. 80) (see Factor D for the Pacific sheath-tailed bat, above).
As described above, the Territorial Coastal Management Act establishes a land use permit (LUP) system for development projects and a Project Notification Review System (PNRS) for multi-agency review and approval of LUP applications (ASAC § 26.0206). The standards and criteria for review of LUP applications include requirements to protect Special Management Areas (SMA), Unique Areas, and “critical habitats” (ASCA § 24.0501
In summary, existing Territorial laws and regulatory mechanisms have the potential to offer some level of protection for the American Samoa DPS of the friendly ground-dove and its habitat but are not currently implemented in a manner that would do so. The DMWR has not exercised its statutory authority to address threats to the ground-dove such as predation by nonnative predators, the species is not listed pursuant to the Territorial Endangered Species Act, and the Coastal Management Act and its implementing regulations have the potential to address the threat of habitat loss to deforestation more substantively, but this law is inadequately
Hurricanes may cause the direct and indirect mortality of the friendly ground-dove, as well as modify its already limited habitat (see Factor A above). This species has likely coexisted with hurricanes for millennia in American Samoa, and if the friendly ground-dove was widely distributed in American Samoa, had ample habitat and sufficient numbers, and was not under chronic pressure from anthropogenic threats such as habitat loss and introduced predators, it might recover from hurricane-related mortality and the temporary loss or redistribution of resources in the wake of severe storms. However, this species' current status in American Samoa makes it highly vulnerable to chance events, such as hurricanes.
Species with a low total number of individuals, restricted distributions, and small, isolated populations are often more susceptible to extinction as a result of natural catastrophes, demographic fluctuations, or inbreeding depression (Shaffer 1981, p. 131; see Factor E discussion for the Pacific sheath-tailed bat, above). The American Samoa DPS of the friendly ground-dove is at risk of extinction because of its probable low remaining number of individuals and distribution restricted to small areas on the islands of Ofu and Olosega, conditions that render this DPS vulnerable to the small-population stressors listed above. These stressors include environmental catastrophes, such as hurricanes, which could immediately extinguish some or all of the remaining populations; demographic stochasticity that could leave the species without sufficient males or females to be viable; and inbreeding depression or loss of adaptive potential that can be associated with loss of genetic diversity and result in eventual extinction. These small-population stressors are a threat to the American Samoa DPS of the friendly ground-dove, and this threat is exacerbated by habitat loss and degradation (Factor A) and predation by nonnative mammals (Factor C).
Our analyses under the Act include consideration of ongoing and projected changes in climate (see Factor E discussion for the Pacific sheath-tailed bat). The magnitude and intensity of the impacts of global climate change and increasing temperatures on western tropical Pacific island ecosystems are currently unknown. In addition, there are no climate change studies that address impacts to the specific habitats of the American Samoa DPS of the friendly ground-dove. The scientific assessment completed by the Pacific Science Climate Science Program provides general projections or trends for predicted changes in climate and associated changes in ambient temperature, precipitation, hurricanes, and sea level rise for countries in the western tropical Pacific region including Samoa (Australian BOM and CSIRO 2011, Vol. 1 and 2; used as a proxy for American Samoa) (see Factor E discussion for the Pacific sheath-tailed bat).
Although we do not have specific information on the impacts of climate change to the American Samoa DPS of the friendly ground-dove, increased ambient temperature and precipitation, increased severity of hurricanes, and sea level rise and inundation would likely exacerbate other threats to its habitat. Although hurricanes are part of the natural disturbance regime in the tropical Pacific, and the friendly ground-dove has evolved in presence of this disturbance, the projected increase in the severity of hurricanes resulting from climate change is expected to exacerbate the hurricane-related impacts such as habitat destruction and modification and availability of food resources of the friendly ground-dove, whose diet consists mainly of seeds, fruit, buds, and young leaves and shoots (Watling 2001, p. 118). For example, Hurricanes Heta (in January 2004) and Olaf (in February 2005) virtually destroyed suitable habitat for the friendly ground-dove at one of the areas on Olosega where this species was most frequently encountered; detections of ground-doves in other, less storm-damaged areas subsequently increased, suggesting they had moved from the area affected by the storms (Seamon 2005, in litt.; Tulafono 2006, in litt.). The probability of species extinction as a result of climate change impacts increases when a species' range is restricted, its habitat decreases, and its numbers are declining (IPCC 2007, p. 8). The friendly ground-dove is limited by its restricted range, diminished habitat, and small population size. Therefore, we expect the friendly ground-dove to be particularly vulnerable to the environmental impacts of projected changes in climate and subsequent impacts to its habitat. Based on the above information, we conclude that habitat impacts resulting from the effects of climate change are not a current threat but are likely to become a threat to the American Samoa DPS of the friendly ground-dove in the future.
We are unaware of any conservation actions planned or implemented at this time to abate the threats of hurricanes and low numbers of individuals that negatively impact the American Samoa DPS of the friendly-ground-dove.
We have carefully assessed the best scientific and commercial information available regarding the past, present, and future threats to the American Samoa DPS of the friendly ground-dove. The American Samoa DPS of the friendly ground-dove is vulnerable to extinction because of its reduced population size and distribution, habitat loss, and probable depredation by nonnative mammals.
The habitat of the American Samoa DPS of the friendly ground-dove remains degraded and destroyed by past land-clearing for agriculture, and hurricanes exacerbate the poor status of this habitat, a threat that is likely to continue in the future (Factor A) and worsen under the projected effects of climate change. The threat of predation by nonnative mammals such as rats and cats is likely to continue in the future (Factor C). Current Territorial wildlife laws and regulations do not address the threats to this DPS (Factor D). The DPS of the friendly ground-dove persists in low numbers of individuals and in few and disjunct populations (Factor E), a threat that interacts synergistically with other threats. These factors pose threats to the American Samoa DPS of the friendly ground-dove, whether we consider their effects individually or cumulatively. These threats will continue in the future.
The Act defines an endangered species as any species that is “in danger of extinction throughout all or a
Therefore, on the basis of the best available scientific and commercial information, we propose listing the American Samoa DPS of the friendly ground-dove as endangered in accordance with sections 3(6) and 4(a)(1) of the Act. We find that the American Samoa DPS of the friendly ground-dove is presently in danger of extinction throughout its entire range based on the severity and immediacy of the ongoing and projected threats described above. The friendly ground-dove is restricted to the islands of Ofu and Olosega, where it exists in low numbers and is subject to predation by nonnative animals. The ground-dove's remaining habitat is limited and at risk from ongoing degradation by hurricanes. Habitat loss and degradation and the imminent threats of predation, the effects of small population size, and stochastic events such as hurricanes render the American Samoa DPS of the friendly ground-dove highly susceptible to extinction.
Under the Act and our implementing regulations, a species may warrant listing if it is in danger of extinction or likely to become so throughout all or a significant portion of its range. Because we have determined that the DPS of the friendly ground-dove is endangered throughout all of its range, no portion of its range can be “significant” for purposes of the definitions of “endangered species” and “threatened species.” See the Final Policy on Interpretation of the Phrase “Significant Portion of Its Range” in the Endangered Species Act's Definitions of “Endangered Species” and “Threatened Species” (79 FR 37577, July 1, 2014).
The biology of Samoan partulid snails has not been extensively studied, but there is considerable information on the partulid snails of the Mariana Islands (Crampton 1925a, pp. 1-113; Cowie 1992, pp. 167-191; Hopper and Smith 1992, pp. 77-85) and Society Islands (Crampton 1925b, pp. 5-35; Crampton 1932, pp. 1-194; Murray
Partulids can have a single preferred host plant or multiple host plants, in addition to having preference toward anatomical parts of the plant (
Review of long-term changes in the American Samoa land snail fauna based on surveys from 1975 to 1998 and pre-1975 collections characterized 3 of 12 species as being stable in numbers, with the rest described as declining in numbers, including
Nonnative plant species can seriously modify native habitat and render it unsuitable for native snail species (Hadfield 1986, p. 325). Although some Hawaiian tree snails have been recorded on nonnative vegetation, it is more generally the case that native snails throughout the Pacific are specialized to survive only on the native plants with which they have evolved (Cowie 2001, p. 219). Cowie (2001, p. 219) reported few observations of native snails, including
The native flora of the Samoan archipelago (plant species that were present before humans arrived) consisted of approximately 550 taxa, 30 percent of which were endemic (species that occur only in the American Samoa and Samoa) (Whistler 2002, p. 8). An additional 250 plant species have been intentionally or accidentally introduced and have become naturalized with 20 or more of these considered invasive or potentially invasive in American Samoa (Whistler 2002, p. 8; Space and Flynn 2000, pp. 23-24). Of these approximately 20 or more nonnative pest plant species, at least 10 have altered or have the potential to alter the habitat of the species proposed for listing as endangered or threatened species (Atkinson and Medeiros 2006, p. 18; Craig 2009, pp. 94, 97-98; ASCC 2010, p. 15).
Nonnative plants can degrade native habitat in Pacific island environments by: (1) Modifying the availability of light through alterations of the canopy structure; (2) altering soil-water regimes; (3) modifying nutrient cycling; (4) ultimately converting native-dominated plant communities to nonnative plant communities; and (5) increasing the frequency of landslides and erosion (Smith 1985, pp. 217-218; Cuddihy and Stone, 1990, p. 74; Matson 1990, p. 245; D'Antonio and Vitousek 1992, p. 73; Vitousek
For brief descriptions of the nonnative plants that impose the greatest negative impacts to the native habitats in American Samoa, see the list provided in Habitat Destruction and Modification by Nonnative Plants for the mao, above.
In summary, based on the potential invasion and habitat-modifying impacts of nonnative plant species, habitat destruction and modification by nonnative plant species is and will continue to be a threat to
Several thousand years of subsistence agriculture and more recent plantation agriculture has resulted in the alteration and great reduction in area of forests at lower elevations (Whistler 1994, p. 40; Mueller-Dombois and Fosberg 1998, p. 361). The threat of land conversion to unsuitable habitat will accelerate if the human population continues to grow or if the changes in the economy shift toward commercial agriculture (DMWR 2006, p. 71). On the island of Tutuila, agriculture and urban development covers approximately 24 percent of the island, and up to 60 percent of the island contains slopes of less than 30 percent where additional land-clearing is feasible (ASCC 2010, p. 13; DWMR 2006, p. 25). Farmers are increasingly encroaching into some of the steep forested areas as a result of suitable flat lands already being occupied with urban development and agriculture (ASCC 2010, p. 13). Consequently, agricultural plots on Tutuila have spread from low elevations up to middle and some high elevations on Tutuila, significantly reducing the forest area and thus reducing the resilience of the native forest and populations of native snails. In addition, substantial housing increases are also projected to occur in some rural forests along the northern coastline of Tutuila, and in a few scattered areas near existing population bases with established roads (Stein
The development of roads, trails, and utility corridors has also caused habitat destruction and modification in or adjacent to existing populations of
Feral pigs are known to cause deleterious impacts to ecosystem processes and functions throughout their worldwide distribution (Aplet
Feral pigs have been present in American Samoa since antiquity (American Samoa Historic Preservation Office 2015, in litt.). In the past, hunting pressure kept their numbers down, however, increasing urbanization and increasing availability of material goods has resulted in the decline in the practice of pig hunting to almost nothing (Whistler 1992, p. 21; 1994, p. 41). Feral pigs are moderately common to abundant in many forested areas, where they spread invasive plants, damage understory vegetation, and destroy riparian areas by their feeding and wallowing behavior (DMWR 2006, p. 23; ASCC 2010, p. 15). Feral pigs are a serious problem in the NPSA because of the damage they cause to native vegetation through their rooting and wallowing (Whistler 1992, p. 21; 1994, p. 41; Hoshide 1996, p. 2; Cowie and Cook 1999, p. 48; Togia pers. comm. in Loope
Several programs and partnerships to address the threat of habitat modification by nonnative plant species and feral pigs have been established and are ongoing within areas that provide habitat for
In summary, based on the best available scientific and commercial information, we consider the threats of destruction, modification, and curtailment of the species habitat and range to be ongoing threats to
Tree snails can be found around the world in tropical and subtropical regions and have been valued as collectibles for centuries. For example, the endemic Hawaiian tree snails within the family Achatinellidae were extensively collected for scientific and recreational purposes by Europeans in the 18th to early 20th centuries (Hadfield 1986, p. 322). During the 1800s, collectors sometimes took more than 4,000 snails in several hours (Hadfield 1986, p. 322). Repeated collections of hundreds to thousands of individuals may have contributed to decline in these species by reduction of reproductive potential (removal of breeding adults) as well as by reduction of total numbers (Hadfield 1986, p. 327). In the Hawaiian genus
In general, the collection of tree snails persists to this day, and the market for rare tree snails serves as an incentive to collect them. A recent search of the Internet found a Web site advertising the sale of
We are not aware of any threats to
At present, the major existing threat to long-term survival of the native snail fauna in American Samoa is predation by the nonnative rosy wolf snail (
Numerous studies show that the rosy wolf snail feeds on endemic island snails and is a major agent in their declines and extinctions (Hadfield and Mountain 1981, p. 357; Howarth 1983, p. 240, 1985, p. 161, 1991, p. 489; Clarke
Predation by several other nonnative carnivorous snails,
In summary, predation by nonnative snails, especially the rosy wolf snail, is a current threat to
Predation by the nonnative New Guinea or snail-eating flatworm (
The New Guinea flatworm has contributed to the decline of native tree snails due to its ability to ascend into trees and bushes (Sugiura and Yamaura 2009, p. 741). Although mostly ground-dwelling, the New Guinea flatworm has also been observed to climb trees and feed on partulid tree snails (Hopper and Smith 1992, p. 82). Areas with populations of the flatworm usually lack partulid tree snails or have declining numbers of snails (Hopper and Smith 1992, p. 82). Because
Rats are likely responsible for the greatest number of animal extinctions on islands throughout the world, including extinctions of various snail species (Towns
Evidence of predation by rats on
We are unaware of any conservation actions planned or implemented at this time to abate the threats of predation by rats, nonnative snails or flatworms to
In summary, based on the best available scientific and commercial information, we consider predation by the rosy wolf snail,
The Act requires that the Secretary assess available regulatory mechanisms in order to determine whether existing regulatory mechanisms may be inadequate as designed to address threats to the species being evaluated (Factor D). Under this factor, we examine whether existing regulatory mechanisms are inadequate to address the potential threats to
No existing Federal laws, treaties, or regulations specify protection of
The Territorial Endangered Species Act provides for appointment of a Commission with the authority to nominate species as either endangered or threatened (ASCA, title 24, chapter 7). Regulations adopted under the Coastal Management Act (ASCA § 24.0501
Under ASCA, title 24, chapter 08 (Noxious Weeds), the Territorial DOA has the authority to ban, confiscate, and destroy species of plants harmful to the agricultural economy. Similarly, under ASCA, title 24, chapter 06 (Quarantine), the director of DOA has the authority to promulgate agriculture quarantine restrictions concerning animals. These laws may provide some protection against the introduction of new nonnative species that may have negative effects on
As described above, the Territorial Coastal Management Act establishes a land use permit (LUP) system for development projects and a Project Notification Review System (PNRS) for multi-agency review and approval of LUP applications (ASAC § 26.0206). The standards and criteria for review of LUP applications include requirements to protect Special Management Areas (SMA), Unique Areas, and “critical habitats” (ASCA § 24.0501
In summary, existing Territorial laws and regulatory mechanisms have the potential to offer some level of protection for
Hurricanes are a common natural disturbance in the tropical Pacific and have occurred in American Samoa with varying frequency and intensity (see Factor E discussion for the Pacific sheath-tailed bat). Hurricanes may adversely impact the habitat of
The negative impact on
Nevertheless, the destruction of native vegetation and forest canopy, and modification of light and moisture conditions both during and in the months and possibly years following hurricanes can negatively impact the populations of
Species that undergo significant habitat loss and degradation and other threats resulting in decline and range reduction are inherently highly vulnerable to extinction resulting from localized catastrophes such as severe storms or disease outbreaks, climate change effects, and demographic stochasticity (Gilpin and Soulé 1986, pp. 24-34; Pimm
We consider
Our analyses under the Act include consideration of ongoing and projected changes in climate (see Factor E discussion for the Pacific sheath-tailed bat). The magnitude and intensity of the impacts of global climate change and increasing temperatures on western tropical Pacific island ecosystems currently are unknown. In addition, there are no climate change studies that address impacts to the specific habitats of
Although we do not have specific information on the impacts of the effects of climate change to
We are unaware of any conservation actions planned or implemented at this time to abate the threats of hurricanes and low numbers of individuals that negatively impact
We have carefully assessed the best scientific and commercial information available regarding the past, present, and future threats to
The threat of habitat destruction and modification from agriculture and development, nonnative plant species, and feral pigs is occurring throughout the range of
The Act defines an endangered species as any species that is “in danger of extinction throughout all or a significant portion of its range” and a threatened species as any species “that is likely to become endangered throughout all or a significant portion of its range within the foreseeable future.” We find that
Therefore, on the basis of the best available scientific and commercial information, we propose listing
Under the Act and our implementing regulations, a species may warrant listing if it is in danger of extinction or likely to become so throughout all or a significant portion of its range. Because we have determined that the snail
Although the biology of the genus
The threats of nonnative plants, agriculture and development, and feral pigs negatively impact the habitat of
Several programs and partnerships to address the threat of habitat modification by nonnative plant species and feral pigs have been established and are ongoing within areas that provide habitat for
Collection of land snail shells for commercial, scientific, recreational, or educational purposes has had a moderate influence in the decline of
We are not aware of any threats to
The nonnative rosy wolf snail is widespread on Tutuila and has been shown to contribute to the decline and extinction of native land snails (see Factor C discussion for
Predation by several other nonnative carnivorous snails,
The nonnative New Guinea or snail-eating flatworm has been the cause of decline and extinction of native land snails (see Factor C discussion for
Rats are known to prey upon endemic land snails and can devastate populations (see Factor C discussion for
We are unaware of any conservation actions planned or implemented at this time to abate the threats of predation by rats, nonnative snails, or flatworms to
In summary, based on the best available scientific and commercial information, we consider predation by the rosy wolf snail, the New Guinea flatworm, and rats to be a threat to of
The Act requires that the Secretary assess available regulatory mechanisms in order to determine whether existing regulatory mechanisms may be inadequate as designed to address threats to the species being evaluated (Factor D). Under this factor, we examine whether existing regulatory mechanisms are inadequate to address the potential threats to
No existing Federal laws, treaties, or regulations specify protection of the habitat of
The Territorial Endangered Species Act provides for appointment of a Commission with the authority to nominate species as either endangered or threatened (ASCA, title 24, chapter 7). Regulations adopted under the Coastal Management Act (ASCA § 24.0501
Under ASCA, title 24, chapter 08 (Noxious Weeds), the Territorial DOA has the authority to ban, confiscate, and destroy species of plants harmful to the agricultural economy. Similarly, under ASCA, title 24, chapter 06 (Quarantine), the director of DOA has the authority to promulgate agriculture quarantine restrictions concerning animals. These laws may provide some protection against the introduction of new nonnative species that may have negative effects on the habitat of
As described above, The Territorial Coastal Management Act establishes a land use permit (LUP) system for development projects and a Project Notification Review System (PNRS) for multi-agency review and approval of LUP applications (ASAC § 26.0206). The standards and criteria for review of LUP applications include requirements to protect Special Management Areas (SMA), Unique Areas, and “critical habitats” (ASCA § 24.0501
In summary, existing Territorial laws and regulatory mechanisms have the potential to offer some level of protection for
Species with low numbers of individuals, restricted distributions, and small, isolated populations are often more susceptible to extinction as a result of reduced levels of genetic variation, inbreeding depression, reproduced reproductive vigor, random demographic fluctuations, and natural catastrophes such as hurricanes (see Factor E discussion for
We consider
We do not have specific information on the impacts of the effects of climate change to
We are unaware of any conservation actions planned or implemented at this time to abate the threats of hurricanes and low numbers of individuals that negatively impact
We have carefully assessed the best scientific and commercial information available regarding the past, present, and future threats to
The threat of habitat destruction and modification from agriculture and development, hurricanes, nonnative plant species, and feral pigs is occurring throughout the range of
The Act defines an endangered species as any species that is “in danger of extinction throughout all or a significant portion of its range” and a threatened species as any species “that is likely to become endangered throughout all or a significant portion of its range within the foreseeable future.” We find that
Therefore, on the basis of the best available scientific and commercial information, we propose listing
Under the Act and our implementing regulations, a species may warrant listing if it is endangered or threatened throughout all or a significant portion of its range. Because we have determined that the snail
Conservation measures provided to species listed as endangered or threatened under the Act include recognition, recovery actions, requirements for Federal protection, and prohibitions against certain practices. Recognition through listing results in public awareness and conservation by Federal, State, Territorial, and local agencies, private organizations, and individuals. The Act encourages cooperation with the States and requires that recovery actions be carried out for all listed species. The protection required by Federal agencies and the prohibitions against certain activities are discussed, in part, below.
The primary purpose of the Act is the conservation of endangered and threatened species and the ecosystems upon which they depend. The ultimate goal of such conservation efforts is the recovery of these listed species, so that they no longer need the protective measures of the Act. Subsection 4(f) of the Act requires the Service to develop and implement recovery plans for the conservation of endangered and threatened species. The recovery planning process involves the identification of actions that are necessary to halt or reverse the species' decline by addressing the threats to its survival and recovery. The goal of this process is to restore listed species to a point where they are secure, self-sustaining, and functioning components of their ecosystems.
Recovery planning includes the development of a recovery outline shortly after a species is listed and preparation of a draft and final recovery plan. The recovery outline guides the immediate implementation of urgent recovery actions and describes the process to be used to develop a recovery plan. Revisions of the plan may be done to address continuing or new threats to the species, as new substantive information becomes available. The recovery plan identifies site-specific management actions that set a trigger for review of the five factors that control whether a species remains endangered or may be downlisted or delisted, and methods for monitoring recovery progress. Recovery plans also establish a framework for agencies to coordinate their recovery efforts and provide estimates of the cost of implementing recovery tasks. Recovery teams (composed of species experts, Federal and State agencies, nongovernmental organizations, and stakeholders) are often established to develop recovery plans. When completed, the recovery outline, draft recovery plan, and the final recovery plan will be available on our Web site (
Implementation of recovery actions generally requires the participation of a broad range of partners, including other Federal agencies, States, Tribes, nongovernmental organizations, businesses, and private landowners. Examples of recovery actions include habitat restoration (
If these species are listed, funding for recovery actions will be available from a variety of sources, including Federal budgets, State programs, and cost share grants for non-Federal landowners, the academic community, and nongovernmental organizations. In addition, pursuant to section 6 of the Act, U.S. Territory of American Samoa would be eligible for Federal funds to implement management actions that promote the protection or recovery of these species. Information on our grant programs that are available to aid species recovery can be found at:
Although these species are only proposed for listing under the Act at this time, please let us know if you are interested in participating in recovery efforts for these species. Additionally, we invite you to submit any new information on these species whenever it becomes available and any information you may have for recovery
Section 7(a) of the Act requires Federal agencies to evaluate their actions with respect to any species that is proposed or listed as an endangered or threatened species and with respect to its critical habitat, if any is designated. Regulations implementing this interagency cooperation provision of the Act are codified at 50 CFR part 402. Section 7(a)(4) of the Act requires Federal agencies to confer with the Service on any action that is likely to jeopardize the continued existence of a species proposed for listing or result in destruction or adverse modification of proposed critical habitat. If a species is listed subsequently, section 7(a)(2) of the Act requires Federal agencies to ensure that activities they authorize, fund, or carry out are not likely to jeopardize the continued existence of the species or destroy or adversely modify its critical habitat. If a Federal action may affect a listed species or its critical habitat, the responsible Federal agency must enter into consultation with the Service.
The Act and its implementing regulations set forth a series of general prohibitions and exceptions that apply to all endangered wildlife. The prohibitions of section 9(a)(1) of the Act, codified at 50 CFR 17.21 for endangered wildlife, in part, make it illegal for any person subject to the jurisdiction of the United States to take (includes harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect; or to attempt any of these) any such species within the United States or the territorial sea of the United States or upon the high seas; to import into or export from the United States any such species; to deliver, receive, carry, transport, or ship in interstate or foreign commerce, by any means whatsoever and in the course of commercial activity any such species; or sell or offer for sale in interstate or foreign commerce any such species. In addition, prohibitions of section 9(a)(1) of the Act make it unlawful to possess, sell, deliver, carry, transport, or ship, by any means whatsoever, any such species taken in violation of the Act. Certain exceptions apply to agents of the Service and State conservation agencies.
We may issue permits to carry out otherwise prohibited activities involving endangered and threatened wildlife species under certain circumstances. Regulations governing permits are codified at 50 CFR 17.22 for endangered species. With regard to endangered wildlife, a permit may be issued for the following purposes: for scientific purposes, to enhance the propagation or survival of the species, or for incidental take in connection with otherwise lawful activities. Requests for copies of the regulations regarding listed species and inquiries about prohibitions and permits may be addressed to U.S. Fish and Wildlife Service, Pacific Region, Ecological Services, Eastside Federal Complex, 911 NE. 11th Avenue, Portland, OR 97232-4181 (telephone 503-231-6131; facsimile 503-231-6243).
It is our policy, as published in the
Activities that result in take of any of the five species in American Samoa by causing significant habitat modification or degradation such that it causes actual injury by significantly impairing essential behaviors. This may include, but is not limited to, introduction of nonnative species in American Samoa that compete with or prey upon the species or the unauthorized release in the territory of biological control agents that attack any life-stage of these species.
Questions regarding whether specific activities would constitute a violation of section 9 of the Act should be directed to the Pacific Islands Fish and Wildlife Office (see
Section 3(5)(A) of the Act defines critical habitat as (i) the specific areas within the geographical area occupied by the species, at the time it is listed . . . on which are found those physical or biological features (I) essential to the conservation of the species and (II) which may require special management considerations or protection; and (ii) specific areas outside the geographical area occupied by the species at the time it is listed upon a determination by the Secretary that such areas are essential for the conservation of the species. Section 3(3) of the Act defines conservation as to use and the use of all methods and procedures which are necessary to bring any endangered species or threatened species to the point at which the measures provided pursuant to the Act are no longer necessary.
Section 4(a)(3) of the Act, as amended, and implementing regulations (50 CFR 424.12), require that, to the maximum extent prudent and determinable, the Secretary will designate critical habitat at the time the species is determined to be an endangered or threatened species. Our regulations (50 CFR 424.12(a)(1)) state that the designation of critical habitat is not prudent when one or both of the following situations exist:
(1) The species is threatened by taking or other human activity, and identification of critical habitat can be expected to increase the degree of threat to the species, or
(2) Such designation of critical habitat would not be beneficial to the species.
Besides the potential for unpermitted collection of the snails
Because we have determined that the designation of critical habitat will not likely increase the degree of threat to the species and may provide some measure of benefit, we determine that
Our regulations (50 CFR 424.12(a)(2)) further state that critical habitat is not determinable when one or both of the following situations exists: (1) Information sufficient to perform required analysis of the impacts of the designation is lacking; or (2) the biological needs of the species are not sufficiently well known to permit identification of an area as critical habitat.
Delineation of critical habitat requires, within the geographical area occupied by the species, identification of the physical or biological features essential to the species' conservation. Information regarding these five species' life functions is complex, and complete data are lacking for most of them. We require additional time to analyze the best available scientific data in order to identify specific areas appropriate for critical habitat designation and to prepare and process a proposed rule. Accordingly, we find designation of critical habitat for these species in accordance with section 4(3)(A) of the Act to be “not determinable” at this time.
We are required by Executive Orders 12866 and 12988 and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must:
(1) Be logically organized;
(2) Use the active voice to address readers directly;
(3) Use clear language rather than jargon;
(4) Be divided into short sections and sentences; and
(5) Use lists and tables wherever possible.
If you feel that we have not met these requirements, send us comments by one of the methods listed in
We have determined that environmental assessments and environmental impact statements, as defined under the authority of the National Environmental Policy Act (NEPA; 42 U.S.C. 4321
A complete list of references cited in this rulemaking is available on the Internet at
The primary authors of this proposed rule are the staff members of the Pacific Islands Fish and Wildlife Office.
Endangered and threatened species, Exports, Imports, Reporting and recordkeeping requirements, Transportation.
Accordingly, we propose to amend part 17, subchapter B of chapter I, title 50 of the Code of Federal Regulations, as set forth below:
16 U.S.C. 1361-1407; 1531-1544; 4201-4245 unless otherwise noted.
(h) * * *
Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT).
Notice of proposed rulemaking.
In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, Michigan, during which almost one million gallons of crude oil were spilled into the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) in the
In response to these mandates, recommendations, lessons learned, and public input, PHMSA is proposing to make changes to the hazardous liquid pipeline safety regulations. PHMSA is proposing these changes to improve protection of the public, property, and the environment by closing regulatory gaps where appropriate, and ensuring that operators are increasing the detection and remediation of unsafe conditions, and mitigating the adverse effects of pipeline failures.
Persons interested in submitting written comments on this NPRM must do so by January 8, 2016. PHMSA will consider late filed comments so far as practicable.
You may submit comments identified by the docket number PHMSA-2010-0229 by any of the following methods:
Comments are posted without changes or edits to
Mike Israni, by telephone at 202-366-4571, by fax at 202-366-4566, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP-30, Washington, DC 20590-0001.
Outline of this document:
In recent years, there have been significant hazardous liquid pipeline accidents, most notably the 2010 crude oil spill near Marshall, Michigan, during which almost one million gallons of crude oil were spilled into the Kalamazoo River. In response to accident investigation findings, incident report data and trends, and stakeholder input, PHMSA published an ANPRM in the
Subsequently, Congress enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. Shortly after the Act was passed, NTSB issued its accident investigation report on the Marshall, Michigan accident. In it, NTSB made additional recommendations regarding the need to revise and update hazardous liquid pipeline regulations. Specifically, the NTSB issued recommendations P-12-03 and P-12-04 respectively, which addressed detection of pipeline cracks and “discovery of condition”. The “discovery of condition” recommendation would require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators notify the Pipeline and Hazardous Materials Safety Administration and provide an expected date when adequate information will become available.
The Government Accounting Office (GAO) also issued a recommendation in 2012 concerning hazardous liquid and gas gathering pipelines. Recommendation GAO-12-388, dated March 22, 2012, states “To enhance the safety of unregulated onshore hazardous liquid and gas gathering pipelines, the Secretary of Transportation should direct the PHMSA Administrator to collect data from operators of federally unregulated onshore hazardous liquid and gas gathering pipelines, subsequent to an analysis of the benefits and industry burdens associated with such data collection”.
In response to these mandates, recommendations, lessons learned, and public input, PHMSA is proposing to make certain changes to the Hazardous Liquid Pipeline Safety Regulations. The first and second proposals are to extend reporting requirements to all hazardous liquid gravity and gathering lines. The collection of information about these lines is authorized under the Pipeline Safety Laws, and the resulting data will assist in determining whether the existing federal and state regulations for these lines are adequate.
The third proposal is to require inspections of pipelines in areas affected by extreme weather, natural disasters, and other similar events. Such inspections will ensure that pipelines
The fifth proposal is to require the use of leak detection systems on hazardous liquid pipelines in all locations. The use of such systems will help to mitigate the effects of hazardous liquid pipeline failures that occur outside of HCAs. The sixth proposal is to modify the provisions for making pipeline repairs. Additional conservatism will be incorporated into the existing repair criteria and an adjusted schedule will be established to provide greater uniformity. These criteria will also be made applicable to all hazardous liquid pipelines, with an extended timeframe for making repairs outside of HCAs.
The seventh proposal is to require that all pipelines subject to the IM requirements be capable of accommodating inline inspection tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. Inline inspection tools are an effective means of assessing the integrity of a pipeline and broadening their use will improve the detection of anomalies and prevent or mitigate future accidents in high-risk areas. Finally, other regulations will be clarified to improve certainty and compliance. PHMSA estimates that 421 hazardous liquid operators may incur costs to comply with the proposed rule. The estimated annual costs for the different requirements range from approximately $1,000 to $16.7 million, with aggregate costs of approximately $22.4 million. These wide ranges exist because the requirements vary widely. For example, some requirements apply only to pipelines within HCAs, some only to those outside HCAs, and some to both; other requirements apply only to onshore pipelines, and others to both on- and offshore; the length of pipeline, and the number of operators affected both vary for the different requirements. These proposals are designed to mitigate or prevent some number of hazardous liquid pipeline incidents resulting in annualized benefits estimated between approximately $3.5 and $17.7 million, depending on the requirement. Factors such as increased safety, public confidence that all pipelines are regulated, quicker discovery of leaks and mitigation of environmental damages, and better risk management are considered in this analysis. The dollar value of fatalities, injuries, and property damages due to pipeline incidents are societal costs and their prevention represents potential benefits. The changes proposed in this Notice of Proposed Rulemaking (NPRM) are expected to enhance overall pipeline safety and protection of the environment.
Congress established the current framework for regulating the safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline Safety Act (HLPSA) of 1979 (Pub. L. 96-129). Like its predecessor, the Natural Gas Pipeline Safety Act (NGPSA) of 1968 (Pub. L. 90-481), the HLPSA provides the Secretary of Transportation (Secretary) with the authority to prescribe minimum federal safety standards for hazardous liquid pipeline facilities. That authority, as amended in subsequent reauthorizations, is currently codified in the Pipeline Safety Laws (49 U.S.C. 60101
PHMSA is the agency within DOT that administers the Pipeline Safety Laws. PHMSA has issued a set of comprehensive safety standards for the design, construction, testing, operation, and maintenance of hazardous liquid pipelines. Those standards are codified in the Hazardous Liquid Pipeline Safety Regulations (49 CFR part 195).
Part 195 applies broadly to the transportation of hazardous liquids or carbon dioxide by pipeline, including on the Outer Continental Shelf, with certain exceptions set forth by statute or regulation. Performance-based safety standards are generally favored (
PHMSA exercises primary regulatory authority over interstate hazardous liquid pipelines, and the owners and operators of those facilities must comply with safety standards in part 195. The states may submit a certification to regulate the safety standards and practices for intrastate pipelines. States certified to regulate their intrastate lines can also enter into agreements with PHMSA to serve as an agent for inspecting interstate facilities.
Most state pipeline safety programs are administered by public utility commissions. These state authorities must adopt the Pipeline Safety Regulations as part of a certification or agreement, but can establish more stringent safety standards for those intrastate pipeline facilities that they have responsibility to regulate. PHMSA cannot regulate the safety standards or practices for an intrastate pipeline facility if a state has a current certification to regulate such facilities.
Congress recently enacted the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act). That legislation included several provisions that are relevant to the regulation of hazardous liquid pipelines. As part of the rulemaking process, PHMSA presented proposed changes in response to this Act in an ANPRM published in the
Gravity lines; pipelines that carry product by means of gravity, are currently exempt from PHMSA regulations. Many gravity lines are short and within tank farms or other pipeline facilities; however, some gravity lines are longer and are capable of building up large amounts of pressure. PHMSA is aware of gravity lines that traverse long distances with significant elevation changes which could have significant consequences in the event of a release.
In order for PHMSA to effectively analyze safety performance and pipeline risk of gravity lines, PHMSA needs basic data about those pipelines. The agency has the statutory authority to gather data for all gravity lines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing to add 49 CFR 195.1(a)(5) to require that the operators of all gravity lines comply with requirements for submitting annual, safety-related condition, and incident reports. PHMSA estimates that, at most, five hazardous liquid pipeline operators will be affected. Based on comments from API-AOPL to the ANPRM, 3 operators have approximately 17 miles of gravity fed pipelines. PHMSA estimated that proportionally 5 operators would have 28 miles of gravity-fed pipelines.
PHMSA is also proposing to extend the reporting requirements of part 195 to all hazardous liquid gathering lines. According to the legislative history, Congress originally opposed any
Recent data indicates, however, that PHMSA regulates less than 4,000 miles of the approximately 30,000 to 40,000 miles of onshore hazardous liquid gathering lines in the United States. That means that as much as 90 percent of the onshore gathering line mileage is not currently subject to any minimum federal pipeline safety standards. The NTSB has also raised concerns about the safety of hazardous liquid gathering lines in the Gulf of Mexico and its inlets, which are only subject to certain inspection and reburial requirements.
Congress also ordered the review of existing state and federal regulations for hazardous liquid gathering lines in the Pipeline Safety Act of 2011, to prepare a report on whether any of the existing exceptions for these lines should be modified or repealed, and to determine whether hazardous liquid gathering lines located offshore or in the inlets of the Gulf of Mexico should be subjected to the same safety standards as all other hazardous liquid gathering lines. Based on the study titled “Review of Existing Federal and State Regulations for Gas and Hazardous Liquid Gathering Lines,”
In order for PHMSA to effectively analyze safety performance and pipeline risk of gathering lines, we need basic data about those pipelines. PHMSA has statutory authority to gather data for all gathering lines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing to add § 195.1(a)(5) to require that the operators of all gathering lines (whether onshore, offshore, regulated, or unregulated) comply with requirements for submitting annual, safety-related condition, and incident reports.
In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for hazardous liquid gathering lines. Section 195.1(a)(4)(ii) states that part 195 applies to a “regulated rural gathering line as provided in § 195.11.” PHMSA adopted a regulation in a June 2008 final rule (73 FR 31634) that prescribed certain safety requirements for regulated rural gathering lines (
The June 2008 final rule did not establish safety standards for all rural hazardous liquid gathering lines. Some of those lines cannot be regulated by statute (
In July 2011 a pipeline failure occurred near Laurel, Montana, causing the release of an estimated 1,000 barrels of crude oil into the Yellowstone River. That area had experienced extensive flooding in the weeks leading up to the failure, and the operator has estimated the cleanup costs at approximately $135 million. An instance of flooding also occurred in 1994 in the State of Texas, leading to the failure of eight pipelines and the release of more than 35,000 barrels of hazardous liquids into the San Jacinto River. Some of that released product also ignited, causing minor burns and other injuries to nearly 550 people according to the NTSB. As the agency has noted in a series of advisory bulletins, hurricanes are capable of causing extensive damage to both offshore and inland pipelines (
These events demonstrate the importance of ensuring that our nation's waterways are adequately protected in the event of a natural disaster or extreme weather. PHMSA is aware that responsible operators might do such inspections; however, because it is not a requirement, some operators do not. Therefore, PHMSA is proposing to require that operators perform an additional inspection within 72 hours after the cessation of an extreme weather event such as a hurricane or flood, an earthquake, a natural disaster, or other similar event.
Specifically, under this proposal an operator must inspect all potentially affected pipeline facilities post extreme weather event to ensure that no conditions exist that could adversely affect the safe operation of that pipeline. The operator would be required to consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the inspection required. The inspection must occur within 72 hours after the cessation of the event, or as soon as the affected area can be safely accessed by the personnel and equipment required to perform the inspection. PHMSA has found that 72 hours is reasonable and achievable in most cases. If an adverse condition is found, the operator must take appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection. Such actions might include, but are not limited to:
• Reducing the operating pressure or shutting down the pipeline;
• Modifying, repairing, or replacing any damaged pipeline facilities;
• Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-ways (ROWS);
• Performing additional patrols, surveys, tests, or inspections;
• Implementing emergency response activities with federal, state, or local personnel; and
• Notifying affected communities of the steps that can be taken to ensure public safety.
This proposal is based on the experience of PHMSA and is expected to increase the likelihood that safety
PHMSA is proposing to require assessments for pipeline segments in non-HCAs. PHMSA believes that expanded assessment of non-HCA pipeline segments areas will provide operators with valuable information they may not have collected if regulations were not in place such a requirement would ensure prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Specifically, the proposed § 195.416 would require operators to assess non-HCA (non-IM) pipeline segments with an inline inspection (ILI) tool at least once every 10 years. PHMSA needs operators to complete assessments in HCAs followed by assessments in non-HCAs. Other assessment methods could be used if an operator provides the Office of Pipeline Safety (OPS) with prior written notice that a pipeline is not capable of accommodating an ILI tool. The written notice provided to PHMSA must include a technical demonstration of why the pipeline is not capable of accommodating an ILI tool and what alternative technology the operator proposes to use. The operator must also detail how the alternative technology would provide a substantially equivalent understanding of the pipeline's condition in light of the threats that could affect its safe operation. Such alternative technologies would include hydrostatic pressure testing or appropriate forms of direct assessment.
The individuals who review the results of these periodic assessments would need to be qualified by knowledge, training, and experience and would be required to consider any uncertainty in the results obtained, including ILI tool tolerance, when determining whether any conditions could adversely affect the safe operation of a pipeline. Such determinations would have to be made promptly, but no later than 180 days after an inspection, unless the operator demonstrates that the 180-day deadline is impracticable.
Operators would be required to comply with the other provisions in part 195 in implementing the requirements in § 195.416. That includes having appropriate provisions for performing these periodic assessments and any resulting repairs in an operator's procedural manual (see § 195.402), adhering to the recordkeeping provisions for inspections, test, and repairs (see § 195.404), and taking appropriate remedial action under § 195.422, as discussed below. Section 195.11 would also be amended to subject regulated onshore gathering lines to the periodic assessment requirement.
PHMSA believes by proposing the above amendment to the existing pipeline safety regulations, safety will be increased for all pipelines both in and out of HCAs. Such a requirement would ensure operators obtain information necessary for prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just HCAs. Currently, operators have indicated that they are performing ILI assessments on a large majority of their pipelines even though no regulation requires them to do so outside of HCAs. PHMSA wants to ensure that current assessment rates continue and expand to those areas not voluntarily assessed. Of the many methods to assess, PHMSA has found that ILI in many cases is the most efficient and effective. PHMSA considered alternatives to its proposal that would likely have lower overall costs and benefits, but potentially higher net benefits. For instance, PHMSA considered limiting the proposed expansion of certain IM requirements to those pipelines where a spill could affect a building or occupied site such as a playground, or highway. Under this alternative, pipelines in a location where a spill could not affect a building, occupied site, or highway would not be subject to these new requirements. However, this alternative would offer less protection to the natural environment, including sensitive and protected habitats and species. PHMSA also considered alternative assessment intervals to the proposed 10 year interval, such as a 15- or 20-year interval. However, substantial changes to pipeline integrity can occur in a short timeframe. PHMSA declined to propose these alternatives because they would provide fewer benefits than the proposed approach. More specifically, liquid spills, even in remote areas, can result in environmental damage necessitating clean up and incurring restoration costs and lost use and nonuse values. If pipe is not assessed and repaired in accordance with this proposal, liquid spills are likely to occur.
Also, a longer interval between assessments would increase risks of integrity-related failure compared to PHMSA's proposal. PHMSA was unable to quantify the benefits and costs of these alternatives due to limitations in available information, such as the amount of unassessed pipe where a spill could not affect a building, occupied site, or highway; the environmental impact of spills from such pipe; and the incremental reduction in benefit between 10-year and alternative interval periods. PHMSA seeks public comments on these alternatives, and the regulatory impact analysis contains specific questions for public comment on quantifying these alternatives.
Inspection experience indicates a weakness in current repair criteria. Specifically, the current repair criteria in non-HCAs (immediate and reasonable time) does not specify anomaly or repair time frames. It is left entirely at the operator's discretion. Therefore, PHMSA is proposing to modify the IM pipeline repair criteria and to apply the criteria to non-IM pipeline repairs. Specifically, the criteria in § 195.452(h) for IM repairs would be modified to:
• Categorize bottom-side dents with stress risers as immediate repair conditions;
• Require immediate repairs whenever the calculated burst pressure is less than 1.1 times maximum operating pressure;
• Eliminate the 60-day and 180-day repair categories; and
• Establish a new, consolidated 270-day repair category.
PHMSA is also proposing to amend the requirements in § 195.422 for performing non-IM repairs by:
• Applying the criteria in the immediate repair category in § 195.452(h); and
• Establishing an 18-month repair category for hazardous liquid pipelines that are not subject to IM requirements.
PHMSA believes that these changes will ensure that immediate action is taken to remediate anomalies that present an imminent threat to the integrity of hazardous liquid pipelines in all locations. Moreover, many anomalies that would not qualify as immediate repairs under the current criteria will meet that requirement as a result of the additional conservatism
As a result of these changes, PHMSA would modify the existing general requirements for pipeline repairs in § 195.401(b). Paragraph (b)(1) would be modified to reference the new timeframes in § 195.422(d) and (e) for remediating conditions that could adversely affect the safe operation of a pipeline segment not subject to the IM requirements in § 195.452. The requirements in paragraph (b)(2) for IM repairs under § 195.452(h) will be retained without change. A new paragraph (b)(3) will be added, however, to require operators to consider the risk to people, property, and the environment in prioritizing the remediation of any condition that could adversely affect the safe operation of a pipeline system, including those covered by the timeframes specified in §§ 195.422(d) and (e) and 195.452(h).
PHMSA is proposing to amend § 195.134 to require that all new hazardous liquid pipelines be designed to include leak detection systems. Recent pipeline accidents, including a pair of related failures that occurred in 2010 on a crude oil pipeline in Salt Lake City, Utah, corroborate the significance of having an adequate means for identifying leaks in all locations. PHMSA, aware of the significance of leak detection, held two recent workshops in Rockville, Maryland on March 27-28 of 2012. These workshops sought comment from the public concerning many of the issues raised in the 2010 ANPRM, including leak detection expansion. Both workshops were well attended and PHMSA received valuable input from stakeholders.
Currently, part 195 contains mandatory leak detection requirements for hazardous liquid pipelines that could affect an HCA.
Congress included additional requirements for leak detection systems in section 8 of the Pipeline Safety Act of 2011. That legislation requires the Secretary to submit a report to Congress, within 1-year of the enactment date, on the use of leak detection systems, including an analysis of the technical limitations and the practicability, safety benefits, and adverse consequence of establishing additional standards for the use of those systems. To provide Congress with an opportunity to review that report, the Secretary is prohibited from issuing any final leak detection regulations for a specified time period (
In addition to modifying § 195.444 to require a means for detecting leaks on all portions of a hazardous liquid pipeline system, PHMSA is proposing that operators be required to have an evaluation performed to determine what kinds of systems must be installed to adequately protect the public, property, and the environment. The factors that must be considered in performing that evaluation would include the characteristics and history of the affected pipeline, the capabilities of the available leak detection systems, and the location of emergency response personnel. A proposed amendment to § 195.11 would extend these new leak detection requirements to regulated onshore gathering lines. PHMSA is retaining and is not proposing any modification to the requirement in §§ 195.134 and 195.444 that each new computational leak detection system comply with the applicable requirements in the API RP 1130 standard.
PHMSA does not propose to make any additional changes to the regulations concerning specific leak detection requirements at this time. PHMSA will be studying this issue further and may make proposals concerning this topic in a later rulemaking. PHMSA recently publicly provided the results of the 2012 Keifner and Associates study of leak detection systems in the pipeline industry, including the current state of technology.
PHMSA is proposing to require that all hazardous liquid pipelines in HCA's and areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless the basic construction of a pipeline will not accommodate the passage of such a device.
The current requirements for the passage of ILI devices in hazardous liquid pipelines are prescribed in § 195.120, which require that new and replaced pipelines are designed to accommodate inline inspection tools. The basis for these requirements was a 1988 law that addressed the Secretary's authority with regard to requiring the accommodation of ILI tools. This law required the Secretary to establish minimum federal safety standards for the use of ILI tools, but only in newly constructed and replaced hazardous liquid pipelines (Pub. L. 100-561).
In 1996, Congress passed another law further expanding the Secretary's authority to require pipeline operators to have systems that can accommodate ILI tools. In particular, Congress provided additional authority for the Secretary to require the modification of existing pipelines whose basic construction would accommodate an ILI tool to accommodate such a tool and permit internal inspection (Pub. L. 104-304).
As the Research and Special Programs Administration (RSPA), (a predecessor agency of PHMSA) explained in the final rule April 12, 1994 (59 FR 17275) that promulgated § 195.120, “[t]he clear intent of th[at] congressional mandate [wa]s to improve an existing pipeline's piggability,” and to “require[] the gradual elimination of restrictions in existing hazardous liquid and carbon dioxide lines in a manner that will eventually make the lines piggable.” April 2, 1994, (59 FR 17279). RSPA also noted that Congress amended the 1988 law in the Pipeline Safety Act of 1992 (Pub. L. 102-508) to require the periodic internal inspection of hazardous liquid pipelines, including with ILI tools in appropriate circumstances April 2, 1994, (59 FR 17275). RSPA established requirements for the use of ILI tools in pipelines that could affect HCAs in the December 2000 IM final rule December 1, 2000, (65 FR 75378).
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the requirements for the passage of ILI tools to be extended to existing hazardous liquid pipeline facilities, provided the basic construction of those facilities can be modified to permit the use of smart pigs.
PHMSA is proposing to use the authority provided in section 60102(f)(1)(B) to further facilitate the “gradual elimination” of pipelines that are not capable of accommodating smart pigs. PHMSA would limit the circumstances where a pipeline can be constructed without being able to accommodate a smart pig. Under the current regulation, an operator can petition the PHMSA Administrator for such an allowance for reasons of impracticability, emergencies, construction time constraints, and other unforeseen construction problems. PHMSA believes that an exception should still be available for emergencies and where the basic construction of a pipeline makes that accommodation impracticable, but that the other, less urgent circumstances listed in the regulation are no longer appropriate. Accordingly, the allowances for construction-related time constraints and problems would be repealed.
Modern ILI tools are capable of providing a relatively complete examination of the entire length of a pipeline, including information about threats that cannot always be identified using other assessment methods. ILI tools also provide superior information about incipient flaws (
As with new pipelines, operators will be allowed to petition the PHMSA Administrator for a finding that the basic construction, (
PHMSA is also proposing several other clarifying changes to the regulations that are intended to improve compliance and enforcement. First, PHMSA is proposing to revise paragraph (b)(1) of § 195.452 to correct an inconsistency in the current regulations. Currently, § 195.452(b)(2) requires that segments of new pipelines that could affect HCAs be identified before the pipeline begins operations and § 195.452(d)(1) requires that baseline assessments for covered segments of new pipelines be completed by the date the pipeline begins operation. However, § 195.452(b)(1) does not require an operator to draft its IM program for a new pipeline until one-year after the pipeline begins operation. These provisions are inconsistent as the identification could affect segments, and performance of baseline assessments are elements of the written IM program. PHMSA would amend the table in (b)(1) to resolve this inconsistency by eliminating the one-year compliance deadline for Category 3 pipelines. An operator of a new pipeline would be required to develop its written IM program before the pipeline begins operation.
A decade's worth of IM inspection experience has shown that many operators are performing inadequate information analyses (
For this reason, PHMSA is proposing to add additional specificity to paragraph (g) by establishing a number of pipeline attributes that must be included in these analyses and to require explicitly that operators integrate analyzed information. PHMSA is also proposing that operators consider explicitly any spatial relationships among anomalous information. PHMSA supports the use of computer-based geographic information systems (GIS) to record this information. GIS systems can be beneficial in identifying spatial relationships, but analysis is required to identify where these relationships could result in situations adverse to pipeline integrity.
Second, PHMSA is proposing that operators verify their segment identification annually by determining whether factors considered in their analysis have changed. Section 195.452(b) currently requires that operators identify each segment of their pipeline that could affect an HCA in the event of a release but there is no explicit requirement that operators assure that their identification of covered segments remains current. As time goes by, the likelihood increases that factors considered in the original identification of covered segments may have changed. PHMSA believes that operators should periodically re-visit their initial analyses to determine whether they need to be updated. New HCAs may be identified. Construction activities or erosion near the pipeline could change local topography in a way that could cause product released in an accident to travel further than initially analyzed. Changes in agricultural land use could also affect an operator's analysis of the distance released product could be expected to travel. Changes in the deployment of emergency response personnel could increase the time required to respond to a release and result in a larger area being affected by a potential release if the original segment identification relied on emergency response to limit the transport of released product.
The change that PHMSA is proposing would not require that operators re-perform their segment analyses. Rather, it would require operators to identify the factors considered in their original analyses, determine whether those factors have changed, and consider whether any such change would be likely to affect the results of the original segment identification. If so, the operator would be required to perform a new analysis to validate or change the endpoints of the segments affected by the change.
Third, PHMSA is proposing to clarify, through the use of an explicit reference that the IM requirements apply to portions of “pipelines” other than line pipe. Unlike integrity assessments for line pipe, § 195.452 does not include explicit deadlines for completing the analyses of other facilities within the definition of “pipeline” or for implementing actions in response to those analyses. Through IM inspections,
Section 29 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 states that “[i]n identifying and evaluating all potential threats to each pipeline segment pursuant to parts 192 and 195 of title 49, Code of Federal Regulations, an operator of a pipeline facility shall consider the seismicity of the area.” While seismicity is already mentioned at several points in the IM program guidance provided in Appendix C of part 195, PHMSA is proposing to further comply with Congress's directive by including an explicit reference to seismicity in the list of risk factors that must be considered in establishing assessment schedules (§ 195.452(e)), performing information analyses (§ 195.452(g)), and implementing preventive and mitigative measures (§ 195.452(i)) under the IM requirements.
On October 18, 2010, (75 FR 63774), PHMSA published an ANPRM asking the public to comment on several proposed changes to part 195. The ANPRM sought comments on:
• Scope of part 195 and existing regulatory exceptions;
• Criteria for designation of HCAs;
• Leak detection and emergency flow restricting devices;
• Valve spacing;
• Repair criteria outside of HCAs; and
• Stress corrosion cracking.
Twenty-one organizations and individuals submitted comments in response to the ANPRM. The individual docket item numbers are listed for each comment.
Comments are reviewed in the order the ANPRM presented questions for comment. PHMSA responses to the comments follow.
API-AOPL, LMOGA, TxOGA, and TransCanada Keystone expressed support for the gravity line exception. These commenters stated that gravity lines are short, pose little risk, and are usually located within other regulated facilities, such as tank farms. NAPSR did not support a complete repeal of this exception, suggesting there was no data to support such an action. NAPSR did suggest that the exception should not apply to ethanol pipelines, which are very susceptible to internal corrosion.
MAWUC indicated that gravity lines in HCAs should be regulated because of the sensitivity of these areas. MAWUC further stated that these lines (and other rural onshore gathering lines) contain contaminants that are not present in products carried by other pipelines, that these contaminants are dangerous to pipeline workers, and that the impact of releases from these pipelines on the environment is the same as releases from regulated pipelines.
PHMSA does not, at this time, intend to repeal the exemption for gravity lines, but does propose to extend reporting requirements to all hazardous liquid gravity lines. The collection of information about these lines is authorized under the Pipeline Safety Laws, and the resulting data will assist in determining whether the existing federal and state regulations for these lines are adequate.
PHMSA received a number of comments on whether to modify or repeal the requirements in § 195.1(a)(4). API-AOPL, LMOG, IPAA, OIPA, and TxOGA stated that the regulatory exception for rural gathering lines is appropriate and should not be repealed or modified. They indicated that these lines are the source of a small percentage of spills, and that gathering lines in populated areas and near navigable waterways are already subject to PHMSA regulation.
Among citizens' groups, TWS suggested that PHMSA should examine federal and state release data from all excepted pipelines and regulate those with release rates similar to currently regulated pipelines. PST supported expansion of the definition of gathering line to the extent statutorily possible to capture all lines. Similarly, CRAC, TWS, and AKW indicated the exception should be removed and regulation expanded to include produced water lines and production lines. TWS and AKW also stated that flow lines, which are currently defined by regulation as production facilities, should be reclassified and regulated as gathering lines.
The government/municipalities NSB and MAWUC also commented concerning the rural gathering line exception. NSB requested PHMSA place a high priority on removing the
Citizen Miller commented that PHMSA should regulate production and produced water lines on Alaska's North Slope, because this area is very sensitive and includes pristine wetlands and fish and wildlife habitats of national and international importance. She further commented that river and coastline pipeline routes and crossings in the Arctic and subarctic Alaska are particularly of concern due to the rapid change in permafrost, as well as high rates of coastal erosion which greatly increases the environmental and human impacts of spills.
PHMSA believes that the requirements of the Pipeline Safety Act of 2011 and concerns for adequate regulatory oversight can only be addressed if PHMSA obtains additional information about gathering lines. PHMSA has the statutory authority to gather data for all gathering lines (49 U.S.C. 60117(b)), and that authority was not affected by any of the provisions in the Pipeline Safety Act of 2011. Accordingly, PHMSA is proposing to amend 49 CFR 195.1(a)(5) to require that the operators of all gathering lines (whether onshore, offshore, regulated, or unregulated) comply with requirements for submitting annual, safety-related condition, and incident reports.
In the ANPRM, PHMSA asked whether the agency should repeal or modify the regulatory exception for carbon dioxide pipelines used in the well injection and recovery production process. Section 195.1(b)(10) states that part 195 does not apply to the transportation of carbon dioxide downstream from the applicable following point:
(i) The inlet of a compressor used in the injection of carbon dioxide for oil recovery operations, or the point where recycled carbon dioxide enters the injection system, whichever is farther upstream; or
(ii) The connection of the first branch pipeline in the production field where the pipeline transports carbon dioxide to an injection well or to a header or manifold from which a pipeline branches to an injection well.
The trade associations, LMOGA, API-AOPL, OIPA, TxOGA, and IPAA, commented that PHMSA should not repeal the exception for carbon dioxide lines used in the well injection and recovery production process. They indicated the potential risk from a production facility carbon dioxide pipeline failure is low due to factors of low potential release volumes, rapid dispersion, and low potential for human exposure. NAPSR suggested the current exception is appropriate and noted that there is no data indicating the need for a repeal.
The regulatory history shows that the exception in § 195.1(b)(10) is limited in scope and only applies to carbon dioxide pipelines that are directly used in the production of hazardous liquids. See June 12, 1994, (56 FR 26923) (stating in preamble to 1991 final rule that “the exception is limited to lines downstream of where carbon dioxide is delivered to a production facility in the vicinity of a well site, rather than excepting all the CO2 lines in the broad expanses of a production field.”); January 21, 1994, (59 FR 3390) (stating in preamble to June 1994 that agency adopted amendment “to clarify that the exception covers pipelines used in the injection of carbon dioxide for oil recovery operations.”). Congress has indicated that such facilities should not be subject to federal regulation, and none of the commenters supported a repeal or modification of this exception. Accordingly, PHMSA is not proposing to repeal or modify § 195.1(b)(10).
In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for offshore pipelines in state waters.
TransCanada Keystone, an industry commenter, and the trade associations, API-AOPL, LMOGA and TxOGA, stated the current exception should not be changed. API-AOPL pointed out that PHMSA's jurisdiction lies only with the transportation of hazardous liquids, not hydrocarbon production areas of offshore operations. API-AOPL further stated that changing the state waters exception would unnecessarily add a duplicative layer of federal regulation.
The citizens' groups, TWS and AKW, supported removal of this exemption and increased enforcement in state waters. Likewise, among the government/municipality comments, NSB indicated that the regulations need to be expanded to include lines in offshore state waters. NSB expressed concerns with lack of state enforcement, high corrosion potential, and the sensitivity of the location of the offshore lines, such as those in the Beaufort and Chukchi Seas.
The prohibitions of the Pipeline Safety Act of 2011 do not affect PHMSA's authority to ensure the safety of offshore gathering lines under other statutory provisions, including if such a line is hazardous to life, property, or the environment (49 U.S.C. 60112)). PHMSA also notes that the generally-applicable limitation in section 60101(a)(22) of the Pipeline Safety Laws only applies to “onshore production . . . facilities,” and that the states may regulate such intrastate facilities (see
Congress has indicated that additional federal safety standards may be warranted for offshore gathering lines. First, we would note that this does not include offshore production pipelines. Section 195.1(b)(5) states that part 195 does not apply to the: Transportation of hazardous liquid or carbon dioxide in an offshore pipeline in state waters where the pipeline is located upstream from the outlet flange of the following farthest downstream facility; the facility where hydrocarbons or carbon dioxide are produced; or the facility where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed.
RSPA, a predecessor agency of PHMSA, adopted § 195.1(b)(5) in a June 1994 final rule June 28, 1994, (59 FR 33388). Before that time, part 195 only included an explicit exception for offshore production pipelines located on the Outer Continental Shelf. However, as explained in the preamble to the June 1994 final rule, RSPA believed that the same exception should be applied to all offshore production pipelines, including those located in state waters. Under the federal pipeline safety laws, the agency does not regulate production facilities at all. Section 21 of the Pipeline Safety Act of 2011 requires the Secretary to review the existing federal and state regulations for gathering lines and to submit a report to Congress with the results of that review. A study on these regulations, titled “Review of Existing Federal and State Regulations for Gas and Hazardous Liquid Lines,” was performed by the Oak Ridge National Laboratory and was published on May 8, 2015. The Secretary is also required, if appropriate, to issue regulations subjecting hazardous liquid gathering lines located offshore and in the inlets of the Gulf of Mexico to the same safety standards that apply to all other hazardous gathering lines. Section 21
Congress also included a provision authorizing the collection of geospatial or technical data on transportation-related flow lines in section 12 of the Pipeline Safety Act of 2011. A transportation-related flow line is defined for purposes of that provision as “a pipeline transporting oil off of the grounds of the well where it originated and across areas not owned by the producer, regardless of the extent to which the oil has been processed, if at all.” Section 12 also states that nothing in that provision “authorizes the Secretary to prescribe standards for the movement of oil through production, refining, or manufacturing facilities or through oil production flow lines located on the grounds of wells.”
In the ANPRM, PHMSA asked whether the agency should repeal or modify any of the exceptions for pipelines on the OCS.
TransCanada Keystone, an industry commenter, and the trade associations, API-AOPL, LMOGA, and TxOGA, stated that the current exceptions for pipelines on the OCS should remain unchanged. API-AOPL requested that PHMSA indicate what impact the Bureau of Ocean Energy Management, Regulation and Enforcement's (BOEMRE) recent publication regarding Safety and Environmental Management Systems (SEMS) has on transportation operators. API-AOPL expressed concern that joint jurisdiction, if created by the recent BOEMRE publication, would result in regulatory uncertainty.
NAPSR responded that the exceptions for pipelines on the OCS should not be changed as these lines are already regulated by the Department of Interior.
Section 195.1(b)(6) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide in a pipeline on the OCS where the pipeline is located upstream of the point at which operating responsibility transfers from a producting operator to a transporting operator. Section 195.1(b)(7) further provides that part 195 does not apply to a pipeline segment upstream (generally seaward) of the last valve on the last production facility on the OCS where a pipeline on the OCS is producer-operated and crosses into state waters without first connecting to a transporting operator's facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. A producing operator of a segment falling within this exception may petition the Administrator, under § 190.9 of this chapter, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance. These exceptions are designed to ensure that a single federal agency is responsible for regulating the safety of any given pipeline segment on the OCS (
None of the commenters supported the repeal or modification of § 195.1(b)(6) or (7). Accordingly, PHMSA is not proposing to take any further action with respect to these two provisions. It should also be noted that PHMSA is not responsible for administering another federal agency's statutes or regulations.
In the ANPRM, PHMSA asked for comment on whether the agency should expand the extent to which part 195 applies to breakout tanks.
PHMSA received several comments on whether the agency should expand the extent to which part 195 applies to breakout tanks. API-AOPL, supported by the industry commenter, TransCanada Keystone, and the trade associations, LMOGA and TxOGA, stated that the current definition is appropriate, and that PHMSA should review its current MOU with the Environmental Protection Agency (EPA) before making any changes to avoid duplicative regulation of these facilities. DLA, a governmental/municipal entity, echoed the comments of API-AOPL.
Conversely, NAPSR stated that if PHMSA is referring to the large number of small tanks that are technically under PHMSA's authority, but currently not regulated, then this exception should be removed.
The Pipeline Safety Laws provide PHMSA with broad authority to regulate “the storage of hazardous liquid incidental to the movement of hazardous liquid by pipeline” (49 U.S.C. 60101(a)(22)(A)). The term “breakout tank” is defined in § 195.2 to designate which aboveground tanks are regulated as breakout under part 195. See Exxon Corporation v. U.S. Department of Transportation, 978 F.Supp. 946, 949-54 (E.D. Wash. 1997).
As some of the commenters noted, PHMSA has an MOU with EPA on the treatment of breakout tanks and bulk storage tanks under the requirements of the Oil Pollution Act of 1990. Such agreements can ensure the effective regulation of facilities that are subject to regulation by more than one federal agency. As in the case of offshore pipeline facilities, those agreements can also serve as a guideline on whether a tank is transportation related or non-transportation related.
Accordingly, PHMSA will review its agreements with EPA to determine whether any modifications are necessary, but is not proposing to change the definition of a “breakout tank” in part 195 at this time.
In the ANPRM, PHMSA asked for comment on whether the agency should repeal or modify any of the other exceptions in part 195. API-AOPL, supported by several other trade associations, including LMOGA, TxOGA, OIPA, and IPAA, commented that the exception in § 195.1(b)(8) for transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant pipeline systems associated with such facilities should not be changed. API-AOPL commented that these facilities are not within the scope of the Pipeline Safety Laws, because they are not typically operated by midstream oil and gas pipeline companies operating in the pipeline transportation system. These facilities are already covered under a 1972 MOU with EPA and do not require further duplicative regulation.
API-AOPL commented that the exception in § 195.1(b)(9) for piping located on the grounds of a materials
The citizens' groups NRDC and PST indicated that PHMSA should establish additional standards for diluted bitumen. Both groups suggested PHMSA establish additional regulations for that commodity due to the high temperatures and pressures at which the lines that carry it operate.
Both regulatory associations, NAPSR and MAWUC, commented on other exemptions or limitations of the pipeline safety regulations. NAPSR indicated that the exemptions for pipelines under 1-mile long that serve refining, manufacturing, or terminal facilities should be eliminated for ethanol pipelines. NAPSR also requested that PHMSA verify that intrastate lines carrying other hazardous liquids, such as sulfuric acid, are regulated by the states. MAWUC indicated that there should be no regulatory exceptions in HCA segments, because these areas must be treated with the highest degree of both prevention and emergency remediation measures.
Among government and municipality commenters, NSB stated that § 195.1 should be amended to include regulation of all onshore pipelines and offshore pipelines in areas of the North Slope. NSB suggests regulation should occur where the consequences of a hazardous liquid pipeline failure could adversely impact: (1) An endangered, threatened or depleted species; (2) subsistence resources and subsistence use areas; (3) a drinking water supply; (4) cultural, archeological, and historical resources; (5) navigable waterways (including waterways navigated by rural residents for the purposes of recreation, commerce, and subsistence use); (6) recreational use areas; or (7) the functioning of other regulated facilities. Regulation of all high pressure, large diameter (6-inch and greater) onshore pipelines and all offshore pipelines should start at the wellhead.
One citizen commented that the river and coastline routes in the Arctic and sub-Arctic are particularly of concern because of the rapid change in permafrost, as well as high rate of coastal erosion, which greatly increase the environmental and human impacts of hazardous liquid spills.
Section 195.1(b)(8) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant piping systems associated with such facilities. That exception is based on section 60101(a)(22) of the Pipeline Safety Laws, which exempts the movement of hazardous liquid through onshore production, refining, or manufacturing facilities; or storage or in-plant piping systems associated with onshore production, refining, or manufacturing facilities. Accordingly, PHMSA agrees with the commenters that the exception in § 195.1(b)(8) should not be changed.
With respect to the terminal exemption in § 195.1(b)(9)(ii), it should first be noted that the term “Pipeline or pipeline system” is defined in § 195.2 as “all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks.” The term “Pipeline facility” is defined in § 195.2 as “new and existing pipe, rights-of-way and any equipment, facility, or building used in the transportation of hazardous liquids or carbon dioxide.” Under 49 U.S.C. 60101(a)(22), “transporting hazardous liquid” includes “the storage of hazardous liquid incidental to the movement of hazardous liquid by pipeline.”
Section 195.1(b)(9) states that part 195 does not apply to the transportation of hazardous liquid or carbon dioxide by vessel, aircraft, tank truck, tank car, or other non-pipeline mode of transportation or through facilities located on the grounds of a materials transportation terminal if the facilities are used exclusively to transfer hazardous liquid or carbon dioxide between non-pipeline modes of transportation or between a non-pipeline mode and a pipeline. These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b).
One of PHMSA's predecessors, the Materials Transportation Bureau (MTB), adopted the original version of that exception in a July 1981 final rule July 27, 1981, (46 FR 38357). In excepting the “[t]ransportation of a hazardous liquid by vessel, aircraft, tank truck, tank car, or other vehicle or terminal facilities used exclusively to transfer hazardous liquids between such modes of transportation,” MTB stated that: [Its] authority to establish minimum Federal hazardous liquid pipeline safety standards under the [Hazardous Liquid Pipeline Safety Act (HLPSA) of 1979] extends to “the movement of hazardous liquids by pipeline, or their storage incidental to such movement.” The Senate report that accompanied the HLPSA states that, “It is not intended that authority over storage facilities extend to storage in marine vessels or storage other than those which are incidental to pipeline transportation.” (Sen. Rpt. 96-182, 1st Sess., 96th Cong. (1979), p. 18.) Earlier laws had vested DOT with extensive authority to prescribe safety standards governing the movement of hazardous liquids in seagoing vessels, barges, rail cars, trucks or aircraft and storage incidental to those forms of transportation. From the words of the new HLPSA and the related Senate report language, it is clear that Congress did not want to duplicate or overlap any of those earlier laws. Thus, HLPSA regulatory authority over storage does not extend to any form of transportation other than pipeline or to any storage or terminal facilities that are used exclusively for transfer of hazardous liquids in or between any of the other forms of transportation unless that storage or terminal facility is also “incidental” to a pipeline which is subject to the HLPSA. These storage and terminal facilities are expressly excluded from the coverage of part 195 July 27, 1981, (46 FR 38358). RSPA modified that exception in the final rule June 28, 1994, (59 FR 33388).
RSPA, however, continued to maintain the exclusion for the transportation of hazardous liquids or carbon dioxide by non-pipeline modes, and added a more detailed exclusion for transfer piping located on the grounds of a materials transportation terminal.
The regulatory history demonstrates that the exception in § 195.1(b)(9) is designed to exclude piping used in transfers to non-pipeline modes of transportation and the facilities and piping at terminals that are used exclusively for such transfers. The provision is drafted to ensure that any piping that is not used exclusively to transfer product between non-pipeline modes or transportation between a non-pipeline mode and a pipeline and facilities are subject to regulation by PHMSA. None of the commenters argued in favor of changing the exception, and there is no information to suggest that such action is necessary at this time. Accordingly, PHMSA is not
With regard to the remaining comments, section 16 of the Pipeline Safety Act of 2011 requires the Secretary to perform a comprehensive review of whether the requirements in part 195 are sufficient to ensure the safety of pipelines that transport diluted bitumen (dilbit) and to provide Congress with a report on the results of that review. That review, titled “Effects of Diluted Bitumen on Crude Oil Transmission Pipelines,” was performed by the National Academy of Sciences and was published in 2013. The review found there were no causes of pipeline failure unique to the transportation of diluted bitumen, or evidence of chemical or physical properties of diluted bitumen shipments that are outside the range of other crude oil shipments, or any other aspect of diluted bitumen's transportation by pipeline that would make it more likely than other crude oils to cause releases.
Multiproduct petroleum pipelines transporting ethanol blends of up to 95% are currently regulated by PHMSA under part 195 and no major ethanol spills have occurred on these pipelines. PHMSA is performing additional research into the technical issues associated with the transportation of ethanol by pipeline and will use that information to determine whether such transportation should be subject to any additional safety requirements in the future. This NPRM proposes to conform part 195 with 49 U.S.C. 60101(a)(4) making the transportation by pipeline of any biofuel that is flammable, toxic, corrosive, or would be harmful to the environment if released in significant quantities, subject to part 195.
The requirements for HCA's are addressed in another portion of this document. As noted above, PHMSA is proposing to extend the federal reporting requirements to all hazardous liquid gathering lines (whether onshore, offshore, regulated, or unregulated).
In conclusion, PHMSA will not be proposing to change or eliminate any other regulatory exceptions at this time. The exception for carbon dioxide pipelines is limited in scope and only applies to production facilities. Although breakout tanks are defined in a way that limits the application of part 195, these certain storage tanks may also be subject to regulation by EPA. PHMSA continues to study the scope of the gathering line exemptions, but is not proposing to modify these or any other exemption. At present, nothing indicates that any of the other exceptions should be modified as part of this rulemaking proceeding, or that the issuance of regulations for underground storage facilities is necessary.
The definition of a pipeline facility in part 195 includes “any equipment, facility, or building used in the transportation of hazardous liquids . . .” and, as already noted above, includes storage terminals. While surface piping in storage fields located at midstream terminal facilities falls within this definition, part 195 does not contain comprehensive safety standards for the “downhole” underground hazardous liquid storage caverns. In addition, surface piping at storage fields located either at the production facility where a pipeline originates or a destination/consumption facility where a pipeline terminates would generally not be considered part of the transportation and, therefore, not be regulated by PHMSA in the manner that such piping located on the grounds of the midstream terminal would. RSPA provided an explanation in a July 1997 advisory bulletin June 2, 1997, (62 FR 37118) which the agency issued in response to a NTSB recommendation on the regulation of underground storage caverns (P-93-9). RSPA noted in that advisory bulletin that a recent report indicated that state regulations applied in some form to significant percentages of these facilities, and that API had developed a set of comprehensive guidelines for the underground storage of liquid hydrocarbons. As result of these state regulations, the API guidelines, and “the varying and diverse geology and hydrology of the many sites” RSPA stated that agency had “decided that generally applicable federal standards may not be appropriate for underground storage facilities.” June 2, 1997, (62 FR 37118) RSPA further stated it would be “encouraging state action and voluntary industry action as a way to assure underground storage safety instead of proposing additional federal regulations.”
PHMSA requested comment on the promulgation of new or additional safety standards for underground hazardous liquid storage. The industry commenter, TransCanada Keystone, supported the comments of API-AOPL, as did the trade associations LMOGA and TxOGA. API-AOPL stated that the current exclusion of the underground cavern is appropriate as they are already regulated by the states. API-AOPL indicated that the states are better suited to regulate these facilities because of their knowledge of these facilities and locations.
One government/municipality, DLA, commented that there was no need for new regulations for underground hazardous liquid storage facilities. DLA maintains that these facilities are currently regulated for purposes of the Clean Air Act under both 40 CFR parts 112 and 280 by the EPA.
None of the commenters supported the issuance of additional regulations for underground hazardous liquid storage caverns, and there is no information suggesting that such action is necessary at this time. Therefore, PHMSA is not proposing to issue any new regulations for underground storage of hazardous liquids in this proceeding.
PHMSA received comments from industry, trade associations, one government/municipality, and one regulatory association responding to the question on the order of the actions PHMSA should take to best protect the public, property, or the environment. API-AOPL, supported by TransCanada Keystone and the trade associations, OIPA, TxOGA, and LMOGA, indicated that PHMSA's actions should be risk-based. Similarly, NAPSR had no recommendation on the order, but suggested that it be based on risk.
The government/municipality NSB requested that PHMSA place a high priority on the repeal of regulatory exceptions for gathering of hazardous liquids in rural areas, offshore pipelines in state waters, and producer-operated lines on the OCS. NSB stated that unregulated rural pipelines are located in Unusually Sensitive Areas (USAs) of the NSB. These pipelines cross sensitive arctic tundra vegetation and impact areas used by endangered species. As North Slope development continues to expand to the west, east, and south,
PHMSA is proposing to repeal the exception for gravity lines and to apply the reporting requirements in part 195 to all gathering lines.
In the ANPRM, PHMSA asked for public comment on whether to modify the requirements in part 195 for HCAs. Specifically, PHMSA asked whether:
• The criteria for identifying HCAs should be changed to incorporate additional pipeline mileage or better reflect risk;
• All navigable waterways should be included within the definition of an HCA;
• The process for making HCA determinations on pipeline ROWs can be improved;
• The public and state and local governments should be more involved in making HCA determinations;
• Additional safety requirements should be developed for areas outside of HCAs; and
• Major road and railway crossings should be included within the definition of an HCA.
As discussed in detail later in the Background and NPRM Proposals section, PHMSA is proposing to adopt additional safety standards for pipelines that are located outside of areas that could affect an HCA. These measures will increase the safety of all of the nation's pipelines without necessitating any change to the HCA definition; therefore, PHMSA is not taking any further action on that proposal at this time.
In the ANPRM, PHMSA asked whether the current criteria for identifying HCAs should be modified to incorporate additional pipeline mileage.
TransCanada Keystone recommended that PHMSA further define the meaning of an HCA, and that the agency provide greater clarity with respect to the HCA classification, including the magnitude of impacts that differentiate HCAs from other areas.
API-AOPL, supported by the trade associations, TxOGA and LMOGA, and an industry commenter, TransCanada Keystone, stated that the current criteria should not be changed. API-AOPL stated that PHMSA should serve a clearinghouse function by displaying HCA information on the NPMS, with updates every 10 years based on census information. API-AOPL further noted that “other populated areas” includes Census-delineated areas, like Metropolitan Statistical Areas (MSA) and Consolidated Metropolitan Statistical Areas, which are not densely populated, and that the current HCA criteria are thus conservative. API-AOPL also stated that the current ability of operators to demonstrate why segments of pipeline could not affect an HCA should be retained.
The trade associations, OIPA and TPA, suggested that more data is needed to make a decision on HCA definition expansion, and that any changes would likely impact small operators.
Among citizens' groups, PST favored expanding the IM requirements to all hazardous liquid lines, with initial inspections required within 5 years of identification. PST stated that using census data to designate high population and other population areas is arbitrary and not necessarily a predictor of risk. Noting that the public could not fully comment because HCA boundaries are not publicly available (for security reasons); PST stated that the definition of HCA should be expanded to include national parks, monuments, recreation areas, and national forests. PST also pointed to the recent trend in extreme accidents in HCAs.
Two other citizens' groups, AKW and NRDC, commented. AKW requested that the criteria be changed. NRDC indicated that PHMSA should have a broader definition of HCAs, particularly with respect to ecological resources and drinking water criterion.
NAPSR commented that the current criteria are generally adequate, but that other threats and risks could be considered, including petroleum product supply loss, leaks that could affect private wells, and impacts to major infrastructure.
NSB favored an expansion of HCAs to include pipelines located in subsistence areas, cultural resources, archeological, historical, and recreational areas of significance and offshore.
Congress recently directed the Secretary to prepare a report on whether the IM requirements should be extended to pipelines outside of areas that could affect HCAs. The Secretary is prohibited from issuing any final regulations that would expand those requirements during a subsequent Congressional review period, unless those regulations are necessary to address a condition posing a risk to public safety, property, or the environment, or an imminent hazard. PHMSA is preparing the Secretary's report to Congress on the need to expand the IM requirements and is not proposing to change the definition of an HCA to incorporate additional pipeline mileage at this time.
PHMSA is, however, proposing to adopt additional safety standards for pipelines that are not covered under the IM program requirements. The proposals are detailed later in this NPRM under the Background and NPRM proposals section.
PHMSA is aware of its obligation to consider other locations near pipeline ROWs in defining USAs, including “critical wetlands, riverine or estuarine systems, national parks, wilderness areas, wildlife preservation areas or refuges, wild and scenic rivers, or critical habitat areas for threatened and endangered species.” However, PHMSA is not proposing to make any of these areas USAs in light of the new requirements that are being proposed for non-IM pipelines. PHMSA will be considering whether to include these locations in the HCA definition in performing the evaluation required under section 5 of the Pipeline Safety Act of 2011 and will comply with the applicable provisions of that legislation before taking any final regulatory action to adopt the proposed requirements for non-IM pipelines.
PHMSA asked whether the criteria for identifying HCAs should be changed to better reflect risk.
TransCanada Keystone's comment focused specifically on the classification of groundwater USAs in § 195.6, stating that groundwater HCA buffers should not be expanded, and that the existing criteria, which identify community water intakes where contamination has the potential to cause greater impacts compared to other areas, are sufficient.
API-AOPL stated that there are various risk factors applicable to HCA classifications and that the current definition should not be changed. API-AOPL recommended that buffer zones be used as an acceptable alternative to the more detailed “could affect” analysis for new, expanded, or modified HCAs. API-AOPL also suggested that operators should retain the ability, with technical justification, to determine whether a pipeline can actually impact an HCA. TransCanada Keystone, LMOGA, and TxOGA endorsed API-AOPL's comments. TPA, the other trade association commenter, mentioned that
A number of citizens' groups commented on this issue. NRDC, AKW, and TWS indicated the HCA definition needs to be broadened to reflect risk and to include entire pipelines in some cases. NRDC stated that the threshold for a populated area should be lowered, and that the definition of populated areas and USA should be improved. NRDC commented that the current HCA definition provides limited protection to threatened or endangered species. NRDC also recommended strengthening the USA definition to protect more migratory bird areas and national landmarks, including national parks, wild and scenic rivers, estuaries, wilderness areas, wildlife refuges, and drinking water sources, including private wells and open source aquifers. TWS and AKW proposed to revise the HCA criteria to include all transportation infrastructure, public lands, waterways, wetlands, and cultural, historic, archeological, and recreation sites, including subsistence areas.
NAPSR stated that the current HCA definition should not be changed, but that PHMSA should consider incorporating others threats and risks, including supply interruptions and small leaks that could affect private wells.
NSB favored changing the existing HCA definition. NSB stated that USAs should include subsistence, cultural, archeological, historical, and recreational areas of significance within the NSB and offshore waters of the Beaufort and Chukchi Seas. NSB suggested a formal process for nominating areas that should be afforded HCA status, and that the NPMS data should be updated.
Both MAWUC and DLA indicated the definition could be modified to better reflect risk. MAWUC suggested a tiered, prioritized system with enforceable criteria that are appropriate for the risk to water supplies. DLA stated that higher risk locations should be protected instead of simply creating more HCAs.
PHMSA is not proposing to make any changes to the criteria for identifying HCAs at this time. The existing Census-based approach for determining high population and other populated areas ensures uniformity and provides an adequate margin of safety by including some less densely populated areas. None of the commenters offered a more effective alternative.
PHMSA recognizes that other areas of ecological, cultural, or national significance could be designated as USAs. However, PHMSA is not proposing to add any of these areas in light of the new safety standards that are being proposed for hazardous liquid pipelines that are not subject to the IM program requirements.
PHMSA does not support any of the suggested alternative approaches for identifying HCAs. The widespread use of the buffer method is not justified based on the available information, and the use of a more lenient standard in making HCA determinations would not provide adequate protection for these sensitive areas. PHMSA will revisit these conclusions in preparing the Secretary's report to Congress on expanding the IM program for hazardous liquid pipelines.
The ANPRM posed the question of expansion of the definition of HCAs beyond commercially navigable waterways.
Several trade associations, API-AOPL, OIPA, and IPAA, and one industry representative, TransCanada Keystone, opposed expanding the HCA definition beyond commercially navigable waterways. These commenters stated that the vast majority of surface waters are already covered under the present criteria. TPA stated that adopting a navigable waters standard would make every creek an HCA, resulting in a significant increase in the burden associated with implementing IM requirements.
Two citizens' groups commented on the phrase “commercially navigable.” PST also recommended defining HCA to include all “waters of the United States,” provided PHMSA did not adopt its suggestion to apply IM requirements to all regulated pipelines. NRDC proposed to amend the term “commercially navigable waterways” to include other bodies of water that are not necessarily navigable, such as lakes, streams, and wetlands.
Two government/municipalities commented on the commercial limitation on navigable waterways. DLA, a government/municipality, echoed the comments of the trade associations and TransCanada Keystone previously mentioned. NSB requested PHMSA change commercially navigable to “navigable waters” or “waters of the U.S.” to encompass more environmentally-sensitive areas.
Section 195.450 states that an HCA includes any “waterway where a substantial likelihood of commercial navigation exists.” RSPA first proposed to include commercially navigable waterways as HCAs in the April 2000 NPRM that contained the original IM requirements for hazardous liquid pipelines April 24, 2000, (65 FR 21695). RSPA stated that it “[wa]s including commercially navigable waterways in the proposed [HCA] definition[,] [b]ecause these waterways are critical to interstate and foreign commerce and supply vital resources to many American communities, are a major means of commercial transportation, and are a part of a national defense system, a pipeline release in these areas could have significant impacts.” April 24, 2000, (65 FR 21700).
RSPA adopted the HCA definition as proposed in the NPRM in the final rule December 1, 2000, (65 FR 75378). In the preamble to that final rule, RSPA stated that it had received the following comments on its proposal to include commercially navigable waterways in the HCA definition:
API and liquid operators questioned the inclusion of commercially navigable waterways into the HCA's definition. API pointed out that Congress required OPS to identify hazardous liquid pipelines that cross waters where a substantial likelihood of commercial navigation exists and once identified, issue standards, if necessary, requiring periodic inspection of the pipelines in these areas. API said that OPS had not determined the necessity for including these waterways in areas that trigger additional integrity protections. BP Amoco said the rule should be limited to protection of public safety, rather than commercial interests. Enbridge and Lakehead also questioned why waterways that are not otherwise environmentally sensitive should be included for protection.
EPA Region III said that we should also consider recreational and waterways other than those for commercial use. Environmental Defense, Batten, City of Austin and other[s] commented that we should consider all navigable waterways as HCA's, because of the environmental consequences a hazardous liquid release could have on such waters. December 1, 2000, (65 FR 75390).
RSPA provided the following response to those comments:
“Our inclusion of commercially navigable waterways for public safety and secondary reasons is not based on the ecological sensitivity of these
For these reasons, RSPA defined HCAs in § 195.450 to include commercially navigable waterways.
Thus, the Pipeline Safety Laws do not necessarily limit the definition of an HCA to commercially navigable waterways. RSPA relied on several statutes in promulgating the IM requirements for hazardous liquid pipelines, including the mandates that required the Secretary to establish criteria for identifying pipelines in high density population and environmentally sensitive areas (49 U.S.C. 60109(a)(1)) and to promulgate standards for ensuring the periodic inspection of these lines (49 U.S.C. 60102(f)(2)). Nothing in these provisions or the Pipeline Safety Act of 2011 prohibits PHSMA from using its general rulemaking authority to apply the hazardous liquid pipeline IM regulations to waterways that are not used for commercial navigation. Other kinds of waterways are also referenced in the statutory criteria that must be considered in defining USAs.
PHMSA will be considering the expansion of current HCA or the extension of critical IM requirements to non-HCAs-when completing the Secretary's report to Congress on the need to expand the IM requirement under section 5 of the Pipeline Safety Act of 2011. In the meantime, PHMSA is not proposing to include any additional waterways in the HCA definition.
PHMSA is, however, proposing to adopt other regulations that will increase the safety of our nation's waterways. One such proposal is to require leak detection systems for pipelines in all locations, that operators perform periodic assessments of pipelines not already covered under the IM program requirements, and that new pipeline repair criteria be applied to anomalous conditions discovered in all areas. Another proposal is to require operators to inspect their pipelines in areas affected by extreme weather, natural disasters, and other similar events (
In regard to seismic events and earthquakes, in determining whether a pipeline has potentially been affected and needs inspection, operators should consider relevant factors such as magnitude of the earthquake, distance from the epicenter, and pipeline characteristics and history. PHMSA recognizes that after considering these factors, operators may determine that smaller seismic events do not have the potential to affect their pipelines. Based on available studies, however, earthquakes over 6.0 in magnitude can potentially damage pipelines and operators would be required to inspect these pipelines.
PHMSA requested comment on whether the operator's process for making HCA determinations should be modified, including by having greater involvement by the public and state and local governments.
PHMSA received comments from industry, trade associations, and one regulatory association. API-AOPL supported the existing process for identifying HCAs and suggested that any input from local communities should be through the regulating agency, rather than pipeline operators. OPIA and IPAA noted that a consistent and reliable approach is needed to prevent variations that would result in unnecessary confusion.
The trade associations, TxOGA, LMOGA, API-AOPL, supported by TransCanada Keystone, indicated that operators perform geographic overlay of their pipeline systems with PHMSA-determined HCAs. Operators also utilize the “could affect” analysis, which typically considers technical assessments using dispersion models. Through the process of HCA evaluation, operators are sometimes able to determine, with technical justification, that their assets are not capable of impacting an HCA.
NAPSR indicated that PHMSA could consider adding minimum time intervals for operators to review HCA identifications, including a shorter time interval if a pipeline is routed through high population areas. NAPSR also stated that there are areas where private wells have been extremely affected by small leaks that go undetected for years, that this is especially true in areas of sandy soil where leaks do not necessarily bubble up to the surface, and that there should be some consideration to address these “seepers” that have very large total leak volume over time.
On the matter of greater public participation, TransCanada Keystone suggested that PHMSA collect data from the states and provide updated HCA information for operator use. The trade associations, LMOGA, TxOGA and API-AOPL, supported by TransCanada Keystone, recommended that additional local involvement be routed through the regulating agency, such as PHMSA. TPA, in contrast, stated that there should be no requirement for public involvement. OIPA and IPAA held that a consistent and reliable approach is needed for the issue of public involvement.
Among the citizens' groups, NRDC supported additional public involvement. Several commenters, including NRDC, PST, and TWS, recommended that the NPMS be revised to display all HCAs so that the public can be better informed.
One regulatory association, NAPSR, suggested that the public be allowed to comment. NAPSR recognized that PHMSA has a process in place for HCA selection that can be enhanced if the public is allowed to provide input. NAPSR stated that the general public and local communities often recognize changes in areas near pipelines before operators.
Government and municipal commenters supported local involvement in the HCA determination process. MAWUC commented that it is important that local communities and water suppliers play a role in preventing and minimizing pipeline failures, including HCA identification. DLA also supported additional public involvement. NSB recommended that state and local governments, as well as local tribes, villages, and the Alaskan Eskimo Whaling Commission, have a role in making HCA determinations.
Congress included new requirements for promoting public education and awareness in section 6 of the Pipeline Safety Act of 2011. Specifically, that provision requires PHMSA (1) to maintain, and update on a biennial basis, a map of designated HCAs in the NPMS; (2) to establish a program that promotes greater awareness of the existence of the NPMS to state and local emergency responders and other interested parties, to include the issuance of guidance on using the NPMS to locate pipelines in communities and local jurisdictions; and (3) to issue additional guidance to owners and operators of pipeline facilities on the importance of providing system-specific information to emergency response agencies. PHMSA believes that such actions will address many of the concerns raised by the commenters.
PHMSA inquired as to whether additional safety measures should be developed for areas outside of HCAs.
PHMSA received comments from three trade associations and one regulatory association. TransCanada Keystone, TxOGA, API-AOPL, and LMOGA indicated that no new requirements are necessary for areas outside of HCAs. The regulatory association, NAPSR, remarked that operators should be precluded from turning off in-line inspection sensors outside of an HCA when performing an integrity assessment under the IM regulations.
PHMSA agrees with the NAPSR comment and has likewise found that some operators do turn off inspection tools outside of HCAs. Therefore, PHMSA is proposing to require that operators perform periodic assessments of pipelines that are not already covered under the IM program requirements in § 195.452. Promulgation of such a requirement will ensure that pipeline operators obtain the information necessary for the prompt detection and remediation of corrosion and other deformation anomalies (
PHMSA requested comment on the need to include major road and railway crossings as HCAs.
Industry, three trade associations, three citizens' groups, one regulatory association, one government/municipality, and one citizen commented on this question.
TransCanada Keystone, supported by the trade associations, API-AOPL, TPA, TxOGA, and LMOGA, opposed including major roads and railway crossings as HCAs. The commenters offered several reasons to support that position (
Among the citizens' groups, PST stated that rail and major road crossings should be included. TWS and AKW stated that all transportation infrastructure, public lands, wetlands under the Clean Water Act (CWA), cultural, historical, archeological and recreation areas used for subsistence be included in HCAs.
NAPSR also suggested that rail and major road crossings should be included. NAPSR urged PHMSA to consider the effect of a release on electric transmission facilities, gas pipelines, and railroads if major road and rail crossings were not to be included in HCAs. NAPSR would consider the effect of a release on electric transmission facilities, gas pipelines, railroads, etc., and would treat major road and rail crossings as HCAs for highly volatile liquids (HVLs) pipelines.
The only government/municipality to comment on this question was DLA. DLA indicated that these structures should be included in HCAs.
Citizen Coyle commented that major roadways should be HCAs because these areas could be affected by pipelines carrying HVLs that would produce poisonous clouds if released.
PHMSA is not proposing to designate major road and railway crossings as HCAs, but will consider whether the pipeline IM requirements should be applied to these areas when completing the study that Congress mandated under section 5 of the Pipeline Safety Act of 2011. PHMSA notes that the pipelines at such crossings would be afforded additional protections under the other proposals made in this proceeding, including the requirements for the performance of periodic internal inspections and the use of leak detection systems.
In the ANPRM, PHMSA asked for comment on whether to modify the current requirements part 195 for leak detection equipment and emergency flow restricting devices (EFRDs). Specifically, PHMSA asked whether
• The use of leak detection equipment should be required for hazardous liquid pipelines;
• The pipeline industry has developed any practices, standards, or leak detection technologies that should be incorporated by reference;
• Any industry practices or standards adequately address the relevant safety considerations;
• State regulations for leak detection should be adopted by regulation;
• Any new leak detection requirements should vary based on the sensitivity of the affected areas;
• The pipeline industry has developed standards or practices for the performance and location of EFRDs;
• The location of EFRDs should be specified by regulation; and
• Additional research and development is needed to demonstrate the suitability of any new leak detection technologies.
As discussed below, PHMSA is considering requiring that all hazardous liquid pipelines have a system for detecting leaks and expand the use of EFRDs.
In the ANPRM, PHMSA asked for comment on whether the agency should expand the leak detection requirements.
Industry and trade associations generally supported expansion of the existing requirement in § 195.452(i)(3) to most pipelines, but opposed including more-specific requirements in the regulations. API-AOPL, TxOGA, TransCanada Keystone, and LMOGA supported extending leak detection requirements to all PHMSA-regulated pipelines, except for rural gathering lines.
Citizens' groups supported enhanced leak detection requirements. TWS and PST opposed additional reliance on the current requirements in § 195.452(i)(3), stating that this regulation includes no acceptance criteria and is virtually unenforceable. TWS further supported expanding leak detection requirements to all pipelines under PHMSA jurisdiction. NRDC indicated that leak detection requirements should be expanded to include a requirement that
The regulatory associations, DLA and MAWUC, supported expanded leak detection requirements. MAWUC suggested PHMSA require the use of leak detection equipment in all HCAs. DLA indicated that any new requirements should be delayed until better technology is available.
The government/municipality, NSB, recommended leak detection requirements be expanded to all pipelines under PHMSA regulation. NSB encouraged adoption of more stringent leak detection requirements for sensitive offshore areas of the Beaufort and Chukchi seas.
As discussed earlier in this NPRM under the Background and Proposals section, PHMSA will propose to expand the leak detection requirements for HCA and non-HCA areas.
PHMSA asked for public comment on whether any new industry standards or practices should be considered for adoption in part 195.
API-AOPL, TxOGA, LMOGA, and TransCanada Keystone all indicated that the API-AOPL standard RP1165 (SCADA), RP 1167 (Pipeline Alarm Management), and RP1168 (Control Room Management) are good standards to utilize for leak detection systems. API-AOPL also pointed out that many new technologies are being developed and existing methodologies are continuously being improved for better leak detection capability; however, many of these new technologies have not been proven in service on cross-country pipelines.
One citizens' group, NRDC, commented that new leak detection standards should address the additional demands posed by hazardous liquids. In particular, NRDC mentioned some hazardous liquids, such as diluted bitumen, have multiphase properties that can cause false alarms.
The regulatory associations, NAPSR and DLA, both commented on new industry standards and practices in leak detection. NAPSR mentioned the new technology forward-looking infrared radar (FLIR) and encouraged PHMSA to consider using such new technologies. NAPSR reported that FLIR can detect changes in temperature near a pipeline from a winter leak, even under snow, and that it can be used from aerial patrols.
DLA indicated that any leak detection standards should be third-party validated and listed by the National Work Group on Leak Detection Evaluations (NWGLDE) and that leak detection in general for large volume pipelines is not very effective at this time.
The commenters only offered three specific industry standards or practices for consideration, and two of those standards, API RP1165 (SCADA) and RP1168 (Control Room Management), are already incorporated into part 195 (
As previously discussed, PHMSA is proposing to require that operators have a means for detecting leaks on all portions of a hazardous liquid pipeline system. Consideration of FLIR and any other emerging technologies would be required in evaluating what kinds of leak detection systems are appropriate for a particular pipeline. PHMSA will also be considering whether the use of specific leak detection technologies should be required in preparing the Secretary's report to Congress on that issue.
PHMSA does not agree that third-party validation is a prerequisite to issuing new leak detection requirements for hazardous liquid pipelines. That limitation is not included in the Pipeline Safety Laws, and PHMSA does not believe that such action is necessary as a matter of administrative discretion.
PHMSA asked for public comment on whether any existing industry standards or practices for leak detection are adequate for adoption into part 195.
TransCanada Keystone, TxOGA, LMOGA and API-AOPL submitted comments indicating that the current leak detection evaluations performed as a requirement of the IM program encompass many important factors for proper leak detection. PHMSA should allow for the implementation of recent regulatory changes, including the new Control Room Management (CRM) rule, before making any changes. NAPSR commented that all pipeline operators should, at a minimum, perform a tank balance periodically to detect leakage.
NSB recommended that PHMSA adopt improved leak detection system standards and implement more stringent leak detection requirements for the sensitive offshore areas of the Beaufort and Chukchi seas. NSB stated that PHMSA should require: (1) Redundant leak detection systems for offshore pipelines; (2) All offshore pipeline leak detection systems to have the continuous capability to detect a daily discharge equal to not more than 0.5% of daily throughput within 15 minutes, and detect a pinhole leak within less than 24 hours; (3) All onshore pipeline leak detection systems to have the continuous capability to detect a daily discharge equal to not more than 1% of daily throughput within 15 minutes, and detect a pinhole leak within less than 24 hours; and (4) An initial performance test to verify leak detection accuracy upon installation and at regular intervals thereafter.
PHMSA agrees that the factors listed in § 195.452(i)(3) are an appropriate basis for determining whether hazardous liquid pipelines have an adequate leak detection system and is proposing to use those factors as the basis for the requirements that would apply in all other locations. However, a December 31, 2007, report that PHMSA prepared in response to a mandate in the Pipeline Inspection, Protection, Enforcement, and Safety Act (PIPES Act) of 2006 (Pub. L. 109-468), confirmed that some operators had IM procedures that did not require the performance of a leak detection evaluation, and others had adopted an inadequate process for performing those evaluations. Operators are reminded that any failure to comply with part 195, including the leak detection requirements in § 195.452(i)(3) and the proposed modifications to §§ 195.134 and 195.444, increases both the likelihood and severity of pipeline accidents.
PHMSA agrees that the new CRM requirements will improve the detection and mitigation of leaks on hazardous liquid pipeline systems, but does not agree that the implementation of improved leak detection requirements should be delayed solely on account of the recent issuance of those regulations. PHMSA will be monitoring the use of
Some states have established leak detection requirements for hazardous liquid pipeline systems. For example, the Alaska Department of Environmental Conservation (ADEC) has promulgated a regulation (18 AAC 75.055) that states:
(a) A crude oil transmission pipeline must be equipped with a leak detection system capable of promptly detecting a leak, including
(1) if technically feasible, the continuous capability to detect a daily discharge equal to not more than one percent of daily throughput;
(2) flow verification through an accounting method, at least once every 24 hours; and
(3) for a remote pipeline not otherwise directly accessible, weekly aerial surveillance, unless precluded by safety or weather conditions.
(b) The owner or operator of a crude oil transmission pipeline shall ensure that the incoming flow of oil can be completely stopped within one hour after detection of a discharge.
(c) If above ground oil storage tanks are present at the crude oil transmission pipeline facility, the owner or operator shall meet the applicable requirements of 18 AAC 75.065, 18 AAC 75.066, and 18 AAC 75.075.
(d) For facility oil piping connected to or associated with the main crude oil transmission pipeline the owner or operator shall meet the requirements of 18 AAC 75.080.
Operators who install online leak detection systems can also receive a reduction in the volume of crude oil that must be used in complying with Alaska's oil spill response planning requirements (18 AAC 75.436(c)(3)).
The State of Washington has also prescribed leak detection requirements for hazardous liquid pipelines (WAC 480-75-300). Those requirements, which are administered by the Washington Utilities and Transportation Commission (WUTC), state:
(1) Pipeline companies must rapidly locate leaks from their pipeline. Pipeline companies must provide leak detection under flow and no flow conditions.
(2) Leak detection systems must be capable of detecting an eight percent of maximum flow leak within fifteen minutes or less.
(3) Pipeline companies must have a leak detection procedure and a procedure for responding to alarms. The pipeline company must maintain leak detection maintenance and alarm records.
PHMSA received comments from several trade associations and one citizens' group on state requirements for leak detection systems. API-AOPL indicated that pipeline configuration and operational factors vary by geographic location, and that other variability exists, including fluid or product differences, batching, and other operational conditions. Due to these factors, any type of prescriptive approach to standards for leak detection is difficult to achieve and would be better served using a performance standard. CRAC noted that multi-phase lines are more susceptible to internal corrosion, and that state regulations do not require IM or leak detection.
NAPSR and DLA also commented. NAPSR encouraged PHMSA to allow the states to set minimum leak detection criteria for intrastate pipelines. DLA opposed development of criteria based on state requirements and suggested that new requirements be third-party validated and listed by NWGLDE.
PHMSA favors the use of performance-based safety standards and believes that the regulations adopted by ADEC and WUTC show that certain minimum threshold requirements can be established for leak detection systems. PHMSA will be considering these and other similar regulations in an evaluation of leak detection systems.
With regard to NAPSR's comment, section 60104(c) of the Pipeline Safety Laws allows states that have submitted a current certification to adopt additional or more stringent safety standards for intrastate hazardous liquid pipeline facilities, so long as those requirements are compatible with the minimum federal safety standards. PHMSA has prescribed mandatory leak detection requirements for hazardous liquid pipelines that could affect HCAs and is proposing to make those requirements applicable to all pipelines subject to part 195. States that have submitted a current certification can establish additional or more stringent leak detection standards for intrastate hazardous liquid pipeline facilities, subject to the statutory compatibility requirement.
PHMSA does not agree that third-party validation is a prerequisite to issuing new leak detection requirements for hazardous liquid pipelines. That limitation is not included in the Pipeline Safety Laws, and PHMSA does not believe that such action is necessary as a matter of administrative discretion.
Section 195.452(i)(3) contains a mandatory leak detection requirement for hazardous liquid pipelines that could affect an HCA. That regulation requires operators to consider several factors (
PHMSA received many comments in response to whether there should be different leak detection requirements for sensitive areas. The trade associations, TxOGA and LMOGA, supported API-AOPL's comments that most leak detection methods cannot target specific areas. API-AOPL further stated that leak detection for sensitive areas can be achieved through comprehensive risk-based evaluation, but that external monitoring is too invasive and is not yet proven or cost effective.
The regulatory associations, government/municipalities, and citizens all supported increased leak detection requirements for sensitive areas. The regulatory association, NAPSR, mentioned the use of FLIR for sensitive areas and stated that special actions beyond patrols should be required for sensitive areas. DLA indicated leak detection standards should be third-party validated. MAWUC and a citizen, Coyle, recommended requiring external leak detectors in HCAs. Coyle would also require external leak detectors for above-ground pipelines transporting highly volatile liquids. NSB encouraged PHMSA to adopt improved leak detection standards and implement more stringent requirements for sensitive areas.
PHMSA believes that the leak detection requirements in § 195.452(i)(3) can provide adequate protection for sensitive areas and is proposing to use those requirements as the basis for establishing requirements that would apply to hazardous liquid pipelines in all other locations. Under the current and proposed regulations, operators are required to consider several factors in selecting an appropriate leak detection system, including the characteristics and history of the affected pipeline, the capabilities of the available leak
The trade associations, TxOGA, LMOGA, and API-AOPL, supported by an industry commenter, TransCanada Keystone, stated that PHMSA should identify issues that might adversely affect response times, including limiting the consequences for first responder deployment and allowing for the withdrawal of erroneous leak notifications. NAPSR, the only regulatory association to comment, found that any new standards should consider detection of small leaks in HCAs, maintenance, accuracy, transient conditions, system capabilities, and alarm management.
Three government/municipalities commented on this issue. DLA stated that any standards should address sensitivity, probability of false alarms, minimum leak detection capabilities, frequency, and be based on leak detection technology. MAWUC supported more stringent reporting and repair requirements. NSB indicated that PHMSA should require redundant leak detection systems for offshore lines. NSB also indicated the technology available for leak detection systems is vastly improved and industry should bear the burden to utilize these systems.
The Pipeline Safety Laws contain a number of general factors that must be considered in prescribing new safety standards, including the reasonableness of the standard, the estimated benefits and costs, and the views and recommendations of the Technical Hazardous Liquid Pipeline Safety Standards Committee (49 U.S.C. 60102(b)). The Pipeline Safety Laws also contain specific factors that must be considered in prescribing certain safety standards, such as for smart pigs (49 U.S.C. 60102(f)) or low-stress hazardous liquid pipelines (49 U.S.C. 60102(k)).
In the case of leak detection, Congress has enacted prior statutory mandates that required the Secretary to survey and assess the need for additional safety standards. PHMSA and its predecessor agency, RSPA, complied with those mandates by producing two reports and promulgating additional safety standards for leak detection systems. Congress enacted a similar provision in section 8 of the Pipeline Safety Act of 2011, including a requirement that the Secretary submit a report to Congress that provides an analysis of the technical limitations of current leak detection systems and the practicability, safety benefits, and adverse consequence of establishing additional standards for the use of such systems.
The commenters identified several issues that should be considered in establishing new leak detection standards, including the need to minimize false alarms, to set appropriate volumetric thresholds, and to encourage the use of best available technologies.
PHMSA asked the public to comment on the availability of statistics on whether existing practices or standards on leak detection have contributed to reduced spill volumes and consequences.
One response submitted by API-AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, stated that the association was unaware of any recent statistics in regard to this topic. API-AOPL further indicated that PHMSA should allow time for recent regulatory changes to take effect on the regulated population.
PHMSA's December 2007 report on leak detection systems noted that from 1997 to 2007 “the median volume lost from hazardous liquid pipeline accidents dropped by more than half, from 200 to less than 100 barrels,” and that “the number of accidents declined by over a third.” The report attributed that positive trend to the implementation of the pipeline IM requirements in § 195.452. However, the report also indicated that all of the available leak detection technologies have strengths and weakness, that some are only suitable for use on particular pipeline systems, and that establishing safety standards would require consideration of a number of factors.
Part 195 requires that EFRDs be considered as potential mitigation measure on pipeline segments that could affect HCAs. In terms of §§ 195.450 and 195.452 the definition for check valve means a valve that permits fluid to flow freely in one direction and contains a mechanism to automatically prevent flow in the other direction. Likewise, remote control valve or RCV means any valve that is operated from a location remote from where the valve is installed. The RCV is usually operated by the supervisory control and data acquisition (SCADA) system. The linkage between the pipeline control center and the RCV may be by fiber optics, microwave, telephone lines, or satellite.
Section 195.452(i)(4) further states that if an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, consider the following factors—the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain between the pipeline segment and the high consequence area, and benefits expected by reducing the spill size.
RSPA adopted the EFRD requirements in §§ 195.450 and 195.452 in a December 2000 final rule December 1, 2000, (65 FR 75378). Part 195 does not require that EFRDs be used on pipelines outside of HCAs, but § 195.260 does require that valves be installed at certain locations.
Congress included additional requirements for the use of automatic and remote-controlled shut-off valves in section 4 of the Pipeline Safety Act of 2011. That provision requires the Secretary, if appropriate and where economically, technically, and operationally feasible, to issue regulations for the use of automatic and remote-controlled shut-off valves on transmission lines that are newly constructed or entirely replaced. The Comptroller General is also required to perform a study on the effectiveness of these valves and to provide a report to Congress within one year of the date of the enactment of that legislation. PHMSA commissioned a study titled “Studies for the Requirements of
PHMSA received comment on this issue from industry and trade associations. API-AOPL, TxOGA, LMOGA, and TransCanada Keystone reported that no industry standards currently address EFRD use, although ASME B31.4, “Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids” (2009), addresses mainline valves and requires remote operation and/or check valves in some instances. ASME B31.4 (2009) also has guidelines for mainline valves and requires remote and check valves, but is not currently incorporated by reference into part 195. Section 195.452 does require that operators identify the need for additional preventive and mitigation measures.
PHMSA is studying issues concerning the development of additional safety standards for the use of EFRDs. PHMSA will consider the industry standards mentioned by the commenters, as well as the results of the September 1996 Volpe Report, the December 2007 Leak Detection Study, and the 2012 Oak Ridge National Laboratory study, for the purposes of any future rulemaking on the topic.
PHMSA asked for comment on the adequacy of existing industry practices or standards for EFRDs.
API-AOPL, TxOGA, LMOGA, and TransCanada Keystone stated that there is no current industry standard that sets a maximum spill volume or activation timing due to the widespread variation in pipeline dynamics; therefore, it would be difficult to establish a one-size-fits-all maximum spill volume requirement. API-AOPL suggests PHMSA should focus on prevention and response rather than spill size reduction through EFRDs.
Section 195.452(i)(4) contains a requirement for the use of EFRDs on hazardous liquid pipelines that could affect an HCA. PHMSA agrees with the commenters that oil spill prevention and response are important to ensuring the safety of hazardous liquid pipelines, and believes that the appropriate use of EFRDs could be complementary to these efforts.
Part 195 requires that EFRDs be considered as potential mitigation measure on pipeline segments that could affect HCAs, but it does not specify any particular location for the use of those devices. Operators must perform a risk analysis in determining whether and where to install EFRDs for such lines. Part 195 does not require that EFRDs be used on pipelines outside of HCAs. In the ANPRM, PHMSA asked for comment on whether additional standards should be developed to specify the location for EFRDs.
PHMSA received comments from four trade associations, one industry operator, and one regulatory association regarding prescriptive location of EFRDs. API-AOPL, TransCanada Keystone, LMOGA, and TxOGA indicated PHMSA should not specify location of EFRD placement for the reasons provided in response to previous questions. TPA agreed that no general criteria beyond those in existing regulations are appropriate because decisions on EFRD placement are driven by local factors. NAPSR supported the comments of the trade associations.
PHMSA recognizes the commenters' concerns about mandating the installation of EFRDs in particular locations, but notes that other provisions in part 195 require that valves and other safety devices be installed in certain areas.
PHMSA requested comment on mandated use of EFRDs in all locations under PHMSA jurisdiction.
API-AOPL, TransCanada Keystone, LMOGA, and TxOGA indicated that a requirement to place EFRDs at predetermined locations or fixed intervals would be arbitrary, costly, and potentially counterproductive to pipeline safety. They noted that not all valves are mainline valves, and that a requirement for all valves to be remote would cause confusion. Many valves are at manned facilities. Some EFRDs are check valves, which are not amenable to remote control. API-AOPL noted that costs related to providing remote operation would vary based on proximity to power and communications, but that a December 2010 study by the Congressional Research Service estimated retrofit costs of $40K to $1.5M per valve. NAPSR agreed with the comments supplied by the trade associations and TransCanada Keystone. Finally, NSB stated EFRDs should be required on all pipelines PHMSA regulates with specific instruction on when and where EFRDs need to be utilized.
PHMSA recognizes the commenters' concerns about mandating the installation of EFRDs in all locations and plans on continuing to study this issue.
PHMSA requested comment regarding what leak detection technologies or methods require further research and development to demonstrate their efficacy.
PHMSA received no comments in response to this question.
The ANPRM asked whether PHMSA should repeal or modify the valve spacing requirements in part 195. Specifically, the ANPRM asked:
• For information on the average distance between valves;
• Whether valves are manually operated or remotely controlled;
• Whether additional standards should be adopted for evaluating valve spacing and location;
• Whether the maximum permissible distance between valves should be specified by regulation;
• Whether to adopt additional valve spacing requirements for hazardous liquid pipelines near HCAs;
• Whether additional valve spacing requirements should be adopted to protect narrower bodies of water;
• Whether all valves should be remotely controlled; and
• What the cost impact would be from requiring the installation of certain types of valves.
Part 195 contains general construction requirements for valves. Specifically, § 195.258 provides that each valve must be installed in a location that is accessible to authorized employees and protected from damage or tampering. This section further states that submerged valves located offshore or in inland navigable waters must be marked, or located by conventional survey techniques, to facilitate quick location when operation of the valve is required.
PHMSA pipeline safety regulations found in section 195.260 indicate that a valve must be installed at certain locations. The locations named include on the suction end and the discharge end of a pump station or a breakout storage tank area in a manner that permits isolation of the tank area from other facilities and on each mainline at locations along the pipeline system that will minimize damage or pollution from accidental hazardous liquid discharge, as appropriate for the terrain in open country, for offshore areas, or for populated areas. Three additional requirements for valve location in section 195.260 include each lateral takeoff from a trunk line, on each side of a water crossing that is more than 100 feet (30 meters) wide from high-water mark to high-water mark and on each side of a reservoir holding water for human consumption. The Department adopted these regulations in an October 1969 final rule October 4, 1969, (34 FR 15475).
As discussed in section 3, part 195 requires the use of EFRDs as a potential mitigation measure on pipeline segments that could affect HCAs. As also discussed in section 3, Congress included new provisions for the use of automatic and remote-controlled shut-off valves and leak detection systems in the Pipeline Safety Act of 2011.
PHMSA asked the public to provide information on the average distance between valves and whether such valves are manually operated or remotely controlled.
The commenters did not provide any data on the average distance between valves, but did provide general information on valve spacing, location, and type. The commenters further noted that ASME B31.4, a consensus industry standard, includes a minimum valve spacing requirement of 7.5 miles for liquefied petroleum gas (LPG) and anhydrous ammonia pipelines in populated areas.
Specifically, API-AOPL, LMOGA, TxOGA, and TransCanada Keystone stated that valve spacing varies, that most mainline valves are manually operated, that check valves are used in certain cases, and that some remotely controlled valves had been added as a result of the IM requirements. API-AOPL also commented that ASME B31.4 provides additional requirements for LPG and anhydrous ammonia in populated areas, including a 7.5-mile spacing requirement for valves, but noted that PHMSA had not incorporated this version of B31.4 into part 195. NAPSR stated that proper valve location is more important than distance placement.
Part 195 requires the installation of valves at certain locations, including pump stations, breakout tanks, mainlines, lateral lines, water crossings, and reservoirs. These requirements are generally directed toward achieving a particular result (
Part 195 does not prescribe whether manual or remotely controlled valves must be installed at particular locations, but does require consideration of check valves and remotely controlled valves under the EFRD requirements for pipelines that could affect an HCA. Section 4 of the Pipeline Safety Act of 2011 includes new requirements for evaluating and issuing additional regulations for the use of the automatic and remote-controlled shut-off valves.
PHMSA is not proposing to make any changes to the current valve spacing requirements at this time. A coordinated analysis will ensure that these issues are addressed in a way that maximizes the potential benefits and minimizes the potential burdens imposed by any new leak detection and valve spacing standards.
PHMSA asked for comment on the adoption of additional standards for valve spacing and location.
TransCanada Keystone, API-AOPL, TxOGA, and LMOGA stated that the standards in §§ 195.260 and 195.452 are satisfactory. NAPSR supported the comments of API-AOPL. NSB recommended that DOT adopt standards for pipeline operators to use in evaluating valve spacing and location and identifying the maximum distance between valves.
PHMSA is not proposing to adopt any additional standards for valve spacing and locations, but will be considering that issue in complying with the various mandates in the Pipeline Safety Act of 2011. PHMSA held a public meeting/workshop on valve spacing and locations on March 28, 2012. Information from this workshop was used in Oak Ridge National Laboratory's study, completed October 31, 2012, titled: “Studies for the Requirements of Automatic and Remotely Controlled Shutoff Valves on Hazardous Liquids and Natural Gas Pipelines with Respect to Public and Environmental Safety”
PHMSA asked for public comment on whether part 195 should specify the maximum permissible distance between valves.
API-AOPL, TxOGA, LMOGA, TransCanada Keystone, and TPA opposed such a requirement and stated that valve spacing should be based on conditions and terrain. NAPSR also supported this position. NSB and MAWUC recommended the DOT adopt specific valve spacing standards. MAWUC stated that the criteria for valve spacing should be developed, but that the precise location of valves should not be made publicly available.
Similarly, PHMSA is not proposing to adopt any additional standards for valve spacing at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking.
PHMSA asked for public comment on whether part 195 should contain additional requirements for valve spacing in areas near HCAs beyond what is already required in § 195.452(i)(4) for EFRDs.
NSB encouraged PHMSA to adopt additional requirements for these areas. Taking a contrary position, API-AOPL, LMOGA, TxOGA, NAPSR, and TransCanada Keystone indicated that the current requirements adequately address the need for EFRDs and allow operators to assess the specific risks on each individual pipeline that could affect an HCA.
PHMSA does not propose to make any changes to the regulations concerning the valve spacing at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking.
Section 195.260(e) requires the installation of a valve “[o]n each side of a water crossing that is more than 100 feet (30 meters) wide from high-water mark to high-water mark unless the Administrator finds in a particular case that valves are not justified.” The Department adopted that requirement in an October 1969 final rule October 4, 1969, (34 FR 15475) after adding the provision that allows the Administrator to find that the installation of a valve is not justified in specific cases. Such a finding requires the filing of a petition with the Administrator under 49 CFR 190.9.
API-AOPL, TxOGA, LMOGA, and TransCanada Keystone indicated that the current water crossing requirements are adequate, but that PHMSA could improve the regulation by allowing a risk-based approach for valve placement at water crossings and adding an exclusion for carbon dioxide pipelines.
TWS stated that PHMSA should require valves for waterways that are at least 25-feet in width and all feeder streams and creeks leading to such waterways. NSB supported the view of TWS and indicated the current 100-foot threshold for waterways should be reduced to 25 feet.
As mentioned previously, PHMSA is proposing that all pipelines be inspected after extreme weather events or natural disasters. This is a natural extension of IM and ensures continued safe operations of the pipeline after abnormal operating conditions. Past events have strongly demonstrated that inspections after these events do prevent pipeline incidents from occurring. PHMSA is also proposing to require that all hazardous liquid pipelines have leak detection systems; that pipelines in areas that could affect HCAs be capable of accommodating ILIs within 20 years, unless the basic construction of the pipeline will not permit such an accommodation; that periodic assessments be performed of pipelines that are not already receiving such assessments under the IM program requirements; and that modified repair criteria be applied to pipelines in all locations. PHMSA will comply with the applicable provisions in the Pipeline Safety Act of 2011 before adopting any of these proposals in a final rule.
PHMSA asked the public to comment on whether part 195 should include a requirement mandating the use of remotely-controlled valves in all cases.
API-AOPL, LMOGA, and TxOGA stated that PHMSA should not require remotely controlled valves in all cases. API-AOPL indicated that such a requirement would cause confusion as to which valves need to be operated manually, burden the industry with additional costs, and provide minimal safety benefits. API-AOPL submitted that the costs of retrofitting a valve to be remotely controlled varies widely from $40,000 to $1.5 million per valve as indicated in a recent report issued by the Congressional Research Service on pipeline safety and security. TPA further stated that the benefits of such requirements are dependent on local factors, and that additional requirements would add to pipeline system complexity and increase the probability of failure. Similarly, NAPSR stated that remote control valves should not be required, but that PHMSA should consider performance language for maximum response time to operate manual valves.
MAWUC indicated that PHMSA should consider requiring all valves to be remotely controlled, but that its decision should be based on an analysis of benefits and risks. NSB supported the use of remotely controlled valves in all instances. Coyle, a citizen, commented that PHMSA should promulgate regulatory language requiring remotely controlled valves for poison inhalation hazard pipelines.
PHMSA notes that a risk-assessment must be performed in developing any new safety standards for the use of remotely controlled valves, and that any such standards will only be proposed upon a reasoned determination that the benefits justify the costs.
Section 195.452(i)(4) does not require the installation of an EFRD on all pipeline segments that could affect HCAs. Rather, it states that “[i]f an operator determines that an EFRD is needed on a pipeline segment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must install the EFRD.” It also states that an operator must at least consider a list of factors in making that determination.
API-AOPL, LMOGA, TxOGA and TransCanada Keystone stated that § 192.452 already requires EFRDs to be installed to protect a HCA if the operator finds, through a risk assessment, that an HCA is threatened. MAWUC commented that EFRDs should be required if they can limit a spill. Likewise, NSB supported the use of EFRDs for HCAs.
PHMSA does not propose to make any changes to the regulations concerning the use of EFRDs at this time. PHMSA will be studying this issue and may make proposals concerning this topic in a later rulemaking.
In the ANPRM, PHMSA asked for public comment on how the agency should apply any new valve location requirements that are developed for hazardous liquid pipelines.
The trade association, API-AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, indicated that valve spacing requirements should not be changed, and that delineating new construction for any type of grandfathering purpose would be difficult and confusing. Requiring retrofitting of existing lines to meet any
The regulatory association, NAPSR, suggested that exemptions to new valve location requirements should be based on the consequence of failure. Particular attention should be paid to spills into water as even a small spill can create a large problem.
Two government/municipalities commented. MAWUC indicated that there should be no waivers for valve spacing in HCAs due to the importance and interconnectivity of water supplies. NSB recommended that any new valve locations or remote actuation regulation be applied to new pipelines or existing pipelines that are repaired.
PHMSA will continue to study valve spacing and automatic valve placement and may address these issues in a future rulemaking.
The ANPRM asked for public comment on whether to extend the IM repair criteria in § 195.452(h) to pipeline segments that are not located in HCAs. Specifically, the ANPRM asked “Whether the IM repair criteria should apply to anomalous conditions discovered in areas outside of HCAs; whether the application of the IM repair criteria to non-HCA areas should be tiered on the basis of risk; what schedule should be applied to the repair of anomalous conditions discovered in non-HCA areas; whether standards should be specified for the accuracy and tolerance of inline inspection (ILI) tools; and whether additional standards should be established for performing ILI inspections with “smart pigs”.
As discussed below, PHMSA is proposing to modify the provisions for making pipeline repairs. Additional conservatism will be incorporated into the existing IM repair criteria and an adjusted schedule for making immediate and non-immediate repairs will be established to provide greater uniformity. These criteria will also be made applicable to all pipelines, with an extended timeframe for making repairs outside of HCAs.
In the ANPRM, PHMSA asked for comment on whether the IM repair criteria should apply to anomalous conditions discovered in areas outside of HCAs.
API-AOPL, supported by TransCanada Keystone, LMOGA, and TxOGA, stated that the repair criteria in or outside of HCAs should be the same. Likewise, the citizens' groups TWS and AKW echoed the comments of API-AOPL and further recommended that a phased-in time period should be utilized. NSB commented that anomalous conditions found during inspection in non-HCA areas should trigger expedited repair times.
Section 195.452(h) specifies the actions that an operator must take to address integrity issues on hazardous liquid pipelines that could affect an HCA in the event of a leak or failure. Those actions include initiating temporary and long-term pressure reductions and evaluating and remediating certain anomalous conditions (
Section 5 of the Pipeline Safety Act of 2011 requires the Secretary to perform an evaluation to determine if the IM requirements should be extended outside of and to submit a report to Congress with the result of that review. The Secretary is authorized to collect data for purposes of completing the evaluation and report to Congress. Section 5 also prohibits the issuance of any final regulations that would expand the IM requirements during a subsequent Congressional review period, subject to a savings clause that permits such action if a condition poses a risk to public safety, property, or the environment or is an imminent hazard and the regulations in question will address that risk or imminent hazard.
PHMSA is proposing to make certain modifications to the IM repair criteria and to establish similar repair criteria for pipeline segments that are not located in HCAs. Specifically, the repair criteria in § 195.452(h) would be amended to:
• Categorize bottom-side dents with stress risers as immediate repair conditions;
• Require immediate repairs whenever the calculated burst pressure is less than 1.1 times MOP;
• Eliminate the 60-day and 180-day repair categories; and
• Establish a new, consolidated 270-day repair category.
These changes will ensure that immediate action is taken to remediate anomalies that present an imminent threat to the integrity of hazardous liquid pipelines in all locations. Many anomalies that would not qualify as immediate repairs under the current criteria will meet that requirement as a result of the additional conservatism that will be incorporated into the burst pressure calculations. The new timeframes for performing other repairs will allow operators to remediate those conditions in a timely manner while allocating resources to those areas that present a higher risk of harm to the public, property, and the environment.
In the ANPRM, PHMSA asked for comment on whether the application of the IM repair criteria to non-HCA areas should be tiered on the basis of risk.
API-AOPL, LMOGA, TPA, TxOGA, and TransCanada Keystone commented that PHMSA should not impose any sort of tiering to repair criteria because that is already inherent to the IM program. Scheduling flexibility would minimize disruption to the affected public, as well as the overall environmental impact, by preventing multiple excavation work on a given property. Requiring additional risk tiering of anomalies would not reduce safety risks to the public.
NAPSR, in contrast, commented that tiering should be utilized for repair criteria inside or outside of HCAs. NSB also indicated that risk tiering should be used. MAWUC supported risk tiering based on preselected criteria for HCAs.
As previously discussed, PHMSA is proposing to apply new repair criteria for anomalous conditions discovered on hazardous liquid pipelines that are not located in HCAs. PHMSA is also proposing to establish two timeframes for performing those repairs: immediate repair conditions and 18-month repair conditions. If adopted as proposed, these changes will ensure the prompt remediation of anomalous conditions on all hazardous liquid pipeline segments, while allowing operators to allocate
Section 195.452(h) contains the criteria for repairing dents with metal loss on hazardous liquid pipeline segments that could affect an HCA in the event of a leak or failure. PHMSA asked for comment on whether advances in ILI tool capability justified an update in the dent-with-metal-loss repair criteria.
API-AOPL, LMOGA, TxOGA, and TransCanada Keystone indicated that the anticipated update to API 1160 will contain proposals to update the dent-with-metal-loss repair criterion. API-AOPL intends to support these proposals with data resulting from analyses of member company's experience measuring and characterizing metal loss in dents.
NAPSR encouraged PHMSA not to make the current standards less stringent even for dents without metal loss, citing a recent bottom side dent less than 6 inches that failed. NAPSR recommended strengthening the repair criteria for bottom-side dents in areas of heavy traffic or near swamps/bogs or in clay soils.
As previously discussed, PHMSA is proposing to categorize bottom-side dents with stress risers as an immediate repair condition and to require immediate repairs when calculated burst pressure is less than 1.1 times MOP. These changes should ensure the prompt and effective remediation of anomalous conditions on all pipeline segments. With respect to API 1160, PHMSA will consider incorporating the 2013 edition in a future rulemaking.
PHMSA requested comment on whether to adopt an explicit standard to account for the accuracy of ILI tools when comparing ILI data with repair criteria.
API-AOPL supports PHMSA's adoption of API 1163, the “In-Line Inspection Systems Qualification Standard”. That standard includes a System Results Verification section, which describes methods to verify that the reported inspection results meet, or are within, the performance specification for the pipeline being inspected. That standard also requires that inconsistencies uncovered during the process validation be evaluated and resolved.
NAPSR supports the adoption of a standard because the IM process already is considering tool accuracy during the selection process and suggests revising the regulations to provide minimum standards of expected accuracy.
In reviewing IM inspection data, PHMSA discovered that some operators were not considering the accuracy (
Specifically, under the proposed amendment to § 195.452(c)(1)(i) and the new provisions in § 195.416, operators will be required to consider tool tolerance and other uncertainties in evaluating ILI results for all hazardous liquid pipeline segments. Tool accuracy should include excavation findings and usage of unity plots of inline tool and excavation findings. When combined with the proposed changes to the repair criteria, the proposed tool tolerance requirement will ensure the prompt detection and remediation of anomalous conditions on all hazardous liquid pipelines. With respect to API 1163, as of January 2013, PHMSA is required by section 24 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 not to incorporate any consensus standards that are not available to the public, for free, on an internet Web site. PHMSA has sought a solution to this issue and as a result, all incorporated by reference standards in the pipeline safety regulations would be available for viewing to the public for free.
In the ANPRM, PHMSA asked if additional quality control standards are needed for conducting ILIs using smart pigs, the qualification of persons interpreting ILI data, the review of ILI results, and the quality and accuracy of ILI tool performance.
API-AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that PHMSA should adopt API 1163 and American Society of Nondestructive Testing ILI PQ. These commenters stated that a certification program for analyzing ILI data would not add value to pipeline operators' IM programs, as operator experience has shown that these types of programs do not adequately reflect the highly technical nature of, and the intimate knowledge and experience of personnel practicing, IM programs. According to the commenters, there is no evidence that the current requirements and industry standards are leaving the public or environment at risk.
NAPSR indicated that if there is data to show this is an issue, PHMSA should adopt a standard. Additionally, a state could impose a more stringent standard based on prior experience. Both the NSB and MAWUC supported adoption of standards for ILI use.
As noted in the response to the previous question, PHMSA is proposing to require operators to consider tool tolerance and other uncertainties in evaluating ILI results in complying with the IM requirements of § 195.452 and the proposed assessment requirement in § 195.416. PHMSA believes that this requirement and the proposed changes to the repair criteria will ensure the prompt detection and remediation of anomalous conditions (
In the October 2010 ANPRM, PHMSA asked for public comment on whether to adopt additional safety standards for stress corrosion cracking (SCC). SCC is cracking induced from the combined influence of tensile stress and a corrosive medium. Sections 195.553 and 195.588 and Appendix C of the Hazardous Liquid Pipeline Safety Standards contain provisions for the direct assessment of SCC, but do not include comprehensive requirements for preventing, detecting, and remediating that condition.
Specifically, PHMSA asked in the ANPRM whether:
• Any existing industry standards for preventing, detecting, and remediating SCC should be incorporated by reference;
• Any data or statistics are available on the effectiveness of these industry standards;
• Any data or statistics are available on the effectiveness of SCC detection tools and methodologies;
• Any tools or methods are available for detecting SCC associated with longitudinal pipe seams;
• An SCC threat analysis should be conducted for all pipeline segments;
• Any particular integrity assessment methods should be used when SCC is a credible threat; and
• Operators should be required to perform a periodic analysis of the effectiveness of their corrosion management programs.
In the ANPRM, PHMSA asked for comment on whether the agency should incorporate any consensus industry standards for assessing SCC, including the NACE International (NACE) SP0204-2008 (formerly RP0204), Stress Corrosion Cracking (SCC) Direct Assessment Methodology.
API-AOPL, TransCanada Keystone, TxOGA, and LMOGA stated that NACE SP0204-2008 provides an effective framework for the application of direct assessment, but does not sufficiently address other assessment methods, including ILI and hydrostatic testing. These commenters were also not aware of any industry statistics that directly correlate the application of that standard to the SCC detection or failure rate. These commenters stated the most appropriate standard for SCC assessment of hazardous liquid pipelines is the soon-to-be-released version of API Standard 1160, Managing System Integrity for Hazardous Liquid Pipelines.
Another trade association, TPA, stated that “because [the NACE Standard] was just finished in 2008, PHMSA should wait at least 2-3 years more before attempting to assess the desirability of incorporating that standard into the regulations.”
One regulatory association, MAWUC, commented that PHMSA should adopt standards that address direct assessment, prevention, and remediation of SCC. The municipality/government entity, NSB, offered a similar comment.
The commenters did not indicate that NACE SP0204-2008 would address the full lifecycle of SCC safety issues. Moreover, none of the commenters identified any other industry standards that would be appropriate for adoption at this time.
PHMSA recognizes that SCC is an important safety concern, but does not believe that further action can be taken based on the information available in this proceeding. PHMSA is establishing a team of experts to study this issue and will be holding a public forum on the development of SCC standards. Once that process is complete, PHMSA will consider whether to establish new safety standards for SCC. With respect to NACE SP0204-2008 PHMSA is proposing this standard by a separate rulemaking via incorporation by reference.
PHMSA asked the public to identify any other standards and practices for the prevention, detection, assessment, and remediation of SCC.
API-AOPL, LMOGA, and TxOGA indicated that there are several good standards that address SCC, including API 1160, ASME STP-PT-011, Integrity Management of Stress Corrosion Cracking in Gas Pipeline High Consequence Areas, and the Canadian Energy Pipeline Association (CEPA) Stress Corrosion Cracking Recommended Practices (CEPA SCC RP), but acknowledged that all of these standards have weaknesses.
The trade association, CEPA, also stated that the 2008 ASME STP-PT-011 should be considered. While written for gas pipelines, CEPA stated that this standard could be adapted to hazardous liquids.
PHMSA appreciates the information provided by the commenters. PHMSA will be studying the SCC issue and will consider incorporating by reference suggested standards in future rulemakings.
CEPA is an organization that represents Canada's transmission pipeline companies. In 1997, CEPA developed its SCC Recommended Practice (RP) in response to a public inquiry by National Energy Board of Canada. In 2007, CEPA released an updated version of its SCC RP,
API-AOPL, LMOGA, TxOGA, and TransCanada Keystone commented that the CEPA SCC RP provides the most thorough overview of the various assessment techniques, but is limited to near neutral SCC in terms of causal considerations. These commenters also stated that there are no industry statistics on the application of the CEPA RP SCC. CEPA and API-AOPL both indicated that companies continue to use the CEPA SCC RP as a guideline, but that there are no statistics on its use.
PHMSA appreciates the comments provided on the use of the CEPA SCC RP and will consider that standard in its study of comprehensive safety requirements for SCC and in future rulemakings.
PHMSA requested comment as to the effectiveness of current SCC detection tools and methods.
API-AOPL, supported by LMOGA, TxOGA, and TransCanada Keystone, stated that there are no industry statistics that directly correlate the application of the CEPA RP to the SCC detection or failure rate, but that the National Energy Board of Canada has noted the effectiveness of the CEPA RP for managing SCC. API-AOPL also stated the planned revisions of API 1160 and 1163 will address the current gaps regarding SCC in the standards and recommended practices relevant to liquid pipelines. One citizens' group,
PHMSA appreciates the comments provided on the effectiveness of SCC detection tools and methods and will be considering that information in evaluating comprehensive safety requirements for SCC and consider incorporating in future rulemakings.
Section 195.1(a) lists the pipelines that are subject to the requirements in part 195, including gathering lines that cross waterways used for commercial navigation as well as certain onshore gathering lines (
Section 195.2 provides definitions for various terms used throughout part 195. On August 10, 2007, (72 FR 45002; Docket number PHMSA-2007-28136) PHMSA published a policy statement and request for comment on the transportation of ethanol, ethanol blends, and other biofuels by pipeline. PHMSA noted in the policy statement that the demand for biofuels was projected to increase in the future as a result of several federal energy policy initiatives, and that the predominant modes for transporting such commodities (
PHMSA is now proposing to modify its definition of hazardous liquid in § 195.2. Such a change would make clear that the transportation of biofuel by pipeline is subject to the requirements of 49 CFR part 195.
PHMSA is also proposing to add a new definition of “Significant Stress Corrosion Cracking.” This new definition will provide criteria for determining when a probable crack defect in a pipeline segment must be excavated and repaired.
Section 195.11 defines and establishes the requirements that are applicable to regulated rural gathering lines. PHMSA has determined that these lines should be subject to the new requirements in the NPRM for the performance of periodic pipeline assessments and pipeline remediation and for establishing leak detection systems. Consequently, the NPRM would amend § 195.11 by adding paragraphs (b)(12) and (13) to ensure that these requirements are applicable to regulated rural gathering lines.
Section 195.13 will be added which subjects gravity lines to the same reporting requirements in subpart B of part 195 as other hazardous liquid pipelines. PHMSA has determined that additional information about gravity lines is needed to fulfill its statutory obligations.
Section 195.120 contains the requirements for accommodating the passage of internal inspection devices in the design and construction of new or replaced pipelines. PHMSA has decided that, in the absence of an emergency or where the basic construction makes that accommodation impracticable, a pipeline should be designed and constructed to permit the use of ILIs. Accordingly, the NPRM would repeal the provisions in the regulation that allow operators to petition the Administrator for a finding that the ILI compatibility requirement should not apply as a result of construction-related time constraints and problems. The other provisions in § 195.120 would be re-organized without altering the existing substantive requirements.
Section 195.134 contains the design requirements for computational pipeline monitoring leak detection systems. The NPRM would restructure the existing requirements into paragraphs (a) and (b) and add a new provision in paragraph (c) to ensure that all newly constructed pipelines are designed to include leak detection systems based upon standards in section 4.2 of API 1130 or other applicable design criteria in the standard.
Section 195.401 prescribes general requirements for the operation and maintenance of hazardous liquid pipelines. PHMSA is proposing to modify the pipeline repair requirements in § 195.401(b). Paragraph (b)(1) will be modified to reference the new timeframes in § 195.422 for performing non-IM repairs. The requirements in paragraph (b)(2) for IM repairs will be retained without change. A new paragraph (b)(3) will be added, however, to clearly require operators to consider the risk to people, property, and the environment in prioritizing the remediation of any condition that could adversely affect the safe operation of a pipeline system, including those covered by the timeframes specified in §§ 195.422(d) and (e) and 195.452(h).
Extreme weather, natural disasters and other similar events can affect the safe operation of a pipeline. Accordingly, the NPRM would establish a new regulation in § 195.414 that would require operators to perform inspections after these events and to take appropriate remedial actions.
Periodic assessments, particularly with ILI tools, provide critical information about the condition of a pipeline, but are only currently required under IM requirements in §§ 195.450 through 195.452. PHMSA has determined that operators should be required to have the information that is needed to promptly detect and remediate conditions that could affect the safe operation of pipelines in all areas. Accordingly, the NPRM would establish a new regulation in § 195.416 that requires operators to perform an assessment of pipelines that are not already subject to the IM requirements at least once every 10 years. The regulation would require that these assessments be performed with an ILI tool, unless an operator demonstrates and provides 90-days prior notice that a pipeline is not capable of accommodating such a device and that an alternative method will provide a substantially equivalent understanding of its condition.
The regulation would also require that the results of these assessments be reviewed by a person qualified to determine if any conditions exist that could affect the safe operation of a pipeline; that such determinations be made promptly, but no later than 180 days after the assessment; that any unsafe conditions be remediated in accordance with the new requirements in § 195.422 of the NPRM; and that all relevant information about the pipeline be considering in complying with the requirements of § 195.416.
Section 195.422 contains the requirements for performing pipeline repairs. PHMSA has determined that new criteria should be established for remediating conditions that affect the safe operation of a pipeline. The NPRM would add a new paragraph (a) specifying that the provisions in the regulation are applicable to pipelines that are not subject to the IM requirements in § 195.452 (
Section 195.444 contains the operation and maintenance requirements for Computational Pipeline Monitoring leak detection systems. PHMSA is proposing that all pipelines should have leak detection systems. Therefore, the NPRM would reorganize the existing requirements of the regulation into paragraphs (a) and (c), and add a new general provision in paragraph (b) that would require operators to have leak detection systems on all pipelines and to consider certain factors in determining what kind of system is necessary to protect the public, property, and the environment.
Section 195.452 contains the IM requirements for hazardous liquid pipelines that could affect a HCA in the event of a leak or failure. The NPRM would clarify the applicability of the deadlines in paragraph (b) for the development of a written program for new pipelines, regulated rural gathering lines, and low-stress pipelines in rural areas. Paragraph (c)(1)(i)(A) would also be amended to ensure that operators consider uncertainty in tool tolerance in reviewing the results of ILI assessments. Paragraph (d) would be amended to eliminate obsolete deadlines for performing baseline assessments and to clarify the requirements for newly-identified HCAs. Paragraph (e)(1)(vii) is amended to include local environmental factors that might affect pipeline integrity. Paragraph (g) would be amended to expand upon the factors and criteria that operators must consider in performing the information analysis that is required in periodically evaluating the integrity of covered pipeline segments. Paragraph (h)(1) would also be amended by modifying the criteria, and establishing a new, consolidated timeframe, for performing immediate and 270-day pipeline repairs based on the information obtained as a result of ILI assessments or through an information analysis of a covered segment.
PHMSA is also proposing to amend the existing “discovery of condition” language in the pipeline safety regulations. The revised § 195.452(h)(2) will require, in cases where a determination about pipeline threats has not been obtained within 180 days following the date of inspection, that pipeline operators must notify PHMSA and provide an expected date when adequate information will become available. Paragraphs 195.452(h)(4)(i)(E) and (F) are also added to address issues of significant stress corrosion cracking and selective seam corrosion.
PHMSA proposes further changes to § 195.452. These changes include paragraph (j) which would be amended to establish a new provision for verifying the risk factors used in identifying covered segments on at least an annual basis, not to exceed 15 months. A new paragraph (n) would also be added to require that all pipelines in areas that could affect an HCA be made capable of accommodating ILI tools within 20 years, unless the basic construction of a pipeline will not permit that accommodation or the existence of an emergency renders such an accommodation impracticable. Paragraph (n) would also require that pipelines in newly-identified HCAs after the 20-year period be made capable of accommodating ILIs within five years of the date of identification or before the performance of the baseline assessment, whichever is sooner. Finally, an explicit reference to seismicity will be added to factors that must be considered in establishing assessment schedules under paragraph (e), for performing information analyses under paragraph (g), and for implementing preventive and mitigative measures under paragraph (i).
Executive Orders 12866 and 13563 require agencies to regulate in the “most cost-effective manner,” to make a “reasoned determination that the benefits of the intended regulation justify its costs,” and to develop regulations that “impose the least burden on society.” This action has been determined to be significant under Executive Order 12866 and the Department of Transportation's Regulatory Policies and Procedures. It has been reviewed by the Office of Management and Budget in accordance with Executive Order 13563 (Improving Regulation and Regulatory Review) and Executive Order 12866 (Regulatory Planning and Review) and is consistent with the requirements in both orders.
In the regulatory analysis, we discuss the alternatives to the proposed requirements and, where possible, provide estimates of the benefits and costs for specific regulatory requirements in the eight areas. The regulatory analysis provides PHMSA's best estimate of the impact of the separate requirements. The chart below summarizes the cost/benefit analysis:
Overall, factors such as increased safety, public confidence that all pipelines are regulated, quicker discovery of leaks and mitigation of environmental damages, and better risk management are expected to yield benefits that are in excess of the cost. PHMSA seeks comment on the Preliminary Regulatory Evaluation, its approach, and the accuracy of its estimates of costs and benefits. A copy of the Preliminary Regulatory evaluation has been placed in the docket.
This NPRM has been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). This NPRM does not propose any regulation that has substantial direct effects on the states, the relationship between the national government and the states, or the distribution of power and responsibilities among the various levels of government. It does not propose any regulation that imposes substantial direct compliance costs on state and local governments. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. Nevertheless, PHMSA has and will continue to consult extensively with state regulators including NAPSR to ensure that any state concerns are taken into account.
The Regulatory Flexibility Act of 1980 (Pub. L. 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
PHMSA performed a screening analysis of the potential economic impact on small entities. The screening analysis is available in the docket for the rulemaking. PHMSA estimates that the proposed rule would impact fewer than 100 small hazardous liquid pipeline operators, and that the majority of these operators would experience annual compliance costs that represent less than 1% of annual revenues. Less than 20 small operators would incur annual compliance costs that represent greater than 1% of annual revenues; less than 10 would incur annual compliance costs of greater than 3% of annual revenues; and none would incur compliance costs of more than 20% of annual revenues. PHMSA determined that these impacts results do not represent a significant impact for a substantial number of small hazardous liquid pipeline operators. Therefore, I certify that this action, if promulgated, will not have a significant economic impact on a substantial number of small entities.
PHMSA analyzed this NPRM in accordance with section 102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), the Council on Environmental Quality regulations (40 CFR parts 1500 through 1508), and DOT Order 5610.1C, and has preliminarily determined that this action will not significantly affect the quality of the human environment. A preliminary environmental assessment of this rulemaking is available in the docket and PHMSA invites comment on environmental impacts of this rule, if any.
This NPRM has been analyzed in accordance with the principles and criteria contained in Executive Order 13175 (“Consultation and Coordination with Indian Tribal Governments”). Because this NPRM does not have Tribal implications and does not impose substantial direct compliance costs on Indian Tribal governments, the funding and consultation requirements of Executive Order 13175 do not apply.
Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide interested members of the public and affected agencies with an opportunity to comment on information collection and recordkeeping requests. PHMSA estimates that the proposals in this rulemaking will add a new information collection and impact several approved information collections titled:
“Transportation of Hazardous Liquids by Pipeline: Recordkeeping and Accident Reporting” identified under Office of Management and Budget (OMB) Control Number 2137-0047;
“Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities” identified under OMB Control Number 2137-0578;
“Integrity Management in High Consequence Areas for Operators of Hazardous Liquid Pipelines” identified under OMB Control Number 2137-0605 and;
“Pipeline Safety: New Reporting Requirements for Hazardous Liquid Pipeline Operators: Hazardous Liquid Annual Report” identified under OMB Control Number 2137-0614.
Based on the proposals in this rulemaking, PHMSA will submit an information collection revision request to OMB for approval based on the requirements in this NPRM. The information collection is contained in the pipeline safety regulations, 49 CFR parts 190 through 199. The following information is provided for each information collection: (1) Title of the information collection; (2) OMB control number; (3) Current expiration date; (4) Type of request; (5) Abstract of the information collection activity; (6) Description of affected public; (7) Estimate of total annual reporting and recordkeeping burden; and (8) Frequency of collection. The information collection burden for the following information collections are estimated to be revised as follows:
1.
Total Annual Responses: 881.
Total Annual Burden Hours: 55,455.
Frequency of Collection: On occasion.
2.
Total Annual Responses: 178.
Total Annual Burden Hours: 1,020.
Frequency of Collection: On occasion.
3.
Total Annual Responses: 278.
Total Annual Burden Hours: 325,508.
Frequency of Collection: Annually.
4.
Total Annual Responses: 475.
Total Annual Burden Hours: 8,567.
Frequency of Collection: Annually.
5.
Total Annual Responses: 10.
Total Annual Burden Hours: 10.
Frequency of Collection: On occasion.
Requests for copies of these information collections should be directed to Angela Dow or Cameron Satterthwaite, Office of Pipeline Safety (PHP-30), Pipeline Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New Jersey Avenue SE., Washington, DC 20590-0001, Telephone (202) 366-4595.
Anyone is able to search the electronic form of all comments received into any of our dockets by the name of the individual submitting the comment (or signing the comment, if submitted on behalf of an association, business, labor union, etc.). You may review DOT's complete Privacy Act Statement in the
A regulation identifier number (RIN) is assigned to each regulatory action listed in the Unified Agenda of Federal Regulations. The Regulatory Information Service Center publishes the Unified Agenda in April and October of each year. The RIN contained in the heading of this document may be used to cross-reference this action with the Unified Agenda.
Incorporation by reference, Integrity management, Pipeline safety.
In consideration of the foregoing, PHMSA proposes to amend 49 CFR part 195 as follows:
49 U.S.C. 5103, 60101, 60102, 60104, 60108, 60109, 60116, 60118, 60131, 60131, 60137, and 49 CFR 1.97.
The addition reads as follows:
(a) * * *
(5) For purposes of the reporting requirements in subpart B of this part, any gathering line not already covered under paragraphs (a)(1), (2), (3) or (4) of this section.
(b) * * *
(12) Perform pipeline assessments and remediation as required under §§ 195.416 and 195.422.
(13) Establish a leak detection system in compliance with §§ 195.134 and 195.444.
(a)
(b)
(a)
(b)
(1) Manifolds;
(2) Station piping such as at pump stations, meter stations, or pressure reducing stations;
(3) Piping associated with tank farms and other storage facilities;
(4) Cross-overs;
(5) Pipe for which an instrumented internal inspection device is not commercially available; and
(6) Offshore pipelines, other than main lines 10 inches (254 millimeters) or greater in nominal diameter, that transport liquids to onshore facilities.
(c)
(d)
(a)
(b)
(c)
(b) An operator must make repairs on its pipeline system according to the following requirements:
(1)
(3)
(a)
(b)
(c)
(d)
(1) Reducing the operating pressure or shutting down the pipeline;
(2) Modifying, repairing, or replacing any damaged pipeline facilities;
(3) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-way;
(4) Performing additional patrols, surveys, tests, or inspections;
(5) Implementing emergency response activities with Federal, State, or local personnel; and
(6) Notifying affected communities of the steps that can be taken to ensure public safety.
(a)
(b)
(c)
(i) Demonstrates that the pipeline is not capable of accommodating an inline inspection tool; and that the use of an alternative assessment method will provide a substantially equivalent understanding of the condition of the pipeline; and
(ii) Notifies the Office of Pipeline Safety (OPS) 90 days before conducting the assessment by:
(A) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590; or
(B) Sending the notification, along with the information required to demonstrate compliance with paragraph (c)(i) of this section, to the Information Resources Manager by facsimile to (202) 366-7128.
(d)
(e)
(f)
(g)
(a)
(b)
(c)
(d)
(1)
(i) Metal loss greater than 80% of nominal wall regardless of dimensions.
(ii) A calculation of the remaining strength of the pipe shows a burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)) (incorporated by reference, see § 195.3.
(iii) A dent located anywhere on the pipeline that has any indication of metal loss, cracking or a stress riser.
(iv) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter.
(v) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(vi) Any indication of significant stress corrosion cracking (SCC).
(vii) Any indication of selective seam weld corrosion (SSWC).
(2) Until the remediation of a condition specified in paragraph (d)(1) of this section is complete, an operator must:
(i) Reduce the operating pressure of the affected pipeline using the formula specified in paragraph 195.422(d)(3)(iv) or;
(ii) Shutdown the affected pipeline.
(3)
(i) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld.
(ii) A dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).
(iii) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter.
(iv) A calculation of the remaining strength of the pipe at the anomaly shows a safe operating pressure that is less than the MOP at that location. Provided the safe operating pressure includes the internal design safety factors in § 195.106 in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991)) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)) (incorporated by reference, see § 195.3).
(v) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.
(vi) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.
(vii) A potential crack indication that when excavated is determined to be a crack.
(viii) Corrosion of or along a seam weld.
(ix) A gouge or groove greater than 12.5% of nominal wall.
(e)
(a)
(b)
(c)
The revisions and additions read as follows:
(a)
(1) Category 1 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this part.
(2) Category 2 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipeline subject to this part.
(3) Category 3 includes pipelines constructed or converted after May 29, 2001, low-stress pipelines in rural areas under § 195.12.
(b) * * *
(1) Develop a written integrity management program that addresses the risks on each segment of pipeline in the first column of the following table not later than the date in the second column:
(c) * * *
(1) * * *
(i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by In Line Inspection tool unless it is impracticable, then use methods (B), (C) or (D) of this paragraph. The methods an operator selects to assess low frequency electric resistance welded pipe, or lap welded pipe, or pipe with a seam factor less than 1.0 as defined in § 195.106(e) or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies.
(A) Internal inspection tool or tools capable of detecting corrosion, and deformation anomalies including dents, cracks (pipe body and weld seams), gouges and grooves. An operator using this method must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or equivalent for determining uncertainties) in identifying anomalies;
(d)
(1)
(2)
(e) * * *
(1) * * *
(vii) Local environmental factors that could affect the pipeline (
(g)
(1) Integrate information and attributes about the pipeline which include, but are not limited to:
(i) Pipe diameter, wall thickness, grade, and seam type;
(ii) Pipe coating including girth weld coating;
(iii) Maximum operating pressure (MOP);
(iv) Endpoints of segments that could affect high consequence areas (HCAs);
(v) Hydrostatic test pressure including any test failures—if known;
(vi) Location of casings and if shorted;
(vii) Any in-service ruptures or leaks—including identified causes;
(viii) Data gathered through integrity assessments required under this section;
(ix) Close interval survey (CIS) survey results;
(x) Depth of cover surveys;
(xi) Corrosion protection (CP) rectifier readings;
(xii) CP test point survey readings and locations;
(xiii) AC/DC and foreign structure interference surveys;
(xiv) Pipe coating surveys and cathodic protection surveys.
(xv) Results of examinations of exposed portions of buried pipelines (
(xvi) Stress corrosion cracking (SCC) and other cracking (pipe body or weld) excavations and findings, including in-situ non-destructive examinations and analysis results for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipeline;
(xvii) Aerial photography;
(xviii) Location of foreign line crossings;
(xix) Pipe exposures resulting from encroachments;
(xx) Seismicity of the area; and
(xxi) Other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this part.
(2) Consider information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline;
(3) Consider how a potential failure would affect high consequence areas, such as location of a water intake.
(4) Identify spatial relationships among anomalous information (
(h) * * *
(1)
(2)
(4)
(A) Metal loss greater than 80% of nominal wall regardless of dimensions.
(B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than 1.1 times the maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)) (incorporated by reference, see § 195.3).
(C) A dent located anywhere on the pipeline that has any indication of metal loss, cracking or a stress riser.
(D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter.
(E) Any indication of significant stress corrosion cracking (SCC).
(F) Any indication of selective seam weld corrosion (SSWC)
(G) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(ii)
(A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld.
(B) A dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).
(C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter.
(D) A calculation of the remaining strength of the pipe at the anomaly shows a safe operating pressure that is less than MOP at that location. Provided the safe operating pressure includes the internal design safety factors in § 195.106 in calculating the pipe anomaly safe operating pressure, suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991)) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)) (incorporated by reference, see § 195.3).
(E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.
(F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.
(G) A potential crack indication that when excavated is determined to be a crack.
(H) Corrosion of or along a longitudinal seam weld.
(I) A gouge or groove greater than 12.5% of nominal wall.
(iii)
(i) * * *
(2) * * *
(ix) Seismicity of the area.
(j) * * * (1)
(2)
(n)
(2)
(3)
(4)
(5)
Bureau of Land Management, Interior.
Proposed rule.
This proposed rule would revise and replace Onshore Oil and Gas Order No. 5 (Order 5) with a new regulation that would be codified in the Code of Federal Regulations. This proposed rule would establish the minimum standards for accurate measurement and proper reporting of all gas removed or sold from Federal and Indian leases (except the Osage Tribe), units, unit participating areas, and areas subject to communitization agreements, by providing a system for production accountability by operators, lessees, purchasers, and transporters. This proposed rule would include requirements for the hardware and software related to approved metering equipment, overall measurement performance standards, and reporting and record keeping. The proposed rule would identify certain specific acts of noncompliance that would result in an immediate assessment and would provide a process for the BLM to consider variances from the requirements of this proposed rule.
Send your comments on this proposed rule to the BLM on or before December 14, 2015. The BLM is not obligated to consider any comments received after the above date in making its decision on the final rule.
If you wish to comment on the information collection requirements in this proposed rule, please note that the Office of Management and Budget (OMB) is required to make a decision concerning the collection of information contained in this proposed rule between 30 to 60 days after publication of this document in the
Comments on the information collection burdens:
Richard Estabrook, petroleum engineer, Division of Fluid Minerals, 707-468-4052. For questions relating to regulatory process issues, please contact Faith Bremner at 202-912-7441. 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 information collection request for this proposed rule has been submitted to OMB for review under 44 U.S.C. 3507(d). A copy of the request can be obtained from the BLM by electronic mail request to Jennifer Spencer at
The BLM's regulations that govern how gas produced from onshore Federal and Indian leases is measured and accounted for are more than 25 years old and need to be updated to be consistent with modern industry practices. Federal laws, metering technology, and industry standards have changed significantly since the BLM adopted Order 5 in 1989. In a number of separate reports, three outside independent entities—the Interior Secretary's Subcommittee on Royalty Management (the Subcommittee) in 2007, the Department of the Interior's Office of the Inspector General (OIG) in 2009, and the Government Accountability Office (GAO) in 2010, 2011, 2013, and 2015—have repeatedly recommended that the BLM evaluate its gas measurement guidance and regulations to ensure that operators pay the proper royalties. Specifically, these groups found that Interior needed to provide Department-wide guidance on measurement technologies and processes not addressed in current regulations, including guidance on the process for approving variances in instances when technologies or processes are not addressed in the future. As explained below, the provisions of this proposed rule respond to these recommendations by the Subcommittee, the GAO, and the OIG.
The BLM's oil and gas program is one of the most important mineral leasing programs in the Federal Government. Domestic production from Federal and Indian onshore oil and gas leases accounts for approximately 10 percent of the nation's natural gas supply and 7 percent of its oil. In Fiscal Year (FY) 2014, the Office of Natural Resources Revenue (ONRR) reported that onshore Federal oil and gas leases produced about 148 million barrels of oil, 2.48 trillion cubic feet of natural gas, and 2.9 billion gallons of natural gas liquids, with a market value of more than $27 billion and generating royalties of almost $3.1 billion. Nearly half of these revenues are distributed to the States in which the leases are located. Leases on Tribal and Indian lands produced 56 million barrels of oil, 240 billion cubic feet of natural gas, 182 million gallons of natural gas liquids, with a market value of almost $6 billion and generating royalties of over $1 billion that were all distributed to the applicable tribes and individual allottee owners. Despite the magnitude of this production, the BLM's rules governing how that gas is measured and accounted for are more than 25 years old and need to be updated and strengthened. Federal laws, technology, and industry standards have all changed significantly in that time.
The Secretary of the Interior has the authority under various Federal and Indian mineral leasing laws to manage oil and gas operations. The Secretary has delegated this authority to the BLM, which issued onshore oil and gas operating regulations codified at 43 CFR part 3160. Over the years, the BLM issued seven Onshore Oil and Gas Orders that deal with different aspects of oil and gas production. These Orders were published in the
The discussion that immediately follows summarizes and briefly explains the most significant changes proposed in this rule. Each of these will be discussed more fully in the section-by-section analysis below. For that reason, references to specific section and paragraph numbers are omitted in the body of this discussion.
The most significant proposed change would be new requirements for determining and reporting the heating value and relative density of all gas produced. Royalties on gas are calculated by multiplying the volume of the gas removed or sold from the lease (generally expressed in thousands of standard cubic feet (Mcf)) by the heating value of the gas in British thermal units (Btu) per unit volume, the value of the gas (expressed in dollars per million Btu (MMBtu), and the fixed royalty rate. So a 10 percent error in the reported heating value would result in the same error in royalty as a 10 percent error in volume measurement. Relative density, which is a measure of the average mass of the molecules flowing through the meter, is used in the calculation of flow rate and volume. Under the flow equation, a 10 percent error in relative density would result in a 5 percent error in the volume calculation. Both heating value and relative density are determined from the same gas sample.
Order 5 requires a determination of heating value only once per year. Federal and Indian onshore gas producers can then use that value in the royalty calculations for an entire year. There are currently no requirements for determining relative density. Existing regulations do not have standards for how gas samples used in determining heating value and relative density should be taken and analyzed to avoid biasing the results. In addition, existing regulations do not prescribe when and how operators should report the results to the BLM.
In response to a Subcommittee recommendation that the BLM determine the potential heating-value variability of produced natural gas and estimate its implications for royalty payments, the BLM conducted a study which found significant sample-to-sample variability in heating value and relative density at many of the 180 gas facility measurement points (FMP) it analyzed. The “BLM Gas Variability Study Final Report,” May 21, 2010, used 1,895 gas analyses gathered from 65 formations. In one example, the study found that heating values measured from samples taken at a gas meter in the Anderson Coal formation in the Powder River Basin varied ±31.41 percent, while relative density varied ±19.98 percent. In multiple samples collected at another gas meter in the same formation, heating values varied by only ±2.58 percent, while relative density varied by ±3.53 percent (p. 25). Overall, the uncertainty in heating value and relative density in this study was ±5.09 percent, which, across the board, could amount to ±$127 million in royalty based on 2008 total onshore Federal and Indian royalty payments of about $2.5 billion (p. 16). Uncertainty is a statistical range of error that indicates the risk of measurement error.
The study concluded that heating value variability is unique to each gas meter and is not related to reservoir type, production type, age of the well, richness of the gas, flowing temperature, flow rate, or a number of other factors that were included in the study (p. 17). The study also concluded that more frequent sampling increases the accuracy of average annual heating value determinations (p. 11).
This proposed rule would strengthen the BLM's regulations on measuring heating value and relative density by requiring operators to sample all meters more frequently than currently required under Order 5, except marginal-volume meters (measuring 15 Mcf/day or less) whose sampling frequency (
The proposed rule would also set new average annual heating value uncertainty standards of ±2 percent for high-volume FMPs and ±1 percent for very-high-volume FMPs. The BLM established these uncertainty thresholds by determining the uncertainty at which the cost of compliance equals the risk of royalty underpayment or overpayment.
In developing this proposed rule, the BLM realized that a fixed sampling frequency may not achieve a consistent level of uncertainty in heating value for high-volume and very-high-volume meters. For example, a 3-month sampling frequency may not adequately reduce average annual heating value uncertainty in a meter which has exhibited a high degree of variability in the past. On the other hand, a 3-month sampling frequency may be excessive for a meter which has very consistent heating values from one sample to the next. If a high- or very-high-volume FMP did not meet these proposed heating-value uncertainty limits, the BLM would adjust the sampling frequency at that FMP until the heating value meets the proposed uncertainty standards. If a high- or very-high-volume FMP continues to not meet the uncertainty standards, the BLM could require the installation of composite samplers or on-line gas chromatographs, which automatically sample gas at frequent intervals.
In addition to prescribing uncertainty standards and more frequent sampling, this proposed rule also would improve measurement and reporting of heating values and relative density by setting standards for gas sampling and analysis. These proposed standards would specify sampling locations and methods, analysis methods, and the minimum number of components that would have to be analyzed. The proposed standards would also set requirements for how and when operators report the results to the BLM and ONRR, and would define the effective date of the heating value and relative density that is determined from the sample.
This proposed rule would require operators to periodically inspect the insides of meter tubes for pitting, scaling, and the buildup of foreign substances, which could bias measurement. Existing regulations do not address this issue. Visual meter tube inspections would be required once every 5 years at low-volume FMPs, once every 2 years at high-volume FMPs, and yearly at very-high-volume FMPs. The BLM could increase this frequency and require a detailed meter-tube inspection of a low-volume FMP meter if the visual inspection identifies any issues or if the meter tube operates in adverse conditions, such as with corrosive or erosive gas flow. A detailed meter-tube inspection involves removing or disassembling the meter run. Detailed meter-tube inspections would be required once every 10 years at high-volume FMPs and once every 5 years at very-high-volume FMPs. Operators would have to replace meter tubes that no longer meet the requirements proposed in this rule.
The proposed rule would increase routine meter verification or calibration requirements for metering equipment at very-high-volume FMPs and decrease the requirements at marginal-volume FMPs. Verification frequency would be unchanged for high-volume FMPs, as well as for low-volume FMPs that use mechanical recorder systems. Verification frequency would be decreased for low-volume FMPs using electronic gas measurement (EGM) systems.
Under Order 5, all meters must undergo routine verification every 3 months, regardless of the throughput volume. This proposed rule would require monthly verification for very-high-volume FMPs, while the verification requirement for high-volume FMPs would remain at every 3 months. The rationale for this proposed change is that the consequences of measurement and royalty-calculation errors at very-high-volume FMPs are more serious than they are at high-, low-, and marginal-volume FMPs. The schedule for routine verification for low- and marginal-volume FMPs that use EGM systems would decrease to every 6 months for low-volume FMPs and yearly for marginal-volume FMPs.
The routine verification schedule for low- and marginal-volume FMPs that use mechanical chart recorders would be every 3 months for low-volume FMPs and every 6 months for marginal-volume FMPs. The proposed rule would restrict the use of mechanical chart recorders to low- and marginal-volume FMPs because the accuracy and performance of mechanical chart recorders is not defined well enough for the BLM to quantify overall measurement uncertainty. Between 80 percent and 90 percent of gas meters at Federal onshore and Indian FMPs use EGM systems.
Although industry has used EGM systems for about 30 years, Order 5 does not address them. Instead, the BLM has regulated their use through statewide Notices to Lessees (NTLs), which do not address many aspects unique to EGMs, such as volume calculation and data-gathering and retention requirements. This proposed rule includes many of the existing NTL requirements for EGM systems and adds some new ones relating to on-site information, gauge lines, verification, test equipment, calculations, and information generated and retained by the EGM systems. The proposed rule would make a significant change in those requirements by revising the maximum flow-rate uncertainty that is currently allowed under existing statewide NTLs. Currently, flow-rate equipment at FMPs that measure more than 100 Mcf/day is required to meet a ±3 percent uncertainty level. The proposed rule would maintain that requirement for high-volume FMPs. However, under this proposed rule, equipment at very-high-volume FMPs would have to comply with a new ±2 percent uncertainty requirement. Consistent with existing guidance, flow-rate equipment at FMPs that measure less than 100 Mcf/day would continue to be exempt from these uncertainty requirements. The BLM would maintain this exemption because it believes that compliance costs for these wells could cause some operators to shut in their wells instead of making changes. The BLM believes the royalties lost by such shut-ins would exceed any royalties that might be gained through upgrades at such facilities. The BLM is interested in any additional information about costs of compliance relative to royalty lost from maintaining the existing exemption.
One area that existing NTLs do not address and that this proposed rule would address is the accuracy of transducers and flow-computer software used in EGM systems. Transducers send electronic data to flow computers, which use that data, along with other data that is programmed into the flow computers, to calculate volumes and flow rates. Currently, the BLM must accept manufacturers' claimed performance specifications when calculating uncertainty. Neither the American Petroleum Institute (API) nor the Gas Processors Association (GPA) has standards for determining these performance specifications. For this reason, the proposed rule would require operators or manufacturers to “type test” transducers and flow-computer software at independent testing facilities, using a standard testing protocol, to quantify the uncertainty of transducers and flow-computer software that are already in use and that will be used in the future. The test results would then be incorporated into the calculation of overall measurement uncertainty for each piece of equipment tested.
An integral part of the BLM's evaluation process would be the Production Measurement Team (PMT), made up of measurement experts designated by the BLM.
If you wish to comment on the proposed rule, you may submit your comments by any one of several methods specified see
Please make your comments as specific as possible by confining them to issues for which comments are sought in this notice, and explain the basis for your comments. The comments and recommendations that will be most useful and likely to influence agency decisions are:
1. Those supported by quantitative information or studies; and
2. Those that include citations to, and analyses of, the applicable laws and regulations.
The BLM is not obligated to consider or include in the Administrative Record for the rule comments received after the close of the comment period (see
Comments, including names and street addresses of respondents, will be available for public review at the
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.
The regulations at 43 CFR part 3160, Onshore Oil and Gas Operations, in § 3164.1, provide for the issuance of Onshore Oil and Gas Orders to “implement and supplement” the regulations in part 3160. Although they are not codified in the CFR, all Onshore Orders have been issued under Administrative Procedure Act notice and comment rulemaking procedures and apply nationwide to all Federal and Indian (except the Osage Tribe) onshore oil and gas leases. The table in 43 CFR 3164.1(b) lists the existing Orders. This proposed rule would update and replace Order 5, which supplements primarily 43 CFR 3162.4, 3162.7-3, subpart 3163, and subpart 3165. Section 3162.4 covers records and reports. Section 3162.7-3 covers the measurement of gas produced from Federal and Indian (except the Osage Tribe) oil and gas leases. Subpart 3163 covers non-compliance, assessments, and civil penalties. Subpart 3165 covers relief, conflicts, and appeals. Order 5 has been in effect since March 27, 1989 (see 54 FR 8100).
This proposed rule would also supersede the following statewide NTLs:
• NM NTL 92-5, January 1, 1992
• WY NTL 2004-1, April 23, 2004
• CA NTL 2007-1, April 16, 2007
• MT NTL 2007-1, May 4, 2007
• UT NTL 2007-1, August 24, 2007
• CO NTL 2007-1, December 21, 2007
• NM NTL 2008-1, January 29, 2008
• ES NTL 2008-1, September 17, 2008
• AK NTL 2009-1, July 29, 2009
• CO NTL 2014-01, May 19, 2014
Although Order 5 and the statewide NTLs listed above would be superseded by this rule, their provisions would remain in effect for measurement facilities already in place on the effective date of the final rule through the phase-in periods specified in proposed § 3175.60(c) and (d).
Part of the Department of the Interior's responsibility in ensuring correct payment of royalty on gas extracted from Federal onshore and Indian leases is to achieve accurate measurement, proper reporting, and accountability.
In 2007, the Secretary of the Interior commissioned the Subcommittee to report to the Royalty Policy Committee (RPC), which is chartered under the Federal Advisory Committee Act, to provide advice to the Secretary and other Departmental officials responsible for managing mineral leasing activities and to provide a forum for members of the public to voice their concerns about mineral leasing activities. The proposed rule is in part a result of the recommendations contained in the Subcommittee's report, which was issued on December 17, 2007. The proposed changes in this rule also address findings and recommendations made in two GAO reports and one OIG report, including: (1) GAO Report to Congressional Requesters,
The GAO found that the Department's measurement regulations and policies do not provide reasonable assurances that oil and gas are accurately measured because, among other things, its policies for tracking where and how oil and gas are measured are not consistent and effective (GAO Report 10-313, p. 20). The report also found that the BLM's regulations do not reflect current industry-adopted measurement technologies and standards designed to improve oil and gas measurement (ibid.). The GAO recommended that Interior provide Department-wide guidance on measurement technologies not addressed in current regulations and approve variances for measurement technologies in instances when the technologies are not addressed in current regulations or Department-wide guidance (see ibid., p. 80). The OIG Report made a similar recommendation that the BLM, “Ensure that oil and gas regulations are current by updating and issuing onshore orders . . . .” (see page 11). In its 2015 report, the GAO reiterated that “Interior's measurement regulations do not reflect current measurement technologies and standards,” and that this “hampers the agency's ability to have reasonable assurance that oil and gas production is being measured accurately and verified . . . .” (GAO Report 15-39, p. 16.) Among its recommendations were that the Secretary direct the BLM to “meet its established time frame for issuing final regulations for oil measurement.” (Ibid., p. 32.)
The GAO's recommendations regarding the gas measurement are also one of the bases for the GAO's inclusion of the Department's oil and gas program on the GAO's High Risk List in 2011 (GAO-11-278) and for its continuing to keep the program on the list in the 2013 and 2015 updates. Specifically, the GAO concluded that the BLM does not have “reasonable assurance that . . . gas produced from federal leases is accurately measured and that the public is getting an appropriate share of oil and gas revenues.” (GAO-11-278, p.38)
Specifically, of the 110 recommendations made in the 2007 Subcommittee report, 12 recommendations relate directly to improving the operators' measurement and reporting of natural gas volume and heating value. The Subcommittee recommendations focus on the measurement and reporting of heating value because it has a direct impact on royalties. Measuring heating value is as important to calculating royalty as measuring gas volume. As noted previously, Order 5 requires only yearly measurement of natural gas heating value. The BLM does not have any standards for how operators should measure heating value, where they should measure it, how they should analyze it, or on what basis they should report it. The proposed requirements in subpart 3175 would establish these standards.
The proposed changes also address findings and recommendations made in the 2010 and 2015 GAO reports. The 2010 GAO report made 19 recommendations to improve the BLM's ability to ensure that oil and gas produced from Federal and Indian lands is accurately measured and properly reported. Some of those recommendations relate to gas measurement. For example, the report recommends that the BLM establish goals that would allow it to witness gas sample collections; however, the BLM must first establish gas sampling standards as a basis for inspection and enforcement actions. This rulemaking would establish these standards. The 2015 GAO report recommends, among other things, that the BLM issue new
Finally, Order 5 is now 26 years old, and many improvements in technology and industry standards have occurred since that time that are not addressed in BLM regulations. In the absence of a new rule, the BLM has had to address these issues through statewide NTLs and site-specific variances. The following summarizes why the BLM is proposing to include some of these changes in this proposed rule:
• The BLM estimates that between 80 percent and 90 percent of gas meters used for royalty determination incorporate EGM systems. EGM systems are not addressed in Order 5, which covers only mechanical chart recorders. BLM requirements for EGM systems, as stated in the various statewide NTLs, are based on the requirements for mechanical recorders in Order 5 and do not address many aspects unique to EGMs, such as volume calculation, data-gathering, and retention requirements. The proposed rule would add requirements specific to EGMs such as new calibration procedures, the use of the latest flow equations, and minimum requirements for quantity transaction records, configuration logs, and event logs.
• Order 5 allows pipe-tapped orifice plates to be used for royalty measurement. Industry has moved away from pipe-tapped orifice plates for custody transfer due to a relatively high degree of measurement uncertainty inherent in that technology. The proposed rule would allow only flange-tapped orifice plates.
• The only industry standard adopted by Order 5 is American Gas Association (AGA) Report No. 3, 1985, which sets standards for orifice plates. This standard has since been superseded based on additional research and analysis. The new standards, which are incorporated by reference in this proposed rule, reduce bias and uncertainty.
• Order 5 does not adopt industry standards related to technologies for EGM systems, calculation of supercompressibility, gas sampling and analysis, calculation of heating value and relative density, or testing protocols for alternate types of primary devices. The proposed rule would add requirements to address all of these shortcomings in Order 5 and would establish the PMT to review new technology.
• Order 5 does not establish testing and approval standards for flow conditioners, transducers used in EGM systems, or flow computer software. To ensure accuracy of measurement, independent verification of these devices, as proposed in this rule, is necessary.
The following chart explains the major changes between Order 5 and the proposed rule.
This proposed rule would be codified primarily in a new 43 CFR subpart 3175. As noted previously, the BLM has already proposed a rule to revise and replace Order 3 (site security), 80 FR 40768 (July 13, 2015). It is the BLM's intent to codify any final rule resulting from that proposal at new 43 CFR subpart 3173. The BLM also anticipates proposing a new rule to replace Onshore Oil and Gas Order No. 4, 54 FR 8086 (February 24, 1989), governing measurement of oil for royalty purposes. The BLM's intent is to codify any final rule governing oil measurement at new 43 CFR subpart 3174. Given this structure, it is the BLM's intent that part 3170, which was proposed together with proposed 43 CFR subpart 3173, would contain definitions of certain terms common to more than one of the proposed rules, as well as other provisions common to all rules,
In addition to the new subpart 3175 provisions, the BLM is also proposing changes to certain other provisions in 43 CFR subparts 3162, 3163, and 3165. The proposed provisions related to the new subpart 3175 are discussed first in the section-by-section analysis below; changes to other subparts are discussed at the end of the section-by-section analysis.
The proposed rule would include numerous new definitions because much of the terminology used in the proposed rule is technical in nature and may not be readily understood by all readers. The BLM would add other definitions because their meaning, as used in the proposed rule, may be different from what is commonly understood, or the definition would include a specific regulatory requirement.
Definitions of terms commonly used in gas measurement or which are already defined in 43 CFR parts 3000, 3100, or 3160 are not discussed in this preamble.
The proposed rule would define the terms “primary device,” “secondary device,” and “tertiary device,” which together measure the amount of natural gas flow. All differential types of gas meters consist of at least a primary device and a secondary device. The primary device is the equipment that creates a measureable and predictable pressure drop in response to the flow rate of fluid through the pipeline. It includes the pressure-drop device, device holder, pressure taps, required lengths of pipe upstream and downstream of the pressure-drop device, and any flow conditioners that may be used to establish a fully-developed symmetrical flow profile.
A flange-tapped orifice plate is the most common primary device. It operates by accelerating the gas as it flows through the device, similar to placing one's thumb at the end of a garden hose. This acceleration creates a difference between the pressure upstream of the orifice and the pressure downstream of the orifice, which is known as differential pressure. It is the only primary device that is approved in Order 5 and in this proposed rule and would not require further specific approval. Other primary devices, such as cone-type meters, operate much like orifice plates and the BLM could approve their use under the requirements of proposed § 3175.47.
The secondary device measures the differential pressure along with static pressure and temperature. The secondary device consists of either the differential-pressure, static-pressure, and temperature transducers in an EGM system or a mechanical recorder (including the differential, static, and temperature elements, and the clock, pens, pen linkages, and circular chart). In the case of an EGM system, there is also a “tertiary device,” namely, the flow computer and associated memory, calculation, and display functions, which calculates volume and flow rate based on data received from the transducers and other data programmed into the flow computer.
The proposed rule would add definitions for “component-type” and “self-contained” EGM systems. The distinction is necessary for the determination of overall measurement uncertainty. To determine overall measurement uncertainty under proposed § 3175.30(a), it is necessary to know the uncertainty, or risk of measurement error, of the transducers that are part of the EGM system. Therefore, the BLM would need to be able to identify the make, model, and upper range limit (URL) of each transducer because the uncertainty of the transducer varies between makes, models, and URLs.
Some EGM systems are sold as a complete package, defined as a self-contained EGM system, which includes the differential-pressure, static-pressure, and temperature transducers, as well as the flow computer. The EGM package is identified by one make and model number. The BLM can access the performance specifications of all three transducers through the one model number, as long as the transducers have not been replaced by different makes or models.
Other EGM systems are assembled using a variety of transducers and flow computers and cannot be identified by
The proposed rule would add a definition for “hydrocarbon dew point.” The hydrocarbon dew point is the temperature at which liquids begin to form within a gas mixture. Because it is not common to determine hydrocarbon dew points for wellhead metering applications on Federal and Indian leases, the BLM would establish a default value using the gas temperature at the meter. By definition, the gas in a separator (if one is used) is in equilibrium with the natural gas liquids, which are at the hydrocarbon dew point. Cooler temperatures between the outlet of the separator and the primary device can result in condensation of heavy gas components, in which case the lower temperature at the primary device would still represent the hydrocarbon dew point at the primary device. The AO may approve a different hydrocarbon dew point if data from an equation-of-state, chilled mirror, or other approved method is submitted.
The proposed rule would define “marginal-volume FMP” as an FMP that measures a default volume of 15 Mcf/day or less. FMPs classified as “marginal-volume” would be exempt from many of the requirements in this proposed rule. The 15 Mcf/day default threshold was derived by performing a discounted cash-flow analysis to account for the initial investment of equipment that may be required to comply with the proposed standards for FMPs that are classified as low-volume FMPs. Assumptions in the discounted cash-flow model included:
• $12,000/year/well operating cost (not including measurement-related expense);
• Verification, orifice-plate inspection, meter-tube inspection, and gas sampling expenditures as would be required for a low-volume FMP in the proposed rule;
• A before-tax rate of return (ROR) of 15 percent;
• An exponential production-rate decline of 10 percent per year; and
• 10-year equipment life.
The model calculated the minimum initial flow rate needed to achieve a 15 percent ROR for various levels of investment in measurement equipment that would be required of a low-volume FMP. The ROR would be from the continued sale of produced gas that would otherwise be lost because the lease, unit participating area (PA), or communitized area (CA) would be shut-in if there were no exemptions for marginal-volume FMPs. Figure 1 shows the results of the modeling for assumed gas sales prices of $3/MMBtu, $4/MMBtu, and $5/MMBtu.
Both wellhead spot prices (Henry Hub) and New York Mercantile Exchange futures prices for natural gas averaged approximately $4/MMBtu for 2013 and 2014. The U.S. Energy Information Administration projects the price for natural gas to range between $5/MMBtu and $10/MMBtu through the end of 2040, depending on the rate at which new natural gas discoveries are made and projected economic growth.
The proposed rule would define “low-volume FMP” as an FMP flowing 100 Mcf/day or less but more than 15 Mcf/day. Low-volume FMPs would have to meet minimum requirements to ensure that measurements are not biased, but would be exempt from the minimum uncertainty requirements in § 3175.30(a) of the proposed rule. It is anticipated that this classification would encompass many FMPs, such as those associated with plunger-lift operations, where attainment of minimum uncertainty requirements would be difficult due to the high fluctuation of flow-rate and other factors. The costs to retrofit these FMPs to achieve minimum uncertainty levels could be significant, although no economic modeling was performed because costs are highly variable and speculative. The exemptions that would be granted for low-volume FMPs are similar to the exemptions granted for meters measuring 100 Mcf/day or less in Order 5 and in BLM requirements stated in the statewide NTLs for electronic flow computers (EFCs).
The proposed rule would define “high-volume FMP,” as an FMP flowing more than 100 Mcf/day, but not more than 1,000 Mcf/day. Proposed requirements for high-volume FMPs would ensure that there is no statistically significant bias in the measurement and would achieve an overall measurement of uncertainty of ±3 percent or less. The BLM anticipates that the higher flow rates would make retrofitting to achieve minimum uncertainty levels more economically feasible. The requirements for high-volume FMPs would be similar to current BLM requirements as stated in the statewide NTLs for EFCs.
The proposed rule would define “very-high-volume FMP,” as an FMP flowing more than 1,000 Mcf/day. Proposed requirements for very-high-volume FMPS would require lower uncertainty than would be required for high-volume FMPs (±2 percent, compared to ±3 percent) and would increase the frequency of primary device inspection and secondary device verification. Stricter measurement accuracy requirements would be imposed for very-high-volume FMPs due to the risk of mis-measurement having a significant impact on royalty calculation. The BLM anticipates that FMPs in this class operate under relatively ideal flowing conditions where lower levels of uncertainty are achievable and the economics for making necessary retrofits are favorable.
The proposed rule would adopt three definitions from API Manual of Petroleum Measurement Standards (MPMS) 21.1. The terms “lower calibrated limit” and “upper calibrated limit” would replace the term “span” as used in the statewide NTLs for EFCs.
In addition, the term “redundancy verification” would be added to address verifications done by comparing the readings from two sets of transducers installed on the same primary device.
Proposed § 3175.20 would require measurement of all gas removed or sold from Federal or Indian leases and unit PAs or CAs that include one or more Federal or Indian leases to comply with the standards of the proposed rule (unless the BLM grants a variance under proposed § 3170.6).
Proposed § 3175.30 would set overall performance standards for measuring gas produced from Federal and Indian leases, regardless of the type of meters used. Order 5 has no explicit statement of performance standards. The performance standards would provide specific objective criteria with which the BLM could analyze meter systems not specifically allowed under the proposed rule. The performance standards also formed the basis of determining the standards that would apply to each flow-rate class of meter (
The first performance standard in proposed § 3175.30(a) is the maximum allowable flow-rate measurement uncertainty. Uncertainty indicates the risk of measurement error. For high-volume FMPs (flow rate greater than 100 Mcf/day, but less than or equal to 1,000 Mcf/day), the maximum allowed overall flow-rate measurement uncertainty would be ±3 percent, which is the same as what is currently required in all of the statewide NTLs for EFCs; therefore, this requirement does not represent a change from existing standards. For very-high-volume FMPs (flow rate of more than 1,000 Mcf/day), the maximum allowable flow-rate uncertainty would be reduced to ±2 percent, because uncertainty in higher-volume meters represents a greater risk of affecting royalty than in lower-volume meters. In addition, upgrades necessary to achieve an uncertainty of ±2 percent for very-high-volume FMPs will be more cost effective. Not only do the higher flow rates make these necessary upgrades more economic, many of the measurement uncertainty problems associated with lower volume FMPs, such as intermittent flow, are not as prevalent with higher volume FMPs. This is a change from the existing statewide NTLs, which use the ±3 percent requirement for all meters measuring more than 100 Mcf/day. As with the existing statewide NTLs, meters measuring 100 Mcf/day or less (low-volume FMPs and marginal-volume FMPs) would be exempt from maximum uncertainty requirements.
This proposed section would also specify the conditions under which flow-rate uncertainty must be calculated. Flow-rate uncertainty is a function of the uncertainty of each variable used to determine flow rate. The uncertainty of variables such as differential pressure, static pressure, and temperature is dynamic and depends on the magnitude of the variables at a point in time.
Proposed § 3175.30(a)(3) lists two sources of data to use for uncertainty determinations. The best data source for average flowing conditions at the FMP would be the monthly averages typically available from a daily quantity transaction record. However, daily quantity transaction records are not usually readily available to the AO at the time of inspection because they must usually be requested by the BLM and provided by the operator ahead of time. If the daily quantity transaction record is not available to the AO, the next best source for uncertainty determinations would be the average flowing parameters from the previous day, which are required under proposed § 3175.101(b)(4)(ix) through (xi) of this rule.
The BLM would enforce measurement uncertainty using standard calculations such as those found in API MPMS 14.3.1, which are incorporated into the BLM uncertainty calculator (
Proposed § 3175.30(b) would add an uncertainty requirement for the measurement of heating value. This would be added because both heating value and volume directly affect royalty calculation if gas is sold at arm's length on the basis of a per-MMBtu price. (The vast majority of gas sold domestically in the United States is priced on a $/MMBtu basis.) In that situation, the royalty is computed by the following equation: Royalty owed = measured volume × heating value per unit volume (
The BLM recognizes that the heating value determined from a spot sample only represents a snapshot in time, and the actual heating value at any point after the sample was taken may be different. The probable difference is a function of the degree of variability in heating values determined from previous samples. If, for example, the previous heating values for a meter are very consistent, then the BLM would expect that the difference between the heating value based on a spot sample and the actual heating value at any given time after the spot sample was
For composite sampling and on-line gas chromatographs, the BLM would determine the heating value uncertainty by analyzing the equipment, procedures, and calculations used to derive the heating value.
The uncertainty limits proposed for heating value are based on the annualized cost of spot sampling and analysis as compared to the royalty risk from the resulting heating value uncertainty. The BLM used the data collected for the gas variability study (see the discussion of proposed § 3175.115 below) as the basis of this analysis. For high-volume FMPs, the BLM determined that the cost to industry of achieving an average annual heating value uncertainty of ±2 percent by using spot sampling methods would approximately equal the royalty risk resulting from the same ±2 percent uncertainty in heating value. For very-high-volume FMP's, an average annual heating value uncertainty of ±1 percent would result in a cost to industry that is approximately equal to the royalty risk of the uncertainty. The proposed rule therefore would prescribe these respective levels as the allowed average annual heating value uncertainty.
Proposed § 3175.30(c) would establish the degree of allowable bias in a measurement. Bias, unlike uncertainty, results in measurement error; uncertainty only indicates the risk of measurement error. For all FMPs, except marginal FMPs, no statistically significant bias would be allowed. The BLM acknowledges that it is virtually impossible to completely remove all bias in measurement. When a measurement device is tested against a laboratory device, there is often slight disagreement, or apparent bias, between the two. However, both the measurement device being tested and the laboratory device have some inherent level of uncertainty. If the disagreement between the measurement device being tested and the laboratory device is less than the uncertainty of the two devices combined, then it is not possible to distinguish apparent bias in the measurement device being tested from inherent uncertainty in the devices (sometimes referred to as “noise” in the data). Therefore, apparent bias that is less than the uncertainty of the two devices combined is not considered to be statistically significant.
Although bias is not specifically addressed in Order 5 or the statewide NTLs, the intent of the existing standards is to reduce bias to less than significant levels. Therefore, minimizing bias does not represent a change in BLM policy.
The bias requirement does not apply to marginal-volume FMPs because marginal-volume FMPs are measuring such low volumes that any bias, even if it is statistically significant, results in little impact to royalty. The small amount of royalty loss (or gain) resulting from bias would be much less than the royalty lost if production were to cease altogether. If it is uneconomic to upgrade a meter to eliminate bias, the operator could opt to shut in production rather than making the necessary upgrades. Therefore, the BLM has determined that it is in the public interest to accept some risk of measurement bias in marginal-volume FMPs in view of maintaining gas production.
Proposed § 3175.30(d) would require that all measurement equipment must allow for independent verification by the BLM. As with the bias requirements, Order 5 and the statewide NTLs for EFCs only allow meters that can be independently verified by the BLM and, therefore, this requirement would not be a change from existing policy. The verifiability requirement in this section would prohibit the use of measurement equipment that does not allow for independent verification. For example, if a new meter was developed that did not record the raw data used to derive a volume, that meter could not be used at an FMP because without the raw data the BLM would be unable to independently verify the volume. Similarly, if a meter was developed that used proprietary methods which precluded the ability to recalculate volumes or heating values, or made it impossible for the BLM to verify its accuracy, its use would also be prohibited.
The proposed rule would incorporate a number of industry standards, either in whole or in part, without republishing the standards in their entirety in the CFR, a practice known as incorporation by reference. These standards were developed through a consensus process, facilitated by the API and the GPA, with input from the oil and gas industry. The BLM has reviewed these standards and determined that they would achieve the intent of §§ 3175.30 and 3175.46 through 3175.125 of this proposed rule. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. This proposed rule would incorporate the current versions of the standards listed.
Some of the standards referenced in this section would be incorporated in their entirety. For other standards, the BLM would incorporate only those sections that are enforceable, meet the intent of § 3175.30 of this proposed rule, or do not need further clarification.
The proposed incorporation of industry standards follows the requirements found in 1 CFR part 51. Industry standards proposed for incorporation are eligible under 1 CFR 51.7 because, among other things, they will substantially reduce the volume of material published in the
All of the API and GPA materials for which the BLM is seeking incorporation by reference are available for inspection at the BLM, Division of Fluid Minerals; 20 M Street SE., Washington, DC 20003; 202-912-7162; and at all BLM offices with jurisdiction over oil and gas activities. The API materials are available for inspection at the API, 1220 L Street NW., Washington DC 20005; telephone 202-682-8000; API also offers free, read-only access to some of the material at
The following describes the API and GPA standards that the BLM proposes to incorporate by reference into this rule:
Proposed § 3175.40 would provide that the specific types of measurement equipment identified in proposed §§ 3175.41—3175.45 could be installed at FMPs without further approval. Flange-tapped orifice plates (proposed § 3175.41) have been rigorously tested and shown that they are capable of meeting the performance standards of proposed § 3175.30(a). Mechanical recorders (proposed § 3175.42) have been in use on gas meters for more than 90 years in custody-transfer applications and their ability to meet the performance standards of proposed §§ 3175.30(b) and (c) is well-established. Because mechanical recorders would be limited to marginal-volume and low-volume FMPs under the proposed rule, they would not have to meet the uncertainty requirements of proposed § 3175.30(a).
While EGM systems are widely accepted for use in custody-transfer applications, there are currently no standardized protocols by which they are tested to document their performance capabilities and limitations. Proposed § 3175.43 (transducers) and proposed § 3175.44 (flow computer software) would require these components of an EGM system to be tested under the protocols proposed in §§ 3175.130 and 3175.140, respectively, in order to be used at high- or very-high-volume FMPs.
To make the review and approval process consistent, all data received from the testing would be reviewed by the PMT, who would make recommendations to the BLM. If approved, the BLM would post the make, model, and range or software version on the BLM Web site at
Gas chromatographs (proposed § 3175.45) are not addressed in Order 5 or statewide NTLs. They have been rigorously tested and used in industry for custody transfer applications and their ability to meet the requirements of § 3175.30 has been demonstrated. Therefore, the proposed rule would allow their use in determining heating value and relative density as long as they meet the design, operation, verification, calibration, and other requirements of proposed §§ 3175.117 and 3175.118.
Proposed §§ 3175.46 and 3175.47 contain new provisions that would establish a consistent nationwide process that the PMT would use to approve certain other devices without the BLM having to update its regulations, issue other forms of guidance such as NTLs, or grant approvals on a case-by-case basis. The PMT would act as a central advisory body for approving equipment and methods not addressed in the proposed regulations. As noted above, the PMT is a panel of oil and gas measurement experts designated by the BLM that would be charged with reviewing changes in industry measurement technology. These proposed sections would describe and clarify the process for approval of specific makes and models of other primary devices and flow conditioners used in conjunction with flange-tapped orifice plates, including specific testing protocols and procedures for review of test data. These sections also would clarify the makes and models of devices approved for use and the conditions under which operators may use them.
Under the proposed rule, if the PMT recommends, and the BLM approves new equipment, the BLM would post the make and model of the device on the BLM Web site
Proposed § 3175.46 would prescribe a testing protocol for flow conditioners used in conjunction with flange-tapped orifice plates. The proposed rule references the current API MPMS 14.3.2 (2000), Appendix 2-D, which provides a testing protocol for flow conditioners. Based on the BLM's experience with other testing protocols, the BLM could prescribe additional testing beyond what Appendix 2-D requires, to meet the intent of the uncertainty limits in proposed § 3175.30(a). Additional testing protocols would be posted on the BLM's Web site at
Proposed § 3175.47 would prescribe a testing protocol for differential types of primary devices other than flange-tapped orifice plates. The protocol is based largely on API MPMS 22.2. The BLM is aware that the API is in the process of making significant changes to this protocol; however, the modifications have not yet been published. Therefore, the BLM could include additional testing requirements beyond those in the current version of API MPMS 22.2 to help ensure that tests are conducted and applied in a manner that meets the intent of proposed § 3175.30 of this rule. The BLM would post any additional testing protocols on its Web site at
Proposed § 3175.48 would provide a process for the BLM to approve linear measurement devices such as ultrasonic meters, Coriolis meters, and other devices on a case-by-case basis.
Proposed § 3175.60(a) would require all meters installed after the effective date of the final rule to meet the proposed requirements. Proposed paragraph (b) would set timeframes for compliance with the provisions of this rule for equipment existing on the effective date of the final rule. The timeframes for compliance generally would depend on the average flow rate at the FMP. Higher-volume FMPs would have shorter timeframes for compliance with this proposed rule because they present a greater risk to royalty than lower-volume FMPs and the costs to comply could be recovered in a shorter period of time.
Proposed paragraphs (b)(1)(ii) and (b)(2)(ii) include some exceptions to the compliance timelines for high-volume and very-high-volume FMPs. To implement the gas-sampling frequency requirements in proposed § 3175.115, the gas-analysis submittal requirements in proposed § 3175.120(f) would go into effect immediately for high-volume and very-high-volume FMPs on the effective date of the final rule. This would allow the BLM to immediately start developing a history of heating values and relative densities at FMPs to determine the variability and uncertainty of these values.
The BLM is not proposing to “grandfather” existing equipment. Operators would be required to upgrade measurement equipment at FMPs to meet the new standards, except for those FMPs that are specifically exempted in the rule. The reason for not grandfathering existing equipment is that compliance with the API and GPA standards that would be adopted by the proposed rule is necessary to minimize bias and meet the proposed uncertainty standards. The BLM is responsible for ensuring accurate, unbiased, and verifiable measurement, as stated in proposed § 3175.30 of this rule, regardless of when the measurement equipment was installed.
Although this rule would supersede Order 5 and any NTLs, variance approvals, and written orders relating to gas measurement, paragraph (c) would specify that their requirements would remain in effect through the timeframes specified in paragraph (b). Paragraph (d) would establish the dates on which the applicable NTLs, variance approvals, and written orders relating to gas measurement would be rescinded. These dates correspond to the phase-in timeframes given in paragraph (b).
Proposed § 3175.70 would require prior approval for commingling of production with production from other leases, unit PAs, or CAs or non-Federal properties before the point of royalty measurement and for measurement off the lease, unit, or CA (referred to as “off-lease measurement”). The process for obtaining approval is included in the proposed rule that would replace Order 3 (new subpart 3173) referred to previously.
Proposed § 3175.80 would prescribe standards for the installation, operation, and inspection of flange-tapped orifice plate primary devices. The standards would include requirements described in the proposed rule as well as requirements described in API standards that would be incorporated by reference. Table 1 is included in this proposed section to clarify and provide easy reference to which requirements would apply to different aspects of the primary device and to adopt specific API standards as necessary. The first column of Table 1 lists the subject area for which a standard exists. The second column of Table 1 contains a reference to the standard that applies to the subject area described in the first column. For subject areas where the BLM would adopt an API standard verbatim, the specific API reference is shown. For subject areas where there is
The final four columns of Table 1 indicate the categories of FMPs to which the standard would apply. The FMPs are categorized by the amount of flow they measure on a monthly basis as follows: “M” is marginal-volume, “L” is low-volume, “H” is high-volume, and “V” is very-high volume. Definitions for these various classifications are included in the definitions section in proposed § 3175.10. An “x” in a column indicates that the standard listed applies to that category of FMP. A number in a column indicates a numeric value for that category, such as the maximum number of months or years between inspections and is explained in the body of the proposed standard. The requirements of the proposed rule would vary depending on the average monthly flow rate being measured. In general, the higher the flow rate, the greater the risk of mis-measurement, and the stricter the requirements would be.
Proposed § 3175.80 would adopt API MPMS 14.3.1.4.1, which sets out requirements for the fluid and flowing conditions that must exist at the FMP (
The proposed requirement for maintaining a Reynolds number greater than 4,000 represents a change from Order 5. Order 5 does not have a requirement for a minimum Reynolds number. The Reynolds number is a measure of how turbulent the flow is. Rather than expressed in units of measurement, the Reynolds number is the ratio of inertial forces (flow rate, relative density, and pipe size) to viscous forces. The higher the flow rate, relative density, or pipe size, the higher the Reynolds number. High viscosity, on the other hand, acts to lower the Reynolds number. At a Reynolds number below 2,000, fluid movement is controlled by viscosity and the fluid molecules tend to flow in straight lines parallel to the direction of flow (generally referred to as laminar flow). At a Reynolds number above 4,000, fluid movement is controlled by inertial forces, with molecules moving chaotically as they collide with other molecules and with the walls of the pipe (generally referred to as turbulent flow). Fluid behavior between a Reynolds number of 2,000 and 4,000 is difficult to predict. For all meters using the principle of differential pressure, including orifice meters, the flow equation assumes turbulent flow with a Reynolds number greater than 4,000.
Using a typical gas viscosity of 0.0103 centipoise and 0.7 relative density, a Reynolds number of 4,000 is achieved at a flow rate of 5.8 thousand standard cubic feet per day (Mcf/day) in a 2-inch diameter pipe, 8.7 Mcf/day in a 3-inch diameter pipe, and 11.6 Mcf/day in a 4-inch diameter pipe. The majority of pipe sizes currently used at FMPs are between 2 inches and 4 inches in diameter. Because low-, high-, and very-high volume FMPs all exceed 15 Mcf/day by definition, most FMPs within these categories and with line sizes of 4 inches or less, would operate at Reynolds numbers well above 4,000. Marginal-volume FMPs would be exempt from this requirement. Therefore, adoption of the proposed requirement to maintain a Reynolds number greater than 4,000 would not represent a significant change from existing conditions. The proposed requirement for maintaining a Reynolds number greater than 4,000 for low-, high-, and very-high volume FMPs would help ensure the accuracy of measurement in rare situations where the pipe size is greater than 4 inches or flowing conditions are significantly different from the conditions used in the examples above.
Marginal-volume FMPs could fall below this limit, but would be exempt from the Reynolds number requirement. While the BLM recognizes that measurement error could occur at FMPs with Reynolds numbers below 4,000, it would be uneconomic to require a different type of meter to be installed at marginal-volume FMPs. The BLM recognizes that not maintaining the fluid and flowing conditions recommended by API can cause significant measurement error. However, the measurement error at such low flow rates would not significantly affect royalty, and the potential error in royalty is small compared to the potential loss of royalty if production were shut in.
Proposed § 3175.80 would adopt API MPMS 14.3.2.4, which establishes requirements for orifice plate construction and condition. Orifice plate standards adopted would be virtually the same as they are in the AGA Report No. 3 (1985). No exemptions to this requirement are proposed, since the cost of obtaining compliant orifice plates for most sizes used at FMPs (2-inch, 3-inch, and 4-inch) is minimal and orifice plates not complying with the API standards can cause significant bias in measurement. Therefore, the BLM proposes to incorporate API MPMS 14.3.2.4.
Proposed § 3175.80 would adopt API MPMS 14.3.2.6.2 regarding orifice plate eccentricity and perpendicularity. The term “eccentricity” refers to the centering of the orifice plate in the meter tube and “perpendicularity” refers to the alignment of the orifice plate with respect to the axis of the meter tube. This represents a change from the existing requirements in AGA Report Number 3 (1985), since the eccentricity tolerances are significantly smaller in the new API standard proposed for incorporation, and will reduce the uncertainty of measurement. Eccentricity can affect the flow profile of the gas through the orifice and larger Beta ratio
The proposed section also incorporates a requirement for the orifice plate to be installed perpendicular to the meter tube axis as required by API MPMS 14.3.2.6.2.2. This requirement is not explicitly stated in Order 5. However, virtually all orifice plate holders, new and existing, maintain perpendicularity between the orifice plate and the meter-tube axis. Therefore, the BLM does not anticipate that this proposed change would impose significant costs.
Proposed § 3175.80(a) would redefine the allowable Beta ratio range for flange-tapped orifice meters to be between 0.10 and 0.75, as recommended by API MPMS 14.3.2. Order 5 established Beta ratio limits of 0.15 and 0.70 for meters measuring more than 100 Mcf/day. These limits were based on AGA Report No. 3 (1985), which was the orifice metering standard in effect at the time Order 5 was published. In the early 1990s, additional testing was done on orifice meters, which resulted in an increased Beta ratio range and a more accurate characterization of the uncertainty of orifice meters over this range. The testing also showed that a meter with a Beta ratio less than 0.10 could result in higher uncertainty due to the increased sensitivity of upstream edge sharpness. Meters with Beta ratios greater than 0.75 exhibited increased uncertainty due to flow profile sensitivity. Because this rule would propose to expand the allowable Beta ratio range, it would be slightly less restrictive than Order 5 for high-volume and very-high-volume FMPs.
This section would also apply the Beta ratio limits to low-volume FMPs, which would be a change from Order 5. Order 5 exempts meters measuring 100 Mcf/day or less from the Beta ratio limits. We know of no data showing that bias is not significant for Beta ratios less than 0.10. Generally, if edge sharpness cannot be maintained, it results in a measurement that is biased to the low side. The low limit for the Beta ratio in API MPMS 14.3.2 is based on the inability to maintain edge sharpness in Beta ratios below 0.10. Therefore, there is a potential for bias if the BLM were to allow Beta ratios lower than 0.10. Because the proposed rule would allow Beta ratios as low as 0.10, and Beta ratios less than 0.10 are relatively rare, this change would not be significant.
While the increased sensitivity to flow profile due to Beta ratios greater than 0.75 does not generally result in bias (only an increase in uncertainty), this section also proposes to maintain the upper Beta ratio limit in API MPMS 14.3.2 for low-volume FMPs. It is very rare for an operator to install a large Beta ratio orifice plate on low-volume meters, so the 0.75 upper Beta ratio limit for low-volume FMPs would not be a significant change either.
Marginal-volume FMPs would be exempt from any Beta ratio restrictions in the proposed rule because it can be difficult to obtain a measureable amount of differential pressure with a Beta ratio of 0.10 or greater at very low flow rates. The increased uncertainty and potential for bias by allowing a Beta ratio less than 0.10 on marginal-volume FMPs is offset by the ability to accurately measure a differential pressure and record flow.
Proposed § 3175.80(b) would establish a minimum orifice bore diameter of 0.45 inches for high-volume and very-high-volume FMPs. This would be a new requirement. API MPMS 14.3.1.12.4.1 states: “Orifice plates with bore diameters less than 0.45 inches . . . may have coefficient of discharge uncertainties as great as 3.0 percent. This large uncertainty is due to problems with edge sharpness.” Because the uncertainty of orifice plates
Proposed § 3175.80(c) would require bi-weekly orifice plate inspections for FMPs measuring production from wells first coming into production, which would be a new requirement. It is common for new wells to produce high amounts of sand, grit, and other particulate matter for some initial period of time. This material can quickly damage an orifice plate, generally causing measurement to be biased low. The proposed requirement would increase the orifice plate inspection frequency until it could be demonstrated that the production of particulate matter from a new well first coming into production has subsided. The bi-weekly inspection requirement would apply to existing FMPs already measuring production from one or more other wells through which gas from a new well first coming into production is measured.
Under this proposed rule, once a bi-weekly inspection demonstrates that no detectable wear occurred over the previous 2 weeks, the BLM would consider the well production to have stabilized and the inspection frequency would revert to the frequency proposed in Table 1. There would be no exemptions proposed for this requirement because: (1) Based on the BLM's experience, pulling and inspecting an orifice plate generally takes less than 30 minutes and is a low-cost operation; and (2) In most cases the new requirement would not apply to marginal wells anyway because rarely would a newly-drilled well have only marginal levels of gas production.
Proposed § 3175.80(d) would establish a frequency for routine orifice plate inspections. The term “routine” is used to differentiate this proposed requirement from proposed § 3175.80(c) of this rule for new FMPs measuring production from new wells. Under this rule, the proposed inspection frequency would depend on the average flow rate measured by the FMP. The required inspection frequency, in months, is given in Table 1. More than any other component of the metering system, orifice plate condition has one of the highest potentials to introduce measurement bias and create error in royalty calculations. The higher the flow rate being measured, the greater the risk to ongoing measurement accuracy. Therefore, the higher the flow rate, the more often orifice plate inspections would be required. Order 5 requires orifice plates to be pulled and inspected every 6 months, regardless of the flow rate. For high-volume and very-high-volume FMPs, this proposal would increase the frequency of orifice plate inspections to every 3 months and every month, respectively. For marginal-volume FMPs, the proposed frequency would be reduced to every 12 months, and for low-volume FMPs there would be no change from the existing inspection frequency of every 6 months. Order 5 also requires that an orifice plate inspection take place during the calibration of the secondary device. This requirement would be retained in the proposed rule.
Proposed § 3175.80(e) would require the operator to document the condition of an orifice plate that is removed and inspected. Documentation of the plate inspection can be a useful part of an audit trail and can also be used to detect and track metering problems. Although this would be a new requirement, many meter operators already record this information as part of their meter calibrations. Thus, this requirement would not be a significant change from prevailing industry practice.
Proposed § 3175.80(f) would require meter tubes to be constructed in compliance with current API standards. This proposed requirement would not include meter tube lengths, which would be addressed in proposed § 3175.80(k). The BLM has reviewed the API standards referenced and believes that they meet the intent of § 3175.30 of the proposed rule. Order 5 adopted the meter tube construction standards of the AGA Report No. 3 (1985). A comparison of meter tube construction requirements between the proposed rule and Order 5 is outlined in the following table. The term “Potentially” as used in the table means that a retrofit could be required if the existing meter tube did not meet the requirements of API MPMS 14.3.2. It is possible, for example, that a meter tube constructed before 2000 could still meet the roughness and roundness standards in API MPMS 14.3.2.
The primary difference in meter tube requirements between Order 5 and the proposed rule is the roundness specifications for the meter tube at upstream and downstream locations. The orifice plate uncertainty specifications given in API MPMS 14.3.1 are based on the tighter roundness tolerances proposed in this rule. The roundness specifications in the AGA Report No. 3 (1985) would increase the uncertainty by an unknown amount. However, there is no existing evidence that bias results from a less round pipe, as allowed in the AGA Report No. 3 (1985).
Uncertainty is the risk of mismeasurement; in contrast, bias necessarily results in mismeasurement. For example, an uncertainty of plus or minus 3 percent means that the meter could be reading anywhere between 3 percent low and 3 percent high. On the other hand, a bias of plus 3 percent means the meter is reading 3 percent high. This rule proposes to restrict the amount of allowable risk or uncertainty of measurement in high-volume and very-high-volume meters. To do so, however, the BLM must be able to quantify the individual sources of uncertainty that go into the calculation of overall measurement uncertainty. This rule also proposes to eliminate statistically significant bias in all FMPs other than marginal-volume FMPs.
Proposed § 3175.80(f)(1) and (2) would include an exception allowing low-volume FMPs to continue using the tolerances in the AGA Report No (1985). While the BLM recognizes this could result in higher uncertainty, we are not proposing uncertainty requirements for low-volume FMPs. Since the AGA Report No. 3 (1985) is no longer readily available to the public, and cannot be incorporated by reference, this proposed rule includes an equation in proposed § 3175.80(f)(1) that approximates the roundness tolerance graph in the AGA Report No. 3 (1985).
Marginal FMPs would not be required to meet the construction standards of either API MPMS 14.3.2 (2000) or the 1985 Report No. 3 (AGA), since the cost to bring these meters up to the appropriate standards could be prohibitive based on experience with these production levels.
Proposed § 3175.80(g) would address isolating flow conditioners and tube bundle flow straighteners. To achieve the orifice plate uncertainty stated in API MPMS 14.3.1, the gas flow approaching the orifice plate must be free of swirl and asymmetry. This can be achieved by placing a section of straight pipe between the orifice plate and any upstream flow disturbances such as elbows, tees, and valves. Swirl and asymmetry caused by these disturbances will eventually dissipate if the pipe lengths are long enough. The minimum length of pipe required to achieve the uncertainty stated in API MPMS 14.3.1 is discussed in proposed § 3178.80(k).
Isolating flow conditioners and tube-bundle flow straighteners are designed to reduce the length of straight pipe upstream of an orifice meter by accelerating the dissipation of swirl and asymmetric flow caused by upstream disturbances. Both devices are placed inside the meter tube at a specified distance upstream of the orifice plate. An isolating flow conditioner consists of a flat plate with holes drilled through it in a geometric pattern designed to reduce swirl and asymmetry in the gas flow. A tube bundle is a collection of tubes that are welded together to form a bundle.
Proposed § 3175.80(g) would allow isolating flow conditioners to be used at FMPs if they have been reviewed and approved by the BLM under § 3175.46 of the proposed rule. Isolating flow conditioners are not addressed in Order 5 and currently must be approved on a meter-by-meter basis using the variance process. The approval of isolating flow conditioners in the proposed rule would increase consistency and eliminate the time and expense it takes to apply for and obtain a variance for each FMP.
Proposed § 3175.80(g) would adopt API MPMS 14.3.2.5.5.1 through 14.3.2.5.5.3 regarding the construction of 19-tube-bundle flow straighteners used for flow conditioning. Use of 19-tube-bundle flow straighteners constructed and installed under these API standards would not require BLM approval. Under Order 5, a minimum of four tubes were required in a tube-bundle flow straightener. The proposed rule would require a tube-bundle flow straightener, if used, to consist of 19 tubes because all of the findings in API MPMS 14.3.2.5.5.1 through 14.3.2.5.5.3 are based on 19-tube flow straighteners. Adoption of the proposed rule would prohibit the use of 7-tube-bundle flow straighteners, which are used primarily in 2-inch meters. Additionally, 19-tube-bundle flow straighteners are typically not available in a 2-inch size for these existing meters. A significant number of the meters in use currently are 2-inch in size. Without the ability to use either 7-tube- or 19-tube-bundle flow straighteners, 2-inch meters would be required to be retrofitted to use either: (1) A proprietary type of isolating flow conditioner approved in accordance with proposed § 3175.46; or (2) No flow conditioner, typically requiring much longer lengths of pipe upstream of the orifice plate. Marginal-volume FMPs are proposed to be exempt from the requirement to retrofit because the costs involved are believed to outweigh the benefits based upon experience with these production levels.
Proposed § 3175.80(h) would require an internal visual inspection of all meter tubes at the frequency, in years, shown in Table 1. The visual inspection would have to be conducted using a borescope or similar device (which would obviate the need to remove or disassemble the meter run), unless the operator decided to disassemble the meter run to conduct a detailed inspection, which also would meet the requirements of this proposed paragraph. While an inspection using a borescope or similar device cannot ensure that the meter tube complies with API 14.3.2 requirements, it can identify issues such as pitting, scaling, and buildup of foreign substances that could warrant a detailed inspection under § 3175.80(i) of this proposed rule.
Proposed § 3175.80(i) would require a detailed inspection of meter tubes on
Proposed § 3175.80(j) would require operators to keep documentation of all meter tube inspections performed. The BLM would use this documentation to establish that the inspections met the requirements of the rule, for auditing purposes, and to track the rate of change in meter tube condition to support a change of inspection frequency, if needed. Marginal-volume FMPs would be exempt from this requirement because no meter tube inspections are required.
Proposed § 3175.80(k) would establish requirements for the length of meter tubes upstream and downstream of the orifice plate, and for the location of tube-bundle flow straighteners, if they are used (see discussion of swirl and asymmetry in § 3175.80(g)). Marginal-volume FMPs are proposed to be exempt from the meter tube length requirements because the costs involved in retrofitting the meter tubes are believed to outweigh the benefits based on experience with these production levels.
The pipe length requirements in AGA Report No. 3 (1985) (incorporated by reference in Order 5) were based on orifice plate testing done before 1985. In the early 1990s, extensive additional testing was done to refine the uncertainty and performance of orifice plate meters. This testing revealed that the recommended pipe lengths in the AGA Report No. 3 (1985) were generally too short to achieve the stated uncertainty levels. In addition, the testing revealed that tube bundles placed in accordance with the 1985 AGA Report No. 3 could bias the measured flow rate by several percent.
When API MPMS 14.3.1 was published in 2000, it used the additional test data to revise the meter tube length and tube-bundle location requirements to achieve the stated levels of uncertainty and remove bias. All meter tubes installed after the publication of API MPMS 14.3.2 should already comply with the more stringent requirements for meter tube length and tube-bundle placement.
Because the meter tube lengths in API MPMS 14.3.2 are required to achieve the stated uncertainty, paragraph (k)(1) proposes to adopt these lengths as a minimum standard for high-volume and very-high-volume FMPs. Due to the high production decline rates in many Federal and Indian wells, the BLM does not expect a significant number of meters that were installed prior to 2000, under the AGA Report No. 3 (1985) standards, to still be measuring gas flow rates that would place them in the high-volume or very-high-volume categories. Most high-volume and very-high-volume FMPs were installed after 2000, in compliance with the meter tube length requirements of API MPMS 14.3.2. Therefore, the proposed requirement is not a significant change from existing conditions.
While low-volume FMPs would not be subject to the uncertainty requirements under proposed § 3175.30(a), they still would have to be free of statistically significant bias under proposed § 3175.30(c). Because testing has shown that placement of tube-bundle flow straighteners in conformance with the AGA Report No. 3 (1985) can cause bias, low-volume FMPs utilizing tube-bundle flow straighteners would also be subject to the meter tube length requirements of API MPMS 14.3.2 under proposed paragraph (k)(1).
While this may require some retrofitting of existing meters, the BLM does not expect this to be a significant change for three reasons. First, FMPs installed after 2000 should already comply with the meter tube length and tube-bundle placement requirements of API MPMS 14.3.2. Second, based on the BLM's experience, we estimate that fewer than 25 percent of existing meters use tube-bundle flow straighteners. Third, for those FMPs that would need to be retrofitted, most operators would opt to remove the tube-bundle-flow straightener and replace it with an isolating flow conditioner. Several manufacturers make a type of isolating flow conditioner designed to replace tube bundles without retrofitting the upstream piping. These flow conditioners are relatively inexpensive and would not create an economic burden on the operator for low-volume FMPs.
Proposed paragraph (k)(2) would allow low-volume FMPs that do not have tube-bundle flow straighteners to comply with the less stringent meter tube length requirements of the AGA Report No. 3 (1985). For those meter tubes that do not include tube-bundle flow straighteners, the BLM is not currently aware of any data that shows the shorter meter tube lengths required in the AGA Report No. 3 (1985) result in statistically significant bias. Since the AGA Report No. 3 (1985) is no longer readily available to the public, and cannot be incorporated by reference, this section includes equations that approximate the meter tube length graphs in the AGA Report (1985), Figures 4-8.
Proposed § 3175.80(l) would set standards for thermometer wells, including the adoption of API MPMS 14.3.2.6.5 in proposed § 3175.80(l)(1). While the provisions of the API standard proposed for adoption in the proposed rule are the same as those in the AGA Report No. 3 (1985), several additional items would be added that constitute a change from Order 5. First, proposed § 3175.80(l)(2) would require operators to install the thermometer well in the same ambient conditions as the primary device. The purpose of measuring temperature is to determine the density of the gas at the primary device, which is used in the calculation of flow rate and volume. A 10-degree error in the measured temperature will cause a 1 percent error in the measured flow rate and volume. Even if the thermometer well is located away from the primary device within the distances allowed by API MPMS 14.3.2.6.5, significant temperature measurement error could occur if the ambient conditions at the thermometer well are different. For example, if the orifice plate is located inside of a heated meter house and the thermometer well is located outside of the heated meter house, the measured temperature will be influenced by the ambient temperature, thereby biasing the calculated flow rate. In these situations, the proposed rule would require the thermometer well to be relocated inside of the heated meter house even if the existing location is in compliance with API MPMS 14.3.2.6.5.
Proposed § 3175.80(l)(3) would apply when multiple thermometer wells exist at one meter. Many meter installations include a primary thermometer well for continuous measurement of gas temperature and a test thermometer well, where a certified test thermometer is inserted to verify the accuracy of the
Proposed § 3175.80(l)(4) would require the use of a thermally conductive fluid in a thermometer well. To ensure that the temperature sensed by the thermometer is representative of the gas temperature at the orifice plate, it is important that the thermometer is thermally connected to the gas. Because air is a poor heat conductor, the proposed rule would include a new requirement that a thermally conductive liquid be used in the thermometer well because this would provide a more accurate temperature measurement.
Marginal-volume FMPs would be exempt from the requirement to have thermometer wells because proposed §§ 3175.91(c) and 3175.101(e) would allow operators to estimate flowing temperature in lieu of a temperature measurement for marginal-volume FMPs. Order 5 exempts meters measuring less than 200 Mcf/day from continuous temperature measurement; however, the only alternative to continuous measurement allowed in Order 5 is instantaneous measurement, which still requires a thermometer well. Therefore, the proposed requirement for low-volume, high-volume, and very-high-volume FMPs to have a thermometer well would not constitute a significant change from Order 5.
Proposed § 3175.80(m) would require operators to locate the sample probe as required in § 3175.112(b). This would be a new requirement. The reference to proposed § 3175.112(b) is in proposed § 3175.80(m) because the sample probe is part of the primary device. Please see the discussion of proposed § 3175.112(b) for an explanation of the requirement.
Proposed § 3175.80(n) would include a new requirement for operators to notify the BLM at least 72 hours in advance of a visual or detailed meter-tube inspection or installation of a new meter tube. Because meter tubes are inspected infrequently, it is important that the BLM be given an opportunity to witness the inspection of existing meter tubes or the installation of new meter tubes. Order 5 does not require meter tube inspection. Because meter tube inspections would not be required for marginal FMPs, they would be exempt from this requirement.
Proposed § 3175.90(a) would limit the use of mechanical recorders, also known as chart recorders, to marginal-volume and low-volume FMPs, which would be a change from Order 5. Mechanical recorders would not be allowed at high-volume and very-high-volume FMPs because they may not be able to meet the uncertainty requirements of proposed § 3175.30(a). Mechanical recorders are subject to many of the same uncertainty sources as EGM systems, such as ambient temperature effects, vibration effects, static pressure effects, and drift. In addition, mechanical recorders are vulnerable to other sources of uncertainty such as paper expansion and contraction effects and integration uncertainty. Unlike EGM systems, however, none of these effects have been quantified for mechanical recorders. All of these factors contribute to increased uncertainty and the potential for inaccurate measurement.
Because there is no data which indicate that the use of mechanical recorders results in statistically significant bias, mechanical recorders are proposed to be allowed at low-volume and marginal-volume FMPs due to the limited production from these facilities.
Table 2 was developed as part of proposed § 3175.90 to clarify and provide easy reference to the requirements that would apply to different aspects of mechanical recorders. No industry standards are cited in Table 2 because there are no industry standards applicable to mechanical recorders. The first column of Table 2 lists the subject of the standard. The second column of Table 2 contains a reference to the section and specific paragraph in the proposed rule for the standard that applies to each subject area. (The standards are prescribed in proposed §§ 3175.91 and 3175.92.)
The final two columns of Table 2 indicate the FMPs to which the standard would apply. The FMPs are categorized by the amount of flow they measure on a monthly basis as follows: “M” is marginal-volume FMP and “L” is low-volume FMP. As noted previously, mechanical recorders would not be allowed at high-volume and very-high-volume FMPs; therefore, the table in this section does not include corresponding columns for them. Definitions for the various FMP categories are given in proposed § 3175.10. An “x” in a column indicates that the standard listed applies to that category of FMP. A number in a column indicates a numeric value for that category, such as the maximum number of months or years between inspections, which is explained in the body of the proposed requirement.
Proposed § 3175.91(a) would set requirements for gauge lines, which Order 5 does not address. Gauge lines connect the pressure taps on the primary device to the mechanical recorder and can contribute to bias and uncertainty if not properly designed and installed. For example, a leaking or improperly sloped gauge line could cause significant bias in the differential pressure and static pressure readings. Improperly installed gauge lines can also result in a phenomenon known as “gauge line error” which tends to bias measured flow rate and volume. This is discussed in more detail below.
The proposed requirement in § 3175.91(a)(1) would require a minimum gauge line inside diameter of 0.375” to reduce frictional effects that could result from smaller diameter gauge lines. These frictional effects could dampen pressure changes received by the recorder which could result in measurement error.
Proposed § 3175.91(a)(2) would allow only stainless-steel gauge lines. Carbon steel, copper, plastic tubing, or other material could corrode and leak, thus presenting a safety issue as well as resulting in biased measurement.
Proposed § 3175.91(a)(3) would require gauge lines to be sloped up and away from the meter tube to allow any condensed liquids to drain back into the meter tube. A build-up of liquids in the gauge lines could significantly bias the differential pressure reading.
Proposed requirements in § 3175.91(a)(4) through (7) are intended to reduce a phenomenon known as “gauge line error,” which is caused when changes in differential or static pressure due to pulsating flow are amplified by the gauge lines, thereby causing increased bias and uncertainty. API MPMS 14.3.2.5.4.3 recommends that gauge lines be the same diameter along their entire length, which would be adopted as a minimum standard in proposed paragraph (a)(4).
Proposed §§ 3175.91(a)(5) and (6) are intended to minimize the volume of gas contained in the gauge lines because excessive volume can contribute significantly to gauge-line error whenever pulsation exists. These
Marginal-volume FMPs would be exempt from the requirements of proposed § 3175.91(a) because any bias or uncertainty caused by improperly designed gauge lines of marginal-volume and low-volume FMPs would not have a significant royalty impact.
Proposed § 3175.91(b) would require that all differential pens record at a minimum of 10 percent of the chart range for the majority of the flowing period. This would be a change from Order 5, which has no requirements for the differential pen position for meters measuring 100 Mcf/day or less on a monthly basis. However, the integration of the differential pen when operating very close to the chart hub can cause substantial bias because a small amount of differential pressure could be interpreted as zero, thereby biasing the volume represented by the chart. A reading of at least 10 percent of the chart range will provide adequate separation of the differential pen from the “zero” line while still allowing flexibility for plunger lift operations that operate over a large range. Marginal-volume FMPs would be exempt from this requirement due to the cost associated with compliance.
The proposed rule would eliminate the current requirement in Order 5 that the static pen operate in the outer 2/3 of the chart range for the majority of the flowing period, regardless of flow rate. The primary purpose of this requirement in Order 5 was to reduce measurement uncertainty caused by the operation of the static pen near the hub. However, because proposed § 3175.30(a) would exempt marginal-volume and low-volume FMPs from uncertainty limitations, this requirement would no longer be necessary thereby relieving an operational burden at these FMPs.
Proposed § 3175.91(c) would require the flowing temperature to be continuously recorded for low-volume FMPs. Flowing temperature is needed to determine flowing gas density, which is critical to determining flow rate and volume. Order 5 requires continuous temperature measurement only for meters measuring more than 200 Mcf/day. For meters flowing 200 Mcf/day or less, the use of an indicating thermometer is allowed under Order 5. Typically, an indicating thermometer is inserted into the thermometer well during a chart change. That instantaneous value of flowing temperature is used to calculate volume for the chart period. This introduces a significant potential bias into the calculations. If, for example, the temperature is always obtained early in the morning, then the flowing temperature used in the calculations will be biased low from the true average value due to lower morning ambient temperatures. A continuous temperature recorder is used to obtain the true average flowing temperature over the chart period with no significant bias. Because proposed § 3175.30(c) would prohibit bias that is statistically significant for low-volume FMPs, we propose applying the requirement for continuous recorders to low-volume FMPs, but not to marginal-volume FMPs, as specified in Table 2.
Proposed § 3175.91(d) would require certain information to be available on-site at the FMP and available to the AO at all times. This requirement would allow the BLM to calculate the average flow rate indicated by the chart and to verify compliance with this rule. The information that would be required under proposed § 3175.91(d)(2), (3), (7), and (8) is not required under Order 5, but typically is already available on-site. For example, the static pressure and temperature element ranges are stamped into the elements and are visible to BLM inspectors, and the meter-tube inside diameter is typically stamped into the downstream flange or is on a tag as part of the device holder, making it visible and available to the BLM. Therefore, because this information is typically already available on site, the proposed requirement would not be a significant change from current industry practice.
The information that the operator would have to retain on-site at the FMP under proposed § 3175.91(d)(1), (4), (5), (6), (9), (10), (11), (12), and (13) is not currently required and thus typically has not been maintained on-site as a matter of practice. This proposed requirement therefore represents a change from Order 5. The required information proposed in these paragraphs includes the differential pressure bellows range, the relative density of the gas, the units of measure for static pressure (psia or psig), the meter elevation, the orifice bore diameter, the type and location of flow conditioner, the date of the last orifice plate inspection, and the date of the last meter verification. The BLM is proposing to require this information to be maintained on-site to enable the AO to determine if the meter is operating in compliance with this proposed rule and to determine the reasonableness of reported volume.
Proposed § 3175.91(e) would require the differential pressure, static pressure, and temperature elements to be operated within the range of the respective elements. Operating any of the elements beyond the upper range of the element will cause the pen to record off the chart. When a chart is integrated to determine volume, any parameters recorded off the chart will not be accounted for, which results in biased measurement. Although this would be a new requirement, operating a mechanical recorder within the range of the elements is common industry practice and would not constitute a significant change.
Proposed § 3175.92(a) would set requirements for the verification and calibration of mechanical recorders upon installation or after repairs, and would define the procedures that operators would be required to follow. Order 5 also requires a verification of mechanical recorders upon installation or after repairs. This proposal would be a minor change to Order 5 requirements because the proposed rule differentiates the procedures that are specific to this type of verification from a routine verification that would be required under § 3175.92(b) of the proposed rule.
Proposed § 3175.92(a)(1) would require the operator to perform a successful leak test before starting the mechanical recorder verification. While the requirement for a leak test is in Order 5, the proposed rule would specify the tests that operators would have to perform. We are proposing this level of specificity because it is possible to perform leak tests without ensuring that all valves, connections, and fittings are not leaking. Leak testing is necessary because a verification or calibration done while valves are leaking could result in significant meter bias. A provision would also be added to this section requiring a successful leak test to precede a verification. This is implied in Order 5, but not explicitly stated.
Proposed § 3175.92(a)(2) would require that the differential- and static-pressure pens operate independently of each other, which is accomplished by adjusting the time lag between the pens. Although Order 5 includes a requirement for a time-lag test, the specific amount of required time lag would be new to this proposed rule. Examples of appropriate time lag are given for a 24-hour chart and an 8-day
Proposed § 3175.92(a)(3) would require a test of the differential pen arc. This is the same as the requirement Order 5.
Proposed § 3175.92(a)(4) would require an “as left” verification to be done at zero percent, 50 percent, 100 percent, 80 percent, 20 percent, and zero percent of the differential and static element ranges. This would be a change from Order 5, which only requires a verification at zero and 100 percent of the element range and the normal operating position of the pens. The additional verification points would help ensure that the pens have been properly calibrated to read accurately throughout the element ranges. This section also clarifies the verification of static pressure when the static pressure pen has been offset to include atmospheric pressure. In this case, the element range is assumed to be in pounds per square inch, absolute (psia) instead of pounds per square inch, gauge (psig). For example, if the static pressure element range is 100 psig and the atmospheric pressure at the meter is 14 psia, then the calibrator would apply 86 psig to test the “100 percent” reading as required in proposed § 3175. 92(a)(4)(iii). This prevents the pen from being pushed off the chart during verification. As-found readings are not required in this section because as-found readings would not be available for a newly installed or repaired recorder.
Proposed § 3175.92(a)(5) would require a verification of the temperature element to be done at approximately 10 °F below the lowest expected flowing temperature, approximately 10 °F above the highest expected flowing temperature, and at the expected average flowing temperature. This would be a change from Order 5, which has no requirements for verification of the temperature element. This requirement would ensure that the temperature element is recording accurately over the range of expected flowing temperature.
Proposed § 3175.92(a)(6) would establish a threshold for the amount of error between the pen reading on the chart and the reading from the test equipment that is allowed in the differential pressure element, static pressure element, and temperature element being installed or repaired. If any of the required test points are not within the values shown in Table 2-1, the element must be replaced. The threshold for the differential pressure element is 0.5 percent of the element range and 1.0 percent of the range for the static pressure element. These thresholds are based on the published accuracy specifications for a common brand of mechanical recorders used on Federal and Indian land (“Installation and Operation Manual, Models 202E and 208E″, ITT Barton Instruments, 1986, Table 1-1). The threshold for the temperature element assumes a typical temperature element range of 0-150 °F with an assumed accuracy of ±1.0 percent of range. This yields a tolerance of 1.5 °F which was rounded up to 2 °F for the sake of simplicity. The proposed requirement is less restrictive than the language of Order 5, which requires “zero” error for all three elements. Our experience over the last 3 decades indicates that a zero error is unattainable.
Proposed § 3175.92(a)(7) would establish standards for when the static-pressure pen is offset to account for atmospheric pressure. This would be a new requirement. The equation used to determine atmospheric pressure is discussed in Appendix 2 of this proposed rule. This rule proposes to add the requirement to offset the pen before obtaining the as-left values to ensure that the pen offset did not affect the calibration of any of the required test points.
Proposed § 3175.92(b) would establish requirements for how often a routine verification must be performed, with the minimum frequency, in months, shown in Table 2 in proposed § 3175.90. Under Order 5, a verification must be conducted every 3 months. This proposed rule would continue to require verification every 3 months for a low-volume FMP and would reduce the required frequency to every 6 months for a marginal-volume FMP. The required routine verification frequency for a chart recorder is twice as frequent as it is for an EGM system at low- and marginal-volume FMPs because chart recorders tend to drift more than the transducers of an EGM system.
Proposed § 3175.92(c) would establish procedures for performing a routine verification. These procedures would vary from the procedures used for verification after installation or repair, which are discussed in proposed § 3175.92(a).
Proposed § 3175.92(c)(1) would require that a successful leak test be performed before starting the verification. See the previous discussion of leak testing under proposed § 3175.92(a)(1). Section 3175.92(c)(2) would prohibit any adjustments to the recorder until the as-found verifications are obtained. Although this is not an explicit requirement in Order 5, it is general industry practice to obtain the as-found readings before making adjustments. However, some adjustments that have traditionally been allowed under Order 5 would be specifically prohibited under this proposed rule. For example, some meter calibrators will zero the static pressure pen to remove the atmospheric-pressure offset before obtaining any as-found values. Once the pen has been zeroed it is no longer possible to determine how far off the pen was reading prior to the adjustment, thus making it impossible to determine whether or not a volume correction would be required under 3175.92(f). This proposed section would make it clear that no adjustments, including the previous example, are allowed before obtaining the as-found values.
Proposed § 3175.92(c)(3) would require an as-found verification to be done at zero percent, 50 percent, 100 percent, 80 percent, 20 percent, and zero percent of the differential and static element ranges. This would be a change from Order 5, which only requires a verification at zero and 100 percent of the element range and the normal operating position of the pens. The additional verification points were included to better identify pen error over the chart range. Mechanical recorders are generally more susceptible to varying degrees of recording error (sometimes referred to as an “S” curve) than EGM systems.
Proposed § 3175.92(c)(3)(i) would require that an as-found verification be done at a point that represents where the differential and static pens normally operate. This is the same requirement that is in Order 5. This section would require verification at the points where the pens normally operate only if there is enough information on-site to determine where these points are.
Proposed § 3175.92(c)(3)(ii) would establish additional requirements if there is not sufficient information on site to determine the normal operating points for the differential pressure and static pressure pens. The most likely example would be when the chart on the meter at the time of verification has just been installed and there were no historical pen traces from which to determine the normal operating values. In these cases, additional measurement points would be required at 5 percent and 10 percent of the element range to ensure that the flow-rate error can be accurately calculated once the normal operating points are known. The amount of flow-rate error is more sensitive to pen error at the lower end of the element range than at the upper end of the range. Therefore, more
Proposed § 3175.92(c)(4) would establish standards for determining the as-found value of the temperature pen. In a flowing well, the use of a test-thermometer well is preferred because it more closely represents the flowing temperature of the gas compared to a water bath, which is often set at an arbitrary temperature. However, if the meter is not flowing, temperature differences within the pipeline may occur, which have the potential to introduce error between the primary-thermometer well and the test-thermometer well, thereby causing measurement bias. If the meter is not flowing, temperature verification must be done using a water bath. Order 5 has no requirements for determining the as-found values of flowing temperature and therefore this would be a new requirement.
Proposed § 3175.92(c)(5) would establish a threshold for the degree of allowable error between the pen reading on the chart and the reading from the test equipment for the differential, static, or temperature element being verified. If any of the required points to be tested, as defined in proposed § 3175.92(c)(3) or (4), are not within these thresholds, the element must be calibrated. For a discussion of the thresholds, see previous discussion of proposed § 3175.92(a)(6) and (7). The proposed requirement is less restrictive than the language of Order 5, which requires that the meter (differential pressure, static pressure, and temperature elements) be adjusted to “zero” error. In our experience over the last 3 decades, a zero error is unattainable.
Proposed § 3175.92(c)(6) would require that the differential- and static-pressure pens operate independently of each other, which is accomplished by adjusting the time lag between the pens. Please see previous discussion of proposed § 3175.92(a)(3) for further explanation of this proposed requirement.
Proposed § 3175.92(c)(7) would require a test of the differential-pen arc. This is the same as the requirement in Order 5.
Proposed § 3175.92(c)(8) would require an as-left verification if an adjustment to any of the meter elements was made. As-left readings are implied in Order 5 because the operator is required to adjust the meter to zero error. Obtaining as-left readings whenever a calibration is performed is also standard industry practice. The purpose of the as-left verification is to ensure that the calibration process, required in proposed § 3175.92(c)(5) through (7), was successful before returning the meter to service.
Proposed § 3175.92(c)(9) would establish a threshold for the amount of error allowed in the differential, static, or temperature element after calibration. If any of the required test points, as defined in proposed § 3175.92(c)(3) and (4), are not within the thresholds shown in Table 2-1, the element must be replaced and verified under proposed § 3175.92(c)(5) through (7). The proposed requirement is less restrictive than the language of Order 5, which requires that the meter (differential pressure, static pressure, and temperature elements) be adjusted to “zero” error. In our experience over the last 3 decades, a zero error is unattainable.
Proposed § 3175.92(c)(10) would establish standards if the static-pressure pen is offset to account for atmospheric pressure. Please see previous discussion of proposed § 3175.92(a)(7) for further explanation of this proposed requirement.
Marginal-volume FMPs would not be exempt from any of the verification or calibration requirements in proposed § 3175.92(c) because these requirements would not result in significant additional cost and are necessary to reduce potential measurement bias.
Proposed § 3175.92(d) would establish the minimum information required on a verification/calibration report. The purpose of this documentation is to: (1) Identify the FMP that was verified; (2) Ensure that the operator adheres to the proper verification frequency; (3) Ascertain that the verification/calibration was performed according to the requirements established in proposed § 3175.92(a) through (c), as applicable; (4) Determine the amount of error in the differential-pressure, static-pressure, and temperature pens; (5) Verify the proper offset of the static pen, if applicable; and (6) Allow the determination of flow rate error. The proposed rule would require documentation similar to Order 5, with the addition of the normal operating points for differential pressure, static pressure, flowing temperature, and the differential-device condition. The proposed rule would add the documentation requirement for the normal operating points to allow the BLM to confirm that the proper points were verified and to allow error calculation based on the applicable verification point. The proposed rule would require the primary-device documentation because the primary device is pulled and inspected at the same time as the operator performs a mechanical-recorder verification.
Proposed § 3175.92(e) would require the operator to notify the AO at least 72 hours before verification of the recording device. Order 5 requires only a 24-hour notice. The BLM proposes a longer notification period because a 24-hour notice is generally not enough time for the AO to be present at a verification. A 72-hour notice would be sufficient for the BLM to rearrange schedules, as necessary, to be present at the verification.
Proposed § 3175.92(f) would require the operator to correct flow-rate errors that are greater than 2 Mcf/day, if they are due to the chart recorder being out of calibration, by submitting amended reports to ONRR. Order 5 requires operators to submit amended reports if the error is greater than 2 percent regardless of how much flow the error represents. The 2 Mcf/day flow-rate threshold would eliminate the need for operators to submit—and the BLM to review—amended reports on low-volume meters, where a 2 percent error does not constitute a sufficient volume of gas to justify the cost of processing amended reports. The BLM derived the 2 Mcf/day threshold by multiplying the 2 percent threshold in Order 5 by 100 Mcf/day, which is the maximum flow-rate allowed to be measured with a chart recorder. Marginal-volume FMPs would be exempt from this requirement because the volumes are so small that even relatively large errors discovered during the verification process would not result in significant lost royalties or otherwise justify the costs involved in producing and reviewing amended reports. For example, if an operator discovered that an FMP measuring 15 Mcf/day was off by 10 percent (a very large error based on the BLM's experience) while performing a verification under this section, that would amount to a 1.5 Mcf/day error which, over a month's period, would be 45 Mcf. At $4 per Mcf, that error could result in an under- or over-payment in royalty of $22.50. It could take several hours for the operator to develop and submit amended OGOR reports and it could take several hours for both the BLM and ONRR to review and process those reports.
This proposed paragraph would also clarify a similar requirement in Order 5 by defining the points that are used to determine the flow-rate error. Calculated flow-rate error will vary depending on the verification points
Proposed § 3175.92(g) would require verification equipment to be certified at least every 2 years. The purpose of this requirement would be to ensure that the verification or calibration equipment meets its specified level of accuracy and does not introduce significant bias into the field meter during calibration. Two-year certification of verification equipment is typically recommended by the verification equipment manufacturer, and therefore, this does not represent a major change from existing procedures, although this would be a new requirement in this rule. The proposed paragraph would also require that proof of certification be available to the BLM and would set minimum standards as to what the documentation must include. Although this would also be a new requirement, it represents common industry practice.
Proposed § 3175.93 would establish minimum standards for chart integration statements. The purpose of requiring the information listed is to allow the BLM to independently verify the volumes of gas reported on the integration statement. Currently, the range of information available on integration statements varies greatly. In addition, many integration statements lack one or more items of critical information necessary to verify the reported volumes. The BLM is not aware of any industry standards that apply to chart integration. This would be a new requirement.
Proposed § 3175.94(a) would establish the methodology for determining volume from the integration of a chart. The methodology would include the adoption of the equations published in API MPMS 14.3.3 or AGA Report No. 3 (1985) for flange-tapped orifice plates. Under this proposal, operators using mechanical recorders would have the option to continue using the older AGA Report No. 3 (1985) flow equation. (Operators using EGM systems, on the other hand, would be required to use the flow equations in API 14.3.3 (2013) (see proposed § 3175.103).)
There are three primary reasons for allowing mechanical recorders to use a less strict standard. First, chart recorders, unlike EGM systems, would be restricted to FMPs measuring 100 Mcf/day or less. Therefore, any errors caused by using the older 1985 flow equation would not have nearly as significant of an effect on measured volume or royalty than they would for a high- or very-high-volume meter. Second, the BLM estimates that only 10 to 15 percent of FMPs still use mechanical recorders, and this number is declining steadily. This fact, combined with the proposed 100 Mcf/day flow rate restriction, means that only a small percentage of gas produced from Federal and Indian leases is measured using a mechanical recorder, significantly lowering the risk of volume or royalty error as a result of using the older 1985 equation. Third, it may be economically burdensome for a chart integration company to switch over to the new API 14.3.3 flow equations because much of the equipment and procedures used to integrate charts was established before the revision of AGA Report No. 3 (1985). The BLM is seeking data on the cost for chart integration companies to switch over to the new API MPMS 14.3.3 flow rate.
There are two variables in the API 14.3.3 flow equation that have changed since 1985. The current API equation includes a more accurate curve fit for determining the discharge coefficient (C
While API MPMS 14.3.3 provides equations for calculating instantaneous flow rate, it is silent on determining volume. Therefore, the methodology presented in API MPMS 21.1 for EGM systems would be adapted in this section for volume determination. This methodology is generally consistent with existing methods for chart integration and, as such, should not require any significant modifications. For primary devices other than flange-tapped orifice plates, the BLM would approve, based on the PMT's recommendation, the equations that would be used for volume determination.
Proposed § 3175.94(a)(3) defines the source of the data that goes into the flow equation.
Proposed § 3175.94(b) would establish a standard method for determining atmospheric pressure used to convert pressure measured in psig to units of psia, which is used in the calculation of flow rate. Any error in the value of atmospheric pressure will cause errors in the calculation of flow rate, especially in meters that operate at low pressure. Order 5 requires the use of the atmospheric pressure defined in the buy/sell contract, if specified. If it is not specified, Order 5 requires atmospheric pressure to be determined through a measurement or a calculation based on elevation. The BLM is proposing to eliminate the use of a contract value for atmospheric pressure because contract provisions are not always in the public interest and do not always dictate the best measurement practice. A contract value that is not representative of the actual atmospheric pressure at the meter will cause measurement bias, especially in meters where the static pressure is low.
This rule also proposes to eliminate the option of operators measuring actual atmospheric pressure at the meter location for mechanical recorders. Instead, atmospheric pressure would be determined from an equation or Table (see Appendix 2) based on elevation. Atmospheric pressure is used in one of two ways for a mechanical recorder. First, the static-pressure reading from the chart in psig is converted to absolute pressure during the integration process by adding atmospheric pressure to the static pressure reading. Or, second, the static pressure pen can be offset from zero in an amount that represents atmospheric pressure. In the second case, the static-pressure line on the chart already has atmospheric pressure added to it and no further corrections are made during the integration of the charts. The static-pressure element in a chart recorder is a gauge pressure device—in other words, it measures the difference between the pressure from the pressure tap and atmospheric pressure. Offsetting the pen does not convert it into an absolute pressure device; it is only a convenient way to convert gauge pressure to atmospheric pressure. If measured atmospheric pressure were allowed, the measurement could be made when, for example, a low-pressure weather system was over the area. The measured atmospheric pressure in this example would not be representative of the average atmospheric pressure and would bias the measurements to the low side. This is much more critical in meters operating at low pressure than in meters operating at high pressure. The BLM believes that operators rarely use measured atmospheric pressure to offset the static pressure; therefore, this change would have no significant impact on current industry practice. The
The equation to determine atmospheric pressure from elevation (“U.S. Standard Atmosphere”, National Aeronautics and Space Administration, 1976 (NASA-TM-X-74335)), prescribed in Appendix 2 to the proposed rule, produces similar results to the equation normally used for atmospheric pressure for elevations less than 7,000 feet mean sea level (see Figure 3).
Proposed § 3175.100 would set standards for the installation, operation, and inspection of EGM systems used for FMPs. The proposed standards include requirements prescribed in the proposed rule as well as requirements in referenced API documents. Table 3 was developed as part of proposed § 3175.100 to clarify and provide easy reference to what requirements apply to different aspects of EGM systems and to adopt specific API standards as necessary. The first column of Table 3 lists the subject area for which a standard is proposed. The second column of Table 3 contains a reference for the standard that would apply to the subject area described in the first column (by section number and paragraph, mostly in proposed §§ 3175.101 through 3175.104). The final four columns of Table 3 indicate the FMP categories to which the standard would apply. As is the case in other tables, the FMPs are categorized by the amount of flow they measure on a monthly basis as follows: “M” is marginal-volume FMP, “L” is low-volume FMP, “H” is high-volume FMP, and “V” is very-high-volume FMP. Definitions for the various classifications are given in proposed § 3175.10. An “x” in a column indicates that the standard listed applies to that category of FMP. A number in a column indicates a numeric value for that category, such as the maximum number of months between inspections. For example, the maximum time between verifications, in months, is shown in Table 3 under “Routine verification frequency.” Any character in a column other than an “x” is explained in the body of the proposed standard.
Proposed § 3175.100 would adopt API MPMS 21.1.7.3, regarding EGM equipment commissioning; API MPMS 21.1.9, regarding access and data security; and API MPMS 21.4.4.5, regarding the no-flow cutoff. The BLM has reviewed these sections and believes they are appropriate for use at FMPs. The existing statewide NTLs referenced similar sections in the previous version of API MPMS 21.1 (1993); therefore, this is not a significant change from existing requirements.
Proposed § 3175.101(a) would set requirements for manifolds and gauge lines, which are not addressed in Order 5. Gauge lines connect the pressure taps on the primary device to the EGM secondary device and can contribute to bias and uncertainty if not properly designed and installed. (The requirements in this proposed section are similar to the requirements for installation and operation of gauge lines used in mechanical recorders.)
It is standard industry practice to install gauge lines with a minimum inside diameter of 0.375″, as is proposed in § 3175.101(a)(1). The intent of this standard is to reduce frictional effects potentially caused by smaller line sizes.
Proposed § 3175.101(a)(2) would be a new requirement that gauge lines be made only of stainless steel. Carbon steel, copper, plastic tubing, or other material could corrode and leak, presenting a safety issue as well as biased measurement.
Proposed § 3175.101(a)(3) would require gauge lines to be sloped up and away from the meter tube to allow any condensed liquids to drain back into the meter tube. A build-up of liquids in the gauge lines could significantly bias the differential pressure reading. While both of these requirements are new, they do not represent a significant change from standard industry practice.
The requirements in proposed § 3175.101(a)(1), (4), (5), (6) and (7) are intended to reduce a phenomenon known as “gauge line error,” caused when changes in differential or static pressure due to pulsating flow are amplified by the gauge lines, thereby causing increased bias and uncertainty. API MPMS 14.3.2.5.4.3 recommends that gauge lines be the same diameter along their entire length, which would be adopted as a minimum standard in proposed § 3175.101(a)(4).
Proposed §§ 3175.101(a)(5) and (6) are intended to minimize the volume of gas contained in the gauge lines because excessive volume can contribute significantly to gauge-line error whenever pulsation exists. These paragraphs would prohibit anything except the static-pressure connection in a gauge line, and are intended to prohibit the practice of connecting multiple secondary devices to a single set of pressure taps, the use of drip pots, and the use of gauge lines as a source for pressure-regulated control valves and other equipment. A second set of transducers would be allowed if the operator chooses to employ redundancy verification. Proposed § 3175.101(a)(7) would limit the gauge lines to 6 feet in length, again to minimize the amount of gas volume contained in the gauge lines. Both of these requirements would be new.
Marginal-volume FMPs would be exempt from the requirements of proposed § 3175.101(a) because the potential effect on royalty would be minimal and our experience suggests that the costs would outweigh potential royalty benefits.
Proposed § 3175.101(b) and (c) would specify the minimum information that the operator would have to maintain on site for an EGM system and make available to the BLM for inspection. The purpose of the data requirements in these sections is to allow BLM inspectors to: (1) Verify the flow-rate calculations being made by the flow computer; (2) Compare the daily volumes shown on the flow computer to the volumes reported to ONRR; (3) Determine the uncertainty of the meter; (4) Determine if the Beta ratio is within the required range; (5) Determine if the upstream and downstream piping meets minimum standards; (6) Determine if the thermometer well is properly placed; (7) Determine if the flow computer and transducers have been type-tested under the protocols described in proposed §§ 3175.130 and 3175.140; (8) Verify that the primary device has been inspected at the required frequency; and (9) Verify that the transducers have been verified at the required frequency.
Proposed § 3175.101(b) would require that each EGM system include a display and would set minimum requirements for the information to be displayed. The proposed requirements are similar to existing requirements in paragraph 4 of the statewide NTLs for EFCs with the following additions and modifications:
(1) Proposed § 3175.101(b)(3) would require the units of measure to be on the display; in contrast, the statewide NTLs only require the units of measure to be on site. We propose this change because of the potential to misidentify the units of measure on the data card that would otherwise be required.
(2) Instead of a meter identification number as currently required, § 3175.101(b)(4)(i) would require the
(3) The software version requirement proposed in § 3175.101(b)(4)(ii) is in addition to existing requirements and would be used to ensure that the software version in use has gone through the testing protocol proposed in §§ 3175.130 and 3175.140.
(4) The previous day flow time proposed in § 3175.101(b)(4)(viii) would be a new requirement to allow the calculation of average daily flow rate.
(5) The previous day average differential pressure, static pressure, and flowing temperature proposed in § 3175.101(b)(4)(ix), (x), and (xi), respectively, would be new requirements which would provide the BLM with average values to use in the determination of uncertainty and would define the “normal” operating point for verification purposes. The BLM proposes these requirements because instantaneous values are often not representative of typical operating conditions, especially in meters that experience highly variable flow rates such as those associated with plunger lift operations.
(6) The proposed requirement for displaying relative density in § 3175.101(b)(4)(xii) would be a new requirement because relative density is typically updated every time a new gas analysis is obtained and the updates are often done remotely, making it difficult to update a data card in a timely manner.
(7) The primary device information proposed in § 3175.101(b)(4)(xiii) would be required because the size can change every time an orifice plate or other type of primary device is changed and the calculation of flow rate is based on these values.
(8) Proposed § 3175.101(b)(5) would require that the instantaneous values be displayed consecutively to allow a more accurate verification of the instantaneous flow rate. The more time that passes between the display of instantaneous data, the more the flow rate can change over that time and the less accurate the verification is.
Proposed § 3175.101(c) would set requirements for information that must be on site, but not necessarily on the EGM system display. These requirements are similar to the requirements of the statewide NTLs for EFCs, with the following additions and modifications:
(1) The elevation of the FMP that would be required under proposed § 3175.101(c)(1) would allow the BLM to verify the value of atmospheric pressure used to derive the absolute static pressure.
(2) Proposed § 3175.101(c)(3) would require the make, model, and location of flow conditioners to be identified to ensure that all flow conditioners have been approved by the BLM and installed according to BLM requirements.
(3) Proposed § 3175.101(c)(4) would require that the location of 19-tube-bundle flow straighteners (if used) be indicated in the on-site records so that BLM inspectors can verify that they have been installed to API specifications.
(4) The flow computer make and model number that would be required under proposed § 3175.101(c)(5) and (c)(6) would allow the BLM to verify that the flow computer has been tested under the protocol described in proposed § 3175.140 and has been approved by the BLM as required in proposed § 3175.44.
(5) Proposed § 3175.101(c)(9) and (c)(10) would add requirements to maintain on site the dates of the last primary-device inspection and secondary-device verification. This would allow the BLM to determine whether the meter is being inspected and verified as required under proposed §§ 3175.80(c), 3175.80(d), 3175.92(b) and 3175.102(b). Proposed requirements in § 3175.101(c)(2), (3), (7) and (8) are the same as the existing requirements in the statewide NTLs for EFCs.
Proposed § 3175.101(d) would require the differential pressure, static pressure, and temperature transducers to be operated within the lower and upper calibrated limits of the transducer. Inputs that are outside of these limits would be subject to higher uncertainty and if the transducer is over-ranged, the readings may not be recorded The term “over-ranged” means that the pressure or temperature transducer is trying to measure a pressure or temperature that is beyond the pressure or temperature it was designed or calibrated to measure. In some transducers—typically older ones—the transducer output will be the maximum value for which it was calibrated, even when the pressure being measured exceeds that value. For example, if a differential pressure transducer that has a calibrated range of 250 inches of water is measuring a differential pressure of 300 inches of water, the transducer output will be only 250 inches of water. This results in loss of measured volume and royalty. Many newer transducers will continue to measure values that are over their calibrated range; however, because the transducer has not been calibrated for these values, the uncertainty may be higher than the transducer specification indicates.
Proposed § 3175.101(e) would require the flowing-gas temperature to be continuously recorded. Flowing temperature is needed to determine flowing gas density, which is critical to determining flow rate and volume. Order 5 requires continuous temperature measurement for meters measuring more than 200 Mcf/day, while the proposed rule would require continuous temperature measurement on all FMPs except marginal-volume FMPs. Marginal-volume FMPs would be exempt from this requirement because the potential effect on royalty would be minimal and our experience suggests that the costs would outweigh potential royalty. For marginal-volume FMPs, any errors introduced by using an estimated temperature in lieu of a measured temperature would not have a significant impact on royalties.
Proposed § 3175.102(a) would include several specific requirements for the verification and calibration of transducers following installation and repair. Order 5 also requires a verification upon installation or after repairs. This would be a minor change to Order 5 to differentiate the procedures that are specific to this type of verification from the procedures required for a routine verification under proposed § 3175.102(c). The primary difference between proposed §§ 3175.102(a) and (c) is that an as-found verification would not be required if the meter is being verified following installation or repair.
Proposed § 3175.102(a)(1) would require a leak test before performing a verification or calibration. (Please see the previous discussion regarding proposed § 3175.92(a)(1) for further explanation of leak testing.)
Proposed § 3175.102(a)(2) would require a verification to be done at the points required by API MPMS 21.1.7.3.3 (zero percent, 25 percent, 50 percent, 100 percent, 80 percent, 20 percent, and zero percent of the calibrated span of the differential-pressure and static-pressure transducers, respectively). This would be an addition to the requirements of Order 5 and the statewide NTLs for EFCs, and would include more verification points than are required for a routine verification described in proposed § 3175.102(c). The purpose of requiring more verification points in this section would be: (1) For new installations, the normal operating points for differential and static pressure may not be known because of a lack of historical operating information; and (2) A more rigorous
Proposed § 3175.102(a)(3) would also require the operator to calculate the value of atmospheric pressure used to calibrate an absolute-pressure transducer from elevation using the equation or table given in Appendix 2 of the proposed rule, or be based on a measurement made at the time of verification for absolute-pressure transducers in an EGM system. This would be a change from requirements in Order 5 because under this proposal, the value for atmospheric pressure defined in the buy/sell contract would no longer be allowed unless it met the requirements stated in this section. The BLM is proposing to eliminate the use of a contract value for atmospheric pressure because contract provisions are not always in the public interest, and they do not always dictate the best measurement practice. A contract value that is not representative of the actual atmospheric pressure at the meter will cause measurement bias, especially in meters where the static pressure is low. If a barometer is used to determine the atmospheric pressure, the barometer must be certified by the National Institute of Standards and Technology (NIST) and have an accuracy of ±0.05 psi, or better. This will ensure the value of atmospheric pressure entered into the flow computer during the verification process represents the true atmospheric pressure at the meter station.
This proposed requirement is different from the requirements in proposed § 3175.94(b) for the treatment of atmospheric pressure in connection with mechanical recorders. The difference results from the design of the pressure measurement device—whether it is a gauge pressure device or an absolute pressure device. A gauge pressure device measures the difference between the applied pressure and the atmospheric pressure. An absolute pressure device measures the difference between the applied pressure and an absolute vacuum.
The use of a barometer to determine atmospheric pressure would be allowed only when calibrating an absolute pressure transducer. It would not be allowed for gauge pressure transducers. Because all mechanical recorders are gauge pressure devices (even if the pen has been offset to account for atmospheric pressure), the use of a barometer to establish atmospheric pressure would not be allowed.
Proposed § 3175.102(a)(4) would require the operator to re-zero the differential pressure transducer under working pressure before putting the meter into service. Differential pressure transducers are verified and calibrated by applying known pressures to the high side of the transducer while leaving the low side vented to the atmosphere. When a differential pressure transducer is placed into service, the transducer is subject to static (line) pressure on both the high side and the low side (with small differences in pressure between the high and low sides due to flow). The change from atmospheric pressure conditions to static pressure conditions can cause all the readings from the transducer to shift, usually by the same amount.
Typically, the higher the static pressure is, the more shift occurs. Zero shift can be minimized by re-zeroing the differential pressure transducer when the high side and low side are equalized under static pressure. The re-zeroing proposed in this section would be a new requirement that would eliminate measurement errors caused by static pressure zero-shift of the differential pressure transducer. Re-zeroing is recommended in API MPMS 21.1.8.2.2.3, but not required. The BLM proposes to require it here.
Proposed § 3175.102(b) would establish requirements for how often a routine verification must be done where the minimum frequency, in months, is shown in Table 3 in proposed § 3175.100. Under Order 5, a verification must be conducted every 3 months. The proposed rule would require a verification every month for very-high-volume FMPs, every 3 months for high-volume FMPs, every 6 months for low-volume FMPs, and every 12 months for marginal-volume FMPs. Because there is a greater risk of measurement error for volume calculation for a given transducer error at higher-volume FMPs, the proposed rule would increase the verification frequency as the measured volume increases.
Proposed § 3175.102(c) would adopt the procedures in API MPMS 21.1.8.2 for the routine verification and calibration of transducers with a number of additions and clarifications. Order 5 also requires a routine verification. The primary difference between § 3175.102(a) and (c) is that an as-found verification is required for routine verifications.
Proposed § 3175.102(c)(1) would require a leak test before performing a verification. A leak test is not specified in API MPMS 21.1.8.2; however, the BLM believes that performing a leak test is critical to obtaining accurate measurement. Please see previous discussion of proposed § 3175.92(a)(1) for further explanation of leak testing.
Proposed § 3175.102(c)(2) and (3) would require that the operator perform a verification at the normal operating point of each transducer. This clarifies the requirements in API MPMS 21.1.8.2.2.3, which requires a verification at either the normal point or 50 percent of the upper user-defined operating limit. This section would also define how the normal operating point is determined because this is a common point of confusion for operators and the BLM.
Proposed § 3175.102(c)(4) would require the operator to correct the as-found values for differential pressure taken under atmospheric conditions to working pressure values based on the difference between working pressure zero and the zero value obtained at atmospheric pressure (see previous discussion of proposed § 3175.102(a)(4) for further explanation of zero shift). API MPMS 21.1.8.2.2.3 recommends that this correction be made, but does not require it. API also provides a methodology for the correction. The correction methodology in API MPMS 21.1, Annex H would be required in this section.
Proposed § 3175.102(c)(5) would adopt the allowable tolerance between the test device and the device being tested as stated in API MPMS 21.1.8.2.2.2. This tolerance is based on the reference uncertainty of the transducer and the uncertainty of the test equipment.
Proposed § 3175.102(c)(6) would clarify that all required verification points must be within the verification tolerance before returning the meter to service. This requirement is implied by API MPMS 21.1.8.2.2.2, but is not clearly stated.
Proposed § 3175.102(c)(7) would require the differential pressure transducer to be zeroed at working pressure before returning the meter to service. This is implied by API MPMS 21.1.8.2.2.3, but not required. Refer to the discussion of zero shift under 3175.102(a)(4) for further information.
Proposed § 3175.102(d) would allow for redundancy verification in lieu of a routine verification under § 3175.102(c). Redundancy verification was added to the current version of API MPMS 21.1 as an acceptable method of ensuring the accuracy of the transducers in lieu of performing routine verifications. Redundancy verification is accomplished by installing two EGM systems on a single differential flow meter and then comparing the differential pressure, static pressure, and temperature readings from the two
Proposed § 3175.102(d)(1) would require the operator to identify separately the primary set of transducers from the set of transducers that is used as a check. This requirement would allow the BLM to know which set should be used for auditing the volumes reported on the Oil and Gas Operations Report (OGOR).
Proposed § 3175.102(d)(2) would require the operator to compare the average differential pressure, static pressure, and temperature readings taken by each transducer set every calendar month. API MPMS 21.1.8.2 does not specify a frequency at which this comparison should be done.
Proposed § 3175.102(d)(3) would establish the tolerance between the two sets of transducers that would trigger a verification of both sets of transducers under proposed § 3175.102(c). API MPMS 21.1 does not establish a set tolerance. This proposed section would also require the operator to perform a verification within 5 days of discovering the tolerance had been exceeded.
Proposed § 3175.102(e) would establish requirements for documenting a verification and calibration. The new documentation requirements would be similar to the requirements in Order 5, with the following additions and modifications:
• The FMP number, once assigned, would be a new requirement and would take the place of the station or meter number previously required;
• The lease, communitization agreement, unit, or participating area number would no longer be required once the FMP number is assigned, because the FMP number would provide this information;
• The temperature and pressure base would no longer be required in this proposed rule since these values are set in regulation (43 CFR 3162.7-3);
• Recording the time and date of the previous verification would be a new requirement and was added to allow the BLM to enforce the required verification frequencies;
• Recording the normal operating point for differential pressure, static pressure, and flowing temperature would be a new requirement to allow the BLM to ensure that the required verification points were tested and to facilitate the determination of meter verification error.
• Recording the condition of the differential device would be a new requirement because documentation of differential device condition is needed to ensure accurate measurement. Since inspection of the primary device would be required at the same time a verification is performed, this was added to the verification report; and
• Recording information regarding the verification equipment would be a new requirement to allow the BLM to determine that the proper verification tolerances were used.
This section would also establish the information that the operator must retain on site for redundancy verifications.
Proposed § 3175.102(f) would require the operator to notify the BLM at least 72 hours before verification of an EGM system. Order 5 requires only 24-hour notice. A longer notification period is proposed because 24-hour notice is generally not enough time for the BLM to be present at a verification. A 72-hour notice would be sufficient for the BLM to rearrange schedules, as necessary, to be present at the verification.
Proposed § 3175.102(g) would require correction of flow-rate errors greater than 2 percent or 2 Mcf/day, whichever is less, if they are due to the transducers being out of calibration, by submitting amended reports to ONRR. This is a change from Order 5, which required amended reports only if the flow-rate error was greater than 2 percent. For lower volume meters, a 2 percent error may represent only a small amount of volume. Assuming the 2 percent error resulted in an underpayment of royalty, the amount of royalty recovered by receiving amended reports may not cover the costs incurred by the BLM or ONRR of identifying and correcting the error. This rule proposes to add an additional threshold of 2 Mcf/day to exempt amended reports on low-volume FMPs.
Proposed paragraph (9) would also clarify a similar requirement in Order 5 to submit corrected reports if the flow-rate-error threshold is exceeded by defining the points that are used to determine the flow rate error. Calculated flow-rate error will vary depending on the verification points used in the calculation. The normal operating points must be used because these points, by definition, represent the flow rate normally measured by the meter. As specified in Table 3 (proposed § 3175.100), marginal-volume FMPs would be exempt from this requirement because the volumes are so small that even relatively large errors discovered during the verification process will not result in significant lost royalties, and thus, the process of amending reports would not be worth the costs involved for either the operator or the BLM (please see the example given in the discussion of 3175.92(f)).
Proposed § 3175.102(h)(1) would require verification equipment to be certified at least every 2 years. The purpose of this requirement would be to ensure that the verification or calibration equipment meets its specified level of accuracy and does not introduce significant bias into the field meter during calibration. Two-year certification of verification equipment is not required by API MPMS 21.1; however, the BLM believes that periodic certification is necessary. The proposal would not represent a change from existing requirements. This proposed requirement is consistent with requirements in the previous edition of API MPMS 21.1 (1993), which is adopted by the statewide NTLS for EFCs. The proposed section would also require that proof of certification be available to the BLM and would set minimum standards as to what the documentation must include. Although the minimum documentation standards would be a new requirement, they represent common industry practice.
Proposed paragraph (b) would modify the test equipment requirements in the statewide NTLs by adopting language in API MPMS 21.1.8.4. The statewide NTLs, which adopted the standards of API MPMS 21.1 (1993), required that the test equipment be at least 2 times more accurate than the device being tested. The purpose of this requirement was to reduce the additional uncertainty from the test equipment to an insignificant level. Many of the newer transducers being used in the field are of such high accuracy that field test equipment cannot meet the standard of being twice as accurate. Therefore, the current API MPMS 21.1 allows test equipment with an uncertainty of no more than 0.10 percent of the upper calibrated limit of the transducer being tested, even if it was not two times more accurate than the transducer being tested. For example, verifying a transducer with a reference accuracy of 0.10 percent of upper calibrated limit with test equipment that was at least twice as accurate as the device being tested, would require the test equipment to have an accuracy of 0.05 percent or
This level of accuracy is very difficult to achieve outside of a laboratory. As a result, API MPMS 21.1.8.4, and proposed § 3175.102(h), would only require the test equipment to have an accuracy of 0.10 percent of the upper calibrated limit of the device being tested. However, because the test equipment is no longer at least twice as accurate as the device being tested (they would both have an accuracy of 0.10 percent in this example), the additional uncertainty from the test equipment is no longer insignificant and would have to be accounted for when determining overall measurement uncertainty. The BLM would verify the overall measurement uncertainty—including the effects of the calibration equipment uncertainty—by using the BLM Uncertainty Calculator or an equivalent tool during the witnessing of a meter verification.
Proposed § 3175.103(a) would prescribe the equations that must be used to calculate the flow rate. Proposed § 3175.103(a)(1) would apply to flange-tapped orifice plates and would represent a change from the statewide EFC NTLs because the NTLs allow the use of either the API MPMS 14.3.3 or the AGA Report No.3 (1985) flow equation. The proposed rule would not allow the use of the AGA Report No. 3 (1985) flow equation because it is not as accurate as the API MPMS 14.3.3 flow equation and can result in measurement bias. The NTLs also allow the use of either AGA Report 8 (API MPMS 14.2)
Proposed § 3175.103(a)(2) would require use of BLM-approved equations for devices other than a flange-tapped orifice plate. Because there are typically no API standards for these devices, the PMT would have to check the equations derived by the manufacturer to ensure they were consistent with the laboratory testing of these devices. For example, a manufacturer may use one equation to establish the discharge coefficient for a new type of meter that is being tested in the laboratory, while using another equation for the meter it supplies to operators in the field, potentially resulting in measurement bias or increased uncertainty. The BLM would require that only the equation used during testing be used in the field. This would be a new requirement.
Proposed § 3175.103(b) would establish a standard method for determining atmospheric pressure that is used to convert psig to psia. This would be a new requirement because Order 5 requires the use of the atmospheric pressure defined in the buy/sell contract, if specified. If it is not specified, Order 5 requires atmospheric pressure to be determined through a measurement or a calculation based on elevation. (See the previous discussion of proposed § 3175.94(b) for an explanation of the rationale for this change.)
Proposed § 3175.103(c) would require that volumes and other variables used for verification be determined under API MPMS 21.1.4 and Annex B of API MPMS 21.1. This would be a change to existing requirements because the existing statewide EFC NTLs adopt the previous version of API MPMS 21.1.
Proposed § 3175.104(a) would establish minimum standards for the data that must be provided in a daily and hourly quantity transaction record. The data requirements are listed in API MPMS 21.1.5.2, with the following additions and modifications:
• The FMP number, once established, would be required on all reports (API MPMS 21.1 does not require this data);
• The number of required significant digits is specified. API MPMS 21.1.5.2 recommends that the data be stored with enough resolution to allow recalculation within 50 parts per million, but it does not specify the number of significant digits required in the quantity transaction record (QTR). The BLM added this requirement because if too few significant digits are reported it is impossible for the BLM to recalculate the reported volume with sufficient accuracy to determine if it is correct or in error. The BLM believes that five significant digits is sufficient to recalculate the reported volumes to the necessary level of accuracy; and
• An indication of whether the QTR shows the integral value or average extension under API MPMS 21.1. (Integral value generally is the summation of the product of the square root of the differential pressure and the square root of the static pressure taken at one-second intervals over an hour or a day. Average extension is the integral value divided by the flowing time.) API MPMS 21.1 allows either the integral value or average extension to be reported; however, the recalculation of reported volume is performed differently depending on which value is given. For the BLM to use the appropriate equation to recalculate volumes, the BLM must know what value is listed.
This proposed paragraph would require that both daily and hourly QTRs submitted to the BLM must be original, unaltered, unprocessed, and unedited. It is common practice for operators to submit BLM-required QTRs using third-party software that compiles data from the flow computers and uses it to generate a standard report. However, the BLM has found in numerous cases that the data submitted from the third-party software is not the same as the data generated directly by the flow computer. In addition, the BLM consistently has problems verifying the volumes reported through reports generated by third-party software. Under this proposed paragraph, data submitted to the BLM that was generated by third-party software would not meet the requirements of this section and the BLM would not accept it.
Proposed § 3175.104(b) would be a new requirement that would establish minimum standards for the data that must be provided in the configuration log. The unedited data are similar to the existing requirements found in API MPMS 21.1, which was adopted by the statewide NTLs for EFCs, with the following additions and modifications:
• The FMP number, once established, would be required on all reports;
• The software/firmware identifiers that would allow the BLM to determine if the software or firmware version was approved by the BLM;
• For marginal-volume FMPs, the fixed temperature, if the temperature is not continuously measured, that would allow the BLM to recalculate volumes; and
• The static-pressure tap location that would allow the BLM to recalculate volumes and verify the flow rate calculations done by the flow computer.
Proposed § 3175.104(c) would establish minimum standards for the data that must be provided in the event
Proposed § 3175.109(d) would require the operator to retain an alarm log as required in API MPMS 21.1.5.6. The alarm log records events that could potentially affect measurement, such as over-ranging the transducers, low power, or the failure of a transducer.
All of the provisions in proposed § 3175.110 would be new, since the only requirement in Order 5 relating to gas sampling is for an annual determination of heating value. This proposed section would set standards for gas sampling and analysis at FMPs. Although there are industry standards for gas sampling and analysis, none of these standards were proposed for adoption in whole because the BLM believes that they would be difficult to enforce as written. However, some specific requirements within these standards are sufficiently enforceable and would be adopted in this section. Heating value, which is determined from a gas sample, is as important to royalty determination as volume. Relative density, which is determined from the same gas sample, affects the calculation of volume. To ensure the gas heating value and relative density are properly determined and reported, the BLM is proposing the requirements described in this section. These requirements would address where a sample must be taken, how it must be taken, how the sample is analyzed, and how heating value is reported.
Table 4 in this proposed section contains a summary of requirements for gas sampling and analysis. The first column of Table 4 lists the subject of the proposed standard. The second column contains a reference for the standard (by section number and paragraph) that would apply to each subject area. The final four columns indicate the categories of FMPs for which the standard would apply. The FMPs are categorized by the amount of flow they measure on a monthly basis. As in other tables, “M” is marginal-volume FMP, “L” is low-volume FMP, “H” is high-volume FMP, and “V” is very-high-volume FMP. Definitions of the various classifications are included in proposed § 3175.10. An “x” in a column indicates that the standard listed applies to that category of FMP.
Proposed § 3175.111(a) would establish the allowable methods of sampling. These sampling methods have been reviewed by the BLM and have been determined to be acceptable for heating value and relative density determination at FMPs.
Proposed § 3175.111(b) would set standards for heating requirements which are based on several industry references requiring the heating of all sampling components to at least 30 °F above the hydrocarbon dew point. The purpose of the heating requirement is to prevent the condensation of heavier components, which could bias the heating value. This proposed section would apply to all sampling systems, including spot sampling using a cylinder, spot sampling using a portable gas chromatograph, composite sampling, and on-line gas chromatographs. Because most of the onshore FMPs will be downstream of a separator, the “hydrocarbon dew point” would be defined as the flowing temperature of the gas at the time of sampling, unless otherwise approved by the AO (see the proposed definition of “hydrocarbon dew point”). This would require the heating of all components of the gas sampling system at locations where the ambient temperature is less than 30 °F above the flowing temperature at the time of sampling.
Proposed § 3175.112 would set standards for the location of the sample probe. The intent of the standard would be to obtain a representative sample of the gas flowing through the meter. Samples taken from the wall of a pipe or a meter manifold would not be representative of the gas flowing through the meter and could bias the heating value used in royalty determination.
Proposed § 3175.112(b)(1) places limits on how far away the sample probe can be from the primary device to ensure that the sample taken accurately represents the gas flowing through the meter. API 14.1 requires the sample probe to be at least five pipe diameters downstream of a major disturbance such as a primary device, but it does not specify a maximum distance. Under this proposal the operator would have to place the sample probe between 1.0 and 2.0 times dimension “DL” (downstream length) downstream of the primary device. Dimension “DL” (API 14.3.2, Tables 2.7 and 2.8) ranges from 2.8 to 4.5, depending on the Beta ratio. Therefore, the sample probe would have to be placed between 2.8 and 9.0 pipe diameters downstream of the orifice plate, which is different than the requirement in API 14.1 noted above.
The sampling methods listed in API 14.1 and GPA 2166-05 will provide representative samples only if the gas is at or above the hydrocarbon dew point. It is likely that the gas at many FMPs is at or below the hydrocarbon dew point because many FMPs are immediately downstream of a separator. A separator necessarily operates at the hydrocarbon dew point, and any temperature reduction between the separator and the meter will cause liquids to form at the meter. To properly account for the total energy content of the hydrocarbons flowing through the meter, the sample must account for any liquids that are present. Gas immediately downstream of a primary device has a higher velocity, lower pressure, and a higher amount of turbulence than gas further away from the primary device. As a result, the BLM believes that liquids present immediately downstream of the primary device are more likely to be disbursed into the gas stream than attached to the pipe walls. Therefore, a sample probe placed as close to the primary device as possible should capture a more representative sample of the hydrocarbons—both liquid and gas—flowing through the meter than a sample probe placed further downstream of the meter. Any liquids captured by the sample probe would be vaporized because of the heating requirements in § 3175.111(b).
The BLM is requesting data supporting or contradicting any correlation between sample probe location and heating value or composition. The BLM is also requesting alternatives to this proposal, such as wet gas sampling techniques.
Locating the sample probe in the same ambient conditions as the primary device, as proposed in § 3175.112(b)(2), is not specifically addressed in API or GPA standards, but is intended to ensure that the gas sample contains the same constituents as the gas that flowed through the primary device. For example, if a primary device is located inside a heated meter house and the sample probe is outside the meter house, then condensation of heavier gas components could occur between the
Proposed § 3175.112(c)(1) through (3) would set standards for the design of the sample probe, which are based on API MPMS 14.1 and GPA 2166. The sample probe ensures that the gas sample is representative of the gas flowing through the meter. The sample probe extracts the gas from the center of the flowing stream, where the velocity is the highest. Samples taken from or near the walls of the pipe tend to contain more liquids and are less representative of the gas flowing through the meter.
Proposed § 3175.112(c)(4) would prohibit the use of membranes or other devices used in sample probes to filter out liquids that may be flowing through the FMP. Because a significant number of FMPs operate very near the hydrocarbon dew point, there is a high potential for small amounts of liquid to flow through the meter. These liquids will typically consist of the heavier hydrocarbon components that contain high heating values. The use of membranes or filters in the sampling probe could block these liquids from entering the sampling system and would result in heating values lower than the actual heating value of the fluids passing through the meter. This would result in a bias that would be in violation of proposed § 3175.30(c).
Proposed § 3175.112(d) would set standards for the sample tubing which are based on API MPMS 14.1 and GPA 2166. To avoid reactions with potentially corrosive elements in the gas stream, the sample tubing can be made only from stainless steel or Nylon 11. Materials such as carbon steel can react with certain elements in the gas stream and alter the composition of the gas.
As specified in Table 4 in proposed § 3175.110, marginal-volume FMPs are exempt from all requirements in proposed § 3175.112 because, based on BLM experience with this level of production, a requirement to install or relocate a sample probe in marginal-volume FMPs could cause the well to be shut in.
Proposed § 3175.113(a) would provide an automatic extension of the time for the next sample if the FMP were not flowing at the time the sample was due. Sampling a non-flowing meter would not provide any useful data. A sample would be required to be taken within 5 days of the date the FMP resumed flow.
Proposed § 3175.113(b) would require the operator to notify the BLM at least 72 hours before gas sampling. A 72-hour notification period is proposed to allow sufficient time for the BLM to arrange schedules as necessary to be present when the sample is taken.
Proposed § 3175.113(c) would establish requirements for sample cylinders used in spot or composite sampling. Proposed § 3175.113(c)(1) and (2) would adopt requirements for cylinder construction material and minimum capacity that are based on API and GPA standards.
Proposed § 3175.113(c)(3) would require that sample cylinders be cleaned according to GPA standards. This proposed section also would require documentation of the cylinder cleaning.
It is important to be able to verify that sample cylinders are clean before sampling to avoid contaminating a sample. Therefore, the BLM is seeking comment on the practicality and cost of installing a physical seal on the sample cylinder as proposed in § 3175.113(c)(4), or on other methods that the BLM could use to verify the cylinders are clean. The BLM is not aware of any industry standard or common industry practice that requires a seal to be used.
Proposed § 3175.113(d) would set standards for spot sampling using a portable gas chromatograph. This section primarily addresses the sampling aspects; the analysis requirements are prescribed in proposed § 3175.118. Both the GPA and API recognize that the use of sampling separators, while sometimes necessary for ensuring that liquids do not enter the gas chromatograph, can also cause significant bias in heating value if not used properly. Proposed § 3175.113(d)(1) would adopt GPA standards for the material of construction, heating, cleaning, and operation of sampling separators. It would also require documentation that the sample separator was cleaned as required under GPA 2166-05 Appendix A.
Proposed § 3175.113(d)(2) would require the filter at the inlet to the gas chromatograph to be cleaned or replaced before taking a sample. Industry standards do not provide specific requirements for how often the filter should be cleaned or replaced; however, a contaminated filter could bias the heating value.
Proposed § 3175.113(d)(3) would require the sample line and the sample port to be purged before sealing the connection between them. This requirement was derived from GPA 2166-05, which requires a similar purge when sample cylinders are being used. The purpose of this requirement is to disperse any contaminants that may have collected in the sample port and to purge any air that may otherwise enter the sample line.
Proposed § 3175.113(d)(4) would require portable gas chromatographs to adhere to the same minimum standards as laboratory gas chromatographs under proposed § 3175.118.
Proposed § 3175.113(d)(5) would prohibit the use of portable gas chromatographs if the flowing pressure at the sample port was less than 15 psig, which can affect accuracy of the device. This proposed requirement is based on GPA 2166-05.
Proposed § 3175.114 would adopt three spot sampling methods using a cylinder and one method using a portable gas chromatograph. The three allowable methods using a cylinder were selected for their ability to accurately obtain a representative gas sample at or near the hydrocarbon dew point, the relative effectiveness of the method, and the ease of obtaining the sample. Because the BLM determined that the procedures required by either GPA or API standards were clear and enforceable as written, the BLM proposes to adopt them verbatim.
The most common method currently in use at points of royalty settlement for Federal and Indian leases is the “Purging—Fill and Empty Method,” which is one of the methods that would be allowed in the proposed rule; therefore, it is not expected that this requirement would result in any significant changes to current industry practice. Proposed § 3175.114(a) would also allow the helium “pop” method and the floating piston cylinder method. The fourth proposed spot sampling method (proposed § 3175.114(a)(4)) is the use of a portable gas chromatograph, which is discussed in proposed § 3175.113(d). Proposed § 3175.114(d) would provide that the BLM would post other approved methods on its Web site.
Proposed § 3175.114(b) would allow the use of a vacuum gathering system when the operator uses a purging-fill and empty method or a helium “pop” method and when the flowing pressure is less than or equal to 15 psig. Of the four spot sampling methods allowed in this section, API 14.1.12.10 recommends that only the purging-fill and empty method and the helium “pop” method be used in conjunction with the vacuum gathering system. As a result, neither the floating piston cylinder method nor the portable gas chromatograph method would be allowed in conjunction with a vacuum gathering system.
Proposed § 3175.115(a) would require that gas samples at low-volume FMPs be taken at least every 6 months. Gas samples would have to be taken at marginal-volume FMPs at least annually, which is the same requirement as in Order 5. The BLM determined that sampling no more often than annually has the potential for biasing the heating value. If, for example, an annual sample was always taken in January when the ambient temperature is low, there could be a higher possibility that the heavier components could liquefy and bias the composition. This would not be consistent with proposed § 3175.30(c), which would require the absence of significant bias in low-volume FMPs. The BLM believes that sampling at low-volume FMPs at least every 6 months would reduce the potential for bias.
Proposed § 3175.115(a) would require spot samples at high- and very-high-volume FMPs to be taken at least every 3 months and every month, respectively, unless the BLM determines that more frequent analysis is required under § 3175.115(b). The sampling frequencies presented in Table 4 were developed as part of the “BLM Gas Variability Study Final Report,” May 21, 2010. The study used 1,895 gas analyses from 217 points of royalty settlement and concluded that heating value variability is not a function of reservoir type, production type, age, richness of the gas, flowing temperature, flow rate, or a number of other factors that were included in the study. Instead, the study found that heating value variability appeared to be unique to each meter. The BLM believes that the lack of correlation with at least some of the factors identified here could be a symptom of poor sampling practice in the field. The study also concluded that heating-value uncertainty over a period of time is manifested by the variability of the heating value, and more frequent sampling would lessen the uncertainty of an average annual heating value, regardless of whether the variability is due to actual changes in gas composition or to poor sampling practice.
The frequencies shown in Table 4 for high- and very-high-volume FMPs are typical of the sampling frequency required to obtain the heating value certainty levels that would be required in proposed § 3175.30(b)(1) and (2). Proposed § 3175.115(b) would allow the BLM to require a different sampling frequency if analysis of the historic heating value variability at a given FMP results in an uncertainty that exceeds what would be required in proposed § 3175.30(b)(1) and (2). Under proposed § 3175.115(b), the BLM could increase or decrease the required sampling frequency given in Table 4. To implement this proposed requirement, the BLM would develop a database called the Gas Analysis Reporting Verification System (GARVS). This database would be used to collect gas sampling and analysis information from Federal and Indian oil and gas operators. GARVS would perform analysis of that data to implement other proposed gas sampling requirements as well. The sample frequency calculation in GARVS would be based on the heating values entered into the system under proposed § 3175.120(f). GARVS would round down the calculated sampling frequency to one of seven possible values: Every week, every 2 weeks, every month, every 2 months, every 3 months, every 6 months, or every 12 months. The BLM would notify the operator of the new required sampling frequency.
Proposed § 3175.115(b)(2) would clarify that the new sampling frequency would remain in effect until a different sampling frequency is justified by an increase or decrease of the variability of previous heating values.
Proposed § 3175.115(b)(3) would limit the maximum sampling frequency to once per week. If weekly sampling would still not be sufficient to achieve the certainty levels that would be required under 3175.30(b)(1) or (2), then under 3175.115(b)(4), the BLM could require the operator to install a composite sampling system or an on-line gas chromatograph.
Proposed § 3175.115(c) would establish the maximum allowable time between samples for the range of sampling frequencies that the BLM would require, as shown in Table 5. This would allow some flexibility for situations where the operator is not able to access the location on the day the sample was due, although the total number of samples required every year would not change. For example, if the required sampling frequency was once per month, the operator would have to obtain 12 samples per year. If the operator took a sample on January 1st, the operator would have until February 14th to take the next sample (45 days later).
If a composite sampling system or on-line gas chromatograph is required by the BLM under proposed § 3175.115(b)(5) or opted for by the operator, proposed § 3175.115(d) would require that device to be operational within 30 days after the due date of the next sample. For example, if the required sampling frequency was weekly and the next sample was due on February 18th, the composite sampling system or on-line gas chromatograph would have to be operational by March 18th. The operator would not be required to take spot samples within this 30-day time period. The BLM considers both composite sampling and the use of on-line gas chromatographs to be superior to spot sampling, as long as they are installed and operated under the requirements in proposed §§ 3175.116 and 3175.117, respectively.
Proposed § 3175.115(e) would address meters where a composite sampling system or on-line gas chromatograph was removed from service. In these situations, the spot sampling frequency for that meter would revert to that required under proposed § 3175.115(a) and (b).
Proposed § 3175.116 would set standards for composite sampling. The BLM used API MPMS 14.1.13.1 as the basis for § 3175.116(a) through (c). Proposed § 3175.116(d) would require the composite sampling system to meet the heating-value uncertainty requirements of proposed § 3175.30(b).
Proposed § 3175.117 would set standards for online gas chromatographs. Because there are few industry standards for these devices, the BLM is particularly interested in comments on these proposed requirements or whether different or alternative standards should be adopted. The BLM is aware that API MPMS 22.6, a testing protocol for gas chromatographs, is nearing completion and is requesting comments on whether it should be incorporated by reference in the final rule.
Proposed § 3175.118 would establish requirements for the analysis of gas samples. Under proposed § 3175.118(a), these minimum standards would apply to all gas chromatographs, including portable, online, and stationary laboratory gas chromatographs. These requirements are derived primarily from two industry standards: GPA 2166-00 and GPA 2198-03.
Proposed § 3175.118(b) would require that gas samples be run until three consecutive runs have met the repeatability standards stated in GPA 2261-00. Obtaining three consistent analysis results would ensure that any contaminants in the gas chromatograph system have been purged and that
Proposed § 3175.118(c) would set a minimum frequency for verification of gas chromatographs. More frequent verifications would be required for portable gas chromatographs because these devices may be exposed to field conditions such as temperature changes, dust, and transportation effects. All of these conditions have the potential to affect calibration. In contrast, laboratory gas chromatographs are not exposed to these conditions; therefore, they would not need to be verified as often.
Proposed § 3175.118(d) would require that the gas used for verification be different than the gas used for calibration. This requirement is proposed because it is relatively easy to alter the composition of a reference gas if it is not handled properly. An errant reference gas used to calibrate a gas chromatograph would not be detected if the same gas is used for verification, which could lead to a biased heating value.
Proposed § 3175.118(e) would require a calibration of the gas chromatograph if the specified repeatability could not be achieved during a verification. The calibration would have to comply with GPA 2261-00, Section 9. This section would clarify when a calibration is needed.
Proposed § 3175.118(f) would require the equivalent of an as-left verification after the gas chromatograph was calibrated. A final verification would ensure that the calibration of the gas chromatograph was successful.
Proposed § 3175.118(g) would prohibit the use of a gas chromatograph that has not been verified under § 3175.118(e). This requirement would ensure that gas samples from FMPs are analyzed with gas chromatographs that will yield accurate heating values.
Proposed § 3175.118(h) would adopt the calibration gas standards of GPA 2198-03. This requirement would ensure the accuracy of the gas measurement used to calibrate gas chromatographs.
Proposed § 3175.118(i) would require documentation of gas chromatograph verification to be retained as required under the record-retention requirements in proposed § 3170.7, published previously (80 FR 40768 (July 13, 2015)). For portable gas chromatographs, the documentation must be available onsite. The purpose of the latter requirement is that it would allow the BLM to inspect the verification documents while witnessing a spot sample that is taken with a portable gas chromatograph. If the verification had not been performed at the frequency required in proposed § 3175.118(c)(1), or did not meet the standards of § 3175.118(e), the gas chromatograph would not be allowed to analyze the sample.
Proposed § 3175.119 would establish the minimum gas components which the operator must analyze. Section 3175.119(a) would require an analysis through hexane+ for all FMPs and would also include carbon dioxide and nitrogen analysis. Analysis through hexane+ is common industry practice and does not represent a significant change from existing procedures. Although components heavier than hexane exist in gas streams, these components are typically included in the hexane+ concentration given by the gas chromatograph. Under proposed § 3175.126(a)(3), the heating value of hexane+ would be derived from an assumed gas mixture consisting of 60 mole percent hexane, 30 mole percent heptane, and 10 mole percent octane. At concentrations of hexane+ below the threshold given in proposed § 3175.119(b), the uncertainty due to the assumed gas mixture given in § 3175.126(a)(3) does not significantly contribute to the overall uncertainty in heating value and would not significantly affect royalty.
Proposed § 3175.119(b) would require an extended analysis of the gas sample, through nonane+, if the concentration of hexane+ from the standard analysis is 0.25 mole percent or greater. This requirement would not apply to marginal-volume FMPs or low-volume FMPs. The threshold of 0.25 mole percent was derived through numerical simulation of the assumed composition of hexane+ (60 mole percent hexane, 30 mole percent heptanes, and 10 mole percent octane) compared to randomly generated values of hexane, heptanes, octane, and nonane. The numerical simulation showed that the additional uncertainty of the fixed hexane+ mixture required in § 3175.126(a)(3) does not significantly add to the heating value uncertainties required in § 3175.30(b), until the mole percent of hexane+ exceeds 0.25 mole percent. The BLM is seeking data that confirms or refutes the results of our numerical simulation. Specifically, we are seeking data comparing heating values determined with a hexane+ analysis with heating values of the same samples determined through an extended analysis.
Proposed § 3175.120 would establish minimum standards for the information that must be included in a gas analysis report. This information would allow the BLM to verify that the sampling and analysis comply with the requirements proposed in § 3175.110, and would enable the BLM to independently verify the heating value and relative density used for royalty determination.
Proposed § 3175.120(b) would require that gas components not tested be annotated as such on the gas analysis report. It is common practice for industry to include a mole percent for each component shown on a gas analysis report, even if there was no analysis run for that component. For example, the gas analysis report might indicate the mole percent for hydrogen sulfide to be “0.00 percent,” when, in fact, the sample was not tested for hydrogen sulfide. The BLM believes this practice to be potentially misleading.
Proposed § 3175.120(c) and (d) would adopt API MPMS 14.5 and 14.2, respectively. The BLM believes that these API standards are appropriate for heating value, relative density, and base supercompressibility calculations.
Proposed § 3175.120(e) would require operators to submit all gas analysis reports to the BLM within 5 days of the due date for the sample. For high-volume and very-high-volume FMPs, the gas analyses would be used to calculate the required sampling frequencies under § 3175.115(c). Requiring the submission of all gas analyses would allow the BLM to verify heating-value and relative-density calculations and it would allow the BLM to determine operator compliance with other sampling requirements in proposed § 3175.110. The method of determining gas sampling frequency for high-volume and very-high-volume FMPs assumes a random data set. The intentional omission of valid gas analyses would invalidate this assumption and could result in a biased annual average heating value. This could be considered tampering with a measurement process under proposed 43 CFR 3170.4, published previously. See 80 FR 40768 (July 13, 2015).
Proposed § 3175.120(f) would require operators to submit all gas analysis
Proposed § 3175.121 would establish an effective date for the heating value and relative density determined from spot or composite sampling and analysis. Section 3175.121(a) would establish the effective date as the date on which the spot sample was taken unless it is otherwise specified on the gas analysis report. For example, industry will sometimes choose the first day of the month as the effective date to simplify accounting.
While the BLM believes this is an acceptable practice, there is a need to place limits on the length of time between the sample date and the effective date based on inconsistencies found as part of the gas variability study discussed earlier. Proposed § 3175.121(b) would establish that the effective date could be no later than the first day of the month following the date on which the operator received the laboratory analysis of the sample. This would account for the delay that often occurs between taking the sample, obtaining the analysis, and applying the results of the analysis. If, for example, a sample were taken toward the end of March, the results of the analysis may not be available until after the first of April. The proposed requirement would allow the effective date to be the first of May. Based on the gas variability study conducted by the BLM, the timing of the effective date of the sample is less important than the timing of the samples taken over the year.
Proposed § 3175.121(c) would require the effective dates of a composite sample to coincide with the time that the sample cylinder was collecting samples. A composite sampling system takes small samples of gas over the course of a month or some other time period, and places each small sample into one cylinder. At the end of that time period, the cylinder contains a gas sample that is representative of the gas that flowed through the meter over that time period. Therefore, the heating value and relative density determined from that sample are valid only for the time period the cylinder was collecting samples.
Proposed § 3175.125(a) would be a new requirement that would define how the operator must calculate heating value. Proposed paragraphs (a)(1) and (a)(2) would define the calculation of gross and real heating value. Although this would be a new requirement, the calculation and reporting of gross and real heating value is standard industry practice.
Proposed § 3175.125(b)(1) would establish a standard method for determining the average heating value to be reported for a lease, unit PA, or CA, when the lease, unit PA, or CA contains more than one FMP. Consistent with current ONRR guidance (Minerals Production Reporter Handbook, Release 1.0, 05/09/01, Glossary at 14), the proposed method requires the use of a volume-weighted average heating value to be reported. Proposed § 3175.125(b)(2) would establish a requirement for determining the average heating value of an FMP when the effective date of a gas analysis is other than the first of the month. The proposed methodology also requires a volume-weighted average for determining the heating value to be reported. Although this is not specifically addressed in the Reporter Handbook, the method is consistent with the volume-weighted average proposed for multiple FMPs.
Proposed § 3175.126 would be a new requirement that would define the conditions under which the heating value and volume would be reported for royalty purposes. The reporting of gross and real heating value in § 3175.126(a) would be consistent with standard industry practice.
The proposed requirement to report “dry” heating value (no water vapor) in proposed § 3175.126(a)(1) would be a change for some operators because gas sales contracts often call for “wet” or saturated heating values to be used. The BLM has determined that “wet” heating values almost always bias the heating value to the low side because the definition of “wet” heating value assumes the gas is saturated with water vapor at 14.73 psi and 60
This IM establishes the BLM policy that, when verifying the heating value reported on OGOR-B, the dry reporting basis from the gas analysis must be used unless the water vapor content was determined as part of the analysis, in which case the real or actual heating value will be used. If it is found that the operator has been reporting on the wrong basis, it must be resolved per the instructions in IM 2009-174, “Request for Modified or Missing Oil and Gas Operations Report from the Minerals Management Service.” The description of what was found must state (for typical gas analyses): “Gas volumes have been determined based on the assumption that no water vapor is present. Heating value must be based on the same degree of water saturation. The heating value must, therefore, be reported on a dry basis.”
The Minerals Management Service (MMS) regulations (30 CFR 202.152(a)(1)(i))
The BLM has interpreted this to mean a dry or real/actual reporting basis. In order to determine gas volumes, the relative density (or specific gravity) of the gas must be known. The relative density is determined from the same gas analyses that are used to determine heating value. Because water vapor cannot be detected by most gas chromatographs, the vast majority of gas analyses do not include water vapor as a constituent of the gas sample even if some water vapor is present. While adjustments to the heating value of the gas can be made based on assumptions of water saturation, relative density is rarely adjusted to account for the water vapor that may or may not be present. In essence, the relative density used to determine volume is almost always on a “dry” basis because water vapor is excluded from the calculation. The “dry” relative density is included in the calculations to determine gas flow rate and gas volume; therefore, the volume is ultimately determined on a “dry” basis. According to the MMS regulation cited above, if volume is reported on a “dry” basis, heating values must also be reported on a dry basis.
In the rare instance where water vapor content is actually measured and included in the gas analysis, the relative density calculation includes the actual water vapor content. This would result in volume being
The BLM would consider allowing an adjustment in heating value for assumed water-vapor saturation at flowing pressure and temperature (sometimes referred to as “as delivered”) in the final rule if sufficient data is presented in the public comments on this proposed rule that shows this to be a valid assumption and under what flowing conditions the assumption is valid. Alternatively, if sufficient data is supplied, the BLM may consider adjusting volumes for water vapor in lieu of a heating value adjustment. The BLM will review information and comments submitted to determine if an approach different from the one proposed is justified.
The proposed section also defines the acceptable methods to measure water vapor: A chilled mirror, a laser detection system, and other methods that the BLM may approve through the PMT. Stain tubes and other similar measurement methods would not be allowed because of the high degree of uncertainty inherent in these devices.
Proposed § 3175.126(a)(2) would require the heating value to be reported at 14.73 psia and 60°F. Although this was not required in Order 5, it is currently required by ONRR regulations at 30 CFR 1202.152(a)(1)(ii).
The composition of hexane+ that would be required for heating value and relative density calculation is given in § 3175.126(a)(3). This composition was based on examples shown in API MPMS 14.5, Annex B.
Proposed § 3175.126(b) would define the volume of gas that must be reported for royalty purposes. Proposed § 3175.126(b)(1) would prohibit the practice of adjusting volumes for assumed water-vapor content, since this is currently done in some cases in lieu of adjusting the heating value for water-vapor content. This results in the volume being underreported. The BLM may consider in the final rule allowing for water-vapor adjustment if sufficient data are submitted during the public comment period to support an adjustment, as discussed above. This would be a new requirement.
Proposed § 3175.126(b)(2) would require the unedited volume on a quantity transaction record (EGM systems) or an integration statement (mechanical recorders) to match the volume reported for royalty purposes, unless edits to the data could be justified and documented by the operator. This would be a new requirement and it is needed for verification of production.
Proposed § 3175.126(c) would establish new requirements for edits and adjustments to volume or heating value. Section 3175.126(c)(1) would allow for estimating volumes or heating values if measuring equipment is out of service or malfunctioning. Although this is similar to a requirement in Order 5, additional requirements would be added to prescribe how the estimates would be determined.
Proposed § 3175.126(c)(2) would require documentation justifying all edits made to data affecting volumes or heating values reported on the OGORs. While the BLM recognizes that meter malfunctions and other factors can necessitate editing the data to obtain a more correct volume, this section would require operators to thoroughly justify and document the edits made. This would include quantity transaction records and integration statements. The operator would retain the documentation as required under proposed § 3170.7 and would submit it to the BLM upon request. This would be a new requirement.
Proposed § 3175.126(c)(3) would require that any edited data be clearly identified on reports used to determine volumes or heating values reported on the OGORs and cross-referenced to the documentation required in 3175.126(c)(2). This would include quantity transaction records and integration statements. This would be a new requirement.
Proposed § 3175.126(c)(4) would require the amendment of the OGOR reports submitted to ONRR in the case of an inaccuracy discovered in an FMP. Although this would be a new requirement, it is similar to the requirement for correcting calibration errors in Order 5.
Proposed § 3175.130 would establish a testing protocol for differential-pressure, static-pressure, and temperature transducers used in conjunction with differential-flow meters at FMPs. This would be a new requirement. This section would be added to implement the requirements proposed in § 3175.131(a) for flow-rate uncertainty limits. To determine flow-rate uncertainty, it is necessary to first determine the uncertainty of the variables that go into the calculation of flow rate. For differential flow meters, these variables include differential pressure, static pressure, and flowing temperature. Transducers (secondary devices) derive these variables by measuring, among other things, the pressure drop created by the primary device (
Currently, methods used to determine uncertainty (
The testing procedures in proposed §§ 3175.131 through 3175.135 are based, in large part, on testing procedures published by the International Electrotechnical Commission (IEC). Some of these standards are already used by several transducer manufacturers; however it is unknown which manufacturers use which standards or to what extent they do so.
Proposed § 3175.131(a) would establish standards for test facilities qualified to perform the transducer-testing protocol. Proposed § 3175.130(a)(1) would require tests to be carried out by a lab that is not affiliated with the manufacturer to avoid any real or perceived conflict of interest. Traceability to the NIST proposed in § 3175.131(a)(2) is based on IEC Standard 1298-1, section 7.1.
Proposed § 3175.131(b) would require that the testing protocol be applied to each make, model, and URL of transducers used at FMPs, to ensure that any transducer with the potential to have unique performance characteristics is tested.
In general, the testing requirements in paragraphs (c) through (h) of this proposed section are based on IEC standard 1298-1, Section 6.7. While the IEC does not specify the minimum number of devices required for a representative number, the BLM is proposing (in paragraph (b)(1)) that at least five transducers be tested to ensure testing of a statistically representative sample of the transducers coming off the assembly line. The BLM specifically seeks comments on whether the testing
Proposed §§ 3175.132 and 3175.133 would establish specific testing requirements for reference accuracy and influence effects. These requirements are based on the following IEC standards: IEC 1298-1, IEC 1298-2, IEC 1298-3, and IEC 60770-1.
Proposed § 3175.134 would require documentation of the testing and the submission of the documentation to the PMT. The PMT would use the documentation to determine the uncertainty and influence effects of each make, model, and range of transducer tested.
Proposed § 3175.135 would establish a method of deriving reference uncertainty and quantifying influence effects from the tests required by this protocol. The methods for determining reference uncertainty are based on IEC Standard 1298-2, Section 4.1.7. While the IEC standards define the methods to be used for influence effect testing, no specific methods are given to quantify the influence effects; therefore, the BLM developed statistical methods to determine zero-based effects and span-based effects. In addition, all uncertainty calculations use a “student t-distribution” to account for the small number of transducers of a particular make, model, URL, and turndown, to be tested.
After a transducer has been tested under proposed §§ 3175.130 through 3175.134, the PMT would review the results. The BLM would list the approved transducers for use at FMPs (see § 3175.43), and list the make, model, URL, and turndown of approved transducers on the BLM Web site along with any operating limitations or other conditions.
Proposed § 3175.140 would provide that the BLM would approve a particular version of flow-computer software if the testing is performed under the testing protocol in proposed §§ 3175.141 through 3175.144, to ensure that calculations meet API standards. Unlike the testing protocol for transducers proposed in § 3175.130, which is used to derive performance specifications, the testing protocol for flow computers would establish pass-fail criteria. This would be a new requirement. Testing would only be required for those software revisions that affect volume or flow rate calculations, heating value, or the audit trail.
The testing procedures in this section are based, in large part, on a testing protocol in API MPMS 21.1, Annex E.
Proposed § 3175.141(a) would require that all testing be done by an independent laboratory to avoid any real or perceived conflict of interest in the testing.
Proposed § 3175.141(b)(1) would require that each make, model, and software version tested must be identical to the software version installed at an FMP. Proposed § 3175.141(b)(2) would require that each software version be given a unique identifier, which would have to be part of the display (see proposed § 3175.101(b)(4)(ii)) and the configuration log (see proposed § 3175.104(b)(2)) to allow the BLM to verify that the software version has been tested under the protocol proposed in this section.
Proposed § 3175.141(c) would provide that input variables may be either applied directly to the hardware registers or applied physically to a transducer. In the latter event, the values received by the hardware register from the transducer (which are subject to some uncertainty) must be recorded.
Proposed § 3175.141(d) would establish a pass-fail criteria for the software testing. The digital values obtained for the testing in proposed §§ 3175.142 and 3175.143 would be entered into reference software approved by the BLM, and the resulting values of flow rate, volume, integral value, flow time, and averages of the live input variables would be compared to the values determined from the software under test. A maximum allowable error of 50 parts per million (0.005 percent) would be established in proposed § 3175.141(d)(2).
Proposed § 3175.142(a) would set out six required tests to ensure that the instantaneous flow rate was being properly calculated by the flow computer. The parameters for each of the six tests set out in Tables 6 and 7 in this proposed section are designed to test various aspects of the calculations, including supercompressibility, gas expansion, and discharge coefficient over a range of conditions that could be encountered in the field.
Proposed § 3175.142(b) would test the ability of the software to accurately accumulate volume, integral value, and flow time, and calculate average values of the live input variables over a period of time with fixed inputs applied.
Proposed § 3175.142(c) would test the ability of the event log to capture all required events, test the software's ability to handle inputs to a transducer that are beyond its calibrated span, and test the ability of the software to record the length of any power outage that inhibited the computer's ability to collect and store live data.
Proposed § 3175.143 would establish required dynamic tests that would test the ability of the software to accurately calculate volume, integral value, flow time, and averages of the live input variables under dynamic flowing conditions. The tests are designed to simulate extreme flowing conditions and include a square wave test, a sawtooth test, a random test, and a long-term volume accumulation test. A square wave test applies an input instantaneously, holds that input constant for a period of time and then returns the input to zero instantaneously. A sawtooth test increases an input over time until it reaches a maximum value, and then decreases that input over time until it reaches zero. A random test applies inputs randomly.
After a software version has been tested under proposed §§ 3175.141 through 3175.143, the PMT would review the results. If the test was deemed successful, the BLM would approve the use of the software version and flow computer and would list the make and model of the flow computer, along with the software version tested, on the BLM Web site (see proposed § 3175.44).
Proposed § 3175.150 would identify 10 specific violations that would be subject to elevated civil assessment amounts, as opposed to being subject to the provisions for major and minor violations generally under current guidance. The BLM's existing regulations at 43 CFR 3163.1 and Order 3 establish assessments that an operator or operating rights owner may be subject to for failure to comply with the terms and conditions of a lease or any applicable legal requirements. The authority for the BLM to impose these assessments was explained in the preamble to the final rule in which 43
The provisions providing assessments have been promulgated under the Secretary of the Interior's general authority, which is set out in Section 32 of the Mineral Leasing Act of 1920, as amended and supplemented (30 U.S.C. 189), and under the various other mineral leasing laws. Specific authority for the assessments is found in Section 31(a) of the Mineral Leasing Act (30 U.S.C. 188(a)), which states, in part “. . . the lease may provide for resort to appropriate methods for the settlement of disputes or for remedies for breach of specified conditions thereof.” All Federal onshore and Indian oil and gas lessees must, by the specific terms of their leases which incorporate the regulations by reference, comply with all applicable laws and regulations. Failure of the lessee to comply with the law and applicable regulations is a breach of the lease, and such failure may also be a breach of other specific lease terms and conditions. Under Section 31(a) of the Act and the terms of its leases, the BLM may go to court to seek cancellation of the lease in these circumstances. However, since at least 1942, the BLM (and formerly the Conservation Division, U.S. Geological Survey), has recognized that lease cancellation is too drastic a remedy, except in extreme cases. Therefore, a system of liquidated damages was established to set lesser remedies in lieu of lease cancellation. The BLM recognizes that liquidated damages cannot be punitive, but are a reasonable effort to compensate as fully as possible the offended party, in this case the lessor, for the damage resulting from a breach where a precise financial loss would be difficult to establish. This situation occurs when a lessee fails to comply with the operating and reporting requirements. The rules, therefore, establish uniform estimates for the damages sustained, depending on the nature of the breach. 52 FR 5384 (February 20, 1987).
The existing regulations establish assessments for major and minor violations generally and identify four violations that warrant immediate assessments. Those violations and corresponding assessments are: (1) Failure to install a blowout preventer or other equivalent well-control equipment, $500 per day, not to exceed $5,000; (2) Drilling without approval or causing surface disturbance on Federal or Indian surface preliminary to drilling without approval, $500 per day, not to exceed $5,000; (3) Failure to obtain prior approval of a well-abandonment plan, $500 total; and, in Order 3, (4) Removing a Federal seal without BLM approval, $250. These assessments are in addition to the civil penalties authorized under Section 109 of the Federal Oil and Gas Royalty Management Act (FOGRMA), 30 U.S.C. 1719.
As explained in connection with the changes to 43 CFR 3163.1 being proposed as part of this rule, the BLM is proposing that all civil assessments under § 3163.1 or proposed subparts 3173, 3174, and 3175, should be immediate. With respect to the requirements of the proposed subpart 3175, the proposed rule would identify 10 specific violations that would be subject to elevated assessments as opposed to being subject to the amounts specified under 43 CFR 3163.1 for major and minor violations. These violations would be subject to a $1,000 assessment and include the following:
1. New FMP orifice plate inspections were not conducted as required under proposed § 3175.80(c);
2. Routine FMP orifice plate inspections were not conducted as required under proposed § 3175.80(d);
3. Visual meter-tube inspections were not conducted as required under proposed § 3175.80(h);
4. Detailed meter-tube inspections were not conducted as required under proposed § 3175.80(i);
5. An initial mechanical recorder verification was not conducted as required under proposed § 3175.92(a);
6. Routine mechanical recorder verifications were not conducted as required under proposed § 3175.92(b);
7. An initial EGM system verification was not conducted as required under proposed § 3175.102(a);
8. Routine EGM system verifications were not conducted as required under proposed § 3175.102(b);
9. Spot samples for low-volume and marginal-volume FMPs were not taken as required under proposed § 3175.115(a); and
10. Spot samples for high- and very-high-volume FMPs were not taken as required under proposed § 3175.115(a) and (b).
The BLM chose the $1,000 figure because it approximates the average of what it would cost the agency, based on an analysis of its costs, to identify and document each of the aforementioned violations and verify that the necessary remedial actions have been completed. The BLM seeks comment on whether these assessments should be higher or lower or what other factors it should consider in setting them.
As noted at the beginning of this section-by-section analysis, the BLM is proposing other changes to provisions in 43 CFR part 3160. Some of the changes have been discussed already. The remaining proposed revisions are those noted here.
1. Section 3162.7-3, Measurement of gas, would be rewritten to reflect this proposed rule.
2. Section 3163.1, Remedies for acts of noncompliance, would be rewritten in part in several respects. As explained in connection with proposed revisions to proposed § 3175.150, the BLM's existing regulations contain provisions authorizing the BLM to impose assessments on operators and operating rights owners for violation of the terms and conditions of their lease or any other applicable law. These assessments are a form of liquidated damages designed to capture the costs incurred by the BLM in identifying and responding to these violations. These assessments are not intended to be punitive.
The existing regulations establish two categories of assessments. There is a general category, which authorizes assessments for major and minor violations. Those assessments may be imposed only after a written notice that provides a corrective or abatement period, subject to the limitations in existing paragraph (c).
Therefore, the BLM is proposing to revise paragraphs (a)(1) and (2) to allow the BLM to impose fixed assessments of $1,000 on a per-violation, per-inspection basis for major violations, and $250 on a per-violation, per-inspection basis for minor violations.
The introductory language in paragraph (a) would also be revised to apply to “any person” and would no longer be limited to operating rights owners and operators. This proposed change would enable the agency to impose assessments directly on parties who contract with operating rights owners or operators to perform activities on Federal or Indian leases that violate applicable regulations, lease terms, notices, or orders in performing those activities, and thereby cause the agency to incur the costs to detect and remedy those violations. While the operating rights owner or operator is responsible for violations committed by contractors and therefore is subject to assessments for the contractor's non-compliance, the contractors themselves are also obligated to comply with applicable regulations, lease terms, notices, and orders. Thus, the BLM is proposing to revise the regulations to enable the agency to impose assessments directly on the party whose non-compliance imposes costs on the agency. (The discussion of the new immediate assessments in proposed § 3175.150 explains the authority for assessments of this kind.) The proposed change would also make § 3163.1(a) consistent with the proposed revision to § 3163.2.
Paragraph (b) in the current regulations identifies specific serious violations for which immediate assessments are imposed upon discovery without exception. These are: (1) Failure to install a blowout preventer or other equivalent well control equipment; (2) Drilling without approval or causing surface disturbance on Federal or Indian surface preliminary to drilling without approval; and (3) Failure to obtain approval of a plan for well abandonment prior to commencement of such operations. These assessments are already imposed immediately. Accordingly, no changes were required as a result of the proposed change in the general approach to assessments. The BLM has, however, proposed clarifications to paragraph (b) to make it consistent with the changes proposed for paragraph (a) and to acknowledge that certain assessments would be identified in proposed subparts 3173, 3174, and 3175.
In addition, the BLM proposes to revise the first two assessments found in paragraph (b) to make each of them flat assessments of $1,000 that would be imposed on a per-violation, per-inspection basis, instead of the current framework, which contemplates an assessment of $500 per day up to a maximum cap of $5,000. As explained in connection with § 3175.150, the BLM chose the $1,000 figure because it approximates the average cost to the agency to identify such violations. The BLM seeks comment on whether these assessments should be higher or lower or what other factors it should consider in setting them. Paragraph 3163.1(b)(3) would be unchanged by this proposed rule.
In connection with the proposed shift from assessments that accrue on a daily basis to ones that can be assessed on a per-violation, per-inspection basis, the daily limitations imposed by existing paragraph (c) would no longer be necessary. Therefore, paragraph (c) is proposed for deletion.
Existing paragraph (d), which provides that continued noncompliance subjects the operating rights owner or operator to civil penalties under § 3163.2 of this subpart, would be removed. Continued noncompliance may subject a party to civil penalties under § 3163.2 and the statute that it implements (Section 109 of FOGRMA, 30 U.S.C. 1719) regardless of whether the assessment regulation so provides, and therefore the requirements of paragraph (d) were determined to be redundant and unnecessary.
Finally, as a result of these changes, the current paragraph (e) would be re-designated as paragraph (c).
3. Section 3163.2, Civil penalties, would be rewritten in part in several respects. First, in connection with the recently proposed subpart 3173, 80 FR 40,768 (July 13, 2015), the BLM proposes to add new language and provisions to address purchasers and transporters who are not operating rights owners to make § 3163.2 consistent with the requirements of Section 109 of FOGRMA, 30 U.S.C. 1719, which subjects a purchaser or transporter to civil penalties if they fail to maintain and submit required records. As explained in the proposed rule for subpart 3173, this change resulted in the re-designation of paragraphs (a) and (b) of § 3163.2. The revisions proposed in this rule assume the changes proposed in subpart 3173 are ultimately adopted.
In addition to the changes proposed as part of the proposed rule for subpart 3173, the BLM proposes to revise paragraphs (a)(1) and (b)(1) to refer to “any person” and “the person,” respectively, rather than limiting the applicability of civil penalties to an operating rights owner or operator to be consistent with the statutory language found in Section 109(a) of FOGRMA, 30 U.S.C 1719(a). This proposed change would clarify that potential penalty liability exists for parties who contract with operating rights owners or operators to perform activities on Federal or Indian leases who violate applicable regulations, statutes, or lease terms in performing those activities. While the operating rights owner or operator is responsible (and liable for penalties) for violations committed by contractors, the contractors are also themselves subject to the requirements of the statutes, regulations, and lease terms. The BLM is proposing to revise the regulations to enable the agency to hold contractors directly responsible for violations they commit. Paragraph (g) also would be revised accordingly.
In addition, on April 21, 2015, the BLM published an Advance Notice of Proposed rulemaking (ANPR) (80 FR 22148) in which it requested public comment on whether the current regulatory caps on civil penalty assessments in 43 CFR 3163.2 (b), (d), (e), and (f) should be removed. As
The comment period on the ANPR closed on June 19, 2015. The BLM received approximately 82,000 comments. Of the 82,000 received, roughly 40 were unique, and the remainder were form comments. Of that 40, nine addressed the question of whether the caps imposed on civil penalties should be removed. Six of the nine comments that discussed the issue were in favor of changes to the existing caps; five asserted that existing caps do not provide adequate deterrence, while the sixth suggested that the caps be retained but increased to account for inflation. Three of the nine comments were generally opposed to any changes because of potential deterrence effects to development on public lands, but did not otherwise provide any detailed information.
After consideration of comments received and the concerns identified by the BLM and the OIG, the BLM is proposing as part of this rulemaking to remove those caps. Paragraphs (b), (d), (e), and (f) would be rewritten accordingly, while maintaining the statutory limits imposed on the amount that may be assessed on a daily basis (30 U.S.C. 1719(a)-(d)).
Third, the BLM is also proposing to delete all of paragraph (g). The existing requirements of paragraph (g)(1) and (g)(2)(iii), which require initial proposed penalties to be at the maximum rate, are being removed because they are inconsistent with subsequent judicial and administrative decisions regarding the computation and setting of penalties. The BLM also determined that the requirements in paragraph (g)(1) and (g)(2)(iii) establishing caps on a per operating rights owner or operator per lease) would be removed as those provisions are inconsistent with the BLM's proposal to remove caps on penalties that are not required by statute. With respect to paragraphs (g)(2)(i) and (g)(2)(ii), the BLM is proposing to remove the additional notice procedure and corrective period for minor violations required under those paragraphs because it does not believe those provisions are necessary. The BLM's regulations governing oil and gas operations are clear, and provide more than adequate notice of what is required, making additional notification requirements unnecessary and administratively inefficient. As a result, all of paragraph (g) would be removed as part of this proposal. The removal of paragraph (g) means that existing paragraph (i) would be re-designated (g).
Finally, the BLM is proposing to move the substance of existing paragraph (k), which requires the revocation of a transporter's authority to remove crude oil produced from, or allocated to, any Federal or Indian lease if it fails to permit inspection for required documentation under 43 CFR 3162.7-1(c)), to paragraph (d) in order to streamline the regulations.
4. Paragraph (a) of § 3165.3 Notice, State Director review and hearing on the record, would be revised to refer to “any person” consistent with the revisions to Section 3163.1 and 3163.2.
5. Section 3164.1, Onshore Oil and Gas Orders, the table would be revised to remove the reference to Order 5 because this proposed rule would replace Order 5.
On April 24 and 25, 2013, the BLM held a series of public meetings to discuss draft proposed revisions to Orders 3 and 5, as well as Onshore Oil and Gas Order No. 4 (oil measurement). The meetings were webcast so that tribal members, industry, and the public across the country could participate and ask questions either in person or over the Internet. More than 200 people either logged in or were physically present for at least a portion of the meetings. Following the forum, the BLM opened a 36-day informal comment period, during which 13 comment letters were submitted. The following summarizes comments relating to Order 5 and gas measurement:
1.
2.
Because the water vapor content in a gas sample is not easily measured, industry has been using various assumptions of water vapor content for decades. One commonly used assumption is that the gas is saturated with water vapor at 14.73 psia and 60°F. This assumption has no factual basis and typically results in a reduction of heating value (and royalty) due to water vapor that cannot physically exist at the meter. The publication of GPA 2172-09 was the first industry standard addressing the “as delivered” basis, which assumes the gas is saturated with water vapor at metered pressure and temperature. The “as delivered” basis, however, is still an assumption that lowers the heating value of the gas and the royalty that is owed. The BLM believes that in the absence of data showing otherwise, heating value should be reported based on the assumption that the gas contains no water vapor. To be marketable, gas must be dehydrated to pipeline specifications, which are generally very close to no water vapor. Moreover, under the longstanding “marketable condition” rule, the lessee must perform that dehydration without deducting the costs in determining royalty value. 30 CFR 1206.152(i); 1206.153(i); and 1206.174(h);
The BLM will consider allowing heating value to be reported on an as-delivered basis (or some adaptation of it) if we receive sufficient data showing that assuming water vapor saturation, or a certain level of water vapor, under metered pressure and temperature is reasonable and supported by field data. See discussion of proposed § 3175.120(a)(3) for further explanation of heating value reporting basis.
3.
Based on these comments, the BLM has changed the extended analysis requirement in the proposed rule to apply only to high-volume and very-high-volume FMPs. The BLM's analysis shows that using an assumed component distribution for hexane+ (60 percent hexane, 30 percent heptane, and 10 percent octane) results in additional uncertainty as the hexane+ concentration increases, but does not result in statistically significant bias. Because the heating value certainty standards proposed in § 3175.30(b) do not apply to marginal-volume and low-volume FMPs, marginal- and low-volume FMPs should not be subject to the proposed extended analysis requirement. The BLM may consider further modifications to the proposed extended analysis requirement if commenters submit sufficient extended analysis data that show there is little difference in heating value between the hexane+ analysis and the extended analysis.
4.
Based on these comments, the BLM is proposing a modified version of the dynamic sampling frequency discussed at the public meetings. Following the suggestion of one of the commenters, this proposed rule would establish an initial sampling frequency and then allow for an adjustment of that frequency based on historic heating-value variability. Rather than having sampling frequencies calculated to the nearest day, the calculated sampling frequency would be rounded down to the nearest of one of seven set frequencies: Weekly, every 2 weeks, monthly, every 2 months, every 3 months, every 6 months, and annually. The frequency would not change until a new calculation resulted in either an increase or decrease of the frequency. In addition, the BLM raised the uncertainty standards in proposed § 3175.30(b). We believe the modifications will simplify implementation while still meeting the objective of achieving a set level of uncertainty. Please see the discussion of proposed § 3175.115 for further explanation of gas sampling frequency.
5.
Grandfathering is generally unworkable for two reasons. First, grandfathering would result in two tiers of equipment—older equipment that must meet the standards of a rule that is no longer in effect and newer equipment which would have to meet the standards of the new rule. This would not only require the BLM to maintain, inspect against, and enforce two sets of regulations (one of which no longer applies to equipment coming into service), but also to track which FMPs have been grandfathered and which are subject to the new regulations.
Second, the reason for promulgating new regulations is that the BLM believes new regulations could better ensure accurate and verifiable measurement of oil and gas removed or sold from Federal and Indian leases. In lieu of grandfathering, the BLM has proposed grace periods for bringing existing facilities into compliance with the proposed standards (see proposed § 3175.60). These grace periods are tiered to the volume measured by the FMP, giving more time to bring lower-
6.
The BLM is unaware of any API or GPA standards relating to transducer performance; that is the reason we are proposing the transducer type-testing protocol in this rule (and why API is developing a new standard to address type testing). The proposed type-testing requirement for transducers would not prescribe a standard for transducers. The type testing requirement would quantify the uncertainty of the device tested under specified test conditions. The results of the test would be incorporated into the calculation of overall measurement uncertainty. The transducer performance determined under the proposed protocol could, however, be sufficiently different from the manufacturer's specifications as to result in unacceptable overall meter uncertainty. The BLM does not believe that this will result in a significant cost burden to operators, and specifically requests comment on costs to comply with this proposed requirement.
The BLM agrees with the comments regarding marginal-volume and low-volume FMPs and has exempted both categories of FMPs in the proposed rule. Because transducer testing defines the uncertainty of the devices and marginal volume and low volume FMPs are not subject to uncertainty requirements, we did not feel that characterizing the performance of transducers used at these FMPs is necessary. See the discussion of proposed §§ 3175.43 and 3175.130 for further explanation of this proposed requirement.
However, the BLM did not exempt low-volume FMPs from the flow computer software testing. Errors in flow-computer software can cause biases in measurement. Because low-volume FMPs would have to meet the performance requirements for bias in proposed § 3175.140, flow-computer software testing requirements would apply.
7.
8.
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10.
11.
Executive Order 12866 provides that the Office of Information and Regulatory Affairs (OIRA) will review all significant rules. The OIRA has determined that this rule is significant because it would raise novel legal or policy issues.
Executive Order 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the nation's regulatory system so that it promotes predictability, reduces uncertainty, and uses the best, most innovative, and least burdensome tools for achieving regulatory ends. The Executive Order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We have developed this rulemaking consistent with these requirements.
The BLM certifies that this proposed rule would not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
Of the 6,628 domestic firms involved in onshore oil and gas extraction, 99 percent (or 6,561) had fewer than 500 employees. Based on this national data, the preponderance of firms involved in developing oil and gas resources are small entities as defined by the SBA. As such, it appears a substantial number of small entities would be potentially affected by the proposed rule. Using the best available data, the BLM estimates there are approximately 3,700 lessees and operators conducting gas operations on Federal and Indian lands that could be affected by the proposed rule.
In addition to determining whether a substantial number of small entities are likely to be affected by this rule, the BLM must also determine whether the rule is anticipated to have a significant economic impact on those small entities. On an ongoing basis, we estimate the proposed changes would increase the regulated community's annual costs by about $46 million, or an average of about $13,000 per entity per year (not including anticipated increased royalty on increased revenue discussed earlier). In addition, there would be one-time costs associated with implementing the proposed changes of as much as $33 million, or an average of approximately $8,900 per entity affected by the proposed rule, phased in over a 3-year period. For further information on these costs estimates, please see the Economic and Threshold Analysis prepared for this proposed rule. The BLM is specifically seeking comment on that analysis and the assumptions used to generate these estimates.
Recognizing that the SBA definition for a small business in the relevant categories is one with fewer than 500 employees, which represents a wide range of possible oil and gas producers, the BLM, as part of an Economic and Threshold Analysis conducted for this rulemaking, looked at income data for three different small-sized entities that currently hold Federal oil and gas leases that were issued in competitive sales. Using annual reports that these companies filed with the U.S. Securities and Exchange Commission for 2012, 2013, and 2014, the BLM concluded that the one-time costs and the annual ongoing costs would result in a reduction in the profit margins of these entities ranging from 0.0005 percent to 0.5742 percent, with an average reduction of 0.0362 percent. Copies of the analysis can be obtained from the contact person listed above (see
All of the proposed provisions would apply to entities regardless of size. However, entities with the greatest activity (
Based on the available information, we conclude that the proposed rule would not have a significant impact on a substantial number of small entities. Therefore, a final Regulatory Flexibility Analysis is not required, and a Small Entity Compliance Guide is not required.
This proposed rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule would not have an annual effect on the economy of $100 million or more. As explained under the preamble discussion concerning Executive Order 12866, Regulatory Planning and Review, the proposed rule would increase, by about $46 million annually, the cost associated with the development and production of gas resources under Federal and Indian oil and gas leases. There would also be a one-time cost estimated to be $33 million.
This rulemaking proposes to replace Order 5 to ensure that gas produced from Federal and Indian oil and gas leases is more accurately accounted for. As described under the section concerning Executive Order 12866, Regulatory Planning and Review, the average estimated annual increased cost to each entity that produces gas from all Federal and Indian leases for implementing these changes would be about $13,000 per year, and a one-time average cost of about $8,900 per entity, phased in over a 3-year period.
This proposed rule:
• Would not cause a major increase in costs or prices for consumers, individual industries, Federal, State, tribal, or local government agencies, or geographic regions; and
• Would not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.
Under the Unfunded Mandates Reform Act (2 U.S.C. 1501
• This proposed rule would not “significantly or uniquely” affect small governments. A Small Government Agency Plan is unnecessary.
• This proposed rule would not include any Federal mandate that may result in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100 million or greater in any single year.
The proposed rule is not a “significant regulatory action” under the Unfunded Mandates Reform Act. The changes proposed in this rule would not impose any requirements on any State or local governmental entity.
The proposed rule would not have significant takings implications as defined under Executive Order 12630. A takings implication assessment is not required. This proposed rule would revise the minimum standards for accurate measurement and proper reporting of gas produced from Federal and Indian leases, unit PAs, and CAs, by providing an improved system for production accountability by operators and lessees. Gas production from Federal and Indian leases is subject to lease terms that expressly require that lease activities be conducted in compliance with applicable Federal laws and regulations. The implementation of this proposed rule would not impose requirements or limitations on private property use or require dedications or exactions from owners of private property, and as such, the proposed rule is not a governmental action capable of interfering with constitutionally protected property rights. Therefore, the proposed rule would not cause a taking of private property or require further discussion of takings implications under this Executive Order.
Under Executive Order 13132, the BLM finds that the proposed rule would not have significant Federalism implications. A Federalism assessment is not required. This proposed rule would not change the role of or responsibilities among Federal, State, and local governmental entities. It does not relate to the structure and role of the States and would not have direct or substantive effects on States.
Under Executive order 13175, the President's memorandum of April 29, 1994, “Government-to-Government Relations with Native American Tribal Governments” (59 FR 22951), and 512
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July 13, 2011; and
• Billings, Montana on August 24, 2011.
In addition, the BLM hosted a tribal workshop and webcast on April 24, 2013. The purpose of these meetings was to solicit initial feedback and preliminary comments from the tribes. Comments from the tribes will continue to be accepted and consultation will continue as this rulemaking proceeds. To date, the tribes have expressed concerns about the subordination of tribal laws, rules, and regulations to the proposed rule; tribes' representation on the DOI GOMT; and the BLM's Inspection and Enforcement program's ability to enforce the terms of this proposed rule. While the BLM will continue to address these concerns, none of the concerns expressed relate to or affect the substance of this proposed rule.
Under Executive Order 12988, we have determined that the proposed rule would not unduly burden the judicial system and meets the requirements of Sections 3(a) and 3(b)(2) of the Order. We have reviewed the proposed rule to eliminate drafting errors and ambiguity. It has been written to provide clear legal standards for affected conduct rather than general standards, and promote simplification and burden reduction.
Under Executive Order 13352, the BLM has determined that this proposed rule would not impede facilitating cooperative conservation and would take appropriate account of and consider the interests of persons with ownership or other legally recognized interests in land or other natural resources. This rulemaking process will involve Federal, State, local and tribal governments, private for-profit and nonprofit institutions, other nongovernmental entities and individuals in the decision-making via the public comment process for the rule. The process will provide that the programs, projects, and activities are consistent with protecting public health and safety.
The Paperwork Reduction Act (PRA) (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. This proposed rule contains information collection requirements that are subject to review by OMB under the PRA. Collections of information include any request or requirement that persons obtain, maintain, retain, or report information to an agency, or disclose information to a third party or to the public (44 U.S.C. 3502(3) and 5 CFR 1320.3(c)). After promulgating a final rule and receiving approval from the OMB (in the form of a new control number), the BLM intends to ask OMB to combine the activities authorized by the new control number with existing control number 1004-0137, Onshore Oil and Gas Operations (expiration date January 31, 2018).
The information collection activities in this proposed rule are described below along with estimates of the annual burdens. Included in the burden estimates are the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing each component of the proposed information collection requirements.
The information collection request for this proposed rule has been submitted to OMB for review under 44 U.S.C. 3507(d). A copy of the request can be obtained from the BLM by electronic mail request to Jennifer Spencer at
The BLM requests comments on the following subjects:
1. Whether the collection of information is necessary for the proper functioning of the BLM, including whether the information will have practical utility;
2. The accuracy of the BLM's estimate of the burden of collecting the information, including the validity of the methodology and assumptions used;
3. The quality, utility, and clarity of the information to be collected; and
4. How to minimize the information collection burden on those who are to respond, including the use of appropriate automated, electronic, mechanical, or other forms of information technology.
If you want to comment on the information collection requirements of this proposed rule, please send your comments directly to OMB, with a copy to the BLM, as directed in the
Proposed § 3175.120 would require the submission of gas analysis reports to the BLM within 5 days of the following due dates for the sample as specified in proposed § 3175.115:
(a) Gas samples at low-volume FMPs would be required at least every 6 months;
(b) Gas samples at marginal-volume FMPs would be required at least annually; and
(c) Spot samples at high- and very-high-volume FMPs would be required at least every 3 months and every month, respectively, unless the BLM determines that more frequent analysis is required under § 3175.115(c).
Some of the information collection activities in the proposed rule would involve review of documentation by the PMT, made up of measurement experts from the BLM. The PMT would act as a central BLM advisory body for reviewing and approving devices and software not specifically addressed in the currently proposed regulations. The documentation submitted to the PMT would assist the BLM in ensuring that the hardware and software used in gas measurement are in compliance with performance standards proposed in this rule.
Proposed § 3175.46 would provide for listing of approved makes and models of isolating flow conditioners at
Proposed § 3175.47 would authorize operators to seek approval to use a particular make and model of a differential primary device (other than flange-tapped orifice plates and those listed at
Proposed § 3175.48 would require submission of a report showing the results of each test required by the PMT. This report would be reviewed by the PMT and would be a pre-requisite for BLM approval of a linear type of meter in lieu of an approved type of differential meter. This requirement would assist the BLM in ensuring that meters used in gas measurement are in compliance with performance standards.” The PMT would review the data to determine whether the meter meets the requirements of § 3175.30, and make a recommendation to the BLM, which would approve use of the device, disapprove use of the device, or approve its use with conditions.
Proposed § 3175.43 would require submission of a report showing the results of each test required by proposed §§ 3175.131 through 3175.135, including all data points recorded. This report would be reviewed by the PMT, and would be a pre-requisite for BLM approval of a particular make and model of transducer for use in an electronic gas metering (EGM) system. This requirement would assist the BLM in ensuring that transducers used in gas measurement are in compliance with performance standards.
Proposed § 3175.44 would require submission of a report showing the results of each test required by proposed §§ 3175.141 through 3175.143, including all data points recorded. This report would be reviewed by the PMT, and would be a pre-requisite for BLM approval of software for use in an electronic gas measurement (EGM) system. This requirement would assist the BLM in ensuring that software used in gas measurement is in compliance with performance standards.
Proposed § 3175.80(e) would require operators to retain, and submit to the BLM upon request, usually during a production audit, documentation for every orifice plate inspection and include that documentation as part of the verification report required at proposed § 3175.92(d) (where the operator uses mechanical recorders) or proposed § 3175.102(e) (where the operator uses EGM systems). The documentation would be required to include:
• The information required in proposed § 3170.7(g) (
• Plate orientation (bevel upstream or downstream);
• Measured orifice bore diameter;
• Confirmation that the plate condition complies with the applicable API standard;
• The presence of oil, grease, paraffin, scale, or other contaminants found on the plate;
• Time and date of inspection; and
• Whether or not the plate was replaced.
Proposed § 3175.80(j) would require operators to retain, and submit to the BLM upon request, usually during a production audit, documentation demonstrating that the meter tube complies with applicable API standards and showing completion of all required measurements. Upon request, the operator would also be required to provide the information required in proposed § 3170.7(g) (
Proposed 43 CFR 3175.92(d) would require operators to retain, and submit to the BLM upon request, usually during a production audit, documentation of each verification for mechanical recorders. This documentation would be required to include:
• The information required in proposed § 3170.7(g) (
• The time and date of the verification and the prior verification date;
• Primary-device data (meter-tube inside diameter and differential-device size and beta or area ratio);
• The type and location of taps (flange or pipe, upstream or downstream static tap);
• Atmospheric pressure used to offset the static-pressure pen, if applicable;
• Mechanical recorder data (make, model, and differential pressure, static pressure, and temperature element ranges);
• The normal operating points for differential pressure, static pressure, and flowing temperature;
• Verification points (as-found and applied) for each element;
• Verification points (as-left and applied) for each element, if a calibration was performed;
• Names, contact information, and affiliations of the person performing the verification and any witness, if applicable; and
• Remarks, if any.
Proposed § 3175.92(g) would require operators to certify test equipment used to verify or calibrate the static pressure, differential pressure, and temperature elements/transducers at an FMP at least every 2 years. Documentation of the recertification would be required to be on-site during all verifications and would be required to show:
• Test equipment serial number, make, and model;
• The date on which the recertification took place;
• The test equipment measurement range; and
• The uncertainty determined or verified as part of the recertification.
Proposed § 3175.93 would require operators to retain, and submit to the BLM upon request, usually during a production audit, integration statements containing the following information:
• The information required in proposed § 3170.7(g) (
• The name of the company performing the integration;
• The month and year for which the integration statement applies;
• Meter-tube inside diameter (inches);
• Information of the primary device;
• Relative density (specific gravity);
• CO
• N
• Heating value calculated under § 3175.125 (Btu/standard cubic feet);
• Atmospheric pressure or elevation at the FMP;
• Pressure base;
• Temperature base;
• Static pressure tap location (upstream or downstream);
• Chart rotation (hours or days);
• Differential pressure bellows range (inches of water);
• Static pressure element range (psi); and
• For each chart or day integrated, the time and date on and time and date off, average differential pressure (inches of water), average static pressure, static pressure units of measure (psia or psig), average temperature (° F), integrator counts or extension, hours of flow, and volume (Mcf).
Proposed § 3175.102(e)(1) would require operators to retain, and submit to the BLM upon request, usually during a production audit, documentation of each verification of an EGM . This documentation would be required to include:
• The information required in proposed § 3170.7(g) (
• The time and date of the verification and the last verification date;
• Primary device data (meter-tube inside diameter and differential-device size, beta or area ratio);
• The type and location of taps (flange or pipe, upstream or downstream static tap);
• The flow computer make and model;
• The make and model number for each transducer, for component-type EGM systems;
• Transducer data (make, model, differential, static, temperature URL, and upper calibrated limit);
• The normal operating points for differential pressure, static pressure, and flowing temperature;
• Atmospheric pressure;
• Verification points (as-found and applied) for each transducer;
• Verification points (as-left and applied) for each transducer, if calibration was performed;
• The differential device inspection date and condition (
• Verification of equipment make, model, range, accuracy, and last certification date;
• The name, contact information, and affiliation of the person performing the verification and any witness, if applicable; and
• Remarks, if any.
Proposed 43 CFR 3175.102(e)(2) would allow redundancy verification in lieu of routine verification. If an operator opts to use redundancy verification, the proposed rule would establish standards for the information that must be retained and submitted to the BLM upon request, usually during a production audit. The following would be the required information for redundancy verification checks:
• The information required in proposed § 3170.7(g) (
• The month and year for which the redundancy check applies;
• The makes, models, upper range limits, and upper calibrated limits of the primary set of transducers;
• The makes, models, upper range limits, and upper calibrated limits of the check set of transducers;
• The information required in API 21.1, Annex I, which includes comparisons of volume, energy, differential pressure, static pressure, and temperature both in tabular form (average values) and graphical form (instantaneous values);
• The tolerance for differential pressure, static pressure, and temperature as calculated under proposed 43 CFR 3175.102(d)(2) of this section; and
• Whether or not each transducer required verification under paragraph (c) of this section.
Proposed § 3175.104(a) would require operators to retain the original, unaltered, unprocessed, and unedited daily and hourly quantity transaction record (QTR) and submit them to the BLM upon request, usually during a production audit. The proposed rule would require the QTR to contain the information identified in API 21.1.5.2 (date and time identifier, quantity [volume, mass and/or energy], flow time, integral value/average extension, differential pressure average, static pressure average, temperature average, and relative density, energy content, composition, and/or density averages must be included if they are live inputs), with the following additions and clarifications:
• The information required in proposed § 3170.7(g) (
• The volume, flow time, integral value or average extension, and the average differential pressure, static pressure, and temperature as calculated in proposed § 3175.103(c), reported to at least five significant digits; and
• A statement of whether the operator has submitted the integral value or average extension.
Proposed 43 CFR 3175.104(b) would require operators to retain, and submit to the BLM upon request, usually during a production audit, the original, unaltered, unprocessed, and unedited configuration log. The proposed rule would require the configuration log to contain the information under API 21.1.5.4 (meter identifier, date and time collected, contract hour, atmospheric pressure for sites with gauge pressure transmitters, pressure base, temperature base, timestamp definition, calibrated or user defined span for differential pressure, no flow cutoff, calibrated or user defined span for static pressure, static pressure type [absolute or gauge], calibrated or user defined operating range for temperature or fixed temperature if not live, gas composition [if not live], relative density [if not live], compressibility [if not live], energy content [if not live], meter tube reference inside diameter, meter tube material, meter tube reference temperature, meter tube static pressure tap location [upstream/downstream], orifice plate reference bore size, orifice plate material, orifice plate reference temperature. discharge coefficient calculation method/reference, gas expansion factor method/reference, compressibility calculation method/reference, quantity calculation period, sampling rate, variables included in the integral value, base compressibility of air, absolute viscosity [
• The information required in proposed § 3170.7(g) (
• Software/firmware identifiers that comply with applicable API standards;
• The fixed temperature, if not live (° F);
• The static-pressure tap location (upstream or downstream); and
• The flow computer snapshot report in API 21.1.5.4.2 and API 21.1, Annex G.
Proposed § 3175.104(c) would require operators to retain the original, unaltered, unprocessed, and unedited event log and submit it to the BLM upon request, usually during a production audit. The event log must comply with API 21.1.5.5 (the chronological listing of the date and time of any change to a constant flow parameter that can affect the quantity transaction record, along with the old and new value), with the following additions and clarifications:
• The event log must record all power outages (including the length of the outage) that inhibit the meter's ability to collect and store new data; and
• The event log must have sufficient capacity and must be retrieved and stored at intervals frequent enough to maintain a continuous record of events as required under proposed § 3170.7, or the life of the FMP, whichever is shorter.
Proposed 3175.117(c) and (d) would require operators to retain the manufacturer's specifications and installation and operational recommendations for on-line gas chromatographs, and the results of all verifications of on-line gas chromatographs and submit the information to the BLM upon request, usually during a production audit. Proposed § 3175.118(i) would require the gas chromatograph verification to contain:
• The components analyzed;
• The response factor for each component;
• The peak area for each component;
• The mole percent of each component as determined by the GC;
• The mole percent of each component in the gas used for verification;
• The difference between the mole percents determined in paragraphs (i)(4) and (i)(5) of this section, expressed in relative percent;
• Documentation that the gas used for verification meets the requirements of GPA 2198-03 (incorporated by reference, see § 3175.31), including a unique identification number of the calibration gas used and the name of the supplier of the calibration gas;
• The time and date the verification was performed; and
• The name and affiliation of the person performing the verification.
Operators would be required to submit gas analysis reports to the BLM within 5 days of the due date for the sample as specified in proposed § 3175.115. Submission would be done electronically into a BLM database. Paragraph (a) would provide that, unless otherwise required under paragraph (b), spot samples for all FMPs would be required to be taken and analyzed at the frequency specified at Table 4 of proposed § 3175.110.
Paragraph (b) would provide that the BLM could change the required sampling frequency for high-volume and very-high-volume FMPs if the BLM determines that the sampling frequency required in Table 4 is not sufficient to achieve the heating value certainty levels required in proposed § 3175.30(b). Table 5 at paragraph (c) would limit the amount of time that would be allowed between any two samples.
Proposed 3175.120 would require gas analysis reports to contain the following information:
• The information required in proposed § 3170.7(g) (
• The date and time that the sample for spot samples was taken or, for composite samples, the date the cylinder was installed and the date the cylinder was removed;
• The date and time of the analysis;
• For spot samples, the effective date, if other than the date of sampling;
• For composite samples, the effective start and end date;
• The name of the laboratory where the analysis was performed;
• The device used for analysis (
• The make and model of analyzer;
• The date of last calibration or verification of the analyzer;
• The flowing temperature at the time of sampling;
• The flowing pressure at the time of sampling, including units of measure (psia or psig);
• The flow rate at the time of the sampling;
• The ambient air temperature at the time the sample was taken;
• Whether or not heat trace or any other method of heating was used;
• The type of sample (
• The sampling method if spot-cylinder (
• A list of the components of the gas tested;
• The un-normalized mole percentages of the components tested, including a summation of those mole percents;
• The normalized mole percent of each component tested, including a summation of those mole percents;
• The ideal heating value (Btu/scf);
• The real heating value (Btu/scf), dry basis;
• The pressure base and temperature base;
• The relative density; and
• The name of the company obtaining the gas sample.
Components that are listed on the analysis report, but not tested, would be required to be annotated as such.
Proposed § 3175.126(c)(2) would require operators to identify and verifiably justify all values on daily and hourly QTRs that have been changed or edited as a result of measurement errors stemming from an equipment malfunction causing discrepancies in the calculated volume or heating value of the gas. This documentation would be required to be retained under proposed § 3170.7 and submitted to the BLM upon request, usually during a production audit.
The following table itemizes the annual estimated information collection burdens of this proposed rule:
The information collection activities that appear in the above table with the notation, “Usual and customary, within the meaning of 5 CFR 1320.3(b)(2)” are standard industry practices and will not result in collection burdens for industry in addition to those incurred in the ordinary course of their business. For reasons documented in the descriptions of the proposed information collection requirements, the BLM believes the burdens of these proposals are exempt from the PRA in accordance with 5 CFR 1320.3(b)(2). That is why no burdens are indicated for those activities.
The information collection activities that appear in the above table with the notation, “Recordkeeping requirement” are included in this PRA analysis because this proposed rule would require respondents to collect and retain certain information. However, any requirement to submit the information to the BLM (usually during a production audit) would be in accordance with the BLM's proposed rule on site security, which was published on July 13, 2015 (80 FR 40768). OMB has assigned control number 1004-0207 to that proposed rule, but has not yet authorized the BLM to begin collecting information under that control number.
The BLM has prepared a draft environmental assessment (EA) that concludes that this proposed rule would not have a significant impact on the quality of the environment under NEPA, 42 U.S.C. 4332(2)(C), therefore a detailed statement under NEPA is not required. A copy of the draft EA can be viewed at
The proposed rule would not impact the environment significantly. For the most part, the proposed rule would in substance update the provisions of Order 5 and would involve changes that are of an administrative, technical, or procedural nature that would apply to the BLM's and the lessee's or operator's administrative processes. For example, the proposed rule would clarify the acceptable methods for estimating and documenting reported volumes of gas when metering equipment is malfunctioning or out of service. The proposed rule would also establish new requirements for gas sampling, including sampling location and methods, sampling frequency, analysis methods, and the minimum number of components to be analyzed. Finally, the proposed rule would establish new meter equipment, maintenance, inspection, and reporting standards. These changes would enhance the agency's ability to account for the gas produced from Federal and Indian lands, but should have minimal to no impact on the environment. We will consider any new information we receive during the public comment period for the proposed rule that may inform our analysis of the potential environmental impacts of the rule.
This proposed rule would not have a significant adverse effect on the nation's energy supply, distribution or use, including a shortfall in supply or price increase. Changes in this proposed rule would strengthen the BLM's accountability requirements for operators under Federal and Indian oil and gas leases. As discussed above, these changes would prescribe a number of specific requirements for production measurement, including sampling, measuring, and analysis protocol; categories of violations; and reporting requirements. The proposal also establishes specific requirements related to the physical makeup of meter components. All of the changes would increase the regulated community's annual costs by about $46 million, or an average of approximately $13,000 per entity per year. There would be an additional one-time cost to industry of about $33 million to comply with the changes, or an average of approximately $8,900 per entity, phased in over a 3-year period. Entities with the greatest activity (
We expect that the proposed rule would not result in a net change in the quantity of oil and gas that is produced from oil and gas leases on Federal and Indian lands.
In developing this proposed rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Information Quality Act (Pub. L. 106-554, Appendix C Title IV, Section 515, 114 Stat. 2763A-153).
Executive Order 12866 requires each agency to write regulations that are simple and easy to understand. We invite your comments on how to make these proposed regulations easier to understand, including answers to questions such as the following:
1. Are the requirements in the proposed regulations clearly stated?
2. Do the proposed regulations contain technical language or jargon that interferes with their clarity?
3. Does the format of the proposed regulations (grouping and order of sections, use of headings, paragraphing, etc.) aid or reduce their clarity?
4. Would the regulations be easier to understand if they were divided into more (but shorter) sections?
5. Is the description of the proposed regulations in the
Please send any comments you have on the clarity of the regulations to the address specified in the
The principal authors of this rule are: Richard Estabrook of the BLM Washington Office; Gary Roth of the BLM Buffalo, Wyoming Field Office; Wanda Weatherford of the BLM Farmington, New Mexico Field Office; Clifford Johnson of the BLM Vernal, Utah Field Office; and Rodney Brashear of the BLM Durango, Colorado Field Office, assisted by Mike Wade of the BLM Washington Office; Joe Berry and Faith Bremner of the staff of BLM's Regulatory Affairs Division; John Barder, Office of Natural Resources Revenue; and Geoffrey Heath, 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.
Administrative practice and procedure; Immediate assessments, Incorporation by reference; Indians-lands; Mineral royalties; Oil and gas exploration; Oil and gas measurement; Penalties; Public lands—mineral resources.
For the reasons set out in the preamble, the Bureau of Land Management proposes to amend 43 CFR part 3160 and add a new subpart 3175 to new 43 CFR part 3170 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.
All gas removed or sold from a lease, communitized area, or unit participating area must be measured under subpart 3175 of this title. All measurement must be on the lease, communitized area, or unit from which the gas originated and must not be commingled with gas originating from other sources unless approved by the authorized officer under subpart 3173 of this title.
(a) Whenever any person fails or refuses to comply with the regulations in this part, the terms of any lease or permit, or the requirements of any notice or order, the authorized officer shall notify that person in writing of the violation or default.
(1) For major violations, the authorized officer may also subject the person to an assessment of $1,000 per violation, per inspection.
(2) For minor violations, the authorized officer may also subject the person to an assessment of $250 per violation, per inspection.
(b) Certain instances of noncompliance are violations of such a nature as to warrant the imposition of immediate major assessments upon discovery as compared to those established by paragraph (a) of this section. Upon discovery the following violations, as well as the violations identified in subparts 3173, 3174, and 3175 of this part, will result in assessments in the specified amounts per violation, per inspection, without exception:
(1) For failure to install blowout preventer or other equivalent well control equipment, as required by the approved drilling plan, $1,000;
(2) For drilling without approval or for causing surface disturbance on Federal or Indian surface preliminary to drilling without approval, $1,000;
(c) On a case-by-case basis, the State Director may compromise or reduce assessments under this section. In compromising or reducing the amount
4. Amend § 3163.2 by revising paragraphs (a), (b), and (d) through (f), removing paragraphs (g), (j) and (k), redesignating paragraph (i) as paragraph (g) and revising it. The revisions read as follows:
(a)(1) Whenever any person fails or refuses to comply with any applicable requirements of the Federal Oil and Gas Royalty Management Act, any mineral leasing law, any regulation thereunder, or the terms of any lease or permit issued thereunder, the authorized officer will notify the person in writing of the violation, unless the violation was discovered and reported to the authorized officer by the liable person or the notice was previously issued under § 3163.1 of this subpart.
(2) Whenever a purchaser or transporter who is not an operating rights owner or operator fails or refuses to comply with 30 U.S.C. 1713 or applicable rules or regulations regarding records relevant to determining the quality, quantity, and disposition of oil or gas produced from or allocable to a Federal or Indian oil and gas lease, the authorized officer will notify the purchaser or transporter, as appropriate, in writing of the violation.
(b)(1) If the violation is not corrected within 20 days of such notice or report, or such longer time as the authorized officer may agree to in writing, the person will be liable for a civil penalty of up to $500 per violation for each day such violation continues, dating from the date of such notice or report. Any amount imposed and paid as assessments under § 3163.1(a)(1) of this subpart will be deducted from penalties under this section.
(2) If the violation specified in paragraph (a) of this section is not corrected within 40 days of such notice or report, or a longer period as the authorized officer may agree to in writing, the person will be liable for a civil penalty of up to $5,000 per violation for each day the violation continues, dating from the date of such notice or report. Any amount imposed and paid as assessments under § 3163.1(a)(1) of this subpart will be deducted from penalties under this section.
(d) Whenever a transporter fails to permit inspection for proper documentation by any authorized representative, as provided in § 3162.7-1(c) of this title, the transporter shall be liable for a civil penalty of up to $500 per day for the violation, dating from the date of notice of the failure to permit inspection and continuing until the proper documentation is provided. If the violation continues beyond 20 days, the authorized officer will revoke the transporter's authority to remove crude oil produced from, or allocated to, any Federal or Indian lease under the authority of that authorized officer. This revocation of the transporter's authority will continue until the transporter provides proper documentation and pays any related penalty.
(e) Any person shall be liable for a civil penalty of up to $10,000 per violation for each day such violation continues, if the person:
(1) Fails or refuses to permit lawful entry or inspection authorized by § 3162.1(b) of this title; or
(2) Knowingly or willfully fails to notify the authorized officer by letter or Sundry Notice, Form 3160-5 or orally to be followed by a letter or Sundry Notice, not later than the 5th business day after any well begins production on which royalty is due, or resumes production in the case of a well which has been off of production for more than 90 days, from a well located on a lease site, or allocated to a lease site, of the date on which such production began or resumed.
(f) Any person shall be liable for a civil penalty of up to $25,000 per violation for each day such violation continues, if the person:
(1) Knowingly or willfully prepares, maintains or submits false, inaccurate or misleading reports, notices, affidavits, records, data or other written information required by this part; or
(2) Knowingly or willfully takes or removes, transports, uses or diverts any oil or gas from any Federal or Indian lease site without having valid legal authority to do so; or
(3) Purchases, accepts, sells, transports or conveys to another any oil or gas knowing or having reason to know that such oil or gas was stolen or unlawfully removed or diverted from a Federal or Indian lease site.
(g) Civil penalties provided by this section are supplemental to, and not in derogation of, any other penalties or assessments for noncompliance in any other provision of law, except as provided in paragraphs (a) and (b) of this section.
(a)
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
(a) As used in this subpart, the term:
(b) As used in this subpart the following additional acronyms carry the meaning prescribed:
Measurement of all gas removed or sold from Federal and Indian leases and unit PAs or CAs that include one or more Federal or Indian leases, must comply with the standards prescribed in this subpart, except as otherwise approved under § 3170.6 of this subpart.
(a)
(2) For very-high-volume FMPs, the measuring equipment must achieve an overall flow rate measurement uncertainty within ±2 percent.
(3) The determination of uncertainty is based on the values of flowing parameters (
(i) The average flowing parameters listed on the most recent daily (QTR), if available to the BLM at the time of uncertainty determination; or
(ii) The average flowing parameters from the previous day, as required under § 3175.101(b)(4)(ix) through (xi) of this subpart.
(b)
(2) For very-high-volume FMPs, the measuring equipment must achieve an annual average heating value uncertainty within ±1 percent.
(c)
(d)
(a) Certain material identified in paragraphs (b) and (c) of this section is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that specified in this section, the BLM must publish notice of change in the
(b) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005; telephone 202-682-8000. API also offers free, read-only access to some of the material at
(1) API Manual of Petroleum Measurement Standards (MPMS) Chapter 14, Section 1, Collecting and Handling of Natural Gas Samples for Custody Transfer, Sixth Edition, February 2006, Reaffirmed 2011 (“API 14.1.12.10”), incorporation by reference (IBR) approved for § 3175.114(b).
(2) API MPMS Chapter 14, Section 2, Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases, Second Edition, August 1994, Reaffirmed March 1, 2006 (“API 14.2”), IBR approved for §§ 3175.103(a)(1)(ii) and 3175.120(d).
(3) API MPMS, Chapter 14, Section 3, Part 1, General Equations and Uncertainty Guidelines, Fourth Edition, September 2012, Errata, July 2013. (“API 14.3.1.4.1”), IBR approved for § 3175.80 Table 1.
(4) API MPMS Chapter 14, Section 3, Part 2, Specifications and Installation Requirements, Fourth Edition, April 2000, Reaffirmed 2011 (“API 14.3.2,” “API 14.3.2.4,” “API 14.3.2.5.1 through API 14.3.2.5.4,” “API 14.3.2.5.5.1 through API 14.3.2.5.5.3,” “API 14.3.2.6.2,” “API 14.3.2.6.3,” “API 14.3.2.6.5,” and “API 14.3.2, Appendix 2-D”), IBR approved for §§ 3175.46(b) and (c), 3175.80 Table 1, 3175.80(c), 3175.80(d), 3175.80(e)(4), 3175.80(f), 3175.80(g), 3175.80(g)(3), 3175.80(i), 3175.80(j), 3175.80(k), 3175.80(l), and 3175.112(b)(1).
(5) API MPMS Chapter 14, Section 3, Part 3, Natural Gas Applications, Fourth Edition, November 2013 (“API 14.3.3,” “API 14.3.3.4,” and “API 14.3.3.5.” and “API 14.3.3.5.6,”), IBR approved for §§ 3175.94(a)(1) and 3175.103(a)(1)(i).
(6) API MPMS, Chapter 14, Section 5, Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer, Third Edition, January 2009 (“API 14.5,” “API 14.5.3.7,” and “API 14.5.7.1”), IBR approved for §§ 3175.120(c) and 3175.125 (a)(1).
(7) API MPMS Chapter 21, Section 1, Electronic Gas Measurement, Second Edition, February 2013 (“API 21.1,” “API 21.1.4,” “API 21.1.4.4.5,” “API 21.1.5.2,” “API 21.1.5.3,” “API 21.1.5.4,” “API 21.1.5.4.2,” “API 21.1.5.5,” “API 21.1.5.6,” “API 21.1.7.3,” “API 21.1.7.3.3,” “API 21.1.8.2,” “API 21.1.8.2.2.2, Equation 24,” “API 21.1.9,” “API 21.1 Annex B,” “API 21.1 Annex G,” “API 21.1 Annex H, Equation H.1,” and “API 21.1 Annex I”), IBR approved for §§ 3175.100 Table 3, 3175.101(e), 3175.102(a)(2), 3175.102(c), 3175.102(c)(4), 3175.102(c)(5), 3175.102(d), 3175.102(e)(2)(v), 3175.103(b), 3175.103(c), 3175,104(a), 3175.104(b), 3175.104(b)(2), 3175.104(c), and 3175.104(d).
(8) API MPMS Chapter 22, Section 2, Differential Pressure Flow Measurement Devices, First Edition, August 2005, Reaffirmed 2012 (“API 22.2”), IBR approved for § 3175.47 (a), (b), and (c).
(c) Gas Processors Association (GPA), 6526 E. 60th Street, Tulsa, OK 74145; telephone 918-493-3872.
(1) GPA Standard 2166-05, Obtaining Natural Gas Samples for Analysis by Gas Chromatography, Revised 2005 (“GPA 2166-05 Section 9.1,” “GPA 2166.05 Section 9.5,” “GPA 2166-05 Sections 9.7.1 through 9.7.3,” “GPA 2166-05 Appendix A,” “GPA 2166-05 Appendix B.3,” “GPA 2166-05 Appendix D”), IBR approved for §§ 3175.113(c)(3), 3175.113(d)(1)(ii), 3175.113(d)(1)(iii), 3175.114(a)(1), 3175.114(a)(2), 3175.114(a)(3), 3175.117(a).
(2) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, Revised 2000 (“GPA 2261-00”, “GPA 2261-00, Section 4,” GPA 2261-00, Section 5,” “GPA 2261-00, Section 9”), IBR approved for § 3175.118(a)(b)(c) and (e).
(3) GPA Standard 2198-03, Selection, Preparation, Validation, Care and Storage of Natural Gas and Natural Gas Liquids Reference Standard Blends, Revised 2003. (“GPA 2198-03”), IBR approved for §§ 3175.118(h), 3175.118(i)(7). Note 1 to § 3175.31(b) and (c): You may also be able to purchase these standards from the following resellers: Techstreet, 3916 Ranchero Drive, Ann Arbor, MI 48108; telephone 734-780-8000;
The measurement equipment described in §§ 3175.41 through 3175.48 is approved for use at FMPs under the conditions and circumstances stated in those sections if it meets or exceeds the minimum standards prescribed in this subpart.
Flange-tapped orifice plates constructed and installed under § 3175.80 of this subpart are approved for use.
Chart recorders used in conjunction with approved differential-type meters that are installed, operated, and maintained under § 3175.90 of this subpart are approved for use for low-volume and marginal-volume FMPs only, and are not approved for high-volume or very-high-volume FMPs.
(a) A specific make, model, and URL of a transducer used in conjunction with differential meters for high-volume or very-high-volume FMPs is approved for use if it meets the following requirements:
(1) It has been type-tested under § 3175.130 of this subpart;
(2) The documentation required in § 3175.130 of this subpart has been submitted to the PMT; and
(3) It has been placed on the list of type-tested equipment maintained at
(b) All transducers used at marginal- and low-volume FMPs are approved for use.
(a) A specific make and model of flow computer and software version is approved for use if it meets the following requirements:
(1) The documentation required in § 3175.140 of this subpart has been submitted to the PMT;
(2) The PMT has determined that the flow computer and software version passed the type-testing required in § 3175.140 of this subpart, except as provided in paragraph (b) of this section; and
(3) It has been placed on the list of approved equipment maintained at
(b) Software revisions that do not affect or that do not have the potential to affect determination of flow rate, determination of volume, and data or calculations used to verify flow rate or volume are not required to be type-tested.
GCs that meet the standards in §§ 3175.117 and 3175.118 of this subpart for determining heating value and relative density are approved for use.
An approved make and model of isolating flow conditioner that is listed at
(a) All testing required under this section must be performed at a laboratory that is NIST traceable and not affiliated with the flow-conditioner manufacturer.
(b) The operator or manufacturer must test the flow conditioner under API 14.3.2, Appendix 2-D (incorporated by reference, see § 3175.31), and under any additional test protocols that the BLM requires that are posted on the BLM's Web site at
(c) The PMT will review the test data to ensure that the device meets the requirements of API 14.3.2, Appendix 2-D (incorporated by reference, see § 3175.31) and make a recommendation to the BLM to either approve use of the device, disapprove use of the device, or approve it with conditions for its use.
(d) If approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at
The make and model of a differential primary device that is listed at
(a) The primary device must be tested under API 22.2 (incorporated by reference, see § 3175.31), and under any additional protocols that the BLM requires that are posted on the BLM's Web site at
(b) The operator must submit to the BLM all test data required under API 22.2 (incorporated by reference, see § 3175.31);
(c) The PMT will review the test data to ensure that the primary device meets the requirements of API 22.2 (incorporated by reference, see § 3175.31) and § 3175.30(c) and (d) of this subpart and make a recommendation to the BLM to either approve use of the device, disapprove use of the device, or approve its use with conditions.
(d) If approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at
The BLM may approve linear measurement devices such as ultrasonic meters, Coriolis meters, positive displacement meters, and turbine meters on a case-by-case basis. To request approval, the operator must submit to the AO all data that the BLM requires. The PMT will review the data to determine whether the meter meets the requirements of § 3175.30 of this subpart, and make a recommendation to the BLM, which will either approve use of the device, disapprove use of the device, or approve its use with conditions.
(a) The measuring procedures and equipment installed at any FMP on or after [EFFECTIVE DATE OF THE FINAL RULE] must comply with all of the requirements of this subpart upon installation.
(b) Measuring procedures and equipment at any FMP in place before [EFFECTIVE DATE OF FINAL RULE] must comply with the requirements of this subpart within the timeframes specified in this paragraph.
(1) Very-high-volume FMPs must comply with:
(i) All of the requirements of this subpart except as specified in paragraph (b)(1)(ii) of this section by [SIX MONTHS AFTER THE EFFECTIVE DATE OF THE FINAL RULE]; and
(ii) The gas analysis reporting requirements of § 3175.120(f) of this subpart beginning on [EFFECTIVE DATE OF FINAL RULE].
(2) High-volume FMPs must comply with:
(i) All of the requirements of this subpart except as specified in paragraph (b)(2)(ii) of this section by [ONE YEAR AFTER THE EFFECTIVE DATE OF THE FINAL RULE]; and
(ii) The gas analysis reporting requirements of § 3175.120(f) of this subpart beginning on [EFFECTIVE DATE OF FINAL RULE].
(3) Low-volume FMPs must comply with all of the requirements of this subpart by [TWO YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE].
(4) Marginal-volume FMPs must comply with all of the requirements of this regulation by [THREE YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE].
(c) During the phase-in timeframes in paragraph (b) of this section, measuring procedures and equipment in place before [EFFECTIVE DATE OF THE FINAL RULE] must comply with the requirements of the predecessor rule to this subpart,
(d) The applicability of existing NTLs, variance approvals, and written orders that establish requirements or standards related to gas measurement are rescinded as of:
(i) [SIX MONTHS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for very-high-volume FMPs;
(ii) [ONE YEAR AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for high-volume FMPs;
(iii) [TWO YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for low-volume FMPs; and
(iv) [THREE YEARS AFTER THE EFFECTIVE DATE OF THE FINAL RULE] for marginal-volume FMPs;
(a)
(b)
The following table lists the standards in this subpart and the API standards that the operator must follow to install and maintain flange-tapped orifice plates. A requirement applies when a column is marked with an “x” or a number.
Except as stated in the text of this section or as prescribed in Table 1, the standards and requirements in this section apply to all flange-tapped orifice plates.
(a) The Beta ratio must be no less than 0.10 and no greater than 0.75.
(b) The orifice bore diameter must be no less than 0.45 inches.
(c) For FMPs measuring production from wells first coming into production (including FMPs already measuring production from one or more other wells), the operator must inspect the orifice plate upon installation and then every 2 weeks thereafter. If the inspection shows that the orifice plate does not comply with API 14.3.2.4 and API 14.3.2.6.2 (both incorporated by reference, see § 3175.31), the operator must replace the orifice plate. When the bi-weekly inspection shows that the orifice plate complies with API 14.3.2.4 and API 14.3.2.6.2 (both incorporated by reference, see § 3175.31), the operator thereafter must inspect the orifice plate as prescribed in paragraph (d) of this section.
(d) The operator must pull and inspect the orifice plate at the frequency (in months) identified in Table 1 during verification of the secondary device. The operator must replace orifice plates that do not comply with API 14.3.2.4 or API 14.3.2.6.2 (both incorporated by reference, see § 3175.31) with an orifice plate that does comply with these standards.
(e) The operator must retain documentation for every plate inspection and must include that documentation as part of the verification report (see § 3175.92(d), mechanical recorders, or § 3175.102(e), EGM systems, of this subpart). The operator must provide that documentation to the BLM upon request. The documentation must include:
(1) The information required in § 3170.7(g) of this subpart;
(2) Plate orientation (bevel upstream or downstream);
(3) Measured orifice bore diameter;
(4) Plate condition (compliance with API 14.3.2.4 (incorporated by reference, see § 3175.31));
(5) The presence of oil, grease, paraffin, scale, or other contaminants found on the plate;
(6) Time and date of inspection; and
(7) Whether or not the plate was replaced.
(f) Meter tubes must meet the requirements of API 14.3.2.5.1 through API 14.3.2.5.4 (all incorporated by reference, see § 3175.31). The following exception is allowed for meter tubes at low-volume FMPs only if:
(1) The difference between the maximum and the minimum inside diameter of the meter tube measured 1 inch upstream of the orifice plate does not exceed the following tolerance:
(2) The difference between any measured inside diameter of the meter tube and the average inside diameter of the meter tube measured 1 inch downstream of the orifice plate does not exceed the tolerance given by the equation in paragraph (f)(1) of this section.
(g) If flow conditioners are used, they must be either isolating-flow conditioners approved by the BLM and installed under BLM requirements (see § 3175.46 of this subpart) or 19-tube-bundle flow straighteners constructed and located in compliance with API 14.3.2.5.5.1 through API 14.3.2.5.5.3 (all incorporated by reference, see § 3175.31).
(h)
(1) Visually inspect meter tubes within the timeframe (in years) specified in Table 1.
(2) Use a borescope or equivalent device, capable of determining the condition of the inside of the meter tube along the entire upstream and downstream lengths required by paragraph (k) of this section, including the tap holes and the plate holder. The visual inspection must be able to identify obstructions, pitting, and buildup of foreign substances (
(3) Notify the AO within 72 hours if a visual inspection identifies conditions that indicate the meter tube does not comply with API 14.3.2.5.1 through API 14.3.2.5.4 (all incorporated by reference, see § 3175.31).
(4) Maintain documentation of the findings from the visual meter tube inspection including:
(i) The information required in § 3170.7(g) of this subpart;
(ii) The time and date of inspection; and
(iii) The type of equipment used to make the inspection;
(iv) A description of findings, including location and severity of pitting, obstructions, and buildup of foreign substances.
(5) Conducting a detailed inspection such as that required under paragraph (i) of this section in lieu of a visual inspection satisfies the requirement of this paragraph.
(i)
(2) The AO may adjust the detailed meter inspection frequencies if a visual inspection under paragraph (h) of this section identifies issues regarding compliance with the identified API standards or the operator provides documentation that demonstrates that a different frequency is warranted.
(3) The AO may require additional inspections if conditions warrant, such as corrosive- or erosive-flow conditions (
(4) If a visual inspection of a meter at a low-volume FMP reveals noncompliance with any requirement of API 14.3.2.5.1 through API 14.3.2.5.4 (all incorporated by reference, see § 3175.31), or if the meter tube operates in corrosive- or erosive-flow conditions or has signs of physical damage, the AO may require a detailed inspection.
(j) The operator must retain documentation demonstrating that the meter tube complies with API 14.3.2.5.1 through API 14.3.2.5.4 (all incorporated by reference, see § 3175.31) and showing all required measurements. The operator must provide such documentation to the BLM upon request for every meter-tube inspection (see Appendix 1 to this subpart for sample inspection sheet). Documentation must also include the information required in § 3170.7(g) of this subpart.
(k)
(2) For low-volume FMPs that do not utilize 19-tube-bundle flow straighteners, meter tube lengths may either comply with paragraph (k)(1) of this section or with the lengths calculated as follows:
(l)
(2) Thermometer wells must be exposed to the same ambient conditions as the primary device. For example, if the primary device is located in a heated meter house, the thermometer well also must be located in the same heated meter house.
(3) Where multiple thermometer wells have been installed in a meter tube, the flowing temperature must be measured
(4) Thermometer wells used to measure or verify flowing temperature must contain a thermally conductive liquid.
(m) The sampling probe must be located as specified in § 3175.112(b) of this subpart.
(n) The operator must notify the AO at least 72 hours before a visual or detailed meter-tube inspection or installation of a new meter tube.
(a) The operator may use a mechanical recorder as a secondary device only on marginal-volume and low-volume FMPs.
(b) The following table lists the standards that the operator must follow to install and maintain mechanical recorders. A requirement applies when a column is marked with an “x” or a number.
(a) Gauge lines connecting the pressure taps to the mechanical recorder must:
(1) Have an internal diameter not less than 3/8”, including ports and valves;
(2) Be constructed of stainless steel;
(3) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length;
(4) Be the same internal diameter along their entire length;
(5) Not include any tees, except for the static pressure line;
(6) Not be connected to more than one differential-pressure bellows and static-pressure element, or to any other device; and
(7) Be no longer than 6 feet.
(b) The differential pressure pen must record at a minimum reading of 10 percent of the differential-bellows range for the majority of the flowing period.
(c) The flowing temperature of the gas must be continuously recorded and used in the volume calculations under § 3175.94(a)(1) of this subpart.
(d) The following information must be maintained at the FMP in a legible condition, in compliance with § 3170.7(g) of this subpart, and accessible to the AO at all times:
(1) Differential-bellows range;
(2) Static-pressure-element range;
(3) Temperature-element range;
(4) Relative density (specific gravity);
(5) Static-pressure units of measure (psia or psig);
(6) Meter elevation;
(7) Meter-tube inside diameter;
(8) Primary device type;
(9) Orifice-bore or other primary-device dimensions necessary for device verification, Beta- or area-ratio determination, and gas-volume calculation;
(10) Make, model, and location of approved isolating flow conditioners, if used;
(11) Location of the downstream end of 19-tube-bundle flow straighteners, if used;
(12) Date of last primary-device inspection; and
(13) Date of last verification.
(e) The differential pressure, static pressure, and flowing temperature elements must be operated between the lower- and upper-calibrated limits of the respective elements.
(a)
(i) All connections and fittings of the secondary device, including meter manifolds and verification equipment;
(ii) The isolation valves; and
(iii) The equalizer valves.
(2) The time lag between the differential and static pen must be adjusted, if necessary, to be 1/96 of the chart rotation period, measured at the chart hub. For example, the time lag is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test chart.
(3) The meter's differential pen arc must be adjusted, if necessary, to duplicate the test chart's time arc over the full range of the test chart.
(4) The as-left values must be verified in the following sequence against a certified pressure device for the differential pressure and static pressure elements (if the static-pressure pen has been offset for atmospheric pressure, the static-pressure element range is in psia):
(i) Zero (vented to atmosphere);
(ii) 50 percent of element range;
(iii) 100 percent of element range;
(iv) 80 percent of element range;
(v) 20 percent of element range; and
(vi) Zero (vented to atmosphere).
(5) The following as-left temperatures must be verified by placing the temperature probe in a water bath with a certified test thermometer:
(i) Approximately 10 °F below the lowest expected flowing temperature;
(ii) Approximately 10 °F above the highest expected flowing temperature; and
(iii) At the expected average flowing temperature.
(6) If any of the readings required in paragraph (a)(4) or (5) of this section vary from the test device reading by more than the tolerances shown in the following table, the operator must replace and verify the element whose readings were outside the applicable tolerances before returning the meter to service.
(7) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated under Attachment 2 of this subpart; and
(ii) The pen must be offset prior to obtaining the as-left verification values
(b)
(c)
(2) No adjustments to the pens or linkages may be made until an as-found verification is obtained. If the static pen has been offset for atmospheric pressure, the static pen must not be reset to zero until the as-found verification is obtained.
(3) The operator must obtain the as-found values of differential and static pressure against a certified pressure device at the following readings in the order listed: Zero (vented to atmosphere), 50 percent of the element range, 100 percent of the element range, 80 percent of the element range, 20 percent of the element range, zero (vented to atmosphere), with the following additional requirements:
(i) If there is sufficient data on site to determine the point at which the differential and static pens normally operate, the operator must also obtain an as-found value at those points;
(ii) If there is not sufficient data on site to determine the points at which the differential and static pens normally operate, the operator must also obtain as-found values at 5 percent of the element range and 10 percent of the element range; and
(iii) If the static pressure pen has been offset for atmospheric pressure, the static pressure element range is in units of psia.
(4) The as-found value for temperature must be taken using a certified test thermometer placed in a test thermometer well if there is flow through the meter and the meter tube is equipped with a test thermometer well. If there is no flow through the meter or if the meter is not equipped with a test thermometer well, the temperature probe must be verified by placing it along with a test thermometer in an insulated water bath.
(5) The element undergoing verification must be calibrated according to manufacturer specifications if any of the as-found values determined under paragraphs (c)(3) or (4) of this section are not within the tolerances shown in Table 2-1, when compared to the values applied by the test equipment.
(6) The operator must adjust the time lag between the differential and static pen, if necessary, to be 1/96 of the chart rotation period, measured at the chart hub. For example, the time lag is 15 minutes on a 24-hour test chart and 2 hours on an 8-day test chart.
(7) The meter's differential pen arc must be able to duplicate the test chart's time arc over the full range of the test chart, and must be adjusted, if necessary.
(8) If any adjustment to the meter was made, the operator must perform an as-left verification on each element adjusted using the procedures in paragraphs (c)(3) and (4) of this section.
(9) If, after an as-left verification, any of the readings required in paragraph (c)(3) or (4) of this section vary by more than the tolerances shown in Table 2-1 when compared with the test-device reading, the element whose readings are outside the applicable tolerances must be replaced and verified under this section before returning the meter to service.
(10) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated under Appendix 2 of this subpart; and
(ii) The pen must be offset prior to obtaining the as-left verification values required in paragraph (c)(3) of this section.
(d) The operator must retain documentation of each verification, as required under § 3170.7(g) of this subpart, and submit it to the BLM upon request. This documentation must include:
(1) The time and date of the verification and the prior verification date;
(2) Primary-device data (meter-tube inside diameter and differential-device size and Beta or area ratio);
(3) The type and location of taps (flange or pipe, upstream or downstream static tap);
(4) Atmospheric pressure used to offset the static-pressure pen, if applicable;
(5) Mechanical recorder data (make, model, and differential pressure, static pressure, and temperature element ranges);
(6) The normal operating points for differential pressure, static pressure, and flowing temperature;
(7) Verification points (as-found and applied) for each element;
(8) Verification points (as-left and applied) for each element, if a calibration was performed;
(9) Names, contact information, and affiliations of the person performing the verification and any witness, if applicable; and
(10) Remarks, if any.
(e) The operator must notify the AO at least 72 hours before conducting the verifications required by this subpart.
(f) If, during the verification, the combined errors in as-found differential pressure, static pressure, and flowing temperature taken at the normal operating points tested result in a flow-rate error greater than 2 Mcf/day, the volumes reported on the OGOR and on royalty reports submitted to ONRR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the last verification and the date of the current verification.
(g) Test equipment used to verify or calibrate elements at an FMP must be certified at least every 2 years. Documentation of the recertification must be on-site during all verifications and must show:
(1) Test equipment serial number, make, and model;
(2) The date on which the recertification took place;
(3) The test equipment measurement range; and
(4) The uncertainty determined or verified as part of the recertification.
An unedited integration statement must be retained and made available to the BLM upon request. The integration statement must contain the following information:
(a) The information required in § 3170.7(g) of this subpart;
(b) The name of the company performing the integration;
(c) The month and year for which the integration statement applies;
(d) Meter-tube inside diameter (inches);
(e) The following primary device information, as applicable:
(i) Orifice bore diameter (inches); or
(ii) Beta or area ratio, discharge coefficient, and other information necessary to calculate the flow rate;
(f) Relative density (specific gravity);
(g) CO
(h) N
(i) Heating value calculated under § 3175.125 (Btu/standard cubic feet);
(j) Atmospheric pressure or elevation at the FMP;
(k) Pressure base;
(l) Temperature base;
(m) Static pressure tap location (upstream or downstream);
(n) Chart rotation (hours or days);
(o) Differential pressure bellows range (inches of water);
(p) Static pressure element range (psi); and
(q) For each chart or day integrated:
(i) The time and date on and time and date off;
(ii) Average differential pressure (inches of water);
(iii) Average static pressure;
(iv) Static pressure units of measure (psia or psig);
(v) Average temperature (° F);
(vi) Integrator counts or extension;
(vii) Hours of flow; and
(viii) Volume (Mcf).
(a) The volume for each chart integrated must be determined as follows:
(1) If the primary device is a flange-tapped orifice plate, a single IMV must be calculated for each chart or chart interval using the following equation:
(2) For other types of primary devices, the IMV must be calculated using the equations and procedures recommended by the PMT and approved by the BLM, specific to the make, model, size, and area ratio of the primary device being used.
(3) Variables that are functions of differential pressure, static pressure, or flowing temperature (
(b) Atmospheric pressure used to convert static pressure in psig to static pressure in psia must be determined under Appendix 2 of this subpart.
The following table lists the API standards and BLM requirements that the operator must follow to install and maintain an EGM system on a differential-type primary device. A requirement applies when a column is marked with an “x” or a number.
(a) Manifolds and gauge lines connecting the pressure taps to the secondary device must:
(1) Have an internal diameter not less than
(2) Be constructed of stainless steel;
(3) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length;
(4) Have the same internal diameter along their entire length;
(5) Not include any tees except for the static pressure line;
(6) Not be connected to any other devices or more than one differential pressure and static pressure transducer. If the operator is employing redundancy verification, two differential pressure and two static pressure transducers may be connected; and
(7) Be no longer than 6 feet.
(b) Each FMP must include a display which must:
(1) Be readable without the need for data-collection units, laptop computers, a password, or any special equipment;
(2) Be on site and in a location that is accessible to the AO;
(3) Include the units of measure for each required variable;
(4) Display the following variables:
(i) The FMP number or, if an FMP number has not yet been assigned, a unique meter-identification number;
(ii) Software version;
(iii) Current flowing static pressure with units (psia or psig);
(iv) Current differential pressure (inches of water);
(v) Current flowing temperature (° F);
(vi) Current flow rate (Mcf/day or scf/day);
(vii) Previous-day volume (Mcf);
(viii) Previous-day flow time;
(ix) Previous-day average differential pressure (inches of water);
(x) Previous-day average static pressure with units (psia or psig);
(xi) Previous-day average flowing temperature (° F);
(xii) Relative density (specific gravity); and
(xiii) Primary device information such as orifice-bore diameter (inches) or Beta or area ratio and discharge coefficient, as applicable; and
(5) Display items (iii) through (v) in paragraph (b)(4) of this section consecutively.
(c) The following information must be maintained at the FMP in a legible condition, in compliance with § 3170.7(g) of this part, and accessible to the AO at all times:
(1) Elevation of the FMP;
(3) Meter-tube mean inside diameter;
(3) Make, model, and location of approved isolating flow conditioners, if used;
(4) Location of the downstream end of 19-tube-bundle flow straighteners, if used;
(5) For self-contained EGM systems, the make and model number of the system;
(6) For component-type EGM systems, the make and model number of each transducer and the flow computer;
(7) URL and upper calibrated limit for each transducer;
(8) Location of the static pressure tap (upstream or downstream);
(9) Last primary-device inspection date; and
(10) Last secondary device verification date.
(d) The differential pressure, static pressure, and flowing temperature transducers must be operated between the lower and upper calibrated limits of the transducer.
(e) The flowing temperature of the gas must be continuously measured and used in the flow-rate calculations under API 21.1.4 (incorporated by reference, see § 3175.31).
(a)
(2) The operator must verify the points listed in API 21.1.7.3.3 (incorporated by reference, see § 3175.31) by comparing the values from the certified test device with the values used by the flow computer to calculate flow rate. If any of these as-left readings vary from the test equipment reading by more than the tolerance determined by API 21.1.8.2.2.2, Equation 24 (incorporated by reference, see § 3175.31), then that transducer must be replaced and retested under this paragraph.
(3) For absolute static pressure transducers, the value of atmospheric pressure used when the transducer is vented to atmosphere must be calculated under Appendix 2 to this subpart or measured by a NIST-certified barometer with a stated accuracy of ±0.05 psi, or better.
(4) Before putting a meter into service, the differential-pressure transducer must be re-zeroed with full working pressure applied to both sides of the transducer.
(b)
(2) If redundancy verification under paragraph (d) of this section is used, the differential pressure, static pressure, and temperature transducers must be verified under the requirements of paragraph (d) of this section. In addition, the transducers must be verified under the requirements of paragraph (c) of this section at least annually.
(c)
(1) Before performing any verification required under this section, the operator must perform a leak test consistent with § 3175.92(a)(1) of this subpart.
(2) An as-found verification for differential and static pressure must be conducted at the normal operating point of each transducer. The normal operating point is the flow-time linear average taken over the previous day (
(3) If either the differential- or static-pressure transducer is calibrated, the as-left verification must include the normal operating point of that transducer, as defined in paragraph (c)(2) of this section.
(4) The as-found values for differential pressure obtained with the low side vented to atmospheric pressure must be corrected to working pressure values using API 21.1, Annex H, Equation H.1 (incorporated by reference, see § 3175.31).
(5) The verification tolerance for differential and static pressure is defined by API 21.1.8.2.2.2, Equation 24 (incorporated by reference, see § 3175.31). The verification tolerance for temperature is 0.5 degrees F.
(6) All required verification points must be within the verification tolerance before returning the meter to service.
(7) Before returning a meter to service, the differential pressure transducer must be rezeroed with full working pressure applied to both sides of the transducer.
(d)
(1) The operator must identify which set of transducers is used for reporting on the OGOR (the primary transducers) and which set of transducers is used as a check (the check set of transducers);
(2) For every calendar month, the operator must compare the flow-time linear average of differential pressure, static pressure, and temperature readings from the primary transducers with the check transducers;
(3) If for any transducer the difference between the averages exceeds the tolerance defined by the following equation:
(e) The operator must retain documentation of each verification for the period required under § 3170.6 of this part, and submit it to the BLM upon request.
(1) For routine verifications, this documentation must include:
(i) The information required in § 3170.7(g) of this part;
(ii) The time and date of the verification and the last verification date;
(iii) Primary device data (meter-tube inside diameter and differential-device size, Beta or area ratio);
(iv) The type and location of taps (flange or pipe, upstream or downstream static tap);
(v) The flow computer make and model;
(vi) The make and model number for each transducer, for component-type EGM systems;
(vii) Transducer data (make, model, differential, static, temperature URL, and upper calibrated limit);
(viii) The normal operating points for differential pressure, static pressure, and flowing temperature;
(ix) Atmospheric pressure;
(x) Verification points (as-found and applied) for each transducer;
(xi) Verification points (as-left and applied) for each transducer, if calibration was performed;
(xii) The differential device inspection date and condition (
(xiii) Verification equipment make, model, range, accuracy, and last certification date;
(xiv) The name, contact information, and affiliation of the person performing the verification and any witness, if applicable; and
(xv) Remarks, if any.
(2) For redundancy verification checks, this documentation must include;
(i) The information required in § 3170.7(g) of this part;
(ii) The month and year for which the redundancy check applies;
(iii) The makes, models, upper range limits, and upper calibrated limits of the primary set of transducers;
(iv) The makes, models, upper range limits, and upper calibrated limits of the check set of transducers;
(v) The information required in API 21.1, Annex I (incorporated by reference, see § 3175.31);
(vii) The tolerance for differential pressure, static pressure, and temperature as calculated under paragraph (d)(2) of this section; and
(viii) Whether or not each transducer required verification under paragraph (c) of this section.
(f) The operator must notify the AO at least 72 hours before conducting the tests and verifications required by paragraph (c) of this section.
(g) If, during the verification, the combined errors in as-found differential pressure, static pressure, and flowing temperature taken at the normal operating points tested result in a flow-rate error greater than 2 percent or 2 Mcf/day, whichever is less, the volumes reported on the OGOR and on royalty reports submitted to ONRR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the last verification and the date of the present verification.
(h)
(i) The test equipment serial number, make, and model;
(ii) The date on which the recertification took place;
(iii) The range of the test equipment; and
(iv) The uncertainty determined or verified as part of the recertification.
(2) Test equipment used to verify or calibrate transducers at an FMP must meet the following accuracy standards:
(i) The accuracy of the test equipment, stated in actual units of measure, must be no greater than 0.5 times the reference accuracy of the transducer being verified, also stated in actual units of measure; or
(ii) It must have a stated accuracy of at least 0.10 percent of the upper calibrated limit of the transducer being verified.
(a) The flow rate must be calculated as follows:
(1) For flange-tapped orifice plates, the flow rate must be calculated under:
(i) API 14.3.3.4 and API 14.3.3.5 (both incorporated by reference, see § 3175.31); and
(ii) API 14.2 (incorporated by reference, see § 3175.31), for supercompressibility.
(2) For primary devices other than flange-tapped orifice plates, the flow rate must be calculated under the equations and procedures recommended by the PMT and approved by the BLM, specific to the make, model, size, and area ratio of the primary device used.
(b) Atmospheric pressure used to convert static pressure in psig to static pressure in psia must be determined under API 21.1.8.3.3 (incorporated by reference, see § 3175.31).
(c) Hourly and daily gas volumes, average values of the live input variables, flow time, and integral value or average extension as required under § 3175.104 of this subpart must be determined under API 21.1. 4 and API 21.1 Annex B (both incorporated by reference, see § 3175.31).
(a) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited daily and hourly QTRs, which must contain the information identified in API 21.1.5.2 (incorporated by reference, see § 3175.31), with the following additions and clarifications:
(1) The information required in § 3170.7(g) of this part;
(2) The volume, flow time, integral value or average extension, and the average differential pressure, static pressure, and temperature as calculated in § 3175.103(c) of this subpart, reported to at least five significant digits; and
(3) A statement of whether the operator has submitted the integral value or average extension.
(b) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited configuration log which must contain the information specified in API 21.1.5.4 (including the flow computer snapshot report in API 21.1.5.4.2) and API 21.1 Annex G (all three incorporated by reference, see § 3175.31), with the following additions and clarifications:
(1) The information required in § 3170.7(g) of this part;
(2) Software/firmware identifiers under API 21.1.5.3 (incorporated by reference, see § 3175.31);
(3) For marginal-volume FMPs only, the fixed temperature, if not continuously measured (°F); and
(4) The static-pressure tap location (upstream or downstream);
(c) The operator must retain, and submit to the BLM upon request, the original, unaltered, unprocessed, and unedited event log. The event log must comply with API 21.1.5.5 (incorporated by reference, see § 3175.31), with the following additions and clarifications:
(1) The event log must record all power outages that inhibit the meter's ability to collect and store new data. The event log must indicate the length of the outage; and
(2) The event log must have sufficient capacity and must be retrieved and stored at intervals frequent enough to maintain a continuous record of events as required under § 3170.7 of this part, or the life of the FMP, whichever is shorter.
(d) The operator must retain an alarm log and provide it to the BLM upon request. The alarm log must comply with API 21.1.5.6 (incorporated by reference, see § 3175.31).
The following table lists the standards and practices that the operator must follow to obtain a reliable, accurate gas sample for the determination of relative density and heating value. A requirement applies when a column is marked with an “x” or a number.
(a) Samples must be taken by one of the following methods:
(1) Spot sampling under §§ 3175.113 to 3175.115 of this subpart;
(2) Flow-proportional composite sampling under § 3175.116 of this subpart; or
(3) On-line gas chromatograph under § 3175.117 of this subpart.
(b) The temperature of all gas sampling components must be maintained at least 30 °F above the hydrocarbon dew point of the gas at all times during the sampling process.
(a) All gas samples must be taken from a sample probe that complies with the requirements of paragraphs (b) and (c) of this section.
(b)
(2) The sample probe must be exposed to the same ambient conditions as the primary device. For example, if the primary device is located in a heated meter house, the sample probe must also be located in the same heated meter house.
(c)
(2) If a regulating type of sample probe is used, the pressure-regulating mechanism must be inside the pipe or maintained at a temperature of at least 30 °F above the hydrocarbon dew point of the gas.
(3) The sample probe length must be long enough to place the collection end of the probe in the center one third of the pipe cross-section.
(4) The use of membranes, screens, or filters at any point in the sample probe is prohibited.
(d) Sample tubing connecting the sample probe to the sample container or analyzer must be constructed of stainless steel or nylon 11.
(a) If an FMP is not flowing at the time that a sample is due, a sample must be taken within 5 days of when flow is re-initiated. Documentation of the non-flowing status of the FMP must be entered into GARVS as required under § 3175.120(f) of this subpart.
(b) The operator must notify the AO at least 72 hours before obtaining a spot sample as required by this subpart.
(c)
(1) Be constructed of stainless steel;
(2) Have a minimum capacity of 300 cubic centimeters;
(3) Be cleaned before sampling under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.31), or an equivalent method (of which cleaning the operator must maintain documentation); and
(4) Be physically sealed in a manner that prevents opening the sample cylinder without breaking the seal before sampling.
(d)
(i) Be constructed of stainless steel;
(ii) Be cleaned under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.31), or an equivalent method, prior to sampling (of which cleaning the operator must maintain documentation); and
(iii) Be operated under GPA 2166-05, Appendix B.3 (incorporated by reference, see § 3175.31).
(2) Filters at the inlet of the GC must be cleaned or replaced before sampling.
(3) The sample port and inlet to the sample line must be purged before sealing the connection between them.
(4) The portable GC must be designed, operated, and calibrated under § 3175.118 of this subpart.
(5) Portable GCs may not be used when the flowing pressure of the gas is less than 15 psig.
(a) Spot samples must be obtained using one of the following methods:
(1)
(2)
(3)
(4)
(5) Other methods approved by the BLM (through the PMT) and posted at
(b) If the operator uses either a purging-fill and empty method or a helium “pop” method, and if the flowing pressure at the sample port is less than or equal to 15 psig, the operator may also employ a vacuum-gathering system. Samples taken using a vacuum- gathering system must comply with API 14.1.12.10 (incorporated by reference, see § 3175.31), and the samples must be obtained from the discharge of the vacuum pump.
(a) Unless otherwise required under paragraph (b) of this section, spot samples for all FMPs must be taken and analyzed at the frequency (once during every period, stated in months) prescribed in Table 4 (see § 3175.110).
(b) The BLM may change the required sampling frequency for high-volume and very-high-volume FMPs if the BLM determines that the sampling frequency required in Table 4 is not sufficient to achieve the heating value certainty levels required in § 3175.30(b) of this subpart.
(1) The BLM will calculate the new sampling frequency needed to achieve the heating value certainty levels required in § 3175.30(b) of this subpart. The BLM will base the sampling frequency calculation on the statistical variability of previously reported heating values. The BLM will notify the operator of the new sampling frequency.
(2) The new sampling frequency will remain in effect until the variability of previous heating values justifies a different frequency.
(3) The new sampling frequency will not be more frequent than once per week nor less frequent than once every 6 months.
(4) The BLM may require the installation of a composite sampling system or on-line GC if the heating value certainty levels in 3175.30(b) of this subpart cannot be achieved through spot sampling.
(c) The time between any two samples must not exceed the timeframes shown in Table 5.
(d) If a composite sampling system or an on-line GC is installed under §§ 3175.116 or 3175.117 of this subpart, either on the operator's own initiative or in response to a BLM order to change the sampling frequency for a high-volume or very-high-volume FMP under paragraph (b) of this section, it must be installed and operational no more than 30 days after the due date of the next sample.
(e) The required sampling frequency for an FMP at which a composite sampling system or an on-line gas chromatograph is removed from service is prescribed in paragraph (a).
(a) Composite samplers must be flow-proportional.
(b) Samples must be collected using a positive-displacement pump.
(c) Sample cylinders must be sized to ensure the cylinder capacity is not exceeded within the normal collection frequency.
(d) The composite sampling system must meet the heating value uncertainty requirements of § 3175.30(b) of this subpart.
(a) On-line GCs must be installed, operated, and maintained under GPA 2166-05, Appendix D (incorporated by reference, see § 3175.31), and the manufacturer's specifications, instructions, and recommendations.
(b) The on-line GC must meet the uncertainty requirements for heating values required in § 3175.30(b) of this subpart.
(c) Upon request, the operator must submit to the AO the manufacturer's specifications and installation and operational recommendations.
(d) The GC must comply with the verification and calibration requirements of § 3175.118 of this subpart. The results of all verifications must be submitted to the AO upon request.
(a) All GCs must be designed, installed, operated, and calibrated under GPA 2261-00 (incorporated by reference, see § 3175.31).
(b) Samples must be analyzed until three consecutive runs are within the repeatability standards listed in GPA 2261-00, Section 9 (incorporated by reference, see § 3175.31), and the unnormalized sum of the mole percent of all gases analyzed is between 99 and 101 percent.
(c) GCs must be verified under GPA 2261-00 (incorporated by reference, see § 3175.31), Sections 4 and 5, at the following frequencies:
(1) For portable GCs that are used for spot sampling, not more than 24 hours before sampling at an FMP; or
(2) For laboratory and on-line GCs, not less than once every 7 days.
(d) The gas used for verification must not be the same gas used for calibration.
(e) If the composition of the sample as determined by the GC varies from the composition of the calibration gas by more than the repeatability values listed in GPA 2261-00, Section 9 (incorporated by reference, see § 3175.31), the GC must be calibrated under GPA 2261-00, Section 5 (incorporated by reference, see § 3175.31).
(f) If the GC is calibrated, it must be re-verified under paragraphs (d) and (e) of this section.
(g) A GC may not be used to analyze any sample from an FMP until the verification meets the standards of paragraph (e) of this section.
(h) All gases used for verification and calibration must meet the standards of GPA 2198-03 (incorporated by reference, see § 3175.31).
(i) The operator must retain documentation of the verifications for the period required under § 3170.6 of this part, and make it available to the BLM upon request. For portable GCs used for spot sampling, documentation of the last verification must be on site at the time of sampling. The documentation must include:
(1) The components analyzed;
(2) The response factor for each component;
(3) The peak area for each component;
(4) The mole percent of each component as determined by the GC;
(5) The mole percent of each component in the gas used for verification;
(6) The difference between the mole percents determined in paragraphs (i)(4) and (i)(5) of this section, expressed in relative percent;
(7) Documentation that the gas used for verification meets the requirements of GPA 2198-03 (incorporated by reference, see § 3175.31), including a unique identification number of the calibration gas used and the name of the supplier of the calibration gas;
(8) The time and date the verification was performed; and
(9) The name and affiliation of the person performing the verification.
(a) The gas must be analyzed for the following components:
(1) Methane;
(2) Ethane;
(3) Propane;
(4) Iso Butane;
(5) Normal Butane;
(6) Pentanes;
(7) Hexanes + (C
(8) Carbon dioxide; and
(9) Nitrogen.
(b) For high-volume and very high-volume FMPs, if the concentration of C
(1) Hexane;
(2) Heptane;
(3) Octane; and
(4) Nonane+.
(a) The gas analysis report must contain the following information:
(1) The information required in § 3170.7(g) of this part;
(2) The date and time that the sample for spot samples was taken or, for composite samples, the date the cylinder was installed and the date the cylinder was removed;
(3) The date and time of the analysis;
(4) For spot samples, the effective date, if other than the date of sampling;
(5) For composite samples, the effective start and end date;
(6) The name of the laboratory where the analysis was performed;
(7) The device used for analysis (
(8) The make and model of analyzer;
(9) The date of last calibration or verification of the analyzer;
(10) The flowing temperature at the time of sampling;
(11) The flowing pressure at the time of sampling, including units of measure (psia or psig);
(12) The flow rate at the time of the sampling;
(13) The ambient air temperature at the time the sample was taken;
(14) Whether or not heat trace or any other method of heating was used;
(15) The type of sample (
(16) The sampling method if spot-cylinder (
(17) A list of the components of the gas tested;
(18) The un-normalized mole percentages of the components tested, including a summation of those mole percents;
(19) The normalized mole percent of each component tested, including a summation of those mole percents;
(20) The ideal heating value (Btu/scf);
(21) The real heating value (Btu/scf), dry basis;
(22) The pressure base and temperature base;
(23) The relative density; and
(24) The name of the company obtaining the gas sample.
(b) Components that are listed on the analysis report, but not tested, must be annotated as such.
(c) The heating value and relative density must be calculated under API 14.5 (incorporated by reference, see § 3175.31).
(d) The base supercompressibility must be calculated under API 14.2 (incorporated by reference, see § 3175.31).
(e) The operator must submit all gas analysis reports to the BLM within 5
(f) Unless a variance is granted, the operator must submit all gas analysis reports and other required related information electronically through the GARVS. The BLM will grant a variance only in cases where the operator demonstrates that it is a small business, as defined by the U.S. Small Business Administration, and does not have access to the Internet.
(a) Unless otherwise specified on the gas analysis report, the effective date of a spot sample is the date on which the sample was taken.
(b) The effective date of a spot gas sample may be no later than the first day of the production month following the operator's receipt of the laboratory analysis of the sample.
(c) The effective date of a composite sample is the date when the sample cylinder was installed.
(a) The heating value of the gas sampled must be calculated as follows:
(1) Gross heating value is defined by API 14.5.3.7 (incorporated by reference, see § 3175.31) and must be calculated under API 14.5.7.1 (incorporated by reference, see § 3175.31); and
(2) Real heating value must be calculated by dividing the gross heating value of the gas calculated under paragraph (a)(1) by the compressibility factor of the gas at 14.73 psia and 60 °F.
(b)
(2) If the effective date of a heating value for an FMP is other than the first day of the reporting month, the average heating value of the FMP must be the volume-weighted average of heating values, determined as follows:
(c) The volume must be determined under §§ 3175.94 (mechanical recorders) or 3175.103(c) (EGM systems) of this subpart.
(a) The gross heating value and real heating value, or average gross heating value and average real heating value, as applicable, derived from all samples and analyses must be reported on the OGOR in units of Btu/scf under the following conditions:
(1) Containing no water vapor (“dry”), unless the water vapor content has been determined through actual on-site measurement and reported on the gas analysis report. The heating value may not be reported on the basis of an assumed water vapor content. Acceptable methods of measuring water vapor are:
(i) Chilled mirror;
(ii) Laser detectors; and
(iii) Other methods approved by the BLM;
(2) Adjusted to a pressure of 14.73 psia and a temperature of 60 °F; and
(3) For samples analyzed under § 3175.119(a) of this subpart, and notwithstanding any provision of a contract between the operator and a purchaser or transporter, the composition of hexane+ is deemed to be:
(i) 60 percent n-hexane;
(ii) 30 percent n-heptane; and
(iii) 10 percent n-octane;
(b) The volume for royalty purposes must be reported on the OGOR in units of Mcf as follows:
(1) The volumes must not be adjusted for water vapor content or any other factors that are not included in the calculations required in §§ 3175.94 or 3175.103 of this subpart; and
(2) The volume must match the monthly volume(s) shown in the unedited QTR(s) or integration statement(s) unless edits to the data are documented under paragraph (c) of this section.
(c)
(i) For volume errors, during the time the measurement equipment was malfunctioning or out of service, use the average of the flow rate before the time the error occurred and the flow rate after the error was corrected; and
(ii) For heating value errors, use the average of the heating values determined from five samples from the same FMP taken closest in time to the period in which the error subsisted, excluding the heating value(s) from the sample(s) known to be in error. If fewer than five heating values have been obtained, use the average of the most recent heating values that are known not to be in error.
(2) All edits made to the data before the submission of the OGOR must be documented and include verifiable justifications for the edits made. This documentation must be maintained under § 3170.7 of this part and must be submitted to the BLM upon request.
(3) All values on daily and hourly QTRs that have been changed or edited must be clearly identified and must be cross referenced to the justification required in paragraph (c)(2) of this section.
(4) The volumes reported on the OGOR must be corrected beginning with the date that the inaccuracy occurred. If that date is unknown, the volumes must be corrected beginning with the production month that includes the date that is half way between the date of the previous verification and the most recent verification date.
The BLM will approve a particular make, model, and range of differential-pressure, static-pressure, or temperature transducer for use in an EGM system only if the testing performed on the transducer met all of the standards and requirements stated in §§ 3175.131 through 3175.135 of this subpart.
(a)
(2) All equipment used for testing must be traceable to the NIST and have a current certification proving its traceability.
(b)
(2) The serial number of each transducer selected must be documented. The date, location, and batch identifier, if applicable, of manufacture is ascertainable from the serial number.
(c)
(1) Rated voltage: ±1 percent uncertainty;
(2) Rated frequency: ±1 percent uncertainty;
(3) Alternating current harmonic distortion: Less than 5 percent; and
(4) Direct current ripple: Less than 0.10 percent uncertainty.
(d) The input and output (if the output is analog) of each transducer must be measured with equipment that has a published reference uncertainty less than or equal to 25 percent of the published reference uncertainty of the transducer under test across the measurement range common to both the transducer under test and the test instrument. Reference uncertainty for both the test instrument and the transducer under test must be expressed in the units the transducer measures to determine acceptable uncertainty. For example, if the transducer under test has a published reference uncertainty of ±0.05 percent of span, and a span of 0 to 500 psia, then this transducer has a reference accuracy of ±0.25 psia (0.05 percent of 500 psia). To meet the requirements of this paragraph, the test instrument in this example must have an uncertainty of ±0.0625 psia, or less (25 percent of ±0.25 psia).
(e) If the manufacturer's performance specifications for the transducer under test include corrections made by an external device (such as linearization), then the external device must be tested along with the transducer and be connected to the transducer in the same way as in normal field operations.
(f) If the manufacturer specifies the extent to which the measurement range of the transducer under test may be adjusted downward (
(g) After initial calibration, no calibration adjustments to the transducer may be made until all required tests in §§ 3175.132 and 3175.133 of this subpart are completed.
(h) For all of the testing required in §§ 3175.132 and 3175.133 of this subpart, the term “tested for accuracy” means a comparison between the output of the transducer under test and the test equipment taken as follows:
(1) The following values must be tested in the order shown, expressed as a percent of the transducer span:
(i) (Ascending values) 0, 10, 20, 30, 40, 50, 60, 70, 80, 90, and 100; and
(ii) (descending values) 100, 90, 80, 70, 60, 50, 40, 30, 20, 10, and 0.
(2) If the device under test is an absolute pressure transducer, the “0” values listed in paragraph (h)(1)(i) and (ii) of this section must be replaced with “atmospheric pressure at the test facility;”
(3) Input approaching each required test point must be applied asymptotically without overshooting the test point;
(4) The comparison of the transducer and the test equipment measurements must be recorded at each required point; and
(5) For static pressure transducers, the following test point must be included for all tests:
(i) For gauge pressure transducers, a gauge pressure of −5 psig; and
(ii) For absolute pressure transducers, an absolute pressure of 5 psia.
(a) The following reference test conditions must be maintained for the duration of the testing:
(1) Ambient air temperature must be between 59 °F and 77 °F and must not vary over the duration of the test by more than ±2 °F;
(2) Relative humidity must be between 45 percent and 75 percent and must not vary over the duration of the test by more than ±5 percent;
(3) Atmospheric pressure must be between 12.46 psi and 15.36 psi and must not vary over the duration of the test by more than ±0.2 psi;
(4) The transducer must be isolated from any externally induced vibrations;
(5) The transducer must be mounted according to the manufacturer's specifications in the same manner as it would be mounted in normal field operations;
(6) The transducer must be isolated from any external electromagnetic fields; and
(7) For reference accuracy testing of differential-pressure transducers, the downstream side of the transducer must be vented to the atmosphere.
(b) Before reference testing begins, the following pre-conditioning steps must be followed:
(1) After power is applied to the transducer, it must be allowed to stabilize for at least 30 minutes before applying any input pressure or temperature;
(2) The transducer must be exercised by applying three full-range traverses in each direction; and
(3) The transducer must be calibrated according to manufacturer specifications if a calibration is required or recommended by the manufacturer.
(c) Immediately following preconditioning, the transducer must then be tested at least three times for accuracy under § 3175.131(h) of this subpart. The results of these tests must be used to determine the transducer's reference accuracy under § 3175.135 of this subpart.
(a)
(2) After completing the required tests for each influence effect under this section, the transducer under test must be returned to reference conditions and tested for accuracy under § 3175.132 of this subpart.
(b)
(2) The ambient temperature must be held to ±4 °F from each required temperature during the accuracy test at each point.
(3) The rate of temperature change between tests must not exceed 2 °F per minute.
(4) The transducer must be allowed to stabilize at each test temperature for at least 1 hour.
(5) For each required temperature test point listed in this paragraph, the transducer must be tested for accuracy under § 3175.131(h) of this subpart.
(c)
(2) For multivariable transducers, the following pressures must be applied equally to both sides of the transducer, expressed in percent of the URL of the static-pressure transducer: 0, 50, 100, 75, 25, 0.
(3) For each point required in paragraphs (c)(1) and (2) of this section, the transducer must be tested for accuracy under § 3175.131(h) of this subpart.
(d)
(1) At an angle of −10° from a vertical plane;
(2) At an angle of +10° from a vertical plane;
(3) At an angle of −10° from a vertical plane perpendicular to the original plane; and
(4) At an angle of +10° from a vertical plane perpendicular to the original plane.
(e)
(2) After removing the applied pressure, the transducer must be tested for accuracy under § 3175.131(h) of this subpart.
(3) No more than 5 minutes must be allowed between performing the procedures described in paragraphs (e)(1) and (e)(2) of this section.
(f)
(i) The amplitude of the applied test frequency must be at least 0.35mm below 60 Hertz (Hz) and 49 meter per second squared (m/s
(ii) The applied frequency must be swept from 10 Hz to 2,000 Hz at a rate not greater than 0.5 octaves per minute.
(2) After the initial resonance search, an endurance conditioning test must be conducted as follows:
(i) 20 frequency sweeps from 10 Hz to 2,000 Hz to 10 Hz must be applied to the transducer at a rate of one octave per minute, repeated for each of the 3 major axes; and
(ii) The measurement of the transducer's output during this test is unnecessary.
(3) A final resonance test must be conducted under paragraph (f)(1) of this section.
(g)
(2) At the end of each cycle, the transmitter must be brought back to the same reference conditions used to determine the reference accuracy and allowed to stabilize for at least 3 hours. The transmitter must then be tested for accuracy under § 3175.131(h) of this subpart.
(a) Each test required by §§ 3175.131 through 3175.133 of this subpart must be fully documented by the test facility performing the tests. The report must indicate the results for each required test and include all data points recorded.
(b) The report must be submitted to the AO. If the PMT determines that all testing was completed as required by §§ 3175.131 through 3175.133 of this subpart, it will make a recommendation that the BLM post the transducer make, model, and range, along with the reference uncertainty, influence effects, and any operating restrictions to the BLM's Web site (
(a) Reference uncertainty calculations for each transducer of a given make, model, URL, and turndown must be determined as follows (the result for each transducer is denoted by the subscript i):
(1)
(2)
(3)
(b)
(c) Reference uncertainty for the make, model, URL, and turndown of a transducer (U
(d)
(1)
Δ
(2)
(3) Zero- and span-based errors due to influence effects for a make, model, URL, and turndown of a transducer must be determined as follows:
The BLM will approve a particular version of flow-computer software for use in an EGM system only if the testing performed on the software meets all of the standards and requirements in §§ 3175.141 through 3175.144 of this subpart. Type-testing is required for each software version that affects the calculation of flow rate, volume, heating value, live input variable averaging, flow time, or the integral value.
(a)
(b)
(2) Each software version must have a unique identifier.
(c)
(1) Applied directly to the hardware registers; or
(2) Applied physically to a transducer. If input variables are applied physically to a transducer, the values received by the hardware registers from the transducer must be recorded.
(d)
(2) The software under test may be used at an FMP only if the difference between all values calculated by the software version under test and the reference software is less than 50 parts per million (0.005 percent) and the results of the tests required in §§ 3175.142 and 3175.143 of this subpart are satisfactory to the PMT. If the test results are satisfactory, the BLM will identify the software version tested as acceptable for use on its Web site at
(a)
(b)
(2) At the conclusion of the 24-hour period, the following hourly and daily values must meet the criteria in § 3175.141(d) of this subpart:
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(c)
(1) Each parameter of the configuration log must be changed to ensure the event log properly records the changes according to the variables listed in § 3175.104(c) of this subpart;
(2) Inputs simulating a 15 percent and 150 percent over-range of the differential and static pressure transducers must be entered to verify that the over-range condition triggered an alarm or an entry in the event log; and
(3) The power to the flow computer must be shut off for at least 1 hour and then restored to verify that the power outage and time of outage was recorded in the event log or indicated on the quantity transaction log.
(a)
(1)
(2)
(3)
(4) At the conclusion of the 1-hour period, the following hourly values must meet the criteria in § 3175.141(d) of this subpart:
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(b)
(1)
(2)
(3)
(4) At the conclusion of the 24-hour period, the following hourly and daily values must meet the criteria in § 3175.141(d) of this subpart:
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(c)
(1)
(2)
(3)
(4) At the conclusion of the 24-hour period, the following hourly values must meet the criteria in § 3175.141(d) of this subpart:
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(d)
(1) Fixed inputs of differential pressure, static pressure, and temperature must be applied to the software version under test to simulate a flow rate greater than 500,000 Mcf/day for a period of at least 7 days.
(2) At the end of the 7-day test period, the accumulated volume must meet the criteria in § 3175.141(d) of this subpart.
(a) The test facility performing the tests must fully document each test required by §§ 3175.141 through 3175.143 of this subpart. The report must indicate the results for each required test and include all data points recorded.
(b) The report must be submitted to the AO. If the PMT determines all testing was completed as required by this section, it will make a recommendation that the BLM post the software version on the BLM's Web site (
(a) Certain instances of noncompliance warrant the imposition of immediate assessments upon discovery. Imposition of any of these assessments does not preclude other appropriate enforcement actions.
(b) The BLM will issue the assessments for the violations listed as follows:
Part of the verification process involves venting the pressure device to the atmosphere, recording the reading from the device, and calibrating (adjusting) the reading, if necessary. When a gauge-pressure device is vented to the atmosphere, the reading of the device should be “zero” because both sides of the device are sensing atmospheric pressure. The calibrator will calibrate the device to read “zero” if necessary. When verifying an absolute pressure device, however, the reading should equal the local atmospheric pressure because one side of the device
| 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 |