Federal Register Vol. 81, No.222,
Federal Register Volume 81, Issue 222 (November 17, 2016)
Federal Register Volume 81, Issue 222 (November 17, 2016)
| Page Range | 80989-81640 | |
| FR Document |
![220 Federal Register / Vol. 81, No. 2 / Tuesday, January 5, 2016 / Notices
provides an organized and continuing their parts and supplies, including DEPARTMENT OF COMMERCE
channel of communication between toner, toner cartridges, toner bottles and
recognized experts in the data industry cartridge parts, within Subzone 20D. International Trade Administration
(collection, compilation, analysis, The current request would add foreign- [A–570–896]
dissemination and privacy protection) status materials/components to the
and the Department of Commerce. The scope of authority. Pursuant to 15 CFR Magnesium Metal From the People’s
CDAC provides advice and 400.14(b), additional FTZ authority Republic of China: Preliminary Results
recommendations, to include process would be limited to the specific foreign- of Antidumping Duty Administrative
and infrastructure improvements, to the status materials/components and Review; 2014–2015
Secretary, DOC and the DOC data- specific finished products described in
bureau leadership on ways to make AGENCY: Enforcement and Compliance,
the submitted notification (as described International Trade Administration,
Commerce data easier to find, access, below) and subsequently authorized by
use, combine and disseminate. The aim Department of Commerce.
the FTZ Board. SUMMARY: The Department of Commerce
of this advice shall be to maximize the
value of Commerce data to all users Production under FTZ procedures (‘‘Department’’) is conducting the
including governments, businesses, could exempt Canon from customs duty administrative review of the
communities, academia, and payments on the foreign-status antidumping duty order on magnesium
individuals. materials/components used in export metal from the People’s Republic of
The Committee is established in production. On its domestic sales, China (‘‘PRC’’). The period of review
accordance with the Federal Advisory Canon would be able to choose the duty (‘‘POR’’) is April 1, 2014, through March
Committee Act (Title 5, United States rates during customs entry procedures 31, 2015. This review covers two PRC
Code, Appendix 2, Section 10(a)(b)). that apply to toner cartridges or toner companies, Tianjin Magnesium
All meetings are open to the public. bottles (duty-free) for the foreign-status International, Co., Ltd. (‘‘TMI’’) and
Individuals questions or statements materials/components noted below and Tianjin Magnesium Metal, Co., Ltd.
must submit them in writing to: in the existing scope of authority. (‘‘TMM’’). The Department
DataAdvisoryCouncil@doc.gov (subject Customs duties also could possibly be preliminarily finds that TMI and TMM
line ‘‘January 2016 CDAC Working deferred or reduced on foreign-status did not have reviewable entries during
Group Meeting Public Comment’’), or by production equipment. the POR. We invite interested parties to
letter submission to the Director of comment on these preliminary results.
External Communication and DFO, The materials/components sourced
DATES: Effective Date: January 5, 2016.
CDAC, Department of Commerce, from abroad include: Carbon black and
FOR FURTHER INFORMATION CONTACT:
Economics and Statistics aluminum flanges (duty rates: Duty-free
James Terpstra or Brendan Quinn, AD/
Administration, 1401 Constitution Ave. and 5.7%, respectively).
CVD Operations, Office III, Enforcement
NW., Washington, DC 20230. Such Public comment is invited from and Compliance, International Trade
submissions will be included in the interested parties. Submissions shall be Administration, U.S. Department of
record for the meeting if received by addressed to the FTZ Board’s Executive Commerce, 14th Street and Constitution
Monday, January 11, 2016. Secretary at the address below. The Avenue NW., Washington, DC 20230;
Dated: December 29, 2015. closing period for their receipt is telephone: (202) 482–3965 or (202) 482–
Burton Reist, February 16, 2016. 5848, respectively.
Director for External Affairs, Economics and A copy of the notification will be Scope of the Order
Statistics Administration. available for public inspection at the
[FR Doc. 2015–33154 Filed 12–30–15; 4:15 pm] The product covered by this
Office of the Executive Secretary,
antidumping duty order is magnesium
BILLING CODE P Foreign-Trade Zones Board, Room
metal from the PRC, which includes
21013, U.S. Department of Commerce, primary and secondary alloy
1401 Constitution Avenue NW., magnesium metal, regardless of
DEPARTMENT OF COMMERCE Washington, DC 20230–0002, and in the chemistry, raw material source, form,
Foreign-Trade Zones Board ‘‘Reading Room’’ section of the FTZ shape, or size. Magnesium is a metal or
Board’s Web site, which is accessible alloy containing by weight primarily the
[B–85–2015] via www.trade.gov/ftz. element magnesium. Primary
Foreign-Trade Zone (FTZ) 20—Newport For further information, contact Diane magnesium is produced by
News, Virginia; Notification of Finver at Diane.Finver@trade.gov or decomposing raw materials into
Proposed Production Activity; Canon (202) 482–1367. magnesium metal. Secondary
Virginia, Inc.; Subzone 20D; (Toner magnesium is produced by recycling
Dated: December 29, 2015.
Cartridges and Bottles) Newport News, magnesium-based scrap into magnesium
Andrew McGilvray, metal. The magnesium covered by this
Virginia
Executive Secretary. order includes blends of primary and
Canon Virginia, Inc. (Canon), operator [FR Doc. 2015–33160 Filed 1–4–16; 8:45 am] secondary magnesium.
of Subzone 20D, submitted a BILLING CODE 3510–DS–P The subject merchandise includes the
notification of proposed production following alloy magnesium metal
asabaliauskas on DSK5VPTVN1PROD with NOTICES
activity to the FTZ Board for its facility products made from primary and/or
within Subzone 20D, in Newport News, secondary magnesium including,
Virginia. The notification conforming to without limitation, magnesium cast into
the requirements of the regulations of ingots, slabs, rounds, billets, and other
the FTZ Board (15 CFR 400.22) was shapes; magnesium ground, chipped,
received on December 14, 2015. crushed, or machined into rasping,
Canon already has authority to granules, turnings, chips, powder,
produce a range of printers, copiers and briquettes, and other shapes; and
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![222 Federal Register / Vol. 81, No. 2 / Tuesday, January 5, 2016 / Notices
Room B8024 of the main Department of 751(a)(2)(C) of the Act: (1) For TMI, SUMMARY: On November 25, 2015, the
Commerce building. which claimed no shipments, the cash Department of Commerce (the
Pursuant to 19 CFR 351.310(c), deposit rate will remain unchanged Department) initiated a changed
interested parties who wish to request a from the rate assigned to TMI in the circumstances review and published a
hearing must submit a written request to most recently completed review of the notice of preliminary results of changed
the Assistant Secretary for Enforcement company; (2) for previously investigated circumstances review of the
and Compliance, U.S. Department of or reviewed PRC and non-PRC exporters antidumping duty order on certain
Commerce within 30 days of the date of who are not under review in this frozen warmwater shrimp (shrimp) from
publication of this notice. Requests segment of the proceeding but who have Thailand.1 In that notice, we
should contain the following separate rates, the cash deposit rate will preliminarily determined that Thai
information: (1) The party’s name, continue to be the exporter-specific rate Union Group Public Co., Ltd. (Thai
address, and telephone number; (2) the published for the most recent period; (3) Union Group) is the successor-in-
number of participants; and (3) a list of for all PRC exporters of subject interest to Thai Union Frozen Products
the issues parties intend to discuss. merchandise that have not been found Public Co., Ltd. (Thai Union Frozen) for
Issues raised in the hearing will be to be entitled to a separate rate purposes of determining antidumping
limited to those raised in the respective (including TMM, which claimed no duty cash deposits and liabilities. No
case and rebuttal briefs. If a request for shipments, but has not been found to be interested party submitted comments
a hearing is made, the Department separate from the PRC-wide entity), the on, or requested a public hearing to
intends to hold the hearing at the U.S. cash deposit rate will be the PRC-wide discuss, the Initiation and Preliminary
Department of Commerce, 14th Street rate of 141.49 percent; and (4) for all Results. For these final results, the
and Constitution Avenue NW., non-PRC exporters of subject Department continues to find that Thai
Washington, DC 20230, at a date and merchandise which have not received Union Group is the successor-in-interest
time to be determined. See 19 CFR their own rate, the cash deposit rate will to Thai Union Frozen.
351.310(d). Parties should confirm by be the rate applicable to the PRC DATES: Effective Date: January 5, 2016.
telephone the date, time, and location of exporter(s) that supplied that non-PRC FOR FURTHER INFORMATION CONTACT:
the hearing two days before the exporter. These deposit requirements, Dennis McClure or Elizabeth Eastwood,
scheduled date. when imposed, shall remain in effect AD/CVD Operations, Office II,
The Department intends to issue the until further notice. Enforcement and Compliance,
final results of this administrative International Trade Administration,
review, which will include the results of Notification to Importers
U.S. Department of Commerce, 14th
our analysis of all issues raised in the This notice also serves as a Street and Constitution Avenue NW.,
case briefs, within 120 days of preliminary reminder to importers of Washington, DC 20230; telephone: (202)
publication of these preliminary results their responsibility under 19 CFR 482–5973 or (202) 482–3874,
in the Federal Register, pursuant to 351.402(f)(2) to file a certificate respectively.
section 751(a)(3)(A) of the Act. regarding the reimbursement of
SUPPLEMENTARY INFORMATION:
Assessment Rates antidumping duties prior to liquidation
of the relevant entries during this Background
Upon issuance of the final results, the
period. Failure to comply with this On September 17, 2015, Thai Union
Department will determine, and CBP
requirement could result in the Group, a producer/exporter of Thai
shall assess, antidumping duties on all
Secretary’s presumption that shrimp covered by this order, changed
appropriate entries covered by this
reimbursement of antidumping duties its name from Thai Union Frozen to
review. The Department intends to issue
occurred and the subsequent assessment Thai Union Group. On October 5, 2015,
assessment instructions to CBP 15 days
of double antidumping duties. Thai Union Group requested that the
after the publication date of the final
This administrative review and notice Department conduct an expedited
results of this review. Additionally,
are in accordance with sections changed circumstances review under
pursuant to a refinement to its
751(a)(1) and 777(i)(1) of the Act, and 19 section 751(b) of the Act, 19 CFR
assessment practice in NME cases, if the
CFR 351.221(b)(4). 351.216(c), and 19 CFR 351.221(c)(3)(ii)
Department continues to determine that
an exporter under review had no Dated: December 24, 2015. to confirm that Thai Union Group is the
shipments of the subject merchandise, Paul Piquado, successor-in-interest to Thai Union
any suspended entries that entered Assistant Secretary for Enforcement and Frozen for purposes of determining
under that exporter’s case number (i.e., Compliance. antidumping duty cash deposits and
at that exporter’s rate) will be liquidated [FR Doc. 2015–33162 Filed 1–4–16; 8:45 am] liabilities. On November 25, 2015, the
at the PRC-wide rate. For a full BILLING CODE 3510–DS–P
Department initiated this changed
discussion of this practice, see Non- circumstances review and published the
Market Economy Antidumping notice of preliminary results,
Proceedings: Assessment of DEPARTMENT OF COMMERCE determining that Thai Union Group is
Antidumping Duties, 76 FR 65694 the successor-in-interest to Thai Union
(October 24, 2011). International Trade Administration Frozen.2 In the Initiation and
Preliminary Results, we provided all
Cash Deposit Requirements [A–549–822] interested parties with an opportunity to
asabaliauskas on DSK5VPTVN1PROD with NOTICES
The following cash deposit comment or request a public hearing
Notice of Final Results of Antidumping
requirements will be effective upon regarding our preliminary finding that
Duty Changed Circumstances Review:
publication of the final results of this Certain Frozen Warmwater Shrimp
administrative review for all shipments From Thailand
1 See Notice of Initiation and Preliminary Results
of the subject merchandise entered, or of Antidumping Duty Changed Circumstances
Review: Certain Frozen Warmwater Shrimp from
withdrawn from warehouse, for AGENCY: Enforcement and Compliance, Thailand, 80 FR 73726 (November 25, 2015)
consumption on or after the publication International Trade Administration, (Initiation and Preliminary Results).
date, as provided for by section Department of Commerce. 2 Id., 80 FR at 73728.
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Document Created: 2016-01-05 01:46:56
Document Modified: 2016-01-05 01:46:56
| Page and Subject | |
|---|---|
| 81 FR 81006 - Teacher Preparation Issues | |
| 81 FR 81639 - America Recycles Day, 2016 | |
| 81 FR 81057 - Certain Cold-Rolled Steel Flat Products From the People's Republic of China: Initiation of Anti-Circumvention Inquiries on the Antidumping Duty and Countervailing Duty Orders | |
| 81 FR 81062 - Welded Stainless Pressure Pipe From India: Antidumping Duty and Countervailing Duty Orders | |
| 81 FR 81139 - Sunshine Act Meeting | |
| 81 FR 81233 - Sunshine Act Meetings; Unified Carrier Registration Plan Board of Directors | |
| 81 FR 81116 - Privacy Act of 1974; Publication of Notices of Systems of Records and Proposed New Systems of Records | |
| 81 FR 81140 - Agency Information Collection Activities; Proposed Collection; Comment Request | |
| 81 FR 81172 - Job Corps: Environmental Assessment (EA) for the Rehabilitation or Replacement of Buildings at the Gulfport Job Corps Center, Gulfport, Mississippi | |
| 81 FR 81174 - Advisory Committee on Construction Safety and Health (ACCSH); Notice of Renewal of Charter | |
| 81 FR 81146 - Proposed Data Collection Submitted for Public Comment and Recommendations | |
| 81 FR 81143 - Proposed Data Collection Submitted for Public Comment and Recommendations | |
| 81 FR 81144 - Proposed Data Collection Submitted for Public Comment and Recommendations | |
| 81 FR 81074 - Endangered and Threatened Wildlife; Determination on Whether To List the Harbor Seals in Iliamna Lake, Alaska as a Threatened or Endangered Species | |
| 81 FR 81175 - Proposal Review Panel for Computing and Communication Foundations; Notice of Meeting | |
| 81 FR 81052 - State of Nebraska; Authorization of State Hazardous Waste Management Program | |
| 81 FR 81229 - Petition for Exemption; Summary of Petition Received, Airbus SAS | |
| 81 FR 81172 - Agency Information Collection Activities; Submission for OMB Review; Comment Request; Evaluation of Strategies Used in TechHire and Strengthening Working Families Initiative Grant Programs | |
| 81 FR 81007 - State of Nebraska; Authorization of State Hazardous Waste Management Program | |
| 81 FR 81229 - Petition for Exemption; Summary of Petition Received; Northrop Grumman Corporation | |
| 81 FR 81230 - Petition for Exemption; Summary of Petition Received; Page, Andrew K. | |
| 81 FR 81150 - National Institute on Drug Abuse; Notice of Closed Meetings | |
| 81 FR 81149 - Government-Owned Invention; Availability for Licensing | |
| 81 FR 81149 - National Institute of Allergy and Infectious Diseases; Notice of Closed Meetings | |
| 81 FR 81151 - National Institute of Allergy and Infectious Diseases; Notice of Closed Meeting | |
| 81 FR 81096 - Notice of a Public Meeting of the National Drinking Water Advisory Council | |
| 81 FR 81096 - Privacy Act of 1974; System of Records | |
| 81 FR 81055 - Request for Nominations of Member To Serve on the Commerce Data Advisory Council (CDAC) | |
| 81 FR 81099 - Drinking Water Contaminant Candidate List 4-Final | |
| 81 FR 81056 - Foreign-Trade Zone 12-McAllen, Texas; Application for Reorganization Under Alternative Site Framework | |
| 81 FR 81056 - Foreign-Trade Zone (FTZ) 189-Kent/Ottawa/Muskegon Counties, Michigan, Authorization of Production Activity, Adient US LLC, Subzone 189D, (Motorized Seat Adjusters for Motor Vehicles), Holland and Zeeland, Michigan | |
| 81 FR 81228 - U.S. Advisory Commission on Public Diplomacy; Notice of Meeting | |
| 81 FR 81138 - Disability Advisory Committee; Announcement of Next Meeting | |
| 81 FR 81228 - Culturally Significant Objects Imported for Exhibition Determinations: “Bouchardon: Royal Artist of the Enlightenment” Exhibition | |
| 81 FR 81064 - Glycine From the People's Republic of China: Initiation of Antidumping Duty Changed Circumstances Review | |
| 81 FR 81053 - Notice of Public Meeting of the Kansas Advisory Committee To Discuss the Committee's Draft Report Regarding Voting Rights in the State, as Well as Other Civil Rights Issues for Future Inquiry | |
| 81 FR 81054 - Notice of Public Meeting of the Minnesota Advisory Committee To Begin Preparations for a Public Hearing To Gather Testimony Regarding Civil Rights and Policing Practices in Minnesota | |
| 81 FR 81175 - Diablo Canyon Power Plant, Units 1 and 2 | |
| 81 FR 81176 - Wolf Creek Generating Station; Consideration of Approval of Transfer of License | |
| 81 FR 81228 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
| 81 FR 81320 - Privacy Act of 1974; Republication of Systems of Records Notices | |
| 81 FR 81233 - Qualification of Drivers; Exemption Applications; Epilepsy and Seizure Disorders | |
| 81 FR 81236 - Qualification of Drivers; Exemption Applications; Vision | |
| 81 FR 81230 - Qualification of Drivers; Exemption Applications; Vision | |
| 81 FR 81156 - Agency Information Collection Activities; Proposed eCollection eComments Requested; Request for ATF Background Investigation Information (ATF F 8620.65) | |
| 81 FR 81139 - Notice of Agreements Filed | |
| 81 FR 81235 - Qualification of Drivers; Exemption Applications; Diabetes | |
| 81 FR 80996 - DoD Environmental Laboratory Accreditation Program (ELAP) | |
| 81 FR 81086 - PetSmart, Inc., Provisional Acceptance of a Settlement Agreement and Order | |
| 81 FR 81239 - Agency Information Collection Activity Under OMB Review | |
| 81 FR 81237 - Agency Information Collection Activity Under OMB Review | |
| 81 FR 81154 - Notice of Public Meeting, Eastern Montana Resource Advisory Council Meeting | |
| 81 FR 81151 - Final Habitat Conservation Plan and Supplemental Final Environmental Impact Statement; Na Pua Makani Wind Energy Project, Oahu, Hawaii | |
| 81 FR 81153 - Proposed Information Collection; Approval Procedures for Nontoxic Shot and Shot Coatings | |
| 81 FR 81053 - Notice of Implementation of the Water Erosion Prediction Project (WEPP) Technology for Soil Erodibility System Calculations for the Natural Resources Conservation Service | |
| 81 FR 81065 - Submission for OMB Review; Comment Request | |
| 81 FR 81175 - Proposal Review; Notice of Meetings | |
| 81 FR 81003 - Security Zone; Potomac River and Anacostia River, and Adjacent Waters; Washington, DC | |
| 81 FR 81224 - Agency Information Collection Activities: Proposed Request and Comment Request | |
| 81 FR 81157 - Notice of Proposed Administrative Settlement Order on Consent and Bona Fide Prospective Purchaser Agreement | |
| 81 FR 81157 - Notice of Lodging of Proposed Consent Decree and Proposed First Amendment to Another Consent Decree Under the Clean Air Act | |
| 81 FR 81154 - Certain Table Saws Incorporating Active Injury Mitigation Technology and Components Thereof; Commission Determination Not To Review a Final Initial Determination Finding a Violation of Section 337; Schedule for Briefing on Remedy, the Public Interest, and Bonding | |
| 81 FR 81089 - Shell Energy North America (US), L.P.; Notice of Intent To File License Application, Filing of Pre-Application Document, and Approving Use of the Traditional Licensing Process | |
| 81 FR 81090 - Algonquin Power (Beaver Falls), LLC; Notice of Scoping Meetings and Environmental Site Review and Soliciting Scoping Comments | |
| 81 FR 81092 - Brookfield White Pine Hydro LLC; Notice of Availability of Environmental Assessment | |
| 81 FR 81093 - Florida Gas Transmission Company, LLC; Notice of Application | |
| 81 FR 81093 - Texas Eastern Transmission, LP; Notice of Application | |
| 81 FR 81091 - Northern Natural Gas Company; Notice of Availability of the Environmental Assessment for the Proposed Northern Lights 2017 Expansion Project | |
| 81 FR 81150 - Government-Owned Inventions; Availability for Licensing and/or Co-Development | |
| 81 FR 81246 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81243 - Proposed Collection; Comment Request for Form 8879-EO | |
| 81 FR 81245 - Proposed Collection; Comment Request for Form 8453-EO | |
| 81 FR 81240 - Proposed Collection; Comment Request for Forms 8821 and 8821-A | |
| 81 FR 81243 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81242 - Proposed Collection; Comment Request for Form 8855 | |
| 81 FR 81242 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81245 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81015 - Supplemental Nutrition Assistance Program: Civil Rights Update to the Federal-State Agreement | |
| 81 FR 81189 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Filing of Amendment No. 2 to, and Order Granting Accelerated Approval of, a Proposed Rule Change, as Modified by Amendment No. 2 Thereto, Relating To Listing and Trading of Shares of Cumberland Municipal Bond ETF under NYSE Arca Equities Rule 8.600 | |
| 81 FR 81182 - Self-Regulatory Organizations; NYSE Arca, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the NYSE Arca Options Fee Schedule Effective November 3, 2016 | |
| 81 FR 81184 - Self-Regulatory Organizations; NASDAQ BX, Inc.; The Nasdaq Stock Market LLC; Order Approving Proposed Rule Changes, as Modified by Amendments No. 1, Relating to Post-Only Orders and Orders With Midpoint Pegging | |
| 81 FR 81202 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change Relating to the Implementation Date for Alternative Trading Systems To Report Sequence Numbers Under Rule 4554 | |
| 81 FR 81206 - Self-Regulatory Organizations; The NASDAQ Stock Market LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend the Transaction Fees at Chapter XV, Section 2 Entitled “NASDAQ Options Market-Fees and Rebates” | |
| 81 FR 81216 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Filing and Immediate Effectiveness of Proposed Change Adopting a Decommission Extension Fee for Receipt of the NYSE MKT Order Imbalances Market Data Product | |
| 81 FR 81186 - Self-Regulatory Organizations; New York Stock Exchange LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change Adopting a Decommission Extension Fee for Receipt of the NYSE Order Imbalances Market Data Product | |
| 81 FR 81213 - Self-Regulatory Organizations; Financial Industry Regulatory Authority, Inc.; Order Approving Proposed Rule Change To Amend Rule 12504 of the Code of Arbitration Procedure for Customer Disputes and Rule 13504 of the Code of Arbitration Procedure for Industry Disputes Relating to Motions To Dismiss in Arbitration | |
| 81 FR 81222 - Self-Regulatory Organizations; New York Stock Exchange LLC; Notice of Filing of Proposed Rule Change Amending Rule 104 To Delete Subsection (g)(i)(A)(III) Prohibiting Designated Market Makers From Establishing a New High (Low) Price on the Exchange in a Security the DMM Has a Long (Short) Position During the Last Ten Minutes Prior to the Close of Trading | |
| 81 FR 81210 - Self-Regulatory Organizations; NYSE MKT LLC; Notice of Filing of Proposed Rule Change Amending Rule 104-Equities To Delete Subsection (g)(i)(A)(III) Prohibiting Designated Market Makers From Establishing a New High (Low) Price on the Exchange in a Security the DMM Has a Long (Short) Position During the Last Ten Minutes Prior to the Close of Trading | |
| 81 FR 81219 - Self-Regulatory Organizations; The NASDAQ Stock Market LLC; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend Rule 4702 and Rule 4703 To Add a “Trade Now” Instruction to Certain Order Types | |
| 81 FR 81203 - Self-Regulatory Organizations; NASDAQ BX, Inc.; Notice of Filing and Immediate Effectiveness of Proposed Rule Change To Amend Rule 4702 and Rule 4703 To Add a “Trade Now” Instruction to Certain Order Types | |
| 81 FR 81200 - Self-Regulatory Organizations; Chicago Board Options Exchange, Incorporated; Notice of Filing and Immediate Effectiveness of a Proposed Rule Change To Amend the Fees Schedule | |
| 81 FR 81247 - Proposed Collection; Comment Request for Form 4952 | |
| 81 FR 81244 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81247 - Proposed Collection; Comment Request for Form 926 | |
| 81 FR 81241 - Proposed Collection; Comment Request for Regulation Project | |
| 81 FR 81248 - Proposed Collection; Comment Request for Revenue Procedure 2004-19 | |
| 81 FR 81137 - Consumer Advisory Committee | |
| 81 FR 81094 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; Notification of Chemical Exports-TSCA Section 12(b) | |
| 81 FR 81116 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; NESHAP for Metal Can Manufacturing Surface Coating (Renewal) | |
| 81 FR 81095 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; NESHAP for Boat Manufacturing (Renewal) | |
| 81 FR 81115 - NSPS for Secondary Brass and Bronze Production, Primary Copper Smelters, Primary Zinc Smelters, Primary Lead Smelters, Primary Aluminum Reduction Plants, and Ferroalloy Production Facilities (Renewal) | |
| 81 FR 81098 - Information Collection Request Submitted to OMB for Review and Approval; Comment Request; NSPS for Magnetic Tape Coating Facilities (Renewal) | |
| 81 FR 81238 - Limitation on Claims Against Proposed Public Transportation Projects | |
| 81 FR 81023 - Proposed Addition of New Grape Variety Names for American Wines | |
| 81 FR 81066 - Revised National Environmental Policy Act Implementing Procedures | |
| 81 FR 81179 - Information Collection Request Submission for OMB Review | |
| 81 FR 81158 - Notice of Proposed Exemption Involving UBS Assets Management (Americas) Inc.; UBS Realty Investors LLC; UBS Hedge Fund Solutions LLC; UBS O'Connor LLC; and Certain Future Affiliates in UBS's Asset Management and Wealth Management Americas Divisions (Collectively, the Applicants or the UBS QPAMs) Located in Chicago, Illinois; Hartford, Connecticut; New York, New York; and Chicago, Illinois, Respectively | |
| 81 FR 81240 - Sanctions Action Pursuant to Executive Order 13224 | |
| 81 FR 81174 - NASA Advisory Council; Meeting | |
| 81 FR 81140 - Change in Bank Control Notices; Acquisitions of Shares of a Bank or Bank Holding Company | |
| 81 FR 81139 - Formations of, Acquisitions by, and Mergers of Bank Holding Companies | |
| 81 FR 81049 - Chlorpyrifos; Tolerance Revocations; Notice of Data Availability and Request for Comment | |
| 81 FR 81148 - Agency Information Collection Activities: Proposed Collection; Comment Request | |
| 81 FR 81147 - Agency Information Collection Activities: Proposed Collection; Comment Request; Correction | |
| 81 FR 81018 - Airworthiness Directives; Fokker Services B.V. Airplanes | |
| 81 FR 80993 - Liabilities Recognized as Recourse Partnership Liabilities Under Section 752; Correction | |
| 81 FR 80994 - Liabilities Recognized as Recourse Partnership Liabilities Under Section 752; Correction | |
| 81 FR 80994 - Civil Penalty Inflation Adjustment | |
| 81 FR 81033 - Adjustments to Cost Recovery Fees Relating to the Regulation of Oil, Gas, and Sulfur Activities on the Outer Continental Shelf | |
| 81 FR 81276 - Implementation of the 2015 National Ambient Air Quality Standards for Ozone: Nonattainment Area Classifications and State Implementation Plan Requirements | |
| 81 FR 81250 - Significant New Use Rules on Certain Chemical Substances | |
| 81 FR 81021 - Airworthiness Directives; The Boeing Company Airplanes | |
| 81 FR 80989 - Equal Access to Housing in HUD's Native American and Native Hawaiian Programs-Regardless of Sexual Orientation or Gender Identity | |
| 81 FR 81516 - Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Gas | |
| 81 FR 81356 - Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Site Security | |
| 81 FR 81462 - Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of Oil |
Issue
Food and Nutrition Service
Natural Resources Conservation Service
Economics and Statistics Administration
Foreign-Trade Zones Board
International Trade Administration
National Oceanic and Atmospheric Administration
Federal Energy Regulatory Commission
Centers for Disease Control and Prevention
Centers for Medicare & Medicaid Services
National Institutes of Health
Coast Guard
Bureau of Safety and Environmental Enforcement
Fish and Wildlife Service
Land Management Bureau
Alcohol, Tobacco, Firearms, and Explosives Bureau
Employee Benefits Security Administration
Employment and Training Administration
Occupational Safety and Health Administration
Federal Aviation Administration
Federal Motor Carrier Safety Administration
Federal Transit Administration
Alcohol and Tobacco Tax and Trade Bureau
Foreign Assets Control Office
Internal Revenue Service
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Office of the Secretary, HUD.
Final rule.
As the Nation's housing agency, HUD has the unique charge to promote the Federal goal of providing decent housing and a suitable living environment for all. In February 2012, HUD issued a final rule requiring HUD programs to make eligibility determinations for individuals seeking admission to HUD-assisted or -insured housing without regard to sexual orientation, gender identity, or marital status. The 2012 rule did not, however, cover HUD's Native American and Native Hawaiian programs. Through this final rule, HUD revises its Native American and Native Hawaiian program regulations to ensure all eligible individuals and families, regardless of sexual orientation, gender identity, or marital status, have access to these programs. This final rule seeks to provide consistency across HUD programs and restates the Department's commitment that eligibility for admission and continued occupancy in HUD-assisted and -insured housing is not based on sexual orientation, gender identity, or marital status.
Heidi J. Frechette, Deputy Assistant Secretary, Office of Native American Housing Programs, Office of Public and Indian Housing, 451 7th Street SW., Room 4126, Washington, DC 20410-4000; telephone number 202-402-6321 (this is not a toll-free number). Persons with hearing or speech impairments may access this number through TTY by calling the Federal Relay Service at 800-877-8339 (this is a toll-free number).
On February 3, 2012, at 77 FR 5662, HUD issued a final rule entitled “Equal Access to Housing in HUD Programs Regardless of Sexual Orientation or Gender Identity,” which required that HUD-assisted and -insured housing be made available in accordance with program eligibility requirements and without regard to sexual orientation, gender identity, or marital status, but excluded HUD's Native American and Native Hawaiian programs. HUD committed in the 2012 rule's preamble to engage in tribal consultation before applying these same requirements to its Native American and Native Hawaiian programs. HUD engaged in tribal consultation, in the form of a “Dear Tribal Leader Letter,” before proceeding with this rulemaking.
On May 9, 2016, HUD published a proposed rule, at 81 FR 28037, to amend its Native American and Native Hawaiian program regulations to require that access be provided without regard to actual or perceived sexual orientation, gender identity, or marital status in housing assisted or insured under these programs. The proposed rule sought to add the equal access provisions in 24 CFR 5.105(a)(2) and adopt the definitions of “sexual orientation” and “gender identity” provided in § 5.100 to the Native American and Native Hawaiian programs. Specifically, the proposed rule sought to amend regulations for the following: Native American Housing Activities, at 24 CFR part 1000; Community Development Block Grants for Indian Tribes and Alaska Native Villages, at 24 CFR part 1003; the Section 184 Indian Home Loan Guarantee Program, at 24 CFR part 1005; the Native Hawaiian Housing Block Grant Program, at 24 CFR part 1006; and Section 184A Loan Guarantees For Native Hawaiian Housing, at 24 CFR part 1007. HUD also proposed to make conforming amendments to § 5.105(a)(2) to make explicit that the requirements in § 5.105(a)(2) apply to housing with loans guaranteed or insured under one of HUD's Native American or Native Hawaiian housing programs, and not solely to loans insured by the Federal Housing Administration (FHA). A detailed description of the proposed amendments can be found in the preamble to the proposed rule available at
This final rule follows publication of the May 9, 2016, proposed rule and takes into consideration the public comments received. The public comment period closed on July 8, 2016, and HUD received 13 distinct comments relating to the proposed rule. HUD received public comments from individuals, tribal nations, housing authorities, nonprofit social service providers, and lesbian, gay, bisexual and transgender (LGBT) advocacy organizations. Section III of this preamble responds to the comments received on the proposed rule. HUD has decided to adopt the proposed rule and makes a minor change to § 5.105(a)(2) to clarify that all loans insured by HUD are subject to the equal access provisions, not only loans insured by FHA. This final rule ensures that eligibility determinations for housing-assisted or -insured under HUD's Native American or Native Hawaiian housing programs are made without regard to actual or perceived sexual orientation, gender identity, or marital status.
HUD notes that in adopting this final rule with the cross-references to § 5.105(a)(2), the changes to § 5.105(a) that were adopted in HUD's final rule entitled “Equal Access in Accordance with an Individual's Gender Identity in Community Planning and Development Programs” (the CPD Equal Access Rule), at 81 FR 64763, will apply to HUD's Native American or Native Hawaiian housing programs. Those changes include amended definitions of “gender identity” and “sexual orientation” and the removal of the prohibition of inquiries provision that was previously at § 5.105(a)(2)(ii). The amended “gender identity” definition states that gender identity “means the gender with which a person identifies, regardless of the sex assigned to that person at birth and regardless of the person's perceived gender identity. Perceived gender
HUD received 13 distinct comments relating to the proposed rule. Most commenters were very supportive and appreciative of HUD's efforts to ensure access in HUD's Native American and Native Hawaiian programs for LGBT individuals. Although the majority of commenters supported the rule as important to protect the rights of LGBT individuals, some expressed different opinions on the way the rule could be improved to ensure that vulnerable populations are protected. Many of the commenters stated that the rule's language needed to be clarified to ensure greater protections for the LGBT population. Commenters provided their overall views regarding the rule, as well as specific comments on HUD's regulatory text. All comments can be viewed at
HUD appreciates all of the comments offered in response to HUD's proposed rule.
A commenter stated that the current “gender identity” language under § 5.100 states that gender identity refers to “actual or perceived gender-related characteristics,” and proposed a change to the language to state that gender identity is “the gender with which a person identifies, regardless of the sex assigned to that person at birth or perceived gender identity.”
The Regulatory Flexibility Act (RFA) (5 U.S.C. 601
This final rule sets forth nondiscrimination standards. Accordingly, under 24 CFR 50.19(c)(3), this rule is categorically excluded from environmental review under the National Environmental Policy Act of 1969 (42 U.S.C. 4321).
Executive Order 13132 (entitled “Federalism”) prohibits an agency from publishing any rule that has federalism implications if the rule either: (i) Imposes substantial direct compliance costs on State and local governments and is not required by statute or (ii) preempts State law, unless the agency meets the consultation and funding requirements of section 6 of the Executive order. This final rule would not have federalism implications and would not impose substantial direct compliance costs on State and local governments or preempt State law within the meaning of the Executive order.
Title II of the Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) (UMRA) establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and on the private sector. This final rule would not impose any Federal mandates on any State, local, or tribal governments or on the private sector within the meaning of the UMRA.
Administrative practice and procedure, Aged, Claims, Drug abuse, Drug traffic control, Grant programs—housing and community development, Grant programs—Indians, Individuals with disabilities, Loan programs—housing and community development, Low and moderate income housing, Mortgage insurance, Pets, Public housing, Rent subsidies, Reporting and recordkeeping requirements.
Aged, Community development block grants, Grant programs—housing and community development, Grant programs—Indians, Indians, Individuals with disabilities, Public housing, Reporting and recordkeeping requirements.
Alaska, Community development block grants, Grant programs—housing and community development, Grant programs—Indians, Indians, Reporting and recordkeeping requirements.
Indians, Loan programs—Indians, Reporting and recordkeeping requirements.
Community development block grants, Grant programs—housing and community development, Grant programs—Indians, Hawaiian Natives, Low and moderate income housing, Reporting and recordkeeping requirements.
Hawaiian Natives, Loan programs—housing and community development,
Accordingly, for the reasons stated in the preamble, HUD amends 24 CFR parts 5, 1000, 1003, 1005, 1006, and 1007, as follows:
42 U.S.C. 1437a, 1437c, 1437d, 1437f, 1437n, 3535(d), Sec. 327, Pub. L. 109-115, 119 Stat. 2936, and Sec. 607, Pub. L. 109-162, 119 Stat. 3051.
(a) * * *
(2)
25 U.S.C. 4101
(e) The equal access to HUD-assisted or -insured housing requirements in 24 CFR 5.105(a)(2).
42 U.S.C. 3535(d) and 5301
(c) A grantee shall comply with the equal access to HUD-assisted or -insured housing requirements in 24 CFR 5.105(a)(2).
12 U.S.C. 1715z-13a; 15 U.S.C. 1639c; 42 U.S.C. 3535(d).
The equal access to HUD-assisted or -insured housing requirements in 24 CFR 5.105(a)(2) apply to this part.
25 U.S.C. 4221
Program eligibility under the Act and this part may be restricted to Native Hawaiians. Subject to the preceding sentence, no person may be discriminated against on the basis of race, color, national origin, religion, sex, familial status, or disability, or excluded from program eligibility because of actual or perceived sexual orientation, gender identity, or marital status. The following nondiscrimination requirements are applicable to the use of NHHBG funds:
(d) The equal access to HUD-assisted or -insured housing requirements in 24 CFR 5.105(a)(2).
12 U.S.C. 1715z-13b; 15 U.S.C. 1639c; 42 U.S.C. 3535(d).
(b) The equal access to HUD-assisted or -insured housing requirements in 24 CFR 5.105(a)(2) apply to this part.
Internal Revenue Service (IRS), Treasury.
Correcting amendment.
This document contains corrections to final and temporary regulations (TD 9788) that were published in the
This correction is effective November 17, 2016 and is applicable on and after January 3, 2017.
Caroline E. Hay or Deane M. Burke (202) 317-5279 (not a toll-free number).
The final and temporary regulations (TD 9788) that are the subject of this correction are under sections 707 and 752 of the Internal Revenue Code.
As published, the final and temporary regulations (TD 9788) contain errors that may prove to be misleading and are in need of clarification.
Income taxes, Reporting and recordkeeping requirements.
Accordingly, 26 CFR part 1 is corrected by making the following correcting amendments:
26 U.S.C. 7805 * * *
Section 1.707-5T also issued under 26 U.S.C. 707(a)(2)(B).
(a) * * *
(2) * * *
(i)
(f) * * *
(i) * * * For disguised sale purposes, assume that G's and H's share of liability 1 is $2,000 each in accordance with paragraph (a)(2) of this section (which determines a partner's share of a liability using the percentage under § 1.752-3(a)(3), but not exceeding the partner's share of the liability under section 752 and applicable regulations). * * *
Internal Revenue Service (IRS), Treasury.
Final and temporary regulations; correction.
This document contains corrections to final and temporary regulations (TD 9788) that were published in the
This correction is effective November 17, 2016 and is applicable on and after January 3, 2017.
Caroline E. Hay or Deane M. Burke (202) 317-5279 (not a toll-free number).
The final and temporary regulations (TD 9788) that are the subject of this correction are under sections 707 and 752 of the Internal Revenue Code.
As published, the final and temporary regulations (TD 9788) contain errors that may prove to be misleading and are in need of clarification.
Accordingly, the final and temporary regulations (TD 9788), that are the subject of FR Doc. 2016-23388, are corrected as follows:
On page 69284, in the preamble, first column, the last sentence from the bottom of the first full paragraph, “Therefore, the 707 Temporary Regulations provide that a partner's share of a partnership liability for disguised sale purposes does not include any amount of the liability for which another partner bears the EROL for the partnership liability under § 1.752-2.” is corrected to read “Therefore, the 707 Temporary Regulations provide that for purposes of § 1.707-5, a partner's share of a liability of a partnership, as defined in § 1.752-1(a) (whether a recourse liability or a nonrecourse liability) is determined by applying the same percentage used to determine the partner's share of the excess nonrecourse liability under § 1.752-3(a)(3) (as limited in its application to § 1.707-5T(a)(2)), but such share shall not exceed the partner's share of the partnership liability under section 752 and applicable regulations (as limited in the application of § 1.752-3(a)(3) to § 1.707-5T(a)(2)).”.
Bureau of Safety and Environmental Enforcement, Interior.
Final rule.
This final rule adjusts the level of the civil monetary penalty contained in the Bureau of Safety and Environmental Enforcement (BSEE) regulations pursuant to the Outer Continental Shelf Lands Act (OCSLA), the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015, and Office of Management and Budget (OMB) guidance.
Effective November 17, 2016.
Robert Fisher, Acting Chief Safety and Enforcement Division, Bureau of Safety and Environmental Enforcement, (202) 208-3955 or by email:
This final rule was initiated as a BSEE Interim Final Rule “Civil Penalty Inflation Adjustment,” which was published in the
OCSLA directs the Secretary of the Interior to adjust the OCSLA maximum civil penalty amount at least once every three years to reflect any increase in the Consumer Price Index (CPI) to account for inflation. (43 U.S.C. 1350(b)(1)). The Federal Civil Penalties Inflation Adjustment Act of 1990 (Pub. L. 104-410) (FCPIA of 1990) required that all civil monetary penalties, including the OCSLA maximum civil penalty amount, be adjusted at least once every 4 years. Pursuant to OCSLA and the FCPIA of 1990, the OCSLA maximum civil penalty amount was last adjusted in 2011. (
On November 2, 2015, the President signed into law the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (Sec. 701 of Pub. L. 114-74) (FCPIA of 2015). The FCPIA of 2015 requires Federal agencies to adjust the level of civil monetary penalties with an initial “catch-up” adjustment, if warranted, through rulemaking and then to make subsequent annual adjustments for inflation. The purpose of these adjustments is to maintain the deterrent effect of civil penalties and to further the policy goals of the underlying statutes.
Pursuant to OCSLA and the FCPIA of 2015, this rule adjusts the following maximum civil monetary penalty (per day per violation):
On February 24, 2016, OMB issued guidance on calculating the civil monetary penalty adjustments pursuant to the FCPIA of 2015. (
For 2016, OCSLA and the FCPIA of 2015 required that BSEE adjust the OCSLA maximum civil penalty amount and provide for the adjustment timing. In computing the new OCSLA maximum civil penalty amount, in accordance with the OMB guidance, BSEE divided the October 2015 CPI by the October 2011 CPI (237.838/226.421) since BSEE last adjusted the maximum civil penalty amount in 2011. This resulted in a multiplying factor of 1.05042. The existing maximum civil penalty amount ($40,000) was multiplied by the multiplying factor (40,000 × 1.05042 = 42,016.8). The FCPIA of 2015 requires that the OCSLA maximum civil penalty amount be rounded to the nearest $1.00 at the end of the calculation process. Accordingly, the adjusted OCSLA maximum civil penalty is $42,017. This increase in the OCSLA maximum civil penalty amount does not exceed 150 percent of the OCSLA maximum civil penalty amount as of November 2, 2015, as stipulated by the FCPIA of 2015. Also, pursuant to the FCPIA of 2015, the increase in the OCSLA maximum civil penalty amount applies to civil penalties assessed after the date the increase took effect (July 28, 2016), even when the associated violation(s) predate(s) such increase.
Although the IFR was effective as of July 28, 2016, the IFR included a request for public comments. The public comment period closed on August 29, 2016. BSEE received no comments on the IFR and is therefore finalizing this rulemaking as originally implemented by the IFR.
Executive Order (E.O.) 12866 provides that the OMB Office of Information and Regulatory Affairs will review all significant rules. The Office of Information and Regulatory Affairs has determined that this rule is not significant.
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. E.O. 13563 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,
The Regulatory Flexibility Act (RFA) requires an agency to prepare a regulatory flexibility analysis for all rules unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. The RFA applies only to rules for which an agency is required to first publish a proposed rule. (
This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule:
(1) Does not have an annual effect on the economy of $100 million or more.
(2) Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions.
(3) Does 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.
This rule does not impose an unfunded mandate on State, local, or tribal governments, or the private sector of more than $100 million per year. The rule does not have a significant or unique effect on State, local, or tribal governments or the private sector. Therefore, a statement containing the information required by the Unfunded Mandates Reform Act (2 U.S.C. 1531
This rule does not effect a taking of private property or otherwise have takings implications under E.O. 12630. Therefore, a takings implication assessment is not required.
Under the criteria in section 1 of E.O. 13132, this rule does not have sufficient federalism implications to warrant the preparation of a federalism summary impact statement. Therefore, a federalism summary impact statement is not required.
This rule complies with the requirements of E.O. 12988. Specifically, this rule:
(1) Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and
(2) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.
The Department of the Interior strives to strengthen its government-to-government relationship with Indian tribes through a commitment to consultation with Indian tribes and recognition of their right to self-governance and tribal sovereignty. We have evaluated this rule under the Department of the Interior's consultation policy, under Departmental Manual Part 512 Chapters 4 and 5, and under the criteria in E.O. 13175. We have determined that it has no substantial direct effects on federally recognized Indian tribes and that consultation under the Department of the Interior's tribal consultation policy is not required.
This rule does not contain information collection requirements, and a submission to the OMB under the Paperwork Reduction Act (44 U.S.C. 3501
This rule does not constitute a major Federal action significantly affecting the quality of the human environment. A detailed statement under the National Environmental Policy Act of 1969 (NEPA) is not required because the rule is covered by a categorical exclusion (see 43 CFR 46.210(i)). This rule is excluded from the requirement to prepare a detailed statement because it is a regulation of an administrative nature. We have also determined that the rule does not involve any of the extraordinary circumstances listed in 43 CFR 46.215 that would require further analysis under NEPA.
This rule is not a significant energy action under the definition in E.O. 13211. Therefore, a Statement of Energy Effects is not required.
Administrative practice and procedure, Continental shelf, Environmental impact statements, Environmental protection, Government contracts, Incorporation by reference, Investigations, Oil and gas exploration, Penalties, Pipelines, Continental Shelf—mineral resources, Continental Shelf—rights-of-way, Reporting and recordkeeping requirements, Sulfur.
Under Secretary of Defense for Acquisition, Technology, and Logistics, DoD.
Final rule.
This final rule establishes policy, assigns responsibilities, and provides procedures to be used by DoD personnel for the operation and management of the DoD ELAP. The DoD ELAP provides a unified DoD program through which commercial environmental laboratories can voluntarily demonstrate competency and document conformance to the international quality systems standards as they are implemented by DoD.
This rule is effective on December 19, 2016.
Edmund Miller, 571-372-6904.
On October 15, 2015 (80 FR 61997-62003), the Department of Defense published a proposed rule in the
The purpose of this regulatory action is to document the procedures for the operation and management of the DoD Environmental Laboratory Accreditation Program (ELAP). The legal authority for the regulatory action is Section 515, Treasury and General Government Appropriations Act for Fiscal Year 2001 (Public Law 106-554), which directed the Office of Management and Budget (OMB) to issue government-wide guidelines that “provide policy and procedural guidance to Federal Agencies for ensuring and maximizing the quality, objectivity, utility, and integrity of information (including statistical information) disseminated by Federal Agencies.” OMB guidelines, provided by FR Volume 67, Number 36, page 8452 (February 22, 2002) required federal agencies to maintain a basic standard of quality and take appropriate steps to incorporate information quality criteria into DoD public information dissemination practices. The guidance further provided that DoD Components shall adopt standards of quality that are appropriate to the nature and timeliness of the information they disseminate. The DoD ELAP provides the standards for ensuring the quality, objectivity, utility, and integrity of definitive environmental testing data disseminated by DoD for the Defense Environmental Restoration Program (DERP).
This rule includes a general overview of DoD ELAP and establishment of standard operating procedures. It utilizes the baseline quality systems requirements of The NELAC Institute (TNI) and ISO/IEC 17025 standards, but alone neither of these standards meet the testing and analysis needs for DERP. Therefore the DoD Quality Systems Manual (QSM) for environmental laboratories serves as the standard for DoD ELAP accreditation. The QSM contains the minimum requirements DoD considers essential to ensure the generation of definitive environmental data of know quality, appropriate for their intended uses. These minimal needs are not met by TNI or ISO 17025 standards alone. The DoD ELAP includes procedures on how to evaluate and recognize 3rd party accreditation bodies; perform and document government oversight of the DoD ELAP to ensure ongoing compliance with program requirements and to identify opportunities for continual improvement; conduct project-specific laboratory approvals for specific tests not addressed in the DoD ELAP; and handle specific complaints concerning the processes established by the DoD ELAP or the QSM.
Past DoD laboratory assessment programs were specific to each DoD Component and limited to available resources. This created an overlap in assessments and fewer opportunities for laboratories to participate on DoD contracts. This rule proposes to establish a program to allow qualified laboratories to received third-party accreditation and become eligible to provide environmental sampling and testing services for DoD. It will be a voluntary program open to any qualified laboratories wishing to participate, thereby promoting fair and open competition among commercial laboratories.
Since laboratories fund their own participation in the accreditation process, it will allow DoD to focus its resources on providing oversight of laboratory contracts. By proposing to replace separate DoD Component-specific laboratory approval programs, the DoD ELAP will eliminate redundant assessments, promote interoperability across the Department, streamline the process for DoD to identify and procure competent providers of environmental laboratory services, and provide more opportunities for commercial laboratories to participate in DoD environmental sampling and testing contracts.
The scope of accreditation under ELAP includes specific laboratory services such as the test methods used, type of material tested (soil, water, etc.), and type of contaminants measured. The evaluation of a test method also includes the use of internal laboratory standard operating procedures.
Executive Orders 13563 and 12866 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distribute impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has not been designated a “significant regulatory action,” because it does not: (1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy; a section of the economy; productivity; competition; jobs; the environment; public health or safety; or State, local, or tribal governments or communities; (2) create a serious inconsistency or otherwise interfere with an action taken or planned by another Agency; (3) materially alter the budgetary impact of entitlements, grants, user fees, or loan programs, or the rights and obligations of recipients thereof; or (4) raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in these Executive Orders.
Section 202 of the Unfunded Mandates Reform Act of 1995 (UMRA) (Pub. L. 104-4) requires agencies assess anticipated costs and benefits before issuing any rule whose mandates require spending in any 1 year of $100 million in 1995 dollars, updated annually for inflation. In 2014, that threshold is approximately $141 million. This rule will not mandate any requirements for State, local, or tribal governments, nor will it affect private sector costs.
The Department of Defense does not expect this final rule would have a significant economic impact on a substantial number of small entities
It has been certified that 32 CFR part 188 does not impose reporting or recordkeeping requirements under the Paperwork Reduction Act of 1995. The requirements in this rule do not require OMB approval under the Paperwork Reduction Act as the information is collected by the four accreditation bodies and not the Department. These accreditation bodies accredit the laboratories to meet DoD standards for environmental sampling and testing.
Executive Order 13132 establishes certain requirements that an agency must meet when it promulgates a proposed rule (and subsequent final rule) that imposes substantial direct requirement costs on State and local governments, preempts State law, or otherwise has Federalism implications. This rule will not have a substantial effect on State and local governments.
Laboratories, Oversight.
15 U.S.C. 3701; Pub. L. 106-554, 114 Stat. 2763.
This part implements policy, assigns responsibilities, and provides procedures to be used by DoD personnel for the operation and management of the DoD ELAP.
This part applies to Office of the Secretary of Defense, the Military Departments, the Office of the Chairman of the Joint Chiefs of Staff and the Joint Staff, the Combatant Commands, the Office of the Inspector General of the Department of Defense, the Defense Agencies, the DoD Field Activities, and all other organizational entities within the DoD (referred to collectively in this part as the “DoD Components”).
Unless otherwise noted, these terms and their definitions are for the purposes of this part.
It is DoD policy, in accordance with DoD Instruction 4715.15, to implement the DoD ELAP for the collection of definitive data in support of the Defense Environmental Restoration Program (DERP) at all DoD operations, activities, and installations, including government-owned, contractor-operated facilities and formerly used defense sites.
(a)
(1) Provide resources to support project-specific government oversight for the collection of definitive data in support of the DERP.
(2) Provide resources to support project-specific laboratory approvals, if required.
(b)
(a)
(ii) DoD ELAP was developed in compliance with 15 U.S.C. 3701 (also known as the “National Technology Transfer and Advancement Act”). Support and guidance was provided by the National Institute of Standards and Technology, following procedures used to establish similar programs for other areas of testing. The DoD ELAP supports implementation of section 515 of Public Law 106-554, “Treasury and General Government Appropriations Act, 2001” and Office of Management and Budget Guidance, “Guidelines for Ensuring and Maximizing the Quality, Objectivity, Utility, and Integrity of Information Disseminated by Federal Agencies” (67 FR 8452) as implemented by Deputy Secretary of Defense Memorandum, “Ensuring Quality of Information Disseminated to the Public by the Department of Defense.”
(iii) Using third party ABs operating in accordance with the international standard ISO/IEC 17011:2004(E), “Conformity Assessment—General Requirements for Accreditation Bodies Accrediting Conformity Assessment Bodies” (available for purchase at
(A) Promotes interoperability among the DoD Components.
(B) Promotes fair and open competition among commercial laboratories.
(C) Streamlines the process for identifying and procuring competent providers of environmental laboratory services.
(D) Promotes the collection of data of known and documented quality.
(2)
(3)
(ii) The DoD ELAP applies to:
(A) Environmental programs at DoD operations, activities, and installations, including government-owned, contractor-operated facilities and formerly used defense sites.
(B) Permanent, temporary, and mobile laboratories regardless of their size, volume of business, or field of accreditation that generate definitive data.
(iii) Participation in the program is voluntary and open to all laboratories that operate under a quality system conforming to ISO/IEC 17025:2005 and Deputy Under Secretary of Defense for Environmental Security Memorandum, “DoD Quality Systems Manual for Environmental Laboratories.” Laboratories may seek accreditation for any method they perform in accordance with documented procedures, including non-standard methods. Laboratories are free to select any participating AB for accreditation services.
(iv) To participate in DoD ELAP, ABs must be U.S.-based signatories to the ILAC MRA and must operate in accordance with ISO/IEC 17011:2004(E).
(4)
(i) Provides coordinated responses to legislative and regulatory initiatives.
(ii) Responds to requests for DoD Component information.
(iii) Develops and recommends department-wide policy related to sampling, testing, and quality assurance for environmental programs.
(iv) Implements and provides oversight for the DoD ELAP.
(v) Includes technical experts from the Military Services and DLA as well as an EDQW component principal (voting) member from each of the Military Services.
(vi) Specifies the EDQW Navy principal, Director of Naval Sea Systems Command (NAVSEASYSCOM) 04XQ(LABS), serve as EDQW chair.
(b)
(i) The DoD QSM remains current in accordance with ISO/IEC 17025:2005.
(ii) Minimum essential requirements are met.
(iii) Requirements are clear, concise, and auditable.
(iv) The DoD QSM will efficiently and effectively support the DoD ELAP.
(2)
(ii)
(iii)
(A)
(B)
(C)
(
(
(D)
(
(
(
(
(
(3)
(4)
(c)
(A) Use the procedures in this paragraph to evaluate and recognize third-party ABs in support of the DoD ELAP.
(B) Develop and maintain the application for recognition, the conditions and criteria for recognition and related forms, and review submitted AB applications for completeness and compliance with DoD ELAP requirements.
(ii) The DoD EDQW chair, following consultation with and concurrence by the EDQW component principals, grants or revokes AB recognition in accordance with this paragraph.
(2)
(3)
(A) Application for recognition.
(B) Signed acceptance of the conditions and criteria for DoD ELAP recognition.
(C) Electronic copy of the AB's quality systems documentation.
(D) Copy of the most recent ILAC MRA peer evaluation documentation.
(ii) If necessary to complete the review, the DoD EDQW will request additional documentation from the applicant.
(iii) The EDQW component principals will review the application package for compliance with requirements. Prior to granting recognition, the EDQW component principals must unanimously concur that all application requirements have been met.
(iv) Once the EDQW component principals have completed review of the application package, the DoD EDQW chair will notify the AB, either granting recognition or citing specific reasons for not doing so (
(v) Once recognition has been granted, the DoD EDQW chair will post the name and contact information of the AB on DENIX.
(vi) With unanimous concurrence, the EDQW component principals may revoke recognition if the AB:
(A) Violates any of the conditions or criteria for recognition.
(B) Fails to operate in accordance with its documented quality system.
(vii) Should it become necessary to revoke an AB's recognition, the DoD EDQW chair will notify the AB stating specific reasons for the revocation and remove the AB's name from the list of DoD ELAP-recognized ABs.
(viii) If recognition is revoked, the AB must immediately cease to perform all DoD ELAP assessments.
(ix) ABs who have been denied recognition, or ABs whose recognition has been revoked, may appeal that decision.
(A) Within 15 calendar days of its receipt of a notice denying or revoking recognition, the AB must submit to the DoD EDQW chair a written statement with supporting documentation contesting the denial or revocation.
(B) The submission must demonstrate that:
(
(
(x) The DoD EDQW will have up to 30 calendar days to review the appeal and provide written notice to the AB either accepting the appeal and granting, or restoring, recognition, or explaining the basis for denying the appeal.
(4)
(5)
(d)
(2)
(A) Offer specific advice to the laboratory regarding the development or implementation of quality systems or technical procedures;
(B) Offer specific advice or direction to assessors or peer evaluators regarding accreditation processes, assessment procedures, or documentation of findings; or
(C) Impede assessors, peer reviewers, or laboratory personnel in any way during the performance of their work, including technical procedures, document reviews, observations, interviews, and meetings.
(ii) If, during the course of an assessment, questions by laboratory personnel or assessors are directed to DoD personnel, personnel must limit responses to specific text from the DoD QSM or published FAQs. DoD personnel must not render opinions regarding interpretation of the DoD QSM. If there are questions about the DoD QSM that require interpretation, DoD personnel must advise the assessor to contact the AB who may, if necessary, contact the DoD EDQW chair for a coordinated response.
(iii) If DoD personnel observe any evidence of inappropriate practices on the part of assessors or laboratory personnel during the course of the assessment, they must record the observations and notify the DoD EDQW chair immediately (inappropriate practices are identified in the DoD QSM). DoD personnel must not call either the laboratory's or the assessor's attention to the specific practice in question.
(3)
(i) Meet the government chemist or contractor project chemist requirements contained in the USD(AT&L) Memorandum, “Acquisitions Involving Environmental Sampling or Testing Services.”
(ii) Have a working knowledge of the DoD QSM requirements and be familiar with environmental test methods and instrumentation.
(iii) Obey all laboratory instructions regarding health and safety precautions while in the laboratory.
(4)
(ii) Once an assessment or peer review has been scheduled, the EDQW component principals will determine if DoD oversight of the activity will be performed. The goal will be to observe a representative number of activities for each AB.
(iii) The EDQW component principals will provide the DoD EDQW chair the names of personnel from their respective DoD Components who will participate in the oversight.
(iv) The DoD EDQW chair will provide the AB with contact information for the oversight personnel.
(v) If two or more DoD personnel are scheduled to monitor the assessment, the DoD EDQW chair will designate a lead that will be responsible for compiling an oversight report.
(vi) The lead for the oversight activity will request a copy of the assessment plan from the AB's lead assessor and distribute it to other oversight personnel.
(vii) The lead will review the assessment plan to determine the scope of accreditation and ensure that oversight personnel are assigned to monitor a cross-section of the assessment.
(viii) Persons performing oversight will review previous oversight reports, if available, for the particular AB and assessors performing the assessment.
(ix) Observing all health and safety protective measures, oversight personnel must accompany the assessor(s) as they witness procedures and conduct interviews, taking care not to interfere with the assessment.
(5)
(i) The DoD EDQW chair will provide copies of the report to the EDQW component principals for review.
(ii) After review by the EDQW component principals, the DoD EDQW chair will provide a summary of the oversight report to the AB performing the assessment.
(6)
(i) In the event the laboratory and the AB are unable to resolve a disagreement concerning the interpretation of the DoD QSM, either the laboratory or the AB may request the DoD EDQW provide an interpretation of the DoD QSM. The DoD EDQW chair will provide a written response to the laboratory and the AB providing the DoD authoritative interpretation of the DoD QSM. No review of this interpretation will be available to the laboratory or the AB.
(ii) The DoD EDQW will not consider or take a position on requests by either a laboratory or an AB on a dispute concerning accreditation of the laboratory.
(7)
(i) Review the ABs' assessment reports and the DoD oversight reports to evaluate the thoroughness, consistency, objectivity, and impartiality of the DoD ELAP assessments.
(ii) Compare assessment reports across laboratories, ABs, and assessors.
(iii) Compare DoD ELAP findings to findings from previous assessments.
(iv) Identify opportunities for continual improvement of the DoD ELAP.
(v) Meet with ABs on an annual basis to review lessons learned and identify additional opportunities for continual improvement of the DoD ELAP.
(8)
(e)
(i) The required method, matrix, or analyte is not included in the scope of accreditation for any existing DoD ELAP-accredited laboratories.
(ii) The required method, matrix, and analyte combination is included in the scope of accreditation for an existing accredited laboratory; however, the laboratory is unable to meet one or more of the project-specific measurement performance criteria.
(2)
(ii) The DoD EDQW will not perform project-specific laboratory approvals in cases where one or more DoD ELAP-accredited laboratories capable of meeting project-specific requirements are available.
(iii) The project-specific laboratory approval is a one-time approval, the specific terms of which will be outlined in the approval notice issued by the DoD EDQW.
(3)
(4)
(ii) If, after review of the QAPP, the DoD EDQW determines that an existing DoD ELAP-accredited laboratory is available to provide the required services, the laboratory contact information will be provided to the project manager requesting assistance.
(iii) If, after review of the QAPP, the DoD EDQW determines that no existing DoD ELAP-accredited laboratory is available to provide the required services, the DoD EDQW will:
(A) Work with the project team to determine whether the use of alternative procedures by an existing DoD ELAP-accredited laboratory is feasible;
(B) Determine if the required services can be added to the scope of accreditation of an existing DoD ELAP-accredited laboratory; or
(C) Work with the project team to identify a candidate laboratory for project-specific laboratory approval.
(iv) If a project-specific approval is needed, the DoD EDQW will:
(A) Determine the type of assessment required (on-site, document review, etc.).
(B) Determine if additional funding is required to support the assessment. If additional funding is required, the DoD EDQW will provide a cost estimate and work with the project manager to establish funding.
(v) If the DoD EDQW determines that a project-specific laboratory approval is warranted and resources (including funding and technical expertise) are available to support the assessment, the DoD EDQW chair will coordinate with the EDQW component principals to appoint an assessment team with appropriate technical backgrounds.
(vi) The DoD EDQW chair will designate an assessment team leader. The assessment team leader will:
(A) Request the documentation needed to perform the assessment.
(B) Assign responsibilities for individual members of the assessment team, if appropriate.
(C) Coordinate the document reviews.
(D) Lead the assessment team in the performance of the on-site assessment, if required.
(E) Provide a report to the DoD EDQW chair. The report will identify whether:
(
(
(
(vii) The DoD EDQW chair, with concurrence by the EDQW component principals, will issue a report to the project manager and laboratory detailing the results of the assessment and any deficiencies that must be corrected prior to granting a project-specific laboratory approval.
(viii) Upon receipt of the laboratory's corrective action response, if required, the assessment team will:
(A) Review the laboratory's corrective action response for resolving the deficiencies.
(B) Provide the EDQW component principals with a final report describing the resolution of findings and containing recommendations on whether to grant the project-specific laboratory approval.
(ix) The DoD EDQW chair, with concurrence by the EDQW component principals, will prepare a report for the DoD project manager describing the results of the assessment and the status and terms of the project-specific laboratory approval. Information about project-specific laboratory approvals will not be posted on Web sites listing DoD ELAP-accredited laboratories.
(5)
(6)
(f)
(i) Complaints by any party against an accredited laboratory.
(ii) Complaints by any party against an AB.
(iii) Complaints by any party concerning any assessor acting on behalf of the AB.
(iv) Complaints by any party against the DoD ELAP itself.
(2)
(i) Do not address appeals by laboratories regarding accreditation decisions by ABs. Appeals to decisions made by ABs regarding the accreditation status of any laboratory must be filed directly with the AB in accordance with agreements in place between the laboratory and the AB.
(ii) Are not designed to handle allegations of unethical or illegal actions as described in paragraph (d)(2)(iii) of this section.
(iii) Do not address complaints involving contractual requirements between a laboratory and its client. All contracting issues must be resolved with the contracting officer.
(3)
(ii) Upon receipt of the complaint, the DoD EDQW chair will assign a unique identifier to the complaint, send a notice of acknowledgement to the complainant, and forward a copy of the complaint to the EDQW component principals.
(iii) In consultation with the EDQW component principals, the DoD EDQW chair will make a preliminary determination of the validity of the complaint. Following preliminary review, the actions available to the DoD EDQW chair include:
(A) If the DoD EDQW chair determines the complaint should be handled directly between the complainant and the subject of the complaint, the DoD EDQW will refer the complaint to the laboratory, or AB, as appropriate. The DoD EDQW will notify the complainant of the referral, but will take no further action with respect to investigation of the complaint. The subject of the complaint will be expected to respond to the complainant in accordance with their established procedures and timelines. A copy of the response will be provided to the DoD EDQW.
(B) If insufficient information has been provided to determine whether the complaint has merit, the DoD EDQW will return the complaint to the complainant with a request for additional supporting documentation.
(C) If the complaint appears to have merit and the parties to the complaint have been unable to resolve it, the DoD EDQW will investigate the complaint and recommend actions for its resolution.
(D) If available information does not support the complaint, the DoD EDQW may reject the complaint.
(E) If the complaint alleges inappropriate laboratory practices or other misconduct, the DoD EDQW chair will consult legal counsel to determine the recommended course of action.
(iv) In all cases, the DoD EDQW will notify the complainant and any other entity involved in the complaint and explain the response of the EDQW to the complaint.
(4)
(5)
Coast Guard, DHS.
Final rule.
The Coast Guard is establishing a series of security zones in the National Capital Region (NCR) on specified waters of the Potomac River and Anacostia River, and adjacent waters during increased security events. This action is necessary to prevent terrorist acts and incidents immediately before, during, and after events held within the NCR, whenever such an event exists, as determined by the Captain of the Port Maryland-National Capital Region. This rule prohibits vessels and persons from entering the security zone and requires vessels and persons in the security zone to depart the security zone, unless specifically exempt under the provisions in this rule or granted specific permission from the Coast Guard Captain of the Port Maryland-National Capital Region. The regulations will enhance the safety and security of persons and property within the Nation's Capital, while minimizing, to the extent possible, the impact on commerce and legitimate waterway use.
This rule is effective December 19, 2016.
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 Mr. Ronald L. Houck, at Sector Maryland-National Capital Region Waterways Management Division, U.S. Coast Guard; telephone 410-576-2674, email
On September 2, 2016, the Coast Guard published a notice of proposed rulemaking (NPRM) titled “Security Zone; Potomac River and Anacostia River, and adjacent waters; Washington, DC” in the
The Coast Guard is issuing this rule under authority in 33 U.S.C. 1231. The COTP determined that it is necessary to establish a series of security zones within the NCR. The purpose of these security zones is to ensure the safety of vessels and the relevant navigable waters before, during, and after the event.
As noted above, we received no comments on our NPRM published on September 2, 2016. There are no changes in the regulatory text of this rule from the proposed rule in the NPRM.
This rule establishes a series of security zones on specified waters of the Potomac River, Anacostia River and adjacent waters. The security zones cover specified navigable waters within the NCR whenever an event that requires increased security is taking place. The duration of the zone is intended to ensure the safety of vessels and these navigable waters before, during, and after the event. No vessel or person would be permitted to enter the security zone without obtaining permission from the COTP or a designated representative. The COTP Maryland-National Capital Region will notify the maritime community, via
Security zone one includes all navigable waters of the Potomac River, from shoreline to shoreline, bounded to the north by the Francis Scott Key (US-29) Bridge, at mile 113, and bounded to the south by a line drawn from the Virginia shoreline at Ronald Reagan Washington National Airport, at 38°51′21.3″ N., 077°02′00.0″ W., eastward across the Potomac River to the District of Columbia shoreline at Hains Point at position 38°51′24.3″ N., 077°01′19.8″ W., including the waters of the Boundary Channel, Pentagon Lagoon, Georgetown Channel Tidal Basin, and Roaches Run. Events that typically require enforcement of the zone include activities associated with the U.S. Presidential Inauguration and State funerals for former Presidents of the U.S.
Security zone two includes all navigable waters of the Anacostia River, from shoreline to shoreline, bounded to the north by the John Philip Sousa (Pennsylvania Avenue) Bridge, at mile 2.9, and bounded to the south by a line drawn from the District of Columbia shoreline at Hains Point at position 38°51′24.3″ N., 077°01′19.8″ W., southward across the Anacostia River to the District of Columbia shoreline at Giesboro Point at position 38°50′52.4″ N., 077°01′10.9″ W., including the waters of the Washington Channel. Events that typically require enforcement of the zone include activities associated with the U.S. Presidential Inauguration and State funerals for former Presidents of the U.S.
Security zone three includes all navigable waters of the Potomac River, from shoreline to shoreline, bounded to the north by a line drawn from the Virginia shoreline at Ronald Reagan Washington National Airport, at 38°51′21.3″ N., 077°02′00.0″ W., eastward across the Potomac River to the District of Columbia shoreline at Hains Point at position 38°51′24.3″ N., 077°01′19.8″ W., thence southward across the Anacostia River to the District of Columbia shoreline at Giesboro Point at position 38°50′52.4″ N., 077°01′10.9″ W., and bounded to the south by the Woodrow Wilson Memorial (I-95/I-495) Bridge, at mile 103.8. Events that typically require enforcement of the zone include activities associated with the U.S. Presidential Inauguration and State funerals for former Presidents of the U.S.
The above zones may also be enforced for unplanned events requiring increased security, including but not limited to presidential nominating conventions; international summits and conferences; and meetings of international organizations.
Security zone four includes all navigable waters of the Georgetown Channel of the Potomac River, 75 yards from the eastern shore measured perpendicularly to the shore, between the Long Railroad Bridge (the most eastern bridge of the 5-span, Fourteenth Street Bridge Complex) to the Theodore Roosevelt Memorial Bridge and all waters in between, totally including the waters of the Georgetown Channel Tidal Basin. This zone is enforced annually from 12:01 a.m. to 11:59 p.m. local time on July 4.
Security zone five includes all navigable waters in the Potomac River, including the Boundary Channel and Pentagon Lagoon, bounded on the west by a line running north to south from points along the shoreline at 38°52′50″ N./077°03′25″ W., thence to 38°52′49″ N./077°03′25″ W.; and bounded on the east by a line running from points at 38°53′10″ N./077°03′30″ W., thence northeast to 38°53′12″ N./077°03′26″ W., thence southeast to 38°52′31″ N./077°02′34″ W., and thence southwest to 38°52′28″ N./077°02′38″ W. This zone will be enforced on three days each year: Memorial Day (observed), September 11, and November 11. Specifically, the zone will be enforced from 10 a.m. until 1 p.m. on Memorial Day (observed); from 8 a.m. until 11:59 a.m. on September 11; and from 10 a.m. until 1 p.m. on November 11.
Security zone six includes all navigable waters of the Potomac River, from shoreline to shoreline, bounded on the north by the Francis Scott Key (U.S. Route 29) Bridge at mile 113.0, downstream to and bounded on the south by the Woodrow Wilson Memorial (I-95/I-495) Bridge, at mile 103.8, including the waters of the Boundary Channel, Pentagon Lagoon, Georgetown Channel Tidal Basin, and Roaches Run; and all waters of the Anacostia River, from shoreline to shoreline, bounded on the north by the John Philip Sousa (Pennsylvania Avenue) Bridge, at mile 2.9, downstream to and bounded on the south by its confluence with the Potomac River. This zone will be enforced annually for the State of the Union Address, starting at 9 a.m. on the day of the State of the Union Address through 2 a.m. the following day.
We developed this rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.
Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility. This rule has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, it has not been reviewed by the Office of Management and Budget.
This regulatory action determination is based on the size, location, duration and time of year of the security zones. The Coast Guard determined that this rulemaking would not be a significant regulatory action for the following reasons: Security zones one, two and three are expected to be enforced for only a week or two at a time and on only a few occasions per year. Additionally, the Coast Guard designed the areas for security zones one, two and three to cover only a portion of the navigable waterways while still sustaining the flow of commerce, and mariners may request permission from the COTP Maryland-National Capital Region or the designated representative to transit the zone. Security zones four and five are expected to be enforced for only less than 24 hours at a time and on only a few occasions per year. Additionally, the Coast Guard designed the areas for security zones four and five to cover only a small portion of the navigable waterways, waterway users may transit the Potomac River around the areas, and mariners may request permission from the COTP Maryland-National Capital Region or the designated representative to transit the zone. Security zone six is expected to be enforced for only less than 24 hours at a time and on only on one occasion per year when vessel traffic is normally low. Additionally, the Coast Guard designed the area for security zone six to cover only a portion of the navigable waterways while still sustaining the flow of commerce, and mariners may request permission from the COTP Maryland-National Capital Region or the
The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard received no comments from the Small Business Administration on this rulemaking. 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 Executive Order 13132, Federalism, if it has a substantial direct effect on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.
Also, this rule does not have tribal implications under Executive Order 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 security zones that would prohibit entry on specified waters of the Potomac River and Anacostia River, and adjacent waters, during increased security events. 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, 195; 33 CFR 1.05-1, 6.04-1, 6.04-6, and 160.5; Department of Homeland Security Delegation No. 0170.1.
(a)
(1)
(2)
(3)
(4)
(5)
(6)
(b)
(1) Entry into or remaining in a zone listed in paragraph (a) in this section is prohibited unless authorized by the Coast Guard Captain of the Port Maryland-National Capital Region. Public vessels and vessels already at berth at the time the security zone is implemented do not have to depart the security zone. All vessels underway within the security zone at the time it is implemented are to depart the zone at the time the security zone is implemented.
(2) Persons desiring to transit the area of the security zone must first obtain authorization from the Captain of the Port Maryland-National Capital Region or his or her designated representative. To seek permission to transit the area, the Captain of the Port Maryland-National Capital Region and his or her designated representatives can be contacted at telephone number 410-576-2693 or on Marine Band Radio, VHF-FM channel 16 (156.8 MHz). The Coast Guard vessels enforcing this section can be contacted on Marine Band Radio, VHF-FM channel 16 (156.8 MHz). Upon being hailed by a U.S. Coast Guard vessel, or other Federal, State, or local agency vessel, by siren, radio, flashing light, or other means, the operator of a vessel shall proceed as directed. If permission is granted, all persons and vessels must comply with the instructions of the Captain of the Port Maryland-National Capital Region or his designated representative and proceed at the minimum speed necessary to maintain a safe course while within the zone.
(3) The U.S. Coast Guard may be assisted in the patrol and enforcement of the security zones listed in paragraph (a) in this section by Federal, State, and local agencies.
(c)
(d)
(2) Security Zone 4, established in paragraph (a)(4) of this section, will be enforced annually, from 12:01 a.m. to 11:59 p.m. on July 4.
(3) Security Zone 5, established in paragraph (a)(5) of this section, will be enforced annually on three dates: Memorial Day (observed), September 11, and November 11. Security Zone 5 will be enforced from 10 a.m. until 1 p.m. on Memorial Day (observed); from 8 a.m. until 11:59 a.m. on September 11; and from 10 a.m. until 1 p.m. on November 11.
(4) Security Zone 6, established in paragraph (a)(6) of this section, will be enforced annually on the day the State of the Union Address is delivered. Security Zone 6 will be enforced from 9 a.m. on the day of the State of the Union Address until 2 a.m. on the following day.
(e)
In rule document 2016-24856 beginning on page 75494 in the issue of Monday, October 31, 2016, make the following correction:
On page 75494, in the first column, the
The regulations in 34 CFR part 612 are effective November 30, 2016.
Environmental Protection Agency (EPA).
Direct final rule.
Nebraska has applied to the Environmental Protection Agency (EPA) for final authorization of revisions to its hazardous waste program under the Resource Conservation and Recovery Act (RCRA). EPA has determined that these revisions satisfy all requirements needed to qualify for final authorization and is authorizing Nebraska's revisions through this direct final rule.
This final authorization will become effective on January 17, 2017, unless EPA receives adverse written comments by December 19, 2016. If EPA receives such comments, we will publish a timely withdrawal of this direct final rule in the
Submit your comments, identified by Docket ID No. EPA-R07-RCRA-2016-0637, to
Lisa Haugen, EPA Region 7, Enforcement Coordination Office, 11201 Renner Boulevard, Lenexa, Kansas 66219, phone number: (913) 551-7877, and email address:
In the “Proposed Rules” section of this
States which have received final authorization from EPA under RCRA section 3006(b), 42 U.S.C. 6926(b), must maintain a hazardous waste program that is equivalent to, consistent with, and no less stringent than the Federal hazardous waste program. As the Federal program is revised, the states must change their programs and ask the EPA to authorize the changes. Changes to state hazardous waste programs may be necessary when Federal or state statutory or regulatory authority is modified or when certain other changes occur. Most commonly, states must change their programs because of changes to EPA's regulations in 40 Code of Federal Regulations (CFR) parts 124, 260 through 268, 270, 273 and 279. States can also initiate their own changes to their hazardous waste program and these changes must then be authorized.
EPA concludes that Nebraska's application to revise its authorized program meets all of the statutory and regulatory requirements established by RCRA. Therefore, EPA is granting Nebraska final authorization to operate its hazardous waste program with the revisions described in the authorization application. Nebraska has responsibility for permitting Treatment, Storage, and Disposal Facilities (TSDFs) within its borders (except in Indian Country) and for carrying out the aspects of the RCRA program described in its revised program application, subject to the limitations of the Hazardous and Solid Waste Amendments of 1984 (HSWA). New Federal requirements and prohibitions imposed by Federal regulations that EPA promulgates under the authority of HSWA take effect in authorized states before they are authorized for the requirements. Thus, EPA will implement those requirements and prohibitions in Nebraska, including issuing permits, until Nebraska is granted authorization to do so.
The effect of this decision is that a facility in Nebraska subject to RCRA will now have to comply with the authorized state requirements instead of the equivalent Federal requirements in order to comply with RCRA. Nebraska has enforcement responsibilities under its state hazardous waste program for violations of such program, but EPA retains its authority under RCRA sections 3007, 3008, 3013, and 7003, which include, among others, authority to: (1) Perform inspections, and require monitoring, tests, analyses, or reports; and (2) Enforce RCRA requirements and suspend or revoke permits. This action does not impose additional requirements on the regulated community because the regulations for which Nebraska is being authorized by this direct final action are already effective and are not changed by this action.
Along with this direct final rule, EPA is publishing a separate document in the “Proposed Rules” section of this
If EPA receives comments that oppose this authorization, we will withdraw this rule by publishing a document in the
If EPA receives comments that oppose only the authorization of a particular revision to the State hazardous waste program, we will withdraw only that part of this action, and the authorization of the program revisions that the comments do not oppose will become effective on the date specified above. The
Nebraska initially received final authorization on January 24, 1985, effective February 7, 1985 (50 FR 3345), to implement the RCRA hazardous waste management program. Nebraska received authorization for revisions to its program on October 4, 1985, effective December 3, 1988 (53 FR 38950); June 25, 1996, effective August 26, 1996 (61 FR 32699); April 10, 2003, effective June 9, 2003 (68 FR 17553); October 4, 2004, effective December 3, 2004 (69 FR 59139); and December 30, 2008, effective September 24, 2010 (75 FR 58328).
On September 21, 2016, Nebraska submitted its final application seeking authorization of hazardous waste program revisions in accordance with 40 CFR 271.21. The State's authorization package includes an updated Program Description, a General Memorandum of Agreement (MOA), a Corrective Action MOA between the EPA and the Nebraska Department of Environmental Quality (NDEQ), a copy of title 128 of the Nebraska Administrative Code, as amended on July 6, 2016, and an Attorney General's Statement. The State has made amendments to the provisions listed in the table which follows. The State's laws and regulations, amended by these provisions, provide authority which remains equivalent to, no less stringent than, and not broader in scope than the Federal laws and regulations. Nebraska's regulatory references are to title 128 or title 129, as noted, of the Nebraska Administrative Code, as amended on July 6, 2016. We are granting Nebraska final authorization to carry out the following provisions of the State's program in lieu of the Federal program.
1. State clarification of Federal rules. These clarifications do not affect the enforcement status of the rule, but simply improves clarity for the regulated community.
(a) Nebraska chose not to publish the note in 40 CFR 268.42 because all the information formerly contained in 40 CFR 268.42/tables 2 and 3 are now contained in title 128, chapter 20, section 009/table 9 and section 010/table 10. By omitting the note, the State eliminated a source of possible confusion.
(b) Nebraska chose not to publish the note in 40 CFR 268.43 because all the information formerly contained in 40 CFR 268.43/table CCW is now contained in title 128, chapter 20, section 009/table 9. By omitting the note, the State eliminated a source of possible confusion.
(c) Nebraska chose not to publish the note in 40 CFR 268.46 because all the information formerly contained in 40 CFR 268.46 is now contained in title 128, chapter 20, section 009/table 9. By omitting the note, the State eliminated a source of possible confusion.
2. More Stringent Nebraska Rules. The Nebraska hazardous waste program contains some provisions that are more stringent than is required by the RCRA program as codified in the July 1, 2015, edition of the title 40 of the Code of Federal Regulations. These more stringent provisions are being recognized as a part of the Federally-authorized program.
The specific more stringent provisions are also noted in Nebraska's authorization application. They include, but are not limited to, the following:
(a) 40 CFR 268.7(a)(1) and (a)(2) include parenthetical provisions, beginning with “Alternatively,” which allow a generator of hazardous waste to send the waste to a RCRA-permitted hazardous waste treatment facility
(b) At 20-005.01B1, Nebraska requires specific language for a contaminated soil certification statement. The Federal rules do not specify required language, therefore the State is more stringent.
(c) In title 128, chapter 20, the table—Treatment Standards for Hazardous Waste—Nebraska includes the chemical 1,3-Phenylenediamine under the F039 listing. This chemical is not included in the table located at 40 CFR 268.40. Therefore the State is more stringent.
(d) At 21-006, Nebraska adopts and incorporates by reference 40 CFR part 264, subpart F, pertaining to releases from solid waste management units. Nebraska adds a provision at 21-006.01, which requires groundwater monitoring wells to be designed according to ASTM Standard D5092-90. In addition, any groundwater monitoring well to be placed in a stratigraphic unit composed of loessal sediment must be designed and sampled in a manner approved by NDEQ intended to minimize turbidity in samples taken from the well. The Federal regulations do not have these specific requirements, therefore Nebraska is more stringent.
(e) At 40 CFR 270.60(b)(3), the Federal rules the owner/operator of an injection well disposing of hazardous waste is considered to have RCRA permit if they have a UIC permit issued after November 8, 1984 and meet the conditions listed at 270.60(b)(3)(i) and (ii). Hazardous waste injection wells are expressly prohibited under title 122, Nebraska Administrative Code, Rules and Regulations for Underground Injection and Mineral Production Wells, chapter 3, section 003. Through this prohibition, the State rule is more stringent than the Federal rule.
(f) At 22-006, Nebraska adopts and incorporates by reference 40 CFR part 265, subpart F, pertaining to groundwater monitoring. Nebraska adds a provision at 22-006.01, which requires groundwater monitoring wells to be designed according to ASTM Standard D5092-90. In addition, any groundwater monitoring well to be placed in a stratigraphic unit composed of loessal sediment must be designed and sampled in a manner approved by NDEQ intended to minimize turbidity in samples taken from the well. The Federal regulations do not have these specific requirements, therefore Nebraska is more stringent.
(g) At 22-006, Nebraska adopts and incorporates by reference 40 CFR part 265, subpart F, pertaining to groundwater monitoring. At 22-006.03, Nebraska adds a provision which requires sampling during the initial four consecutive quarters for all analytes listed in 40 CFR 265.92(b), as incorporated by reference at 22-006. This requirement is more stringent than the Federal rules.
The 40 CFR 265.92(b)(1)-(3) outlines criteria required, Nebraska adds a provision at 22-006.03, which requires groundwater monitoring wells to be designed according to ASTM Standard D5092-90. In addition, any groundwater monitoring well to be placed in a stratigraphic unit composed of loessal sediment must be designed and sampled in a manner approved by NDEQ intended to minimize turbidity in samples taken from the well. The Federal regulations do not have these specific requirements, therefore Nebraska is more stringent.
(h) At 22-006, Nebraska adopts and incorporates by reference 40 CFR part 265, subpart F, pertaining to groundwater monitoring. At 40 CFR 265.93(d)(7)(ii), the Federal regulations state that determinations may cease if the groundwater quality assessment plan was implemented during the post-closure care period. At 22-006.04, the State regulations allow these determinations to cease only if the facility is operating under an approved Post Closure Plan. Therefore the State regulations are more stringent than the Federal rules.
(i) At 22-006, Nebraska adopts and incorporates by reference 40 CFR part 265, subpart F, pertaining to groundwater monitoring. Under 265.93(f), the owner or operator must report the results of analyses annually. At 22-006.05, Nebraska requires the analyses to be submitted within 45 days following the end of the quarter in which the sample was taken. Therefore, the State is more stringent.
(j) The Federal regulations at 273.32(b)(4) require a large quantity
(k) At 261.2(c)(3), and in column 3 of 261.2(c)(4) table 1, the Federal regulations list the exclusion cited at 261.4(a)(17). Nebraska did not adopt this exclusion. Therefore, the state is more stringent than the Federal regulations.
3. Broader in scope. EPA considers the following state requirements to be beyond the scope of the Federal program, and therefore EPA is not authorizing these requirements and cannot enforce them. Entities must comply with these requirements in accordance with state law, but they are not RCRA requirements. The specific broader in scope provisions include, but are not limited to, the following:
(a) At 22-006, Nebraska adopts and incorporates by reference 40 CFR part 265, subpart F, pertaining to groundwater monitoring. At 40 CFR 265.92(b), the owner or operator must determine the concentration or value of the listed parameters in ground-water samples. At 22-006.02, Nebraska includes sampling for volatile organic compounds (VOCs) at the discretion of the Director on a case-by-case basis. The VOCs shall be analyzed in accordance with a method approved by the Director. This requirement is broader in scope than the Federal rules.
(b) Title 128 chapter 25 contains Nebraska's “Standards for Universal Waste Management.” The state adds an additional waste stream “electronic items” to the list of types of universal waste subject to these regulations. 40 CFR part 273, the Federal “Standards for Universal Waste Management” do not include “electronic items” as an identified waste stream. Therefore, any references or requirements for managing the “electronic items” waste stream universal waste are broader in scope and not enforceable by EPA.
Nebraska will issue permits for all the provisions for which it is authorized and will administer the permits it issues. EPA will continue to administer and enforce any RCRA hazardous waste permits or portions of permits which EPA issued prior to the effective date of this authorization until they expire or are terminated. EPA will not issue any more permits, or new portions of permits, for the provisions listed in the table above after the effective date of this authorization. EPA will continue to implement and issue permits for HSWA requirements for which Nebraska is not yet authorized.
Nebraska is not authorized to carry out its Hazardous Waste Program in Indian Country within the State. This authority remains with EPA. Therefore, this action has no effect in Indian Country.
Codification is the process of placing the State's statutes and regulations that comprise the State's authorized hazardous waste program into the Code of Federal Regulations. We do this by referencing the authorized State rules in 40 CFR part 272. EPA is not codifying the authorization of Nebraska's changes at this time. However, we reserve the amendment of 40 CFR part 272, subpart CC for the authorization of Nebraska's program changes at a later date.
The Office of Management and Budget (OMB) has exempted this action from the requirements of Executive Order 12866 (58 FR 51735, October 4, 1993), and therefore, this action is not subject to review by OMB. This action authorizes State requirements for the purpose of RCRA 3006 and imposes no additional requirements beyond those imposed by State law. Accordingly, I certify that this action will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
Under RCRA 3006(b), EPA grants a state's application for incorporation by reference as long as the State meets the criteria required by RCRA. It would thus be inconsistent with applicable law for the EPA, when it reviews a state authorization application, to require the use of any particular voluntary consensus standard in place of another standard that otherwise satisfies the requirements of RCRA. Thus, the requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) do not apply. As required by section 3 of Executive Order 12988 (61 FR 4729, February 7, 1996), in issuing this rule, EPA has taken the necessary steps to eliminate drafting errors and ambiguity, minimize potential litigation, and provide a clear legal standard affected conduct. EPA has complied with Executive Order 12630 (53 FR 8859, March 15, 1988) by examining the takings implications of the rule in accordance with the “Attorney General's Supplemental Guidelines for the Evaluation of Risk and Avoidance of Unanticipated Takings” issued under the executive order. This rule does not impose an information collection burden under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501
The Congressional Review Act, 5 U.S.C. 801
Environmental protection, Administrative practice and procedure, Confidential business information, Hazardous waste, Hazardous waste transportation, Indian lands, Intergovernmental relations, Penalties, Reporting and recordkeeping requirements.
This action is issued under the authority of Sections 2002(a), 3006, and 7004(b) of the Solid Waste Disposal Act, as amended, 42 U.S.C. 6912(a), 6926, 6974(b).
Food and Nutrition Service (FNS), USDA.
Proposed rule.
The proposed action would update civil rights assurance language contained in Supplemental Nutrition Assistance Program (SNAP) regulations on the Federal-State Agreement (FSA). The rule does not contain any new requirements and would codify protections already required by Federal law and existing policy.
Written comments must be received on or before January 17, 2017 to be assured of consideration.
The Food and Nutrition Service, USDA, invites interested persons to submit written comments on this proposed rule. Comments may be submitted in writing by one of the following methods:
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Sasha Gersten-Paal, Branch Chief, Certification Policy Branch, Program Development Division, Food and Nutrition Service, 3101 Park Center Drive, Alexandria, Virginia 22302, 703-305-2507.
The Food and Nutrition Act of 2008, as amended (the Act), requires that each State operating SNAP have a State Plan of Operation (State Plan) specifying details as to how the State conducts the program. The State Plan contains forms, plans, agreements and policy descriptions required by Federal regulation and is cleared under OMB No. 0584-0083, Expiration date 4/30/2017. Current SNAP regulations at 7 CFR 272.2(a)(2) include the FSA as one such required component of the State Plan. The FSA is the legal agreement between the Department of Agriculture (Department) and the State agency through which the State elects to operate SNAP and to administer the program in accordance with the Act, SNAP regulations and the State Plan. Although both the Department and the State agency may mutually agree to modify or supplement the language, the regulations at 7 CFR 272.2(b)(1) contain standard FSA language for State agencies operating SNAP.
As a Federal program, civil rights protections for SNAP applicants and recipients are important and essential. The standard FSA language contained in the regulations at 7 CFR 272.2(b)(1) already requires State agencies administering SNAP to agree to assure compliance with civil rights requirements, including Title VI of the Civil Rights Act of 1964, section 11(c) of the Food Stamp Act of 1977 (now the Food and Nutrition Act of 2008, as amended), and the Department's regulatory nondiscrimination requirements.
Since the publication of the final rule establishing the standard FSA language, additional civil rights legislation has been passed and more uniform administrative procedures have been established to support effective enforcement of the civil rights protections. Further, the U.S. Department of Justice (DOJ) recommended the addition of updated references in the Department's civil rights-related materials. The Department understands that similar language has been incorporated into agreements in other Federal agencies, and has incorporated very similar language in agreements in the Department's Child Nutrition Program and Women, Infants and Children programs. We note, by way of background, that the FSA in SNAP is unique within the Department's programs in that most other comparable agreements are not contained in the Federal regulations but in forms formally approved by the Office of Management and Budget (OMB).
This proposed rule would incorporate references to additional civil rights legislation into the standard FSA language at section 272.2. Those references include Title IX of the Education Amendments of 1972 (20 U.S.C. 1681
FSAs, once signed by a State's Governor or authorized designee, are valid indefinitely under 7 CFR 272.2(e)(1) until they are terminated. Section 272.2(e)(1) also provides that the FSA must be signed and submitted to FNS within 120 days after the publication of the regulations in final form and shall remain in effect until terminated. Although initially included in the regulations with other regulatory FSA requirements, the same procedure would apply to this update. That is, upon publication of this proposed rule as final, all State agencies administering SNAP would be required to sign a new FSA with the updated language and provide a copy of the same to the Department within 120 days after publication of the regulations in final form. Although State agencies are already required to abide by the new
The rule also proposes additional items be added to the FSA standard language. The other items allow for the Department to track, analyze and enforce the civil rights protections in the FSA. First, this proposed rule would add that the State agency's agreement to follow civil rights requirements in the FSA is made in consideration of and for the purposes of obtaining Federal financial assistance. Second, the rule would incorporate into the FSA the State agency's obligation to compile data, maintain records, and submit records and reports as required to allow for effective enforcement of the civil rights provisions. This would include an assurance to allow Department personnel to review and access records, access facilities and interview personnel to ascertain compliance with nondiscrimination laws. The rule would also codify procedures to support enforcement of the nondiscrimination protections by updating the FSA to include a provision that the Department may seek judicial enforcement for violations of the FSA, and add assurances that the State agency and its successors are bound by the FSA. Again, these provisions would not only be responsive to DOJ's suggestions regarding nondiscrimination compliance language but also mirror language in other USDA programs.
Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts, and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, of reducing costs, of harmonizing rules, and of promoting flexibility.
This proposed rule has been determined to be not significant and was not reviewed by the OMB in conformance with Executive Order 12866.
This rule has been designated as not significant by the Office of Management and Budget, therefore, no Regulatory Impact Analysis is required.
The Regulatory Flexibility Act (5 U.S.C. 601-612) requires Agencies to analyze the impact of rulemaking on small entities and consider alternatives that would minimize any significant impacts on a substantial number of small entities. Pursuant to that review, it has been certified that this rule would not have a significant impact on a substantial number of small entities.
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local and Tribal governments and the private sector. Under section 202 of the UMRA, the Department generally must prepare a written statement, including a cost benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures by State, local or Tribal governments, in the aggregate, or the private sector, of $146 million or more (when adjusted for inflation; GDP deflator source: Table 1.1.9 at
This proposed rule does not contain Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local and Tribal governments or the private sector of $146 million or more in any one year. Thus, the rule is not subject to the requirements of sections 202 and 205 of the UMRA.
State administrative matching grants for SNAP are listed in the Catalog of Federal Domestic Assistance Programs under 10.561. For the reasons set forth in the final rule in 7 CFR part 3015, subpart V, and related Notice (48 FR 29114, June 24, 1983), this program is included in the scope of Executive Order 12372, which requires intergovernmental consultation with State and local officials. The Department issued guidance in June 2016 to State agencies as part of a larger effort to help States ensure their State Plans are complete and up to date, which in part included direction to State agencies to incorporate updated civil rights provisions as an addendum to existing FSAs. The Department's Food and Nutrition Service SNAP Regional Offices individually discussed these issues directly with State agencies during policy calls and meetings.
Executive Order 13132 requires Federal agencies to consider the impact of their regulatory actions on State and local governments. Where such actions have federalism implications, agencies are directed to provide a statement for inclusion in the preamble to the regulations describing the agency's considerations in terms of the three categories called for under Section (6)(b)(2)(B) of Executive Order 13121. The Department has considered the impact of this rule on State and local governments and has determined that this rule does not have significant federalism implications. State agencies will be required to update the standard language contained in FSAs once. This agreement will then be binding until otherwise terminated. Therefore, under section 6(b) of the Executive Order, a federalism summary is not required.
This proposed rule has been reviewed under Executive Order 12988, Civil Justice Reform. This rule is intended to have preemptive effect with respect to any State or local laws, regulations or policies that conflict with its provisions or that would otherwise impede its full and timely implementation. This rule is not intended to have retroactive effect unless so specified in the
The changes to SNAP regulations in this proposed rule are to incorporate references to additional civil rights legislation into the standard FSA language.
FNS also maintains a public Web site that provides basic information on each program, including SNAP. Interested persons, including potential applicants, applicants, and participants can find information about their right to be treated fairly and the protections they are guaranteed. The Web site also includes information on how to report when an individual feels his or her rights were violated and not treated in accordance with this provision.
Executive Order 13175 requires Federal agencies to consult and coordinate with Tribes on a government-to-government basis on policies that have Tribal implications, including regulations, legislative comments or proposed legislation, and other policy statements or actions that have substantial direct effects on one or more Indian Tribes, on the relationship between the Federal Government and Indian Tribes, or on the distribution of power and responsibilities between the Federal Government and Indian Tribes. The Department notes that the regulatory changes proposed in this rule impact program applicants and participants equally regardless of tribal status or residence. We are unaware of any current Tribal laws that could be in conflict with the final rule.
To share information on the proposed rule with Indian Tribes, FNS discussed the proposed rule at a tribal consultation meeting on August 17, 2016.
The Paperwork Reduction Act of 1995 (44 U.S.C. Chap. 35; 5 CFR 1320) requires OMB to approve all collections of information by a Federal agency before they can be implemented. Respondents are not required to respond to any collection of information unless it displays a current valid OMB control number.
The provisions in this proposed rule do not contain new information collection requirements subject to approval by OMB under the Paperwork Reduction Act of 1994. The Department anticipates that this rule would have no to minimal time and cost impacts on the Federal government and State agencies. State agencies are already required to follow the requirements contained in the added nondiscrimination references. Any time and cost burden would be related to administrative obligations to sign an updated Federal-State Agreement and ensure appropriate recordkeeping to support enforcement of the nondiscrimination provisions as cleared under OMB Number 0584-0083. FNS provides 50 percent of SNAP's administrative cost reimbursement and so a portion of any minimal administrative costs would be offset by federal funding.
Since State agencies are already required to have these agreements, the impact of this provision is negligible. Other minimal burdens imposed on State agencies by this proposed rule are usual and customary within the course of their normal business activities.
The Department is committed to complying with the E-Government Act of 2002, to promote the use of the Internet and other information technologies to provide increased opportunities for citizen access to Government information and services, and for other purposes.
Alaska, Civil rights, Supplemental Nutrition Assistance Program, Grant programs—social programs, Penalties, Reporting and recordkeeping requirements.
For the reasons set forth in the preamble, 7 CFR part 272 is proposed to be amended as follows:
7 U.S.C. 2011-2036.
(b) * * *
(1) The wording of the Federal/State Agreement is as follows:
The State of __ and the Food and Nutrition Service (FNS), U.S. Department of Agriculture (USDA), hereby agree to act in accordance with the provisions of the Food and Nutrition Act of 2008, as amended, implementing regulations, instructions, policy guidance, and other written directions interpreting Federal law and regulations applicable to this program, and the FNS-approved State Plan of Operation. The State and FNS USDA further agree to fully comply with any changes in Federal law and regulations. This agreement may be modified with the mutual written consent of both parties.
The State agrees to:
1. Administer the program in accordance with the provisions contained in the Food and Nutrition Act of 2008, as amended, and in the manner prescribed by regulations issued pursuant to the Act; and to implement the FNS-approved State Plan of Operation.
2. Assurance of Civil Rights Compliance: Comply with Title VI of the Civil Rights Act of 1964 (42 U.S.C. 2000d
This assurance is given in consideration of and for the purpose of obtaining any and all Federal assistance extended to the State by USDA under the authority of the Food and Nutrition Act of 2008, as amended. Federal financial assistance includes grants, and loans of Federal funds; reimbursable expenditures, grants, or donations of Federal property and interest in property; the detail of Federal personnel; the sale, lease of, or permission to use Federal property or interest in such property; the furnishing of services without consideration, or at a nominal consideration, or at a consideration that is reduced for the purpose of assisting the recipient or in recognition of the public interest to be served by such sale, lease, or furnishing of services to the recipient; or any improvements made with Federal financial assistance extended to the State by USDA. This assistance also includes any Federal agreement, arrangement, or other contract that has as one of its purposes the provision of cash assistance for the purchase of food, cash assistance for purchase or rental of food service equipment or any other financial assistance extended in reliance on the representations and agreements made in this assurance.
By accepting this assurance, the State agency agrees to compile data, maintain records, and submit records and reports as required, to permit effective enforcement of nondiscrimination laws and permit authorized USDA personnel during hours of program operation to review and copy such records, books, and accounts, access such facilities and interview such personnel as needed to ascertain compliance with the nondiscrimination laws. If there are any violations of this assurance, USDA, FNS, shall have the right to seek judicial enforcement of this assurance. This assurance is binding on the State agency, its successors, transferees and assignees as long as it receives assistance or retains possession of any assistance from USDA. The person or persons whose signatures appear below are authorized to sign this assurance on behalf of the State agency.
3. (For States with Indian Reservations only). Implement the Program in a manner that is responsive to the special needs of American Indians on reservations and consult in good faith with tribal organizations about that portion of the State's Plan of Operation pertaining to the implementation of the Program for members of the tribe on reservations.
4. FNS agrees to: 1. Pay administrative costs in accordance with the Food and Nutrition Act of 2008, implementing regulations, and an approved Cost Allocation Plan.
2. Carry out any other responsibilities delegated by the Secretary in the Food and Nutrition Act of 2008, as amended.
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new Airworthiness Directive (AD) for all Fokker Services B.V. Model F28 Mark 0100 series airplanes. This proposed AD was prompted by an evaluation by the design approval holder (DAH) indicating that certain wing fuel tank access panels are subject to widespread fatigue damage (WFD). This proposed AD would require replacement of affected access panels and modification of the coamings of the associated access holes. We are proposing this AD to prevent the unsafe condition on these products.
We must receive comments on this proposed AD by January 3, 2017.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
•
•
•
•
For service information identified in this NPRM, contact Fokker Services B.V., Technical Services Dept., P.O. Box 1357, 2130 EL Hoofddorp, the Netherlands; telephone: +31 (0)88-6280-350; fax: +31 (0)88-6280-111; email:
You may examine the AD docket on the Internet at
Tom Rodriguez, Aerospace Engineer, International Branch, ANM-116, Transport Airplane Directorate, FAA, 1601 Lind Avenue SW., Renton, WA 98057-3356; telephone: 425-227-1137; 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
Fatigue damage can occur locally, in small areas or structural design details,
The FAA's WFD final rule (75 FR 69746, November 15, 2010) became effective on January 14, 2011. The WFD rule requires certain actions to prevent structural failure due to WFD throughout the operational life of certain existing transport category airplanes and all of these airplanes that will be certificated in the future. For existing and future airplanes subject to the WFD rule, the rule requires that DAHs establish a limit of validity (LOV) of the engineering data that support the structural maintenance program. Operators affected by the WFD rule may not fly an airplane beyond its LOV, unless an extended LOV is approved.
The WFD rule (75 FR 69746, November 15, 2010) does not require identifying and developing maintenance actions if the DAHs can show that such actions are not necessary to prevent WFD before the airplane reaches the LOV. Many LOVs, however, do depend on accomplishment of future maintenance actions. As stated in the WFD rule, any maintenance actions necessary to reach the LOV will be mandated by airworthiness directives through separate rulemaking actions.
In the context of WFD, this action is necessary to enable DAHs to propose LOVs that allow operators the longest operational lives for their airplanes, and still ensure that WFD will not occur. This approach allows for an implementation strategy that provides flexibility to DAHs in determining the timing of service information development (with FAA approval), while providing operators with certainty regarding the LOV applicable to their airplanes.
The European Aviation Safety Agency (EASA), which is the Technical Agent for the Member States of the European Union, has issued EASA AD 2016-0125, dated June 21, 2016, which supersedes EASA AD 2014-0158, dated July 7, 2014 (referred to after this as the Mandatory Continuing Airworthiness Information, or “the MCAI”), to correct an unsafe condition for all Fokker Services B.V. Model F28 Mark 0100 series airplanes. The MCAI states:
Based on findings on test articles, fatigue-induced cracks may develop in the coamings of certain wing fuel tank access panels Part Number (P/N) D12395-403 and P/N D12450-403, installed on Fokker F28 Mark 0100 aeroplanes.
To ensure the continued structural integrity with respect to fatigue, repetitive inspections were included in the Airworthiness Limitations Section (ALS) of the Instructions for Continued Airworthiness. Fokker Services also developed precautionary measures to reduce stress loads in the affected areas by replacement of the affected access panels with new panels, P/N D19701-401 and P/N D19701-403, having thinner skin, and a modification by introducing internal patches to the coamings of the affected access holes.
These precautionary measures were introduced with Service Bulletins (SB) SBF100-57-027 and SBF100-57-028. As part of the Widespread Fatigue Damage re-evaluation, it was concluded that repetitive inspections through the ALS do not provide a sufficient level of protection against the fatigue-induced cracks.
This condition, if not corrected, would affect the structural integrity of the lower wing skins of both outer wings in the areas surrounding the affected fuel tank access panels.
For the reasons described above, this [EASA] AD requires replacement of the affected access panels and modification of the coamings of these access holes.
Post-modification inspection requirements depend on the actual number of flight cycles accumulated at the moment of modification. Related detailed information is provided in SBF100-57-027 and SBF100-57-028, as well as in Fokker Services ALS Report SE-623 Issue 12.
Fokker Services All Operators Message AOF100.178#05 provides additional information concerning the subject addressed by this [EASA] AD.
You may examine the MCAI in the AD docket on the Internet at
Fokker Services B.V. has issued the following service information:
• Fokker Service Bulletin SBF 100-57-027, Revision 2, dated December 11, 2013. This service information provides instructions to replace certain fuel tank access panels.
• Fokker Service Bulletin SBF 100-57-028, Revision 2, dated December, 11, 2013. This service information provides instructions to modify the coamings of certain fuel tank access holes.
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
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.
In the “Required Action(s) and Compliance Times” section of the MCAI, paragraphs (3) and (4) specify to incorporate or comply with certain maintenance tasks (repetitive inspections). These actions are not included in this proposed AD. Since EASA AD 2014-0158, dated July 7, 2014, was issued, EASA issued AD 2016-0125, dated June 21, 2016, which includes a requirement to incorporate those maintenance tasks. We are considering further rulemaking to require the actions specified in EASA AD 2016-0125, dated June 21, 2016.
We estimate that this proposed AD affects 15 airplanes of U.S. registry.
We estimate the following costs to comply with this proposed AD:
Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. “Subtitle VII: Aviation Programs,” describes in more detail the scope of the Agency's authority.
We are issuing this rulemaking under the authority described in “Subtitle VII, Part A, Subpart III, Section 44701: General requirements.” Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.
We 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 January 3, 2017.
None.
This AD applies to Fokker Services B.V. Model F28 Mark 0100 series airplanes, certificated in any category, all serial numbers.
Air Transport Association (ATA) of America Code 57, Wings.
This AD was prompted by an evaluation by the design approval holder (DAH) indicating that certain wing fuel tank access panels are subject to widespread fatigue damage (WFD). We are issuing this AD to prevent fatigue cracking in the wing structure, which could result in reduced structural integrity of the airplane.
Comply with this AD within the compliance times specified, unless already done.
Within 63,000 flight cycles since first flight of the airplane, or within 90 days after the effective date of this AD, whichever occurs later, accomplish the actions specified in paragraphs (g)(1) and (g)(2) of this AD, as applicable.
(1) For airplanes identified in Fokker Service Bulletin SBF100-57-028, Revision 2, dated December 11, 2013: Modify the coamings of the fuel tank access holes at the access panel locations identified in, and in accordance with the Accomplishment Instructions of Fokker Service Bulletin SBF100-57-028, Revision 2, dated December 11, 2013.
(2) For airplanes identified in Fokker Service Bulletin SBF100-57-027, Revision 2, dated December 11, 2013: Replace access panels having part number D12395-403 and D12450-403 with new panels having part number D19701-401 and D19701-403, at the access panel locations identified in, and in accordance with the Accomplishment Instructions of Fokker Service Bulletin SBF100-57-027, Revision 2, dated December 11, 2013.
(1) For airplanes that, on the effective date of this AD, have an access panel with part number D12395-403 or D12450-403 installed at any of the affected locations: After accomplishing the actions required by paragraphs (g)(1) and (g)(2) of this AD, as applicable, no person may install, on any airplane, access panels having part number D12395-403 or D12450-403 at any access panel location as identified in Fokker Service Bulletin SBF100-57-027, Revision 2, dated December 11, 2013.
(2) For airplanes that, on the effective date of this AD, do not have an access panel with part number D12395-403 or D12450-403 installed at any of the affected locations: As of the effective date of this AD, no person may install, on any airplane, access panels having part number D12395-403 or D12450-403 at any access panel location as identified in Fokker Service Bulletin SBF100-57-027, Revision 2, dated December 11, 2013.
(1) 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 the service information specified in paragraph (i)(1)(i) or (i)(1)(ii) of this AD.
(i) Fokker Service Bulletin SBF100-57-028, dated May 2, 1994.
(ii) Fokker Service Bulletin SBF100-57-028, Revision 1, dated November 1, 1994.
(2) This paragraph provides credit for actions required by paragraph (g)(2) of this AD, if those actions were performed before the effective date of this AD using the service information specified in paragraph (i)(2)(i) or (i)(2)(ii) of this AD.
(i) Fokker Service Bulletin SBF100-57-027, dated September 13, 1993.
(ii) Fokker Service Bulletin SBF100-57-027, Revision 1, dated May 2, 1994.
The following provisions also apply to this AD:
(1)
(2)
(1) Refer to Mandatory Continuing Airworthiness Information (MCAI) EASA AD 2014-0158, dated July 7, 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 Fokker Services B.V., Technical Services Dept., P.O. Box 1357, 2130 EL Hoofddorp, the Netherlands; telephone: +31 (0)88-6280-350; fax: +31 (0)88-6280-111; email:
Federal Aviation Administration (FAA), DOT.
Notice of proposed rulemaking (NPRM).
We propose to adopt a new airworthiness directive (AD) for certain The Boeing Company Model 777-300ER series airplanes. This proposed AD was prompted by a report that certain galley tripod mount assemblies were not connected to the tie rods in the overhead support structure. This proposed AD would require an inspection of certain galleys for the presence of the hardware that connects the tripod mount assembly to the tie rods in the overhead support structure, and corrective actions if necessary. We are proposing this AD to address the unsafe condition on these products.
We must receive comments on this proposed AD by January 3, 2017.
You may send comments, using the procedures found in 14 CFR 11.43 and 11.45, by any of the following methods:
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For service information identified in this NPRM, contact Boeing Commercial Airplanes, Attention: Contractual & Data Services (C&DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740; telephone 562-797-1717; Internet
You may examine the AD docket on the Internet at
Eric Brown, Aerospace Engineer, Cabin Safety and Environmental Systems Branch, ANM-150S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6476; fax: 425-917-6590; email:
We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the
We will post all comments we receive, without change, to
We have received a report that the T53 and T52 tie rods to the tripod mount assembly in the A2 and A3 galleys were found unattached during a routine production inspection of certain airplanes before delivery. The cause was determined to be a change to the galley installation sequence. This changed installation sequence did not include a robust method to make sure that the tie rods were attached to the galley before delivery. Since this unsafe condition was found, Boeing has implemented a new improved process to ensure that the hardware that attaches the T53 and T52 tie rods to the tripod mount assembly in the A2 and A3 galleys is attached. A galley tripod mount assembly that is unconnected to the tie rods in the overhead support structure can cause a galley to come loose under a high dynamic load causing a risk of serious injury to passengers and the blocking of evacuation routes.
We reviewed Boeing Alert Service Bulletin 777-25A0677, dated April 25,
We are proposing this AD because we evaluated all the relevant information and determined the unsafe condition described previously is likely to exist or develop in other products of the same type design.
This proposed AD would require accomplishing the actions specified in the service information described previously, except as discussed under “Differences Between this Proposed AD and the Service Information.” For information on the procedures and compliance times, see this service information at
The phrase “corrective actions” is used in this proposed AD. Corrective actions correct or address any condition found. Corrective actions in an AD could include, for example, repairs.
This proposed AD requires a detailed inspection for specific hardware instead of the general visual inspection specified in Boeing Alert Service Bulletin 777-25A0677, dated April 25, 2016.
We estimate that this proposed AD affects 4 airplanes of U.S. registry. We estimate the following costs to comply with this proposed AD:
We have received no definitive data that would enable us to provide cost estimates for the on-condition actions specified in this proposed AD.
According to the manufacturer, some of the costs of this proposed AD may be covered under warranty, thereby reducing the cost impact on affected individuals. We do not control warranty coverage for affected individuals. As a result, we have included all available costs in our cost estimate.
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 January 3, 2017.
None.
This AD applies to The Boeing Company Model 777-300ER series airplanes, certificated in any category, as identified in Boeing Alert Service Bulletin 777-25A0677, dated April 25, 2016.
Air Transport Association (ATA) of America Code 25, Equipment/furnishings.
This AD was prompted by a report that certain galley tripod mount assemblies were not attached to the tie rods in the overhead support structure. We are issuing this AD to detect and correct an unconnected galley tripod mount assembly to the tie rods in the overhead support structure, which can cause a galley to come loose under a high dynamic load causing a risk of serious injury to passengers and the blocking of evacuation routes.
Comply with this AD within the compliance times specified, unless already done.
Within 12 months after the effective date of this AD: Do a detailed inspection of the area above the A2 and A3 galleys to make sure the hardware (
For the purposes of this AD, a detailed inspection is an intensive examination of a specific item, installation, or assembly to detect damage, failure, or irregularity. Available lighting is normally supplemented with a direct source of good lighting at an intensity deemed appropriate. Inspection aids such as mirror, magnifying lenses, etc., may be necessary. Surface cleaning and elaborate procedures may be required.
(1) The Manager, Seattle Aircraft Certification Office (ACO), FAA, has the authority to approve AMOCs for this AD, if requested using the procedures found in 14 CFR 39.19. In accordance with 14 CFR 39.19, send your request to your principal inspector or local Flight Standards District Office, as appropriate. If sending information directly to the manager of the ACO, send it to the attention of the person identified in paragraph (j)(1) of this AD. Information may be emailed to:
(2) Before using any approved AMOC, notify your appropriate principal inspector, or lacking a principal inspector, the manager of the local flight standards district office/certificate holding district office.
(3) An AMOC that provides an acceptable level of safety may be used for any repair, modification, or alteration required by this AD if it is approved by the Boeing Commercial Airplanes Organization Designation Authorization (ODA) that has been authorized by the Manager, Seattle ACO, to make those findings. To be approved, the repair method, modification deviation, or alteration deviation must meet the certification basis of the airplane, and the approval must specifically refer to this AD.
(4) For service information that contains steps that are labeled as Required for Compliance (RC), the provisions of paragraphs (i)(4)(i) and (i)(4)(ii) of this AD apply.
(i) The steps labeled as RC, including substeps under an RC step and any figures identified in an RC step, must be done to comply with the AD. If a step or substep is labeled “RC Exempt,” then the RC requirement is removed from that step or substep. An AMOC is required for any deviations to RC steps, including substeps and identified figures.
(ii) Steps not labeled as RC may be deviated from using accepted methods in accordance with the operator's maintenance or inspection program without obtaining approval of an AMOC, provided the RC steps, including substeps and identified figures, can still be done as specified, and the airplane can be put back in an airworthy condition.
(1) For more information about this AD, contact Eric Brown, Aerospace Engineer, Cabin Safety and Environmental Systems Branch, ANM-150S, FAA, Seattle Aircraft Certification Office (ACO), 1601 Lind Avenue SW., Renton, WA 98057-3356; phone: 425-917-6476; fax: 425-917-6590; email:
(2) For service information identified in this AD, contact Boeing Commercial Airplanes, Attention: Contractual & Data Services (C&DS), 2600 Westminster Blvd., MC 110-SK57, Seal Beach, CA 90740; telephone 562-797-1717; Internet
Alcohol and Tobacco Tax and Trade Bureau, Treasury.
Notice of proposed rulemaking.
The Alcohol and Tobacco Tax and Trade Bureau (TTB) proposes to amend its wine labeling regulations by adding a number of new names to the list of grape variety names approved for use in designating American wines. TTB also proposes to remove one existing entry and replace it with a slightly different name, and to correct the spelling of another existing entry. The proposed amendments would allow wine bottlers to use these additional approved grape variety names on wine labels and in wine advertisements.
TTB must receive written comments on or before January 17, 2017.
Please send your comments on this proposed rule to one of the following addresses:
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See the Public Participation section of this notice for specific instructions and requirements for submitting comments, and for information on how to request a public hearing.
You may view copies of this proposed rule and any comments TTB receives about this proposal at
Jennifer Berry, Alcohol and Tobacco Tax and Trade Bureau, Regulations and Rulings Division; telephone 202-453-1039, ext. 275.
Section 105(e) of the Federal Alcohol Administration Act (FAA Act), 27 U.S.C. 205(e), authorizes the Secretary of the Treasury to prescribe regulations for the labeling of wine, distilled spirits, and malt beverages. The FAA Act requires that these regulations, among other things, prohibit consumer deception and the use of misleading statements on labels, and ensure that labels provide the consumer with adequate information as to the identity and quality of the product.
The Alcohol and Tobacco Tax and Trade Bureau (TTB) administers the regulations promulgated under the FAA Act pursuant to section 1111(d) of the Homeland Security Act of 2002, codified at 6 U.S.C. 531(d). The Secretary has delegated various authorities through Treasury Department Order 120-01 (dated
Part 4 of the TTB regulations (27 CFR part 4) sets forth the standards promulgated under the FAA Act for the labeling and advertising of wine. Section 4.23 of the TTB regulations (27 CFR 4.23) sets forth rules for varietal (grape type) labeling. Paragraph (a) of that section sets forth the general rule that the names of one or more grape varieties may be used as the type designation of a grape wine only if the wine is labeled with an appellation of origin as defined in § 4.25. Under paragraphs (b) and (c), a wine bottler may use the name of a single grape variety on a label as the type designation of a wine if not less than 75 percent of the wine (or 51 percent in certain limited circumstances) is derived from grapes of that variety grown in the labeled appellation of origin area. Under paragraph (d), a bottler may use two or more grape variety names as the type designation of a wine if all the grapes used to make the wine are of the labeled varieties and if the percentage of the wine derived from each grape variety is shown on the label (and with additional rules in the case of multicounty and multistate appellations of origin). Paragraph (e) of § 4.23 provides that only a grape variety name approved by the TTB Administrator may be used as a type designation for an American wine and states that a list of approved grape variety names appears in subpart J of part 4.
Within subpart J of part 4, the list of grape variety names and their synonyms approved for use as type designations for American wines appears in § 4.91 (27 CFR 4.91). Alternative grape variety names temporarily authorized for use are listed in § 4.92 (27 CFR 4.92). Finally, § 4.93 (27 CFR 4.93) sets forth rules for the approval of grape variety names.
Section 4.93 provides that any interested person may petition the TTB Administrator for the approval of a grape variety name and that the petition should provide evidence of the following:
• That the new grape variety is accepted;
• That the name for identifying the grape variety is valid;
• That the variety is used or will be used in winemaking; and
• That the variety is grown and used in the United States.
Section 4.93 further provides that documentation submitted with the petition may include:
• A reference to the publication of the name of the variety in a scientific or professional journal of horticulture or a published report by a professional, scientific, or winegrowers' organization;
• A reference to a plant patent, if patented; and
• Information pertaining to the commercial potential of the variety, such as the acreage planted and its location or market studies.
Section 4.93 also places certain eligibility restrictions on the approval of grape variety names. TTB will not approve a new name:
• If it has been used previously for a different grape variety;
• If it contains a term or name found to be misleading under § 4.39 (27 CFR 4.39); or
• If it contains the term “Riesling.” (See T.D. ATF-370, 61 FR 522, published 1/8/96.)
Typically, if TTB determines that the evidence submitted with a petition supports approval of the new grape variety name, TTB will send a letter of approval to the petitioner advising the petitioner that TTB will propose to add the grape variety name to the list of approved grape variety names in § 4.91 at a later date. Those letters are considered administrative approvals, and they are posted on TTB's Web site once a grape variety is approved. After one or more approvals have been issued, a notice of proposed rulemaking will be prepared for publication in the
Since the last revision of the approved grape variety names list in § 4.91, (T.D. TTB-95, 76 FR 66625, published October 27, 2011), TTB has received and administratively approved a number of petitions for new grape variety names. In this notice, TTB is proposing to add a number of grape variety names to the list of names in § 4.91 to reflect those approvals. The evidence that the petitioners submitted in support of each name—and that formed the basis for the TTB approval—is summarized below. TTB is requesting comments on the appropriateness of these names for use on American wine labels.
TTB is also requesting comments on one petitioned-for grape name that TTB did not approve administratively. The petition for this name—Phoenix—is also discussed below. In addition, TTB has received a petition requesting that one grape variety name currently listed in § 4.91—Geneva Red 7—be removed from the list and replaced with the name “Geneva Red.” TTB is requesting comments on this petition.
White Heron Cellars, Quincy, Washington, petitioned TTB to add “Amigne” to the list of approved grape variety names. Amigne is a white
Jessica Lyga, Plant Varieties & Germplasm Licensing Associate, Center for Technology Enterprise and Commercialization, Cornell University, petitioned TTB to add “Arandell” to the list of approved grape varieties. Arandell, a red wine grape developed at Cornell, is a cross between two interspecific hybrid selections from Cornell's grape breeding program. According to a Cornell University bulletin submitted by the petitioner, Arandell is a “grape characterized by a high degree of natural disease resistance and producing dark red wines with clean, berry aromas.” The petitioner also submitted Arandell's listing in the National Grape Registry, published by the University of California at Davis (UC Davis), which notes the variety is available for sale at two commercial nurseries in New York. Based on this evidence, TTB proposes to add Arandell to the list of grape variety names in § 4.91.
Jessica Lyga, Plant Varieties & Germplasm Licensing Associate, Center for Technology Enterprise and Commercialization, Cornell University, petitioned TTB to add “Aromella” to the list of approved grape varieties. Aromella is a white wine grape developed at Cornell from a cross between Traminette and Ravat 34. According to a Cornell University bulletin submitted by the petitioner, Aromella is “a winter-hardy white wine grape with high potential productivity and excellent aromatic muscat wine characteristics.” The petitioner also submitted Aromella's listing in UC Davis's National Grape Registry, which notes the variety is available for sale at three commercial nurseries in New York and California. Based on this evidence, TTB proposes to add Aromella to the list of grape variety names in § 4.91.
White Heron Cellars, Quincy, Washington, petitioned TTB to add “Arvine” to the list of approved grape variety names. Arvine is a white
Laraneta Winery, Templeton, California, petitioned TTB to add “Bianchetta trevigiana” to the list of approved grape variety names. Bianchetta trevigiana is a white
Majek Vineyard and Winery, San Antonio, Texas, petitioned TTB to add “Black Spanish” to the list of approved grape variety names as a synonym for the currently listed “Lenoir.” Black Spanish is a hybrid red wine grape grown in Texas and other southern States. As evidence of the validity of the name “Black Spanish” to identify the variety, the petitioner submitted links to several Web sites that refer to the variety by that name. These links include one to UC Davis's National Grape Registry, which lists “Black Spanish” as a common synonym for Lenoir, and three links to nursery Web sites that list the variety by the name “Black Spanish.” If Black Spanish is approved, it will appear as a synonym for Lenoir in § 4.91. TTB believes that the evidence warrants the approval of Black Spanish as a valid name commonly used in the United States for this variety. However, we welcome comments on this issue. Based on the above evidence, TTB proposes to add the name “Black Spanish” to the list of grape variety names in § 4.91 to be identified with its synonym “Lenoir.” TTB also received a petition for approval of the name “Jacquez,” another synonym for Lenoir (see discussion below under “Jacquez”).
Clover Meadow Winery, Shell Lake, Wisconsin, petitioned TTB to add “Bluebell” to the list of approved grape variety names. Bluebell is an interspecific cross developed at the University of Minnesota in 1944. A very cold-hardy variety, it is commonly used for table grapes, juice, and jelly. The petitioner, however, produces wine from the variety. To satisfy the requirements of § 4.93, the petitioner submitted Web site references to Bluebell from the University of Minnesota and UC Davis's National Grape Registry, which lists five nurseries selling the variety. Based on this evidence, TTB proposes to add the name “Bluebell” to the list of grape variety names in § 4.91.
Tablas Creek Vineyard, Paso Robles, California, petitioned TTB to add “Bourboulenc” to the list of approved grape variety names. Bourboulenc is a white
Pete Anderson of Eusinus Vineyard and Witch Creek Winery, Carlsbad, California, petitioned TTB to add “Brachetto” to the list of approved grape variety names. Brachetto is a red
Girouard Vines, Tulsa, Oklahoma, petitioned TTB to add “By George” to the list of approved grape variety names. By George is a red wine grape developed by George E. Girouard by crossing Ruby Cabernet with
RBZ Vineyards, Templeton, California, petitioned TTB to add “Caladoc” to the list of approved grape variety names. Caladoc is a red
Belle Fiore Winery, Ashland, Oregon, petitioned TTB to add “Caprettone” to the list of approved grape variety names. Caprettone is a white
Wine Haven, Inc., Chisago City, Minnesota, petitioned TTB to add “Chisago” to the list of approved grape variety names. Chisago is a red wine variety developed by the petitioner from a crossing of St. Croix and Swenson Red. Noteworthy for its winter hardiness, the variety can survive temperatures that reach minus 40 degrees Fahrenheit. To satisfy the requirements of § 4.93, the petitioner submitted copies of its U.S. Plant Patent and U.S. Trademark Registration for Chisago, along with two articles referencing the variety and a list of wine competition awards won by its Chisago wine. According to the petitioner, several other Minnesota vineyards also are growing Chisago, and two nurseries planned to sell the variety in 2012. Based on this evidence, TTB proposes to add Chisago to the list of grape variety names in § 4.91.
Pete Anderson of Eusinus Vineyard and Witch Creek Winery, Carlsbad, California, petitioned TTB to add “Coda di Volpe” to the list of approved grape variety names. Coda di Volpe is a white
John H. Brahm III, winemaster at Arbor Hill Winery, Naples, New York, petitioned TTB to add “Diana” to the list of approved grape variety names. Diana is a red hybrid variety that has grown in the Finger Lakes region since the mid-1800s. To satisfy the requirements of § 4.93, the petitioner submitted an excerpt from the 1908 book “The Grapes of New York,” which describes Diana as a seedling of Catawba that ripens early and is thus good for cold climates. The petitioner also submitted a photo of a Widmer's Wine Cellars label for a Diana wine, vintage 1942. The petitioner states that Arbor Hill has recently produced a Diana wine which it intends to release for sale. TTB notes that the U.S. Department of Agriculture's Plant Genetic Resources Unit in Geneva, New York, maintains Diana in its collection and distributes the variety. Based on this evidence, TTB proposes to add Diana to the list of grape variety names in § 4.91.
Deja Vine Vineyards & Winery, Martelle, Iowa, petitioned TTB to add “Esprit” to the list of approved grape variety names. Esprit, a white interspecific hybrid, was developed by Elmer Swenson as a cross between Villard blanc and Edelweiss. To satisfy the requirements of § 4.93, the petitioner submitted two publications from Iowa State University describing the viticultural characteristics of Esprit and the quality of its wine. Esprit is also listed in UC Davis's National Grape Registry, which notes that a New York nursery sells the variety. Based on this evidence, TTB proposes to add Esprit to the list of grape variety names in § 4.91.
Pete Anderson of Eusinus Vineyard and Witch Creek Winery, Carlsbad, California, petitioned TTB to add “Falanghina” to the list of approved grape variety names. Falanghina is a white
Jessica Lyga of Cornell University petitioned TTB to change the currently approved grape variety name “Geneva Red 7” to “Geneva Red.” Geneva Red 7 was added to § 4.91 by T.D. TTB-95 as the result of a petition from a New York winery (see 76 FR 66625, October 27, 2011). The Geneva Red petition states that Cornell University, the developer and owner of the grape variety, does not endorse the use of the name “Geneva Red 7” and notes that the petition for that name was submitted without its approval. The petition states that Cornell is concerned that the “7” in “Geneva Red 7” is confusing and leads the consumer to question whether there are similarly named grape varieties, such as Geneva Red 1, 2, 3, etc.
As evidence for the name Geneva Red, the petitioner submitted a 2003 Cornell publication referencing the variety as “Geneva Red,” along with the variety's entry from UC Davis' National Grape Registry which lists the variety as “Geneva Red.” Based on this evidence, TTB granted administrative approval to the name “Geneva Red” as a valid synonym for “Geneva Red 7,” but advised the petitioner that it could not remove the name “Geneva Red 7” from § 4.91 without rulemaking. The petitioner has subsequently submitted a list of four commercial vineyards and wineries that use the name “Geneva Red” for the grape variety on their Web sites. Because the evidence indicates that this is the name currently used in the marketplace for the variety, TTB proposes to remove the name “Geneva Red 7” from § 4.91 and replace it with “Geneva Red.” However, TTB welcomes comments on the validity of the name, Geneva Red, as an approved name for this grape variety.
TTB further proposes to allow the use of the grape variety name “Geneva Red 7” for a period of 1 year after publication of a final rule on this matter if Geneva Red 7 is removed based on sufficient evidence from comments received. If this proposal is adopted as a final rule, those holding a certificate of label approval (COLA) with the name “Geneva Red 7” would have sufficient time to obtain new labels. At the end of the 1-year period, holders of approved “Geneva Red 7” labels would be required to discontinue their use as their COLA approval will be revoked by operation of the final rule (see 27 CFR
California American Terroirs, Sonoma, California, petitioned TTB to add “Godello” to the list of approved grape variety names. Godello is a white
Tablas Creek Vineyard, Paso Robles, California, petitioned TTB to add “Gros Manseng” to the list of approved grape variety names. Gros Manseng is a white
White Heron Cellars, Quincy, Washington, petitioned TTB to add “Humagne Rouge” to the list of approved grape variety names. Humagne Rouge is a red
Haak Vineyards & Winery, Santa Fe, Texas, petitioned TTB to add “Jacquez” to the list of approved grape variety names as a synonym for the currently listed “Lenoir.” Jacquez is a hybrid red wine grape grown in Texas and other southern States, where it is also known by the name “Black Spanish.” The petitioner states it has used the name “Jacquez” on its wine labels since 2003; as a result, its customers identify the wine by that name. As evidence of the validity of the name “Jacquez” to identity the variety, the petitioner submitted an entry for Jacquez from UC Davis's National Grape Registry, which lists “Black Spanish” and “Lenoir” as synonyms. The petitioner also cites a number of wine reference books that refer to the variety as “Jacquez,” including Hugh Johnson's “Story of Wine” (2002 edition, p. 439).
TTB also received a petition for “Black Spanish.” (See discussion above under “Black Spanish.”) If Jacquez and Black Spanish are both approved, three names for one variety will appear in § 4.91. TTB believes that the evidence warrants the approval of Jacquez and Black Spanish as they are both valid names commonly used in the United States for this variety. However, we welcome comments on this issue. Based on the above evidence, TTB proposes to add the name “Jacquez” to the list of grape variety names in § 4.91 to be identified with its synonyms “Black Spanish” and “Lenoir.”
Yamhalis Vineyard, Yamhill, Oregon, petitioned TTB to add “Jupiter” to the list of approved grape variety names. Jupiter is a hybrid grape developed by the University of Arkansas and released for commercial production in 1999. Although it is most commonly used as a table grape, the petitioner states it produces a good dry red wine. To satisfy the requirements of § 4.93, the petitioner submitted an article on Jupiter in the scientific journal HortScience (Vol. 43 (7)), a copy of the plant patent for Jupiter, and a letter from Dr. John R. Clark, one of Jupiter's breeders. According to UC Davis's National Grape Registry, the variety is available from at least four U.S. nurseries. Based on this evidence, TTB proposes to add the name “Jupiter” to the list of grape variety names in § 4.91.
Clover Meadow Winery, Shell Lake, Wisconsin, petitioned TTB to add “King of the North” to the list of approved grape variety names. A black grape, King of the North is an interspecific hybrid of unknown origin. Although it is most frequently grown for table grapes, juice, and jelly, it is also used to produce red wine by the petitioners and other wineries. As supporting evidence, the petitioner submitted Web site references to King of the North from Iowa State University and UC Davis's National Grape Registry, which lists three nurseries selling the variety. Based on this evidence, TTB proposes to add the name “King of the North” to the list of grape variety names in § 4.91.
Pete Anderson of Witch Creek Winery, Carlsbad, California, petitioned TTB to add “Lambrusca di Alessandria” to the list of approved grape variety names. Lambrusca di Alessandria is a red
When the petitioner submitted a grapevine sample that he thought was of the Nebbiolo variety to UC Davis's FPS for DNA analysis, he was informed that the sample was actually Lambrusca di
Lehrman Beverage Law petitioned TTB to add “Loureiro” to the list of approved grape variety names. Loureiro is a white
Comfort Farm and Vineyard, Langley, Washington, petitioned TTB to add “Madeleine Sylvaner” to the list of approved grape variety names. Madeleine Sylvaner is a white
Wyldewood Cellars Winery, Mulvane, Kansas, petitioned TTB to add “Marquis” to the list of approved grape variety names. Marquis is a white hybrid variety developed at Cornell University as a cross of the Athens and Emerald Seedless varieties. To satisfy the requirements of § 4.93, the petitioner submitted a copy of Cornell's 1999 plant patent for Marquis, a 1996 bulletin on Marquis issued by Cornell, and an article about the variety from the journal HortScience (Vol. 32 (1)). Marquis is also listed in UC Davis's National Grape Registry and is available from at least four commercial nurseries. Based on this evidence, TTB proposes to add Marquis to the list of grape variety names in § 4.91.
RBZ Vineyards, Templeton, California, petitioned TTB to add “Marselan” to the list of approved grape variety names. Marselan is a red
Natalia Winery, Natalia, Texas, petitioned TTB to add “Mustang” to the list of approved grape names. Mustang (
Tom Plocher of Plocher Vines, Hugo, Minnesota, petitioned TTB to add “Petite Pearl” to the list of approved grape names. Petite Pearl, a red hybrid known for its cold hardiness, was developed by Mr. Plocher from a 1996 cross of MN 1094 and E.S. 4-7-26. To satisfy the requirements of § 4.93, the petitioner submitted a January 2013 article about Petite Pearl published by Midwest Wine Press entitled “Coming Soon: A New Red Wine That's a Pearl,” along with evidence that two nurseries (in Minnesota and Vermont) sell the variety. He also named four wineries producing Petite Pearl wine. Based on this evidence, TTB proposes to add Petite Pearl to the list of grape variety names in § 4.91.
King's Raven Winery, Oregon City, Oregon, petitioned TTB to add “Phoenix” to the list of approved grape names. Phoenix is a white
Although TTB believes that the petition contains sufficient evidence under § 4.93 to approve the name “Phoenix,” TTB opted to propose adding the name to the list of grape variety names through rulemaking action rather than approve it administratively due to potential conflicts with existing COLAs. An electronic search of TTB's COLAs online database for the word “Phoenix” disclosed 174 COLAS that use the word “Phoenix” on a wine label as part of a brand or fanciful name. Of these, 40 have been approved since 2012 for 12 different wineries. The use of a grape variety name in a brand name potentially could be misleading and prohibited under § 4.39. If the name Phoenix is approved as a grape variety name, these labels potentially could be misleading, particularly if they do not also contain a grape varietal designation. Because of this potential impact on current labels, TTB believes that the label holders should be given an opportunity to comment on this proposal. Those comments will better inform TTB as to whether the grape variety name should be approved and thus added to the list of approved names in § 4.91.
Tablas Creek Vineyard, Paso Robles, California, petitioned TTB to add “Picardan” to the list of approved grape variety names. Picardan is a white
Rodrigue Molyneaux Winery, Livermore, California, petitioned TTB to add “Pinot bianco” to the list of approved grape variety names as a synonym for the currently listed “Pinot blanc.” Pinot bianco is the Italian name for this white wine variety, while Pinot blanc is the French name. The petitioner, who specializes in Italian grape varieties, believes that it would be confusing to customers if it labeled its Pinot bianco wines with the French name for the variety. As evidence of the validity of the synonym “Pinot bianco,” the petitioner cited a Web site about Italian varieties grown in California that refers to the variety by that name (see
Girouard Vines, Tulsa, Oklahoma, petitioned TTB to add “Plymouth” to the list of approved grape variety names. Plymouth is a red wine grape developed by George E. Girouard by crossing Merlot with
Vare Vineyards, Napa, California, petitioned TTB to add “Ribolla Gialla” to the list of approved grape variety names. Ribolla Gialla is a white
Mokelumne Glen Vineyards, Lodi, California, petitioned TTB to add “Rieslaner” to the list of approved grape variety names. Rieslaner is a white
Wild Grape Vineyards, Kindred, North Dakota, petitioned TTB to add “Riverbank” to the list of approved grape variety names. Riverbank (
Galleano Winery, Mira Loma, California, petitioned TTB to add “Rose of Peru” to the list of approved grape variety names. Rose of Peru is a red
Standing Stone Vineyards, Hector, New York, petitioned TTB to add “Saperavi” to the list of approved grape variety names. Saperavi is a red
Plum Hill Vineyards, Gaston, Oregon, petitioned TTB to add “Schönburger” to the list of approved grape variety names. Schönburger is a
Blackhawk Winery, Sheridan, Indiana, petitioned TTB to add “Sheridan” to the list of approved grape variety names. Sheridan, an interspecific cross of Herbert and Worden, was bred at the New York State Agricultural Experiment Station and released in 1921. Black in color, it is often used as a table grape. Sheridan is listed in UC Davis's National Grape Registry, and is available for sale at two New York nurseries. At the time of the petition, the petitioner was growing Sheridan and planning to produce wine from it. Based on this evidence, TTB proposes to add Sheridan to the list of grape variety names in § 4.91.
Girouard Vines, Tulsa, Oklahoma, petitioned TTB to add “Southern Cross” to the list of approved grape variety names. Southern Cross is a red wine grape developed by George E. Girouard by crossing Merlot with
Tablas Creek Vineyard, Paso Robles, California, petitioned TTB to add “Terret Noir” to the list of approved grape variety names. Terret Noir is a red
Abacela Winery, Roseburg, Oregon, petitioned TTB to add “Tinta Amarela” to the list of approved grape variety names. Tinta Amarela is a black
Cypher Winery, Paso Robles, California, petitioned TTB to add “Tinta Cao” to the list of approved grape variety names. Tinta Cao is a synonym for “Tinto cão,” a name already listed in § 4.91. As evidence that Tinta Cao is a valid name for the variety, the petitioner submitted a copy of the 2008 California Grape Crush Report, issued by the California Department of Food and Agriculture. The publication, referring to “Tinta Cao,” reports that 408.6 tons of the grape were crushed in California that year. Additionally, UC Davis's National Grape Register lists “Tinta Cao” as a synonym for Tinto cão and TTB is aware of at least one California vineyard selling the variety by the proposed name. Based on this evidence, TTB proposes to add Tinta Cao to the list of grape variety names in § 4.91 as a synonym for Tinto cão.
Cypher Winery, Paso Robles, California, petitioned TTB to add “Tinta Roriz” to the list of approved grape variety names. Tinta Roriz is a synonym for “Tempranillo” and “Valdepeñas,” names already listed in § 4.91. As evidence that Tinta Roriz is a valid name for the variety, the petitioner submitted a copy of the 2008 California Grape Crush Report, which refers to Tinta Roriz as a synonym for Tempranillo and Valdepeñas. UC Davis's National Grape Registry contains a separate listing for Tinta Roriz, but notes that it is a Portuguese name for the grape variety known in Spain as Tempranillo. If the name “Tinta Roriz” is approved, three names for this variety will appear in § 4.91. TTB believes that the evidence warrants the approval of Tinta Roriz. However, we welcome comments on this issue. Based on the above evidence, TTB proposes to add Tinta Roriz to the list of grape variety names in § 4.91.
Cypher Winery, Paso Robles, California, petitioned TTB to add “Touriga Nacional” to the list of approved grape variety names. Touriga Nacional is a black
The name “Touriga” is currently listed in § 4.91, which the petitioner contends is similar to listing “Cabernet Sauvignon” as “Cabernet.” However, the petitioner did not request the removal of “Touriga” from the list, nor did it submit any evidence for such a removal. TTB is aware that there are other grape variety names that include “Touriga” as part of the name (the National Grape Registry also lists “Touriga Franca” and “Touriga Brasileira”). Because bottlers of wines produced from these grapes may be utilizing the name “Touriga,” TTB proposes to keep the name on the list for now. However, we welcome comments regarding the accuracy of the name “Touriga.”
Tablas Creek Vineyard, Paso Robles, California, petitioned TTB to add “Vaccarèse” to the list of approved grape variety names. Vaccarèse is a red
Girouard Vines, Tulsa, Oklahoma, petitioned TTB to add “Valjohn” to the list of approved grape variety names. Valjohn is a red wine grape developed by George E. Girouard by crossing Cabernet Franc with
Berryessa Gap Vineyards, Winters, California, petitioned TTB to add “Verdejo” to the list of approved grape variety names. Verdejo is a white
TTB has become aware of a technical error in § 4.91 in that the grape variety name “Madeleine Angevine” is currently misspelled as “Madeline Angevine.” TTB proposes to correct this error in this document. TTB also proposes to allow the use of the spelling “Madeline Angevine” for a period of 1 year after publication of a final rule on this matter so that anyone holding a COLA with the misspelling has sufficient time to obtain new labels. If this proposal is adopted as a final rule, at the end of the 1-year period, holders of approved “Madeline Angevine” labels must discontinue their use as their certificates of label approval will be revoked by operation of the final rule (see 27 CFR 13.51 and 13.72(a)(2)). TTB believes the 1-year period will provide such label holders with adequate time to use up their supply of previously approved “Madeline Angevine” labels. This proposal appears in a new paragraph (e) of 27 CFR 4.92.
TTB requests comments from members of the public, particularly any person whose use of an approved label might be impacted by final approval of the grape variety names that are the subject of this proposed rule. TTB is also interested in comments that might bring into question whether an added grape name is accurate and appropriate for the designation of American wines. TTB is particularly interested in comments concerning the grape name discussed above that TTB did not approve by letter, Phoenix, as well as Geneva Red 7, the grape name we are proposing to replace with the name “Geneva Red.” Finally, TTB invites comment on any other issue raised by this notice of proposed rulemaking. Please support your comment with specific information about the grape varietal name in question.
You may submit comments on this notice by using one of the following three methods:
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Please submit your comments by the closing date shown above in this proposed rule. Your comments must reference Notice No. 165 and include your name and mailing address. Your comments also must be made in English, be legible, and be written in language acceptable for public disclosure. TTB does not acknowledge receipt of comments and considers all comments as originals.
In your comment, please clearly state if you are commenting for yourself or on behalf of an association, business, or other entity. If you are commenting on behalf of an entity, your comment must include the entity's name as well as your name and position title. In your comment via
You may also write to the Administrator before the comment closing date to ask for a public hearing. The Administrator reserves the right to determine whether to hold a public hearing.
All submitted comments and attachments are part of the public record and subject to disclosure. Do not enclose any material in your comments that you consider to be confidential or inappropriate for public disclosure.
TTB will post, and you may view, copies of this proposed rule and any online or mailed comments received about this proposal within Docket No. TTB-2016-0011 on the Federal e-rulemaking portal. A direct link to that docket is available on the TTB Web site at
All posted comments will display the commenter's name, organization (if any), city, and State, and, in the case of mailed comments, all address information, including email addresses. TTB may omit voluminous attachments or material that it considers unsuitable for posting.
You may view copies of this proposed rule and any electronic or mailed
TTB certifies that this proposed regulation, if adopted, will not have a significant economic impact on a substantial number of small entities. The decision of a grape grower to petition for a grape variety name approval, or the decision of a wine bottler to use an approved name on a label, is entirely at the discretion of the grower or bottler. This proposed regulation does not impose any new reporting, recordkeeping, or other administrative requirements. Accordingly, a regulatory flexibility analysis is not required.
It has been determined that this proposed rule is not a significant regulatory action as defined by Executive Order 12866 of September 30, 1993. Therefore, no regulatory assessment is required.
Jennifer Berry of the Regulations and Rulings Division, Alcohol and Tobacco Tax and Trade Bureau, drafted this document.
Administrative practice and procedure, Advertising, Customs duties and inspection, Imports, Labeling, Packaging and containers, Reporting and recordkeeping requirements, Trade practices, Wine.
For the reasons discussed in the preamble, TTB proposes to amend 27 CFR, chapter I, part 4 as set forth below:
27 U.S.C. 205, unless otherwise noted.
(e) Wines bottled prior to [
Bureau of Safety and Environmental Enforcement, Interior.
Proposed rule.
The Bureau of Safety and Environmental Enforcement (BSEE) currently charges a fee for 31 different services (hereafter “cost recovery fees”) it provides to non-Federal recipients. The services were identified by BSEE's predecessor agency, the Minerals Management Service (MMS). This proposed rule would revise and clarify the existing fees; add new fees for certain services; revise and codify the existing conditions for refunding fees; and clarify the acceptable methods of fee payment. This proposed rule would enable BSEE to recover its full costs associated with providing these services to recipients of special benefits beyond those accruing to the general public.
BSEE will consider all comments received by January 17, 2017. BSEE may not consider comments received after this date. Submit comments to the Office of Management and Budget (OMB) on the information collection burden in this proposed rule by December 19, 2016.
You may submit comments on the proposed rule by any of the following methods. Please use the Regulatory Identifier Number (RIN) 1014-AA31 as an identifier to your message.
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• Mail or hand-carry comments to the Department of the Interior (DOI); Bureau of Safety and Environmental Enforcement; Attention: Regulations and Standards Branch; 45600 Woodland Road, Sterling, VA 20166. Please reference
• Comments on the information collection contained in this proposed rule are separate from those on the substance of the proposed rule. Send comments on the information collection burden in this rule to: OMB, Interior Desk Officer, 202-395-5806 (fax); email
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Kimberly Monaco, Budget Analyst, Office of Budget at (703) 787-1658,
In accordance with the Independent Offices Appropriation Act, 1952, 31 U.S.C. 9701 and the Office of Management and Budget (OMB) Circular A-25,
OMB Circular A-25 requires a Federal agency to conduct a biennial review of its user charges to determine whether adjustments are necessary and to review other agency programs to determine whether new fees should be established for any services it provides. BSEE reviewed its 31 services and pre-production site visits along with the associated cost recovery fees to determine whether the cost of providing each of the services supports the existing fee structure in the existing regulations. BSEE's methodology for calculating its direct and indirect costs to perform the 31 services and the pre-production site visits is found later in this document. Results from the direct and indirect cost calculations indicate that 17 fees should be increased, eight fees reduced, and six fees subdivided into two tiers by complexity, with six of the subdivided fees increasing above the existing undivided fee, and six decreasing. The results also indicate that the existing pre-production site visit fees for two of the facility production safety system applications should be decreased for visits to facilities offshore and increased for visits to facilities while in a shipyard. Finally, the results suggest that new pre-production site visit fees should be implemented for the four facility production safety system applications that did not previously include site visit fees. The details of these proposed fees are shown in the Service Fee Table later in this document.
The fees are codified in BSEE's regulations at 30 CFR 250.125(a). This proposed rule would: (1) Amend 31 of the cost recovery fees in existing § 250.125; (2) establish two tiers of fees within the Deepwater Operations Plans (DWOPs), New Pipeline Applications, Pipeline Modification Applications for both Lease Term and Right-of-way (ROW) Pipelines, ROW Pipeline Grant Applications, and Unitization Revisions fee categories; (3) add four new pre-production site visit cost recovery fees to the existing two pre-production site visit fees to support the review and approval, if necessary, of production
In addition to BSEE's in-depth review of the bureau's existing cost recovery fees, the need for adjustments is further supported by the fact that, with the exception of adjustments for inflation, BSEE's cost recovery fees have not been adjusted since the 2005 and 2006 rulemakings establishing the fees (
The proposed adjustments are based on an analysis of BSEE's costs for providing services from fiscal year (FY) 2013 to FY 2015. The proposed fee adjustments are necessary to more accurately align fees with the cost of BSEE's services provided to the non-Federal recipients. BSEE invites comments on each of the proposed fee adjustments described later in this document.
Existing §§ 250.125 and 250.126 set out the amount of cost recovery fees for each BSEE service and provide instructions for making payments. Section 250.125(a) lists the 31 cost recovery fees currently imposed by BSEE for specific services. Section 250.125(b) requires that payment of the applicable fee(s) must accompany the request for service and provides that all fees are non-refundable. Section 250.125(c) requires the submission of a written request and accompanying payment within 72 hours of a BSEE verbal approval. Section 250.126 requires that all cost recovery fees be paid electronically through
BSEE proposes to amend § 250.125 by revising the fees for specific services based on its in-depth review and incorporating guidance from NTL No. 2009-N09 regarding conditions for granting fee payment refunds. BSEE proposes amendments to § 250.126 to provide clarification on the payment of cost recovery fees and the acceptable payment methods. BSEE also proposes to amend the following other sections of 30 CFR part 250 that are subject to the proposed § 250.125 amendments in this document: § 250.292 (DWOPs); § 250.1000 (Applications to install or modify lease term pipelines); § 250.1015 (Applications for pipeline ROW grants); and § 250.1303 (Requests for voluntary unitization).
BSEE is proposing adjustments to its 31 existing cost recovery fees to fully account for the costs of providing the services listed in the Service Fee Table below. Additionally, BSEE is proposing to amend § 250.125(a) to:
1. Subdivide into two categories and add different fee levels for six types of cost recovery fees (DWOPs, New Pipeline Applications, Pipeline Modification Applications for both Lease Term and ROW Pipelines, ROW Pipeline Grant Applications, and Unitization Revisions) to accurately reflect the varying levels of complexity of the requested services and the corresponding levels of costs to BSEE from providing those services;
2. Add four new pre-production site visit fees and revise the two existing pre-productions site visit fees to support the review and approval of production safety system applications, if a site visit is deemed necessary. These new and revised site visit fees are proposed to be included in §§ 250.125(a)(5)-(10).
In the Service Fee Table below, the existing regulations are in regular font;
Federal agency policy covering full cost recovery through user charges is outlined in OMB Circular A-25. According to OMB Circular A-25, BSEE should assess fees to recover the bureau's full costs of providing the services to the offshore oil and gas industry, rather than market price, because BSEE is acting on behalf of the United States to issue offshore oil and gas permits, approve DWOPs, and provide the other listed services. Therefore, BSEE used the full cost recovery approach, described in paragraph 6.d.1 of OMB Circular A-25, to assess the cost of each process.
For each of the services provided by BSEE, the process begins with the submission of an application, plan, permit, or other request by an operator. BSEE typically provides the service requested when an operator submits a request and the associated user fee. The output of each service is BSEE's issuance of the permit or application/plan approval or denial.
In order to determine the current cost of BSEE's services, BSEE assessed and itemized its services through data collection and dialogue with BSEE personnel in its Gulf of Mexico Regional Office (GOMR) and other BSEE SMEs. This process included the identification of each task undertaken by BSEE to review and approve each type of plan, application, permit, or other request. These tasks include: The initiating event or BSEE's receipt of a request for service; the identification of personnel to perform the review of the plan, application, permit, or other request; the review of the plan, application, permit, or other request; and the issuance of the permit or approval/denial of the application/plan. This information and the time spent performing each task were used to calculate BSEE's service costs, consistent with the procedures in OMB Circular A-25, as explained in the following discussion.
The direct costs assessed as part of the full cost recovery analysis are direct labor costs,
The following 2016 OPM GS rate tables were used to identify the appropriate hourly rate for the employee responsible for completing each task:
(1) For any task completed by a petroleum engineer, OPM's 2016 special rate tables 711 and 712 were utilized. These tables provide petroleum engineers in GOMR and the Pacific OCS Region (POCSR) with a 35 percent increase above OPM's “Base” pay rate.
(2) For any task completed by a geologist or geophysicist, OPM's 2016 special rate table 711 was utilized. This table provides geologists and geophysicists in Jefferson, LA and Camarillo, CA with a 35 percent increase above OPM's “Base” pay rate. Jefferson, LA includes the GOMR New Orleans District where the majority of these positions are located.
(3) For all other tasks not covered by (1) or (2) above, the GS “REST OF UNITED STATES” 2016 rate table was used.
Along with direct labor salary costs, OMB Circular A-25 requires the collection of direct labor costs classified as fringe benefits, which usually includes paid leave, medical insurance, and retirement. Historically, BSEE has calculated the fringe benefits as 28 percent of the direct salary costs and refers to that percentage as the “fringe benefit factor.” The fringe benefit factor was applied to all labor categories and grades for all cost recovery fee calculations.
In accordance with OMB Circular A-25, indirect costs include personnel fringe benefits, all physical overhead costs, and management and supervisory costs. In accordance with OMB Circular A-25, BSEE assessed indirect costs for all headquarters, Regional, and District personnel and operations involved in the provision of services that are the subject of this proposed rule. These indirect costs include salaries and fringe benefits of personnel providing ancillary support functions, material and supply costs, utilities, and other costs that are allocated across all services provided by BSEE. BSEE has an extensive activity-based costing code table and cost capture database (Cost and Performance Management Tool (CPMT)) that categorizes all BSEE costs as either direct or indirect. Data from CPMT, going back to FY 2007, were analyzed to develop an appropriate methodology for estimating the indirect costs component of the cost recovery fees.
Indirect costs were estimated using the historical ratio of indirect to direct costs observed at the headquarters, Regional, or District levels. From FY 2007 through FY 2015, the ratio was consistently between 51 and 56 percent. An average ratio of 53.51 percent was used. This percentage was applied to each service's direct cost to derive an indirect cost estimate for each service. The following table provides the indirect to direct cost data and ratios for BSEE and the Bureau of Ocean Energy Management's (BOEM) predecessor agencies, MMS and the Bureau of Ocean Energy Management, Regulation, and Enforcement, from FY 2007-FY 2011 and for BSEE from FY 2013-FY 2015.
Two fee levels are proposed for certain applications, plans, permits, and other requests for BSEE services (
1. DWOP: The complexity of processing a DWOP varies and depends on whether it includes new or unusual technology, as well as the scope and scale of the proposed development project.
a. DWOP—Complex: An operator would submit payment for this service when a DWOP meets any of the following criteria:
• The plan contains new or unusual technology, as defined in 30 CFR 250.200(b), and the new or unusual technology:
• The plan includes installation of a new floating production facility.
b. DWOP—Simple: An operator would submit payment for this service for all DWOPs that do not meet the criteria for Deepwater Operation Plans—Complex. This includes, but is not limited to:
• A new or unusual technology as defined in 30 CFR 250.200(b) that does not require a high degree of specialized knowledge.
• A new or unusual technology that is a modification or repair to an existing floating production facility or project.
• A subsea tieback to a new or existing floating production facility.
• A material change, addition or revision to an existing, previously approved project.
• A subsea tieback/additional well(s) for which only minor or no updates for subsea production safety system are necessary.
• Addition of a new subsea development to a new or existing floating production facility.
2. New Pipeline Application (Lease Term): The complexity of processing an application varies and is dependent on the water depth of the pipeline.
a. New Pipeline Application (Lease Term)—Shallow Water: An operator would submit payment for this service when the pipeline in a New Pipeline Application (Lease Term) is located in its entirety in water depths less than or equal to 1,000 feet (ft.).
b. New Pipeline Application (Lease Term)—Deepwater: An operator would submit payment for this service when any portion of the pipeline in a New Pipeline Application (Lease Term) is located in water depths greater than 1,000 ft.
3. Pipeline Application—Modification (Lease Term): The complexity of processing an application varies and is dependent on the complexity of the modification.
a. Pipeline Application—Modification (Lease Term)—Major: An operator would submit payment for this service when a Pipeline Application—Modification (Lease Term) contains a route modification request. Actions which constitute a “route modification” include, but are not limited to, changing a pipeline route, installing a new portion of pipeline, decommissioning a portion of pipeline, and changing service or flow direction of a pipeline.
b. Pipeline Application—Modification (Lease Term)—Minor: An operator would submit payment for this service for all other Pipeline Applications—Modification (Lease Term) requests (
4. Pipeline Application—Modification (ROW): The complexity of processing an application varies and is dependent on the complexity of the modification.
a. Pipeline Application—Modification (ROW)—Major. An operator would submit payment for this service when a Pipeline Application—Modification (ROW) contains a route modification request. Actions that constitute a “route modification” include, but are not limited to, changing a pipeline route, installing a new portion of pipeline, decommissioning a portion of pipeline, and changing service or flow direction of a pipeline.
b. Pipeline Application—Modification (ROW)—Minor: An operator would submit payment for this service for all other Pipeline Applications—Modification (ROW) requests (
5. Pipeline ROW Grant Application: The complexity of processing an application varies and is dependent on the water depth of the pipeline.
a. Pipeline ROW Grant Application—Shallow Water: An operator would submit payment for this service when the pipeline in a Pipeline ROW Grant Application is located in its entirety in water depths less than or equal to 1,000 ft.
b. Pipeline ROW Grant Application—Deepwater: An operator would submit payment for this service when any portion of the pipeline in a Pipeline ROW Grant Application is located in water depths greater than 1,000 ft.
6. Unitization Revision: BSEE currently charges one fee for the review of a Unitization Revision; however, the complexity of processing the application and resulting cost vary based on the specific exhibits being revised in the signed unit agreement. Typical unitization applications contain an Exhibit A, which is the lease plat identifying the unit area; Exhibit B, which is a listing of the component leases and ownership of each; and Exhibit C, which is a listing of the participation and allocation by lease. Payment for unitization revision services are as follows:
a. Unitization Revision—Exhibit A, Exhibit B, and Designation of Successor Unit Operator/Sub-operator: The Unit Operator would submit payment for this service when a Unitization Revision is submitted for approval that revises Exhibit A and/or Exhibit B of the signed unit agreement or designates a Successor Unit Operator and/or Successor Unit Sub-operator.
b. Unitization Revision—Exhibit C: The Unit Operator would submit payment for this service when a Unitization Revision is submitted for approval that revises Exhibit C of the signed unit agreement.
In accordance with existing § 250.800, production must not commence until the production safety system has been approved and a pre-production inspection has been requested by the lessee. If a BSEE application reviewer decides that a pre-production inspection is necessary as part of the production safety system application review and approval process, then a team of engineers and inspectors visits the facility offshore (
Existing §§ 250.125(a)(5) and (6) establish fees for visiting a facility offshore or in a shipyard for two of the six production safety system applications, when necessary, as part of the BSEE review and approval process. Visits to an offshore facility or a shipyard can become necessary in order to verify that safety devices are in the proper locations or to identify if they are missing when compared with the associated application submitted for approval. Any necessary corrections to production safety systems can typically be handled more easily while construction work is ongoing in a shipyard, rather than when the facility is offshore.
BSEE's costs for travel to offshore facilities and shipyard locations and for services, as part of the application review process, can be recovered in accordance with OMB Circular A-25. Estimates for BSEE's costs for these services include costs for transportation, lodging, and labor hours for each labor category involved.
As illustrated in the Service Fee Table, under §§ 250.125(a)(7)-(a)(10), BSEE proposes four new fees for production safety system visits to
1. New Facility Production Safety System Application for Facility with more than 125 components;
2. New Facility Production Safety System Application for Facility with 25-125 components;
3. New Facility Production Safety System Application for Facility with fewer than 25 components;
4. Production Safety System Application—Modification with more than 125 components reviewed;
5. Production Safety System Application—Modification with 25-125 components reviewed; and
6. Production Safety System Application—Modification with fewer than 25 components reviewed.
As previously mentioned, offshore operations have changed dramatically over the last ten years, which has led to adjustments in the review and approval process for a large portion of the services BSEE provides to industry. BSEE proposes the listed fee levels based on the assessment of the bureau's full costs to provide the associated services using the methodology described above. However, this full-cost methodology is not entirely comparable to the methodologies used in the 2005 and 2006 rulemakings that initially established the fees. The following examples provide the general rationale for some of the fee adjustments as compared to the fees in existing regulations.
1. BSEE's assessment of its costs for processing complex DWOPs indicates that six employees, ranging in grades from GS-5 through GS-14, will spend between 310 and 1,094 hours reviewing, analyzing, and processing these plans. As previously discussed, the increased complexity of offshore operations has required additional senior-level employees to spend added time reviewing and approving these plans. This is particularly true with regard to the increased processing time of DWOPs and the associated increased costs to BSEE. In addition, the existing $3,599 fee for processing both complex and simple DWOPs does not account for the special pay that many BSEE employees receive for reviewing and approving these plans and the higher indirect cost ratio. The fee assessed for DWOP review has also not been adjusted since a 2006 rulemaking that established the existing fee. The adjusted fee is the result of calculations performed with input from BSEE Regional Offices and takes into account the increased complexity of submitted DWOPs due to the use of new or unusual technologies and the increased scope or scale of proposed plans. Based on its assessment, BSEE proposes to subdivide the DWOP processing fees and assess a $70,333 fee for processing complex DWOPs in 250.125(a)(2)(ii).
2. Similarly, BSEE proposes subdividing the fees for processing unitization revisions based on its assessment of the bureau's direct and indirect costs. Typically, seven BSEE positions, ranging in grades from GS-5 through GS-15, spend between 6.6 and 29.7 hours processing unitization revisions impacting exhibits A and B, while six BSEE positions spend between 8.5 to 71.9 hours processing unitization revisions impacting exhibit C. As is the case with the existing DWOP fee, the existing $896 fee for processing unitization revisions does not account for the special pay that many BSEE employees receive for reviewing and approving these documents and the higher indirect cost ratio. Based on its assessment, BSEE proposes a $1,683 fee for processing a unitization revision related to exhibits A and B and a $3,255 fee for processing a unitization revision related to exhibit C in 250.125(a)(28)(i) and (ii).
3. BSEE is also proposing to reduce some existing fees based on its assessment of the bureau's full costs to process applications and requests. For example, BSEE's assessment indicated that five BSEE employees, ranging in grades from GS-5 through GS-14, will spend between 5.8 and 12.5 hours processing an application for a minor lease term pipeline modification, resulting in $651 in full bureau costs. Since the existing fee of $2,056 was established, efficiencies have resulted in lower costs to process applications and requests (
Due to the large number of revised applications received by BSEE and the associated costs to BSEE to process them, BSEE is currently evaluating the need for additional fees for revised applications for permits to drill (R-APD) and revised applications for permits to modify (R-APM). Accordingly, BSEE requests comments on whether separate fee levels for R-APD and R-APM should be proposed in a future rulemaking. BSEE also requests comments on the factors that should be the basis for determining the separate fee levels for R-APDs and R-APMs (
E.O. 12866 provides that OMB, Office of Information and Regulatory Affairs (OIRA), will review all significant rules. BSEE has determined that this proposed rule is not a significant regulatory action as defined by section 3(f) of E.O. 12866 because:
Accordingly, BSEE has not prepared an economic analysis, and OIRA has not reviewed this proposed rule.
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the Nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. E.O. 13563 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. It also emphasizes 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. BSEE is developing this rule in a manner consistent with these requirements.
The DOI certifies that this proposed rule would not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act, 5 U.S.C. 601
The Initial Regulatory Flexibility Analysis prepared by BSEE assessed the impact of this proposed rule on small entities, as defined by the applicable Small Business Administration (SBA) size standards. BSEE has determined that this proposed rule potentially affects operators and holders of Federal oil and gas leases, as well as right-of-way holders, on the OCS. This includes an estimated 99 businesses with active operations. Businesses that operate under this rule fall under the SBA's North American Industry Classification System (NAICS) codes 211111 (Crude Petroleum and Natural Gas Extraction) and 213111 (Drilling Oil and Gas Wells). For these NAICS classifications, a small business is defined as one with fewer than 1,251 employees (for NAICS 211111) and fewer than 1,001 (for NAICS 213111). Based on these criteria, 54 of the potentially impacted businesses are considered small and 45 are considered large businesses. BSEE considers that a rule has an impact on a “substantial number of small entities” when the total number of small entities impacted by the rule is equal to or exceeds 10 percent of the relevant universe of impacted entities. Approximately 55% of the businesses that would be affected by this rule are considered small; therefore, BSEE has determined that this rule would impact a substantial number of small businesses under the RFA.
BSEE's analysis estimates the incremental costs for small operators, lease holders, and right-of-way holders in the offshore oil and natural gas industry. Costs already incurred as a result of existing fees were not considered as costs of this proposed rule because they are part of the baseline. Among the 54 small businesses involved in offshore operations, the average annual corporate sales volume, from the latest available data, for the year 2014, is $186 million, which is approximately $192 million in 2016 dollars.
The following “Change in Cost per Small Entity” table provides an analysis and derivation of the estimated average cost, per small firm, that would be incurred per year as a result of the proposed rule. The first column of the table displays the list of services provided, as they appeared earlier in the Service Fee Table. The second column displays an estimate of the total counts of these services expected over the three fiscal year period 2016-2018. The third and fourth columns show the existing fee, and the proposed fee, respectively, for each service provided. The fifth column then displays, for each service, the expected change in total costs over the three-year period, on the basis of the data in the previous columns (the change in fees and the counts of services). The sixth column reflects the estimated proportion of the change in cost per small firm based on BSEE's data regarding counts of services across firms from FY 2013 to FY 2015. Finally, the seventh column reflects the estimated change in cost per small firm per fiscal year, by taking the annualized product of columns five and six. The estimated additional costs of the proposed rule from service fee changes totals approximately $8,875 per small firm per year, or an estimated 0.0046 percent of an average small business's sales.
BSEE has concluded the additional costs of the proposed rule would impose an insignificant, negligible burden on small entities.
The proposed rule is not a major rule under the Small Business Regulatory Enforcement Fairness Act, 5 U.S.C. 804(2). This proposed rule:
(a) Would not have an annual effect on the economy of $100 million or more;
(b) Would not cause a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions; and
(c) 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.
The requirements would apply to all entities operating on the Outer Continental Shelf (OCS) regardless of company designation as a small business. For more information on costs affecting small businesses, see the
Your comments are important. The Small Business and Agriculture Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were established to receive comments from small businesses about federal agency enforcement actions. The Ombudsman will annually evaluate the enforcement activities and rate each agency's responsiveness to small business. If you wish to comment on the actions of BSEE, call 1-888-734-3247. You may comment to the SBA without fear of retaliation. Allegations of discrimination/retaliation filed with the SBA will be investigated for appropriate action.
This proposed rule would not impose an unfunded mandate on State, local, or tribal governments or the private sector of more than $100 million per year. The proposed rule would not have a significant or unique effect on State, local, or tribal governments or the private sector. Therefore, a statement containing the information required by the Unfunded Mandates Reform Act, 2 U.S.C. 1501
Under the criteria in E.O. 12630, this proposed rule does not have significant takings implications. The proposed rule is not a governmental action capable of interference with constitutionally protected property rights. Therefore, a Takings Implication Assessment is not required.
Under the criteria in E.O. 13132, this proposed rule does not have federalism implications. This proposed rule would not substantially and directly affect the relationship between the Federal and State governments. To the extent that State and local governments have a role in OCS activities, this proposed rule would not affect that role. A federalism assessment is not required.
This proposed rule complies with the requirements of E.O. 12988. Specifically, this proposed rule:
(1) Meets the criteria of section 3(a) requiring that all regulations be reviewed to eliminate errors and ambiguity and be written to minimize litigation; and
(2) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal standards.
Under the criteria in E.O. 13175 and the Department's tribal consultation policy, we have evaluated this proposed rule and have determined that it has no substantial direct effects on federally recognized Indian tribes, or on the relationship or distribution of power and responsibilities between the Federal Government and Indian tribes, and that consultation under the Department's tribal consultation policy is not required.
This proposed rule contains a collection of information that will be submitted to OMB for review and approval under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
The PRA 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. OMB is required to make a decision concerning the collection of information contained in these proposed regulations 30 to 60 days after publication of this document in the
The title of the collection of information for this rule is 30 CFR part 250,
Potential respondents comprise Federal OCS oil, gas, and sulfur operators and lessees, as well as pipeline ROW holders. Responses to this collection of information are required to obtain or retain a benefit and are mandatory. The frequency of response varies depending upon the requirement. The IC does not include questions of a sensitive nature. BSEE will protect proprietary information according to the Freedom of Information Act (5 U.S.C. 552) and DOI's implementing regulations (43 CFR part 2), 30 CFR 250.197,
OMB approved the IC burden of the existing 30 CFR part 250 regulations under Control Numbers 1014-0022, Subpart A (84,391 hour burden, $1,371,458 non-hour cost burden; expiration 8/31/17); 1014-0024, Subpart B ($39,589 non-hour cost burden; expiration 11/30/2018); 1014-0025 Applications for Permit to Drill ($862,104 non-hour cost burden, expiration 4/30/2017); 1014-0026, Applications for Permit to Modify ($361,625 non-hour cost burden, expiration 5/31/2017); 1014-0003, Subpart H ($323,481 non-hour cost burden; expiration 12/31/2017); 1014-0011, Subpart I, ($392,874 non-hour cost burden, expiration 5/31/2017); 1014-0016, Subpart J ($1,508,968 non-hour cost burden, expiration 8/31/2018); 1014-0019, Subpart K ($1,361,176 non-hour cost burden, expiration 1/31/2019); 1014-0002, Subpart L ($322,479 non-hour cost burden, expiration 10/31/16); 1014-0015, Subpart M ($138,188 non-hour cost burden, expiration 12/31/2017); and 1014-0010, Subpart Q ($1,686,396 non-hour cost burden, expiration 10/31/2016), respectively.
If this proposed rule is finalized and codified, the various non-hour cost burdens and one new hour burden will be removed from this collection of information and consolidated with their primary information collection burden under their respective OMB Control Numbers.
Hour burdens are included in the regulatory requirements of various OMB-approved ICRs, of which only one is changing and discussed in this ICR.
BSEE currently receives approximately $7,000,000 in cost recovery fees (non-hour cost burdens) annually. This proposed rulemaking would increase that total by approximately $9,000,000 for a total of $16,000,000 in cost recovery fees. The following table provides a breakdown of the non-hour cost burdens for this proposed rulemaking.
[Existing non-hour cost burden/cost recovery fees are in regular font;
Although the total new and revised Non-Hour Cost Burdens are estimated to be $16 million based on 3-year averages of the number of plans, applications, and permits, due to recent declines in the number of these submissions, BSEE anticipates that collections will more closely approximate $11 million in FY 2018.
For further information on this non-hour burden estimation process, refer to 5 CFR 1320.3(b)(1) and (2), or contact the BSEE Information Collection Clearance Officer at (703) 787-1607.
This proposed rule meets the criteria set forth in 516 Departmental Manual (DM) 15.4C(1) for a categorical exclusion because it involves modification of existing regulations, the impacts of which would be limited to administrative or economic effects with minimal environmental impacts. BSEE also analyzed this proposed rule to determine if extraordinary circumstances, set forth in 43 CFR 46.215, exist that would require BSEE to prepare an environmental assessment or an environmental impact statement for actions otherwise eligible for a categorical exclusion. BSEE concluded that this proposed rule does not trigger any of the criteria for extraordinary circumstances and, therefore, has not prepared an environmental assessment or an environmental impact statement.
In developing this proposed rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106-554 § 515).
This proposed rule is not a significant energy action under the definition in E.O. 13211 because:
We are required by E.O. 12866, E.O. 12988, E.O. 13563, and by the Presidential Memorandum of June 1, 1998, to write all rules in plain language. This means that each rule we publish must:
If you feel that we have not met these requirements, send us comments by one of the methods listed in the
Administrative practice and procedure, Continental Shelf, Environmental impact statements, Environmental protection, Government contracts, Investigations, Oil and gas exploration, Penalties, Reporting and recordkeeping requirements, Sulfur.
For the reasons stated in the preamble, the Bureau of Safety and Environmental Enforcement (BSEE) proposes to amend 30 CFR part 250 as follows:
30 U.S.C. 1751; 31 U.S.C. 9701, 33 U.S.C. 1321(j)(1)(C), 43 U.S.C. 1334.
(a) * * *
(b) Fees specified in paragraph (a) must be paid electronically using one of the methods required by § 250.126. Proof of payment of the fees listed in paragraph (a) must accompany the submission of the application or other request for service. Once a fee is paid, it is nonrefundable, except as provided in paragraph (c). If your application is returned to you as incomplete, you are not required to submit a new fee with the amended application.
(c) BSEE will issue a refund in certain situations.
(1) You are eligible for a refund if you submit:
(i) More than one payment with a single request;
(ii) An incorrect fee or fee amount; or
(iii) A payment without submitting any application or other request and the matter does not proceed further.
(2) If you meet the criteria for a refund, you must submit a completed Refund Request form, which can be found at
(3) You must submit all refund requests to BSEE within 150 days of the initial service fee payment. If you do not submit your request within the 150-day timeframe, BSEE will not issue a refund.
(4) If you have any questions pertaining to refund eligibility or to the preparation of the refund request, contact the appropriate Regional Office.
(a) You must file all payments under any provision of this part electronically, as provided in paragraphs (a)(1) or (a)(2) of this section.
(1) If you submit an application through the eWell Web site at
(2) For applications not submitted through eWell, you may make a payment through the Fees for Services page on the BSEE Web site at
(b) Payments at or below the current U.S. Treasury credit card limit may be made using a credit card or through the automated clearing house (ACH-debit). Payments above the current U.S. Treasury credit card limit must be made through ACH-debit.
(c) BSEE does not accept wire transfer electronic payments.
(q) Payment of the service fee listed in § 250.125. The service fee is divided into two levels based on the complexity of the plan, as shown in the following table.
(c) The service fee for a New Pipeline Application (Lease Term) is divided into two levels based on water depth, as shown in the following table:
(d) The service fee for a Pipeline Application—Modification (Lease Term) and a Pipeline Application—Modification (Right-of-way) are divided into two levels based on complexity, as shown in the following table:
(a) You must submit to the Regional Supervisor an original and three copies of an application for a new or modified pipeline ROW grant. The application must address those items required by §§ 250.1007(a) or (b) of this subpart, as applicable. It must also state the primary purpose for which you will use the ROW grant. If the ROW has been used before the application is made, the application must state the date such use began, by whom, and the date the applicant obtained control of the ROW. When you file your application, you must pay the rental required under § 250.1012 of this subpart, as well as the
(d) You must pay the service fee listed in § 250.125 of this part with your request for a voluntary unitization proposal or the expansion of a previously approved voluntary unit to include additional acreage. Additionally, you must pay the service fee listed in § 250.125 with your request for unitization revision. The service fee for a request for unitization revision is divided into two levels, as shown in the following table:
Environmental Protection Agency (EPA).
Proposed rule.
EPA is announcing and inviting comment on additional information obtained and developed by EPA in conjunction with the proposed tolerance revocation for chlorpyrifos. This information includes the revised human health risk assessment and the drinking water assessment. It also includes EPA's issue paper and supporting analyses presented to the Federal Insecticide, Fungicide and Rodenticide Act (FIFRA) Scientific Advisory Panel's (SAP) meeting in April 2016 that addressed chlorpyrifos biomonitoring data and adverse neurodevelopmental outcomes, public comments received during the meeting, the FIFRA SAP's meeting minutes and the FIFRA SAP report. EPA is specifically soliciting comments on the validity and propriety of the use of all the new information, data, and analyses. EPA is accepting comment on the information and analysis, as well as reopening comment on any other aspect of the proposal or the underlying support documents that were previously available for comment. The EPA continues to seek comment on possible mitigation strategies, namely, use deletions, which might allow the EPA to retain a small subset of existing chlorpyrifos food uses. Commenters need not resubmit comments previously submitted. EPA will consider those comments, as well as comments in response to this notice, in taking a final action.
Submit comments on or before January 17, 2017.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPP-2015-0653, by one of the following methods:
•
•
•
Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
Dana Friedman, Pesticide Re-Evaluation Division (7508P), Office of Pesticide Programs, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (703) 347-8827; email address:
Do not submit this information to EPA electronically. Clearly mark the part or all of the information that you claim to be CBI. For CBI information in a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2.
EPA is reopening the comment period on the proposed rule: Entitled “Chlorpyrifos; Tolerance Revocations” (80 FR 69080, November 6, 2015) (FRL-
EPA's revised analyses do not result in a change to the EPA's proposal to revoke all tolerances but it does modify the methods and risk assessment used to support that finding in accordance with the advice of the SAP. The revised analysis indicates that expected residues of chlorpyrifos on most individual food crops exceed the “reasonable certainty of no harm” safety standard under the Federal Food, Drug, and Cosmetic Act (FFDCA). In addition, the majority of estimated drinking water exposures from currently registered uses, including water exposures from non-food uses, continue to exceed safe levels even taking into account more refined drinking water exposures. Accordingly, based on current labeled uses, the agency's analysis provided in this notice continues to indicate that the risk from the potential aggregate exposure does not meet the FFDCA safety standard. EPA can only retain chlorpyrifos tolerances if it is able to conclude that such tolerances are safe. EPA has not identified a set of currently registered uses that meets the FFDCA safety standard because it is likely only a limited number of food uses alone, and in combination with predicted drinking water exposures, would meet the standard. Further, EPA has not received any proposals for mitigation that registrants may be willing to undertake that would allow the EPA to retain any of the tolerances subject to this rulemaking. EPA continues to seek comment on possible mitigation strategies, namely, use deletions, which might allow the EPA to retain a small subset of existing chlorpyrifos food uses.
EPA consulted the FIFRA SAP for scientific advice on its analysis of biomonitoring data at a meeting on April 19-21, 2016, at which time, the public also had an opportunity to provide comment. The FIFRA SAP was asked to address the use of the epidemiological study
The final FIFRA SAP report provides a detailed account of the uncertainties associated with the agency's April 2016 proposed approach to selecting the point of departure and its use in quantitative risk assessment. It also outlines the SAP's concern that “epidemiology and toxicology studies suggest there is evidence for adverse health outcomes associated with chlorpyrifos exposures below levels that result in 10% red blood cell (RBC) acetylcholinesterase (AChE) inhibition” (FIFRA SAP, 2016, p. 18). The FIFRA SAP recommended that EPA should derive the point of departure for neurodevelopmental effects using the “estimated peak blood concentration or time weighted average blood concentration within the prenatal period” (FIFRA SAP, 2016, p. 42).
After careful consideration of public comments and the SAP's recommendations, EPA has concluded the most appropriate path for reconciling the SAP's concerns is to follow through on the SAP's recommendation to use a time weighted average approach. The agency agrees with the 2016 FIFRA SAP (and previous SAPs) that there is a potential for neurodevelopmental effects associated with chlorpyrifos exposure to occur at levels below 10% RBC AChE inhibition, and that EPA's existing point of departure (which is based on 10% AChE inhibition), is therefore not sufficiently health protective.
As detailed in
EPA generally selects the dose at which no toxicological effects are demonstrated to ensure our regulatory endpoint reflects a level of exposure that does not present a risk concern. However, the CCCEH study only supported the determination of a lowest observed adverse effects level (LOAEL). In situations where the agency selects a POD from a study where a no observed adverse effects level (NOAEL) has not been identified, EPA generally will retain the Food Quality Protection Act (FQPA) safety factor of 10X to account for the uncertainty in using a LOAEL. The 2016 revised risk assessment retains this uncertainty factor for chlorpyrifos and also applies a 10X uncertainty factor for intraspecies variability because of the lack of sufficient information to reduce or remove this factor.
The external exposure was calculated based on the assumptions and methods outlined in the EPA's 2012 Standard Operating Procedures (SOPs) for Residential Pesticide Exposure Assessment and chemical-specific exposure data, where available. Specifically, the 2012 Residential SOPs, which were peer reviewed by the FIFRA SAP in October 2009, were used to predict the potential exposures which could have occurred to individuals in the cohort for the indoor crack and crevice pesticide use pattern.
EPA then used the chlorpyrifos physiologically based pharmacokinetic (PBPK) model to estimate the study cohort mothers' systemic dose related to the LOAEL by (1) determining time-weighted average (TWA) blood levels from women exposed to chlorpyrifos from indoor exposures to the cancelled crack and crevice use and (2) using the crack and crevice TWA blood level as the internal dose for determining points of departure for infants, children, and adults exposed to chlorpyrifos using current exposure potential. The use of the PBPK model to assess internal dosimetry from various exposure scenarios continues to be supported by the SAP. This applies to the crack and crevice scenario identified as the most likely exposure pattern in the CCCEH study, where women were potential exposed via the dermal, oral, and inhalation routes. The detailed rationale is presented in
EPA has also completed, and is making available for public comment,
Section IV of this Notice of Data Availability (NODA) describes all additional data and analyses and how they impact the EPA's proposal. Note, however, that this NODA does not provide an exhaustive presentation of the additional data and analysis that EPA is placing in the associated docket and seeking comment on. All the information subject to this notice can be accessed as described in section III of this notice.
EPA is providing notice on these additional analyses to provide an opportunity for the public to submit additional data or information for the agency's consideration as it develops the final rule. Since EPA is still in the process of deliberating the provisions of a final rule, EPA cannot definitively state whether this information will provide support for any provision of the final rule, or that the agency has determined that it is appropriate to rely on this information in developing the final rule.
On December 10, 2015, the Ninth Circuit issued a further order requiring EPA to complete any final rule and fully respond to the PANNA and NRDC petition by December 30, 2016. On June 30, 2016, EPA sought a 6-month extension to that deadline in light of the SAP's recommendation at the meeting and in order to allow EPA to fully consider the SAP's written report. The FIFRA SAP report was finalized and made available for EPA consideration on July 20, 2016. The court rejected EPA's request for a 6-month extension and ordered EPA to complete its final action by March 31, 2017 (an extension of 3 months). The court also announced that no further extensions to that date would be granted.
The information that EPA is be made available for public review and comment can be found in the following dockets: EPA-HQ-OPP-2015-0653, the docket for the proposed tolerance revocations, and EPA-HQ-OPP-2016-0062, the FIFRA SAP docket, which contains the Chlorpyrifos Issue Paper and supporting materials. Both dockets can be accessed through
1. EPA is seeking comment on the following updates to the chlorpyrifos human health risk assessment: (1) Use of the crack and crevice scenario to derive an exposure level for women in the Columbia study; (2) using the LOAEL from the Columbia study and PBPK modeling to derive an endpoint for use in quantitative risk assessment; (3) use of the 10X uncertainty factor for intraspecies variability; (4) use of the 10X FQPA safety factor for LOAEL to NOAEL extrapolation (please include your rationale for any alternative values suggested for this factor). Its analysis is included in the
2. EPA is also making available for comment the issue paper and associated materials presented to the April 2016 FIFRA SAP and the final report of the SAP. The FIFRA SAP materials and final report are available in the FIFRA SAP docket (EPA-HQ-OPP-2016-0062).
3. EPA is also seeking comment on
Environmental protection, Administrative practice and procedure, Agricultural commodities, Pesticides and pests, Reporting and recordkeeping requirements.
Environmental Protection Agency (EPA).
Proposed rule.
Nebraska has applied to the Environmental Protection Agency (EPA) for final authorization of revisions to its hazardous waste program under the Resource Conservation and Recovery Act (RCRA). EPA is proposing to grant final authorization to Nebraska.
Comments on this proposed action must be received in writing by December 19, 2016.
Submit your comments, identified by Docket ID No. EPA-R07-RCRA-2016-0637, to
Lisa Haugen, EPA Region 7, Enforcement Coordination Office, 11201 Renner Boulevard, Lenexa, Kansas 66219, phone number: (913) 551-7877, or email address:
In the final rules section of the
Natural Resources Conservation Service (NRCS), U.S. Department of Agriculture (USDA).
Notice of availability of WEPP for soil erodibility system calculations scheduled for implementation for public review and comment.
Notice is hereby given of the intention of NRCS to implement the WEPP technology to replace the use of the Revised Universal Soil Loss Equation, Version 2 (RUSLE2), where applicable.
You may submit comments, identified by Docket Number NRCS-2016-0009, using any of the following methods:
•
•
•
NRCS will post all comments on
Norman Widman, National Agronomist, Ecological Sciences Division, Natural Resources Conservation Service, 1400 Independence Avenue Southwest, Room 6153, Washington, DC 20250.
The RUSLE2, an empirical erosion prediction model for calculating sheet and rill water erosion, is being replaced by WEPP technology for selected highly erodible compliance applications. The WEPP model is for use where water erosion is the primary causal factor for comparing the annual level of erosion before conservation system application to the expected annual level of erosion after conservation system application (
The implementation of the WEPP technology does not affect the highly erodible soil map unit list contained in the NRCS Field Office Technical Guide as of January 1, 1990. The factor values from the 1990 list will continue to be used for all erodibility index calculations, including sodbuster determinations and review of previous determinations.
The WEPP technology computer model is a process-based, daily time-step model that predicts soil erosion by simulating the fundamental processes controlling water erosion. WEPP calculates sheet and rill erosion rates and sediment deposition and delivery. The WEPP model also provides the user with spatial information regarding soil flux, deposition, and loss from specific regions of a field over time. The model is intended for conservation planning, assessing water erosion for NRCS' National Resources Inventory, and aiding the development of regional and national policy.
The WEPP modular design is amenable to incorporation of new features; thus, WEPP utility also is for estimating long-term soil productivity, the effect of climate change on crop growth and erosion, sediment depositional loading of lakes and streams, and ephemeral erosion prediction.
Further, WEPP aids in calculating onsite and offsite economic costs of erosion and assessing impacts of management strategies on public lands when used in conjunction with other models.
A complete summary of the processes utilized by the WEPP model can be seen in “WEPP Model Documentation” on the USDA Agricultural Research Service Web page at
The proposed implementation timeframe for WEPP in each NRCS field office with a water erosion concern is December 1, 2016. Section 1201(a)(11)(C) of the Food Security Act of 1985, as amended, (16 U.S.C. 3801(a)(11)(C)) requires NRCS to make available for public review and comment all proposed changes to equations to carry out the highly erodible land provisions of the law in a manner consistent with section 553 of title 5.
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
The meeting will take place on Monday, December 12, 2016, at 11:00 a.m. CST.
Public Call Information: Dial: 888-397-5335, Conference ID: 6723214.
Melissa Wojnaroski, DFO, at
Members of the public can listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 888-397-5335, conference ID: 6723214. 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 as time allows. 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. 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 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 Corrine Sanders at
Records generated from this meeting may be inspected and reproduced at the Regional Programs Unit Office, as they become available, both before and after the meeting. Records of the meeting will be available via
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 Minnesota Advisory Committee (Committee) will hold a meeting on Thursday, December 08, 2016, at 1:00pm CST for the purpose of preparing for a public hearing to gather testimony regarding civil rights and policing practices in Minnesota.
The meeting will be held on Thursday, December 8, 2016, at 1:00 p.m. CST.
Melissa Wojnaroski, DFO, at
Members of the public can listen to the discussion. This meeting is available to the public through the following toll-free call-in number: 877-857-6161, conference ID: 6681139. 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 as time allows. 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. 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 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 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 Regional Programs Unit Office, as they become available, both before and after the meeting. Records of the meeting will be available via
Economics and Statistics Administration (ESA), Department of Commerce.
Notice of Request for Nominations to the CDAC.
The Secretary of Commerce is requesting nomination of individuals to the Commerce Data Advisory Council. The Secretary will consider nominations received in response to this notice, as well as from other sources. The
The Economics and Statistics Administration must receive nominations for members by midnight December 1, 2016.
Please submit nominations to the email account
Burton Reist, Director of External Affairs, Economics and Statistics Administration, Department of Commerce, at (202) 482-3331 or email
The Department of Commerce (Department) collects, compiles, analyzes, and disseminates a treasure trove of data, including data on the Nation's economy, population, and environment. This data is fundamental to the Department's mission and is used for the protection of life and property, for scientific purposes, and to enhance economic growth. However, the Department's capacity to disseminate the increasing amount of data held and to disseminate it in formats most useful to its customers is significantly constrained.
In order to realize the potential value of the data the Department collects, stores, and disseminates, the Department must minimize barriers to accessing and using the data. Consistent with privacy and security considerations, the Department is firmly committed to unleashing its untapped data resources in ways that best support downstream information access, processing, analysis, and dissemination.
The Commerce Data Advisory Council (CDAC) provides advice and recommendations, to include process and infrastructure improvements, to the Secretary on ways to make Commerce data easier to find, access, use, combine and disseminate. The aim of this advice shall be to maximize the value of Commerce data to all users including governments, businesses, communities, academia, and individuals.
The Secretary will draw CDAC membership from the data industry academia, non-profits and state and local governments with a focus on recognized expertise in collection, compilation, analysis, and dissemination. As privacy concerns span the entire data lifecycle, expertise in privacy protection also will be represented on the Council. The Secretary will select members that represent the entire spectrum of Commerce data including demographic, economic, scientific, environmental, patent, and geospatial data. The Secretary will select members from the information technology, business, non-profit, and academic communities, and state and local governments. Collectively, their knowledge will include all types of data Commerce distributes and the full lifecycle of data collection, compilation, analysis, and dissemination.
The Council shall advise the Secretary on ways to make Commerce data easier to find, access, use, combine, and disseminate. Such advice may include recommended process and infrastructure improvements. The aim of this advice shall be to maximize the value of Commerce data to governments, businesses, communities, and individuals.
In carrying out its duties, the Council may consider the following:
Federal Advisory Committee Act (5 U.S.C. Appendix 2), which sets forth standards for the formation and use of advisory committees, is the governing instrument for the CDAC.
1. The Council shall consist of up to 20 members.
2. The Secretary shall select and appoint members and members shall serve at the pleasure of the Secretary.
3. Members shall represent a cross-section of business, academic, non-profit, and non-governmental organizations.
4. The Secretary will choose members of the Council who ensure objectivity and balance, a diversity of perspectives, and guard against potential for conflicts of interest.
5. Members shall be prominent experts in their fields, recognized for their professional and other relevant achievements and their objectivity.
6. In order to ensure the continuity of the Commerce Data Advisory Council, the Council shall be appointed so that each year the terms expire of approximately one-third of the members of the Council.
7. Council members serve for terms of two years and may be reappointed to any number of additional terms. Initial appointments may be for 12-, 18-and 24-month increments to provide staggered terms.
8. Nominees must be able to actively participate in the tasks of the Council, including, but not limited to regular
9. Should a council member be unable to complete a two-year term and when vacancies occur, the Secretary will select replacements who can best either replicate the expertise of the departing member or provide the CDAC with a new, identified needed area of expertise. An individual chosen to fill a vacancy shall be appointed for the remainder of the term of the member replaced or for a two-year term as deemed. A vacancy shall not affect the exercise of any power of the remaining members to execute the duties of the Council.
10. No employee of the federal government can serve as a member of the Census Scientific Advisory Committee.
All members of the Commerce Data Advisory Council shall adhere to the conflict of interest rules applicable to Special Government Employees as such employees are defined in 18 U.S.C. 202(a). These rules include relevant provisions in 18 U.S.C. related to criminal activity, Standards of Ethical Conduct for Employees of the Executive Branch (5 CFR part 2635), and Executive Order 12674 (as modified by Executive Order 12731).
1. Membership is under voluntary circumstances and therefore members do not receive compensation for service on the Commerce Data Advisory Council.
2. Members shall receive per diem and travel expenses as authorized by 5 U.S.C. 5703, as amended, for persons employed intermittently in the Government service.
The Secretary will consider nominations of all qualified individuals to ensure that the CDAC includes the areas of subject matter expertise noted above (see ”Background and Membership”). Individuals may nominate themselves or other individuals, and professional associations and organizations may nominate one or more qualified persons for membership on the CDAC. Nominations shall state that the nominee is willing to serve as a member of the Council.
A nomination package should include the following information for each nominee:
1. A letter of nomination stating the name, affiliation, and contact information for the nominee, the basis for the nomination (
2. A biographical sketch of the nominee and a copy of his/her resume or curriculum vitae; and
3. The name, return address, email address, and daytime telephone number at which the nominator can be contacted.
The Department of Commerce is committed to equal opportunity in the workplace and seeks diverse Committee membership. The Department has special interest in assuring that women, minority groups, and the physically disabled are adequately represented on advisory committees; and therefore, extends particular encouragement to nominations for appropriately qualified female, minority, or disabled candidates. The Department of Commerce also encourages geographic diversity in the composition of the Council. All nomination information should be provided in a single, complete package and received by the stated deadline, December 1, 2016. Interested applicants should send their nomination package to the email or postal address provided above.
Potential candidates will be asked to provide detailed information concerning financial interests, consultancies, research grants, and/or contracts that might be affected by recommendations of the Council to permit evaluation of possible sources of conflicts of interest. Finally, nominees will be required to certify that they are not subject to the Foreign Agents Registration Act (22 U.S.C. 611) or the Lobbying Disclosure Act (2 U.S.C. 1601
On July 13, 2016, Adient US LLC (Adient), owned by Johnson Controls, Inc., submitted a notification of proposed production activity to the Foreign-Trade Zones (FTZ) Board for its facility within FTZ 189D, at sites in Holland and Zeeland, Michigan.
The notification was processed in accordance with the regulations of the FTZ Board (15 CFR part 400), including notice in the
An application has been submitted to the Foreign-Trade Zones (FTZ) Board by the McAllen Foreign Trade Zone, Inc., grantee of FTZ 12, requesting authority to reorganize the zone 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. The application was submitted pursuant to 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 November 10, 2016.
FTZ 12 was approved by the FTZ Board on October 23, 1970 (Board Order 84, 35 FR 16962, November 3, 1970), and expanded on May 2, 1984 (Board Order 254, 49 FR 22842, June 1, 1984), on June 19, 1990 (Board Order 469, 55 FR 26225, June 27, 1990), on April 29, 1996 (Board Order 819, 61 FR 21157, May 9, 1996), and on January 21, 2003 (Board Order 1266, 68 FR 5271-5272, February 3, 2003).
The current zone includes the following sites:
The grantee's proposed service area under the ASF would be Hidalgo County, Texas, as described in the application. If approved, the grantee would be able to serve sites throughout the service area based on companies' needs for FTZ designation. The application indicates that the proposed service area is within and adjacent to the Hidalgo/Pharr Customs and Border Protection port of entry.
The applicant is requesting authority to reorganize its existing zone to include all of the existing sites as “magnet” sites. 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. No subzones/usage-driven sites are being requested at this time. The application would have no impact on FTZ 12's previously authorized subzone.
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 January 17, 2017. Rebuttal comments in response to material submitted during the foregoing period may be submitted during the subsequent 15-day period to January 31, 2017.
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
For further information, contact Camille Evans at
Enforcement and Compliance, International Trade Administration, Department of Commerce.
In response to requests from ArcelorMittal USA LLC, Nucor Corporation, United States Steel Corporation, and AK Steel Corporation, as well as Steel Dynamics, Inc. and California Steel Industries, (collectively, Domestic Producers), the Department of Commerce (the Department) is initiating anti-circumvention inquiries to determine whether imports of certain cold-rolled steel flat products (CRS), which are produced in the Socialist Republic of Vietnam (Vietnam) from hot-rolled steel produced in the People's Republic of China (PRC), are circumventing the antidumping duty (AD) and countervailing duty (CVD) orders on CRS from the PRC.
Effective November 17, 2016.
John K. Drury or Victoria Cho, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-0195 or (202) 482-5075, respectively.
On July 28, 2015, AK Steel Corporation, ArcelorMittal USA EEC, Nucor Corporation, Steel Dynamics, Inc., and the United States Steel Corporation (collectively, Petitioners) filed petitions seeking the imposition of antidumping and countervailing duties on imports of CRS from Brazil, the People's Republic of China, India, Japan, the Republic of Korea, the Netherlands, Russia, and the United Kingdom. Following the Department's final affirmative determinations of dumping and countervailable subsidies,
On September 22, 2016, pursuant to section 781(b) of the Tariff Act of 1930, as amended (the Act) and 19 CFR 351.225(h), Steel Dynamics, Inc. and California Steel Industries submitted a request for the Department to initiate anti-circumvention inquiries to determine whether producers of CRS in Vietnam are circumventing the
On October 17, 2016, we received comments objecting to the allegation from Metallia U.S.A., LLC, Metallia, A Division of Hartree Partners, LP, Nippon Steel and Sumiken Bussan Americas Inc., Mitsui & Co. (U.S.A.), Inc., and Marubeni-Itochu Steel America Inc. (MISA).
The products covered by the orders are certain cold-rolled (cold-reduced), flat-rolled steel products, whether or not annealed, painted, varnished, or coated with plastics or other nonmetallic substances. The products covered do not include those that are clad, plated, or coated with metal. The products covered include coils that have a width or other lateral measurement (“width”) of 12.7 mm or greater, regardless of form of coil (
(1) Where the nominal and actual measurements vary, a product is within the scope if application of either the nominal or actual measurement would place it within the scope based on the definitions set forth above, and
(2) where the width and thickness vary for a specific product (
Steel products included in the scope of the orders are products in which: (1) Iron predominates, by weight, over each of the other contained elements; (2) the carbon content is 2 percent or less, by weight; and (3) none of the elements listed below exceeds the quantity, by weight, respectively indicated:
Unless specifically excluded, products are included in this scope regardless of levels of boron and titanium.
For example, specifically included in this scope are vacuum degassed, fully stabilized (commonly referred to as interstitial-free (IF)) steels, high strength low alloy (HSLA) steels, motor lamination steels, Advanced High Strength Steels (AHSS), and Ultra High Strength Steels (UHSS). If steels are recognized as low carbon steels with micro-alloying levels of elements such as titanium and/or niobium added to stabilize carbon and nitrogen elements. HSLA steels are recognized as steels with micro-alloying levels of elements such as chromium, copper, niobium, titanium, vanadium, and molybdenum. Motor lamination steels contain micro-alloying levels of elements such as silicon and aluminum. AHSS and UHSS are considered high tensile strength and high elongation steels, although AHSS and UHSS are covered whether or not they are high tensile strength or high elongation steels.
Subject merchandise includes cold-rolled steel that has been further processed in a third country, including but not limited to annealing, tempering, painting, varnishing, trimming, cutting, punching, and/or slitting, or any other processing that would not otherwise remove the merchandise from the scope of the orders if performed in the country of manufacture of the cold-rolled steel.
All products that meet the written physical description, and in which the chemistry quantities do not exceed any one of the noted element levels listed above, are within the scope of the orders unless specifically excluded. The following products are outside of and/or specifically excluded from the scope of the orders:
• Ball bearing steels;
• Tool steels;
• Silico-manganese steel;
• Grain-oriented electrical steels (GOES) as defined in the final determination of the U.S. Department of Commerce in
• Non-Oriented Electrical Steels (NOES), as defined in the antidumping orders issued by the U.S. Department of Commerce in
The products subject to the orders are currently classified in the Harmonized Tariff Schedule of the United States (HTSUS) under item numbers: 7209.15.0000, 7209.16.0030, 7209.16.0060, 7209.16.0070, 7209.16.0091, 7209.17.0030, 7209.17.0060, 7209.17.0070, 7209.17.0091, 7209.18.1530, 7209.18.1560, 7209.18.2510, 7209.18.2520, 7209.18.2580, 7209.18.6020, 7209.18.6090, 7209.25.0000, 7209.26.0000, 7209.27.0000, 7209.28.0000, 7209.90.0000, 7210.70.3000, 7211.23.1500, 7211.23.2000, 7211.23.3000, 7211.23.4500, 7211.23.6030, 7211.23.6060, 7211.23.6075, 7211.23.6085, 7211.29.2030, 7211.29.2090, 7211.29.4500, 7211.29.6030, 7211.29.6080, 7211.90.0000, 7212.40.1000, 7212.40.5000, 7225.50.6000, 7225.50.8015, 7225.50.8085, 7225.99.0090, 7226.92.5000, 7226.92.7050, and 7226.92.8050.
The products subject to the orders may also enter under the following HTSUS numbers: 7210.90.9000, 7212.50.0000, 7215.10.0010, 7215.10.0080, 7215.50.0016, 7215.50.0018, 7215.50.0020, 7215.50.0061, 7215.50.0063, 7215.50.0065, 7215.50.0090, 7215.90.5000, 7217.10.1000, 7217.10.2000, 7217.10.3000, 7217.10.7000, 7217.90.1000, 7217.90.5030, 7217.90.5060, 7217.90.5090, 7225.19.0000, 7226.19.1000, 7226.19.9000, 7226.99.0180, 7228.50.5015, 7228.50.5040, 7228.50.5070, 7228.60.8000, and 7229.90.1000.
The HTSUS subheadings above are provided for convenience and customs purposes only. The written description of the scope of the orders is dispositive.
These anti-circumvention inquiries cover CRS exported from Vietnam produced from HRS exported from the PRC.
Section 781(b)(1) of the Act provides that the Department may find circumvention of an AD or CVD order when merchandise of the same class or kind subject to the order is completed or assembled in a foreign country other than the country to which the order applies. In conducting an anti-circumvention inquiry, under section 781(b)(1) of the Act, the Department relies on the following criteria: (A) Merchandise imported into the United States is of the same class or kind as any merchandise produced in a foreign country that is the subject of an antidumping or countervailing duty order or finding; (B) before importation into the United States, such imported merchandise is completed or assembled in another foreign country from merchandise which is subject to the order or merchandise which is produced in the foreign country that is subject to the order; (C) the process of assembly or completion in the foreign country referred to in section (B) is minor or insignificant; (D) the value of the merchandise produced in the foreign country to which the AD or CVD order applies is a significant portion of the total value of the merchandise exported to the United States; and (E) the administering authority determines that action is appropriate to prevent evasion of such order or finding. As discussed below, Domestic Producers provided evidence with respect to these criteria.
Domestic Producers claim that CRS exported to the United States is the same class or kind as that covered by the
Domestic Producers note that section 781(b)(l)(B)(ii) of the Act requires that “the Department must also determine whether, prior to importation into the United States, the merchandise in the third country is completed from merchandise produced in the country subject to the antidumping or countervailing duty order.”
Domestic Producers maintain that the process for completing CRS from HRS is minor or insignificant. Under section 781(b)(2) of the Act, the Department considers five factors to determine whether the process of assembly or completion is minor or insignificant. Domestic Producers allege that the production of HRS in the PRC, which is subsequently further processed into CRS in Vietnam, comprises the majority of the value associated with the merchandise imported into the United States, and that the processing of HRS into CRS in Vietnam adds relatively little value.
Domestic Producers contend that the level of investment necessary to construct a factory which can produce CRS from HRS in Vietnam is insignificant. In support of its contention, Domestic Producers compare the investment necessary to install a re-rolling facility with the investment necessary to produce HRS using a fully-integrated production process for melting iron and making steel.
Domestic Producers assert that the level of research and development in Vietnam is either minimal or non-existent. Domestic Producers state that Vietnam is importing technology from other sources, rather than developing its own technology.
According to Domestic Producers, the production process undertaken by Vietnamese producers of CRS is less complex than steelmaking, and minimal in nature.
Domestic Producers provide information indicating that production facilities in Vietnam are more limited compared to facilities in the PRC.
Domestic Producers assert that producing HRS in the PRC accounts for a large percentage of the total value of CRS that is produced in Vietnam using HRS from the PRC. Using information from the recent CRS investigation by the ITC, Domestic Producers state that the price of HRS is consistently between 80 percent and 90 percent of the value of CRS.
Section 781(b)(3) of the Act directs the Department to consider additional factors in determining whether to include merchandise assembled or completed in a foreign country within the scope of the order, such as: “(A) the pattern of trade, including sourcing patterns, (B) whether the manufacturer or exporter of the merchandise . . . is affiliated with the person who uses the merchandise. . . to assemble or complete in the foreign country the merchandise that is subsequently imported into the United States, and (C) whether imports into the foreign country of the merchandise. . . have increased after the initiation of the investigation which resulted in the issuance of such order or finding.”
Domestic Producers provide information reflecting that at the time the petitions were filed for the original investigations of CRS from the PRC, Vietnam was not a source of U.S. imports of CRS in 2014. Domestic
Domestic Producers have not provided any allegation of affiliation between producers of HRS in the PRC and producers of CRS in Vietnam.
Domestic Producers presented evidence indicating that imports of HRS from the PRC to Vietnam have increased since the initiation of the investigations of CRS from the PRC.
Based on our analysis of Domestic Producers anti-circumvention allegations and the information provided therein, the Department determines that anti-circumvention inquiries of the AD and CVD orders on CRS from the PRC are warranted.
With regard to whether the merchandise from Vietnam is of the same class or kind as the merchandise produced in the PRC, Domestic Producers presented information to the Department indicating that, pursuant to section 781(b)(1)(A) of the Act, the merchandise being produced in and/or exported from Vietnam is of the same class or kind as CRS produced in the PRC, which is subject to the
With regard to completion or assembly of merchandise in a foreign country, pursuant to section 781(b)(1)(B) of the Act, Domestic Producers also presented information to the Department indicating that the CRS exported from Vietnam to the United States is produced in Vietnam using HRS from the PRC.
The Department finds that Domestic Producers sufficiently addressed the factors described in section 781(b)(1)(C) and 781(b)(2) of the Act regarding whether the process of assembly or completion of CRS in Vietnam is minor or insignificant. In particular, information in Domestic Producers' submission indicates that: (1) The level of investment in re-rolling facilities is minimal when compared with the level of investment for basic steel making facilities; (2) there is little or no research and development taking place in Vietnam; (3) the CRS production processes involve the simple processing of HRS from a country subject to the
With respect to the value of the merchandise produced in the PRC, pursuant to section 781(b)(1)(D) of the Act, Domestic Producers relied on published sources, a simulated cost structure for producing CRS in Vietnam, and arguments in the “minor or insignificant process” portion of its anti-circumvention allegation to indicate that the value of the key material, HRS, produced in the PRC may be significant relative to the total value of the CRS exported to the United States. We find that this information adequately meets the requirements of this factor, as discussed above, for the purposes of initiating these anti-circumvention inquiries.
Finally, with respect to the additional factors listed under section 781(b)(3) of the Act, we find that Domestic Producers presented evidence indicating that shipments of CRS from Vietnam to the United States increased since the imposition of the
In connection with these anti-circumvention inquiries, in order to determine, (1) the extent to which PRC-sourced HRS is further processed into CRS in Vietnam before shipment to the United States, (2) the extent to which a country-wide finding applicable to all exports might be warranted, as alleged by Domestic Producers, and (3) whether the process of turning PRC-sourced HRS into CRS is minor or insignificant, the Department intends to issue questionnaires to solicit information from interested parties. The Department intends to issue questionnaires to solicit information from the Vietnamese producers and exporters concerning their shipments of CRS to the United States and the origin of the imported HRS being processed into CRS. A company's failure to respond completely to the Department's requests for information may result in the application of partial or total facts available, pursuant to section 776(a) of the Act, which may include adverse inferences, pursuant to section 776(b) of the Act.
While we believe sufficient factual information has been submitted by Domestic Producers supporting their request for inquiries, we do not find that the record supports the simultaneous issuance of a preliminary ruling. Such inquiries are by their nature typically complicated and can require information regarding production in both the country subject to the order and the third country completing the product. As noted above, the Department intends to request additional information regarding the statutory criteria to determine whether shipments of CRS from Vietnam are circumventing the AD and CVD orders on CRS from the PRC. Thus, with further development of the record required before a preliminary ruling can be issued, the Department does not find it appropriate to issue a preliminary ruling at this time.
In accordance with 19 CFR 351.225(e), the Department finds that the issue of whether a product is
In accordance with 19 CFR 351.225(l)(2), if the Department issues a preliminary affirmative determination, we will then instruct U.S. Customs and Border Protection to suspend liquidation and require a cash deposit of estimated antidumping and countervailing duties, at the applicable rate, for each unliquidated entry of the merchandise at issue, entered or withdrawn from warehouse for consumption on or after the date of initiation of the inquiry. The Department will establish a schedule for questionnaires and comments on the issues. In accordance with section 781(f) of the Act and 19 CFR 351.225(f)(5), the Department intends to issue its final determination within 300 days of the date of publication of this initiation.
This notice is published in accordance with 19 CFR 351.225(f).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
Based on affirmative final determinations by the Department of Commerce (“Department”) and the International Trade Commission (“ITC”), the Department is issuing antidumping duty (“AD”) and countervailing duty (“CVD”) orders on welded stainless pressure pipe (“WSPP”) from India.
Effective November 17, 2016.
Alex Rosen at (202) 482-7814 or Mandy Mallot at (202) 482-6430, AD/CVD Operations, Office III, Enforcement and Compliance, U.S. Department of Commerce, 1401 Constitution Avenue NW., Washington, DC 20230.
In accordance with sections 705(d) and 735(d) of the Tariff Act of 1930, as amended (“Act”), on September 29, 2016, the Department published its affirmative final determination of sales at less than fair value (“LTFV”) and its affirmative final determination that countervailable subsidies are being provided to producers and exporters of WSPP from India.
The merchandise covered by these orders is circular welded austenitic stainless pressure pipe not greater than 14 inches in outside diameter. For purposes of this scope, references to size are in nominal inches and include all products within tolerances allowed by pipe specifications. This merchandise includes, but is not limited to, the American Society for Testing and Materials (“ASTM”) A-312 or ASTM A-778 specifications, or comparable domestic or foreign specifications. ASTM A-358 products are only included when they are produced to meet ASTM A-312 or ASTM A-778 specifications, or comparable domestic or foreign specifications.
Excluded from the scope are: (1) Welded stainless mechanical tubing, meeting ASTM A-554 or comparable domestic or foreign specifications; (2) boiler, heat exchanger, superheater, refining furnace, feedwater heater, and condenser tubing, meeting ASTM A-249, ASTM A-688 or comparable domestic or foreign specifications; and (3) specialized tubing, meeting ASTM A-269, ASTM A-270 or comparable domestic or foreign specifications.
The subject imports are normally classified in subheadings 7306.40.5005, 7306.40.5040, 7306.40.5062, 7306.40.5064, and 7306.40.5085 of the Harmonized Tariff Schedule of the United States (“HTSUS”). They may also enter under HTSUS subheadings 7306.40.1010, 7306.40.1015, 7306.40.5042, 7306.40.5044, 7306.40.5080, and 7306.40.5090. The HTSUS subheadings are provided for convenience and customs purposes only; the written description of the scope of these orders is dispositive.
In accordance with sections 735(b)(1)(A)(i) and 735(d) of the Act, the ITC has notified the Department of its final determination that an industry in the United States is materially injured by reason of imports of WSPP that are subsidized by the government of India and sold in the United States at LTFV. Therefore, in accordance with section 735(c)(2) of the Act, we are publishing this antidumping duty order. Because the ITC determined that imports of WSPP from India are materially injuring a U.S. industry, unliquidated entries of such merchandise from India, entered or withdrawn from warehouse for consumption, are subject to the assessment of antidumping duties.
In accordance with section 736(a)(1) of the Act, the Department will direct U.S. Customs and Border Protection (“CBP”) to assess, upon further instruction by the Department, antidumping duties equal to the amount by which the normal value of the merchandise exceeds the export price (or constructed export price) of the merchandise, for all relevant entries of WSPP from India. Antidumping duties will be assessed on unliquidated entries of WSPP from India entered, or withdrawn from warehouse, for consumption on or after May 10, 2016, the date of publication of the
Section 733(d) of the Act states that instructions issued pursuant to an affirmative preliminary determination may not remain in effect for more than four months, except where exporters representing a significant proportion of exports of the subject merchandise request the Department to extend that four-month period to no more than six months. At the request of exporters that account for a significant proportion of WSPP from India, the Department extended the four-month period to six months.
Therefore, in accordance with section 733(d) of the Act and our practice,
In accordance with section 735(c)(1)(B) of the Act, we will instruct CBP to continue to suspend liquidation on entries of subject merchandise from India. These instructions suspending liquidation will remain in effect until further notice.
We will also instruct CBP to require cash deposits equal to the amounts as indicated below, except for Sunrise Stainless Pvt. Ltd. and Sun Mark Stainless Pvt. Ltd. (collectively, “Sunrise Group”), which are adjusted for certain countervailable subsidies, where appropriate, as described below.
The weighted-average antidumping duty margin percentages are as follows:
In accordance with sections 705(b)(1)(A)(i) and 705(d) of the Act, the ITC notified the Department of its final determination that the industry in the United States producing WSPP is materially injured by reason of subsidized imports of WSPP from India.
Pursuant to section 706(a) of the Act, the Department will direct CBP to assess, upon further instruction by the Department, countervailing duties on unliquidated entries of WSPP entered, or withdrawn from warehouse, for consumption on or after March 11, 2016, the date on which the Department published its affirmative preliminary countervailing duty determination in the
In accordance with section 706 of the Act, the Department will direct CBP to reinstitute suspension of liquidation, effective on the date of publication of the ITC's notice of final determination in the
This notice constitutes the AD and CVD orders with respect to WSPP from India pursuant to sections 736(a) and 706(a) of the Act. Interested parties can find an updated list of orders currently in effect by either visiting
These orders are published in accordance with sections 706(a), 736(a), and 777(i) of the Act, and 19 CFR 351.211(b).
Enforcement and Compliance, International Trade Administration, Department of Commerce.
In response to a request from Salvi Chemical Industries Ltd. (Salvi), the Department of Commerce (the Department) is initiating a changed circumstances review of the antidumping duty order on glycine from the People's Republic of China (PRC).
Effective November 17, 2016.
Dena Crossland or Brian Davis, AD/CVD Operations, Office VI, Enforcement and Compliance, International Trade Administration, U.S. Department of Commerce, 14th Street and Constitution Avenue NW., Washington, DC 20230; telephone: (202) 482-3362 or (202) 482-7924, respectively.
On July 18, 2016, the Department received a request from Salvi to initiate a changed circumstances review in order for the Department to determine that the glycine produced by Salvi is no longer processed from PRC-origin glycine.
On July 26, 2016, the Department received comments from domestic interested party, GEO Specialty Chemicals, Inc. (GEO), regarding Salvi's request.
The product covered by this antidumping duty order is glycine, which is a free-flowing crystalline material, like salt or sugar. Glycine is produced at varying levels of purity and is used as a sweetener/taste enhancer, a buffering agent, reabsorbable amino acid, chemical intermediate, and a metal complexing agent. This proceeding includes glycine of all purity levels. Glycine is currently classified under subheading 2922.49.4020 of the Harmonized Tariff Schedule of the United States (HTSUS).
Pursuant to section 751(b)(1) of the Tariff Act of 1930, as amended (the Act), the Department will conduct a changed circumstances review upon receipt of information concerning, or a request from an interested party of, an antidumping duty order which shows changed circumstances sufficient to warrant a review of the order. In accordance with 19 CFR 351.216(d), based on the information provided by Salvi, the Department finds that there is sufficient information to initiate a changed circumstances review. Therefore, we are initiating a changed circumstances review pursuant to section 751(b)(1) of the Act and 19 CFR 351.216(d) to determine whether Salvi is no longer processing PRC-origin glycine, and instead is producing glycine from raw materials of non-PRC origin, and whether it should be able to participate in the certification process described in the Final Scope Ruling. The Department intends to publish in the
This notice is in accordance with section 751(b)(1) of the Act.
The Department of Commerce will submit to the Office of Management and Budget (OMB) for clearance the following proposal for collection of information under the provisions of the Paperwork Reduction Act (44 U.S.C. Chapter 35).
The Southern Distinct Population Segment of North American green sturgeon (
To ensure that activities qualify under exceptions to or exemptions from the take prohibitions, local, state, and federal agencies, non-governmental organizations, academic researchers, and private organizations are asked to voluntarily submit detailed information regarding their activity on a schedule to be determined by National Marine Fisheries Service (NMFS) staff. This information is used by NMFS to (1) track the number of Southern DPS fish taken as a result of each action; (2) understand and evaluate the cumulative effects of each action on the Southern DPS; and (3) determine whether additional protections are needed for the species, or whether additional exceptions may be warranted. NMFS designed the criteria to ensure that plans meeting the criteria would adequately limit impacts on threatened Southern DPS fish, such that additional protections in the form of a federal take prohibition would not be necessary and advisable.
This information collection request may be viewed at
Written comments and recommendations for the proposed information collection should be sent within 30 days of publication of this notice to
National Oceanic and Atmospheric Administration, Department of Commerce.
Notice of availability; request for comments.
The National Oceanic and Atmospheric Administration (NOAA) publishes this notice to request comments on its draft Companion Manual to NOAA Administrative Order NAO 216-6A (“Companion Manual”) containing policy and procedures for implementing the National Environmental Policy Act (NEPA) and related authorities. Included in the Companion Manual are NOAA's proposed revised categorical exclusions (CE) and related extraordinary circumstances. Pursuant to Council on Environmental Quality (CEQ) regulations, NOAA is soliciting comments on its proposed procedures from members of the interested public. Additionally, in this notice, NOAA is providing a synopsis of the proposed changes to NOAA's CEs to assist the public in reviewing those changes.
Comments on the revised NEPA procedures must be received by December 19, 2016.
Comments on NOAA's proposed NEPA procedures may be submitted through one of these methods: (1)
Please send questions by email to
NEPA (42 U.S.C. 4321
NEPA and the CEQ implementing regulations provide for environmental review of a proposed government action in the form of an Environmental Assessment (EA), Environmental Impact Statement (EIS), or Categorical Exclusion (CE). A CE is “a category of actions which do not individually or cumulatively have a significant effect on the human environment,” and, based on the agency's past experience, does not require further NEPA review in the form of either an EA or EIS.
On April 22, 2016, NOAA issued NOAA Administrative Order 216-6A (NAO 216-6A), which updated NOAA's policy for compliance with NEPA, the CEQ NEPA regulations, and other related authorities, including Executive Order (EO) 12114,
NOAA last updated its NEPA Procedures in 1999. In order to ensure that its procedures, including CEs and
Upon review of NOAA's overall NEPA procedures, the agency determined that its existing procedures would benefit from clarifying revisions and that NOAA's CEs would benefit from revisions to clarify the scope and applicability and that several new CEs were appropriate to improve NEPA review by categorically excluding actions that, based on NOAA's experience, have no potential to significantly impact the human environment. In some instances, NOAA determined that providing additional language to describe the categories of actions covered by an existing CE was necessary to clarify the intended scope of that CE. In other cases, NOAA determined that the scope of a CE was unclear because it covered too many disparate activities with few meaningful limitations. The Working Group determined that breaking out components of these CEs into discrete CEs that accurately described the category of actions to be excluded from further NEPA review and including appropriately limiting language clarified the proper scope and application of the CE for the decision maker. Additionally, NOAA identified CEs that either lacked adequate substantiation or were no longer necessary because of mission changes. Accordingly, NOAA proposes to eliminate these types of CEs.
NOAA proposes to substantiate its new and revised CEs by benchmarking other agencies' CEs, relying on previously implemented actions, and/or relying on the expert opinions of NOAA's professional staff, all of which are methods recommended by CEQ to substantiate proposed new or revised CEs.
Additionally, and where appropriate, NOAA relied on its professional staff to analyze the activities encompassed by the proposed CEs and explain the expert's conclusion that those activities have no potential for significant effects on the environment. Finally, NOAA relied on its own experience with previously implemented actions (
Certain terms appear frequently in the language of NOAA's proposed CEs to limit their scope and ensure they are applied properly and limited to those activities that NOAA has determined have no potential for significant impacts. The following list presents and describes these terms:
(1) “Previously disturbed ground” refers to land that has been changed such that its functioning ecological processes have been and remain substantially altered by human activity. The term encompasses areas that have been transformed from natural cover to non-native species or a developed state, including but not limited to, utility and electrical power transmission corridors and rights-of-way, paved and unpaved roads, and construction footprints.
(2) “Minor” and “small-scale” are terms NOAA considers in the context of the particular proposal, including its proposed location. In assessing whether a proposed action is small, in addition to the actual magnitude of the proposal, NOAA considers factors such as industry norms and the relationship of the proposed action to similar types of development or activity in the vicinity of the proposed action. When considering the size of a proposed facility, for example, NOAA would review the surround land uses, the scale of the proposed action relative to existing development, and the capacity of existing roads and other infrastructure to support the proposed action. When these limiting terms are used within a specific CE, the administrative record for that CE provides further explanation of their meaning in the context of the activity addressed by that CE.
(3) “Negligible” refers to a level of impact that is below significant to the point of being hardly detectable. Factors for consideration include: Procedures that employ generally accepted industry standards or best management practices that have been tested and verified at the time an activity is proposed; whether an activity has understood or well-documented impacts at the time an activity is proposed; whether control and quality measures are in place (
NOAA's proposed revised CEs are organized into eight series, based on the types of activities encompassed by each group. Series A encompasses CEs that pertain to Trust Resource Management Actions. B pertains to Trust Resource Authorization and Permitting Actions. C pertains to Habitat Restoration Actions. D pertains to Additional External Funding. E pertains to Research Actions. F pertains to Real and Personal Property Improvement, Maintenance, and Construction Actions. G pertains to Operational Actions. Finally, H pertains to Acquisition and Leasing Actions.
The following list presents NOAA's proposed CEs, followed by a description of the CE's relationship to the existing CEs from the 1999 NAO and an explanation of how and why a CE was revised or developed.
[A1]. “An action that is a technical correction or a change to a fishery management action or regulation, which does not result in a substantial change in any of the following: Fishing location, timing, effort, authorized gear types, access to fishery resources or harvest levels.”
NOAA proposes to consolidate components of several CEs from the 1999 NOA: 6.03a.3(b)(1), 6.03a.3(b)(2), 6.03d.4(a), and 6.03d.4(b). NOAA realized in implementing NEPA since 1999 that there were several very similar CEs that frequently served the same purpose. NOAA also determined that it would be most helpful for practitioners to address different types of management plans in separate CEs so that limitations to ensure that the category of actions would not result in significant impacts were appropriate to the types of management plan in place. Accordingly, consolidating these classes of actions into a single CE for fishery management actions and regulations clarified the CE's scope and applicability for decision makers. The proposed revision limits the scope of the CE so that any corrections or changes to which the CE is to be applied may not result in a substantial change in fishing location, timing, effort, authorized gear types, access to fishery resources or harvest levels. The proposed changes and revisions do not result in a substantial change in scope or applicability from the listed CEs in the 1999 NAO.
[A2]. “Preparation of a recovery plan pursuant to section 4(f)(1) of the ESA. Such plans are advisory documents that provide consultative and technical assistance in recovery planning and do not implement site-specific or species-specific management actions. However, implementation of specific tasks identified in a recovery plan may require an EA or EIS depending on the nature of the action.”
NOAA proposes to revise CE 6.03e.3(a) by adding “and do not direct site-specific or species-specific management actions” to the definition of consultative. NOAA's use of the language “. . .
[A3.] “Temporary fishery closures or extensions of closures under section 305(c)(3)(C) of the Magnuson-Stevens Fishery Conservation and Management Act to ensure public health and safety.”
NOAA proposes a new CE to cover temporary fishery closures or extensions of closures under section 305(c)(3)(C) of the Magnuson-Stevens Fishery Conservation and Management Act to ensure public health and safety following a public health emergency or an oil spill.
[A4.] “Minor updates to existing national marine sanctuary management plans. This CE does not apply to sanctuary designations, expansions, changes in terms of designation, or new sanctuary management plans.”
NOAA proposes to consolidate components of two CEs from the 1999 NOA: 6.03a.3(b)(1) and 6.03a.3(b)(2). NOAA realized in implementing NEPA since 1999 that there were several very similar CEs that frequently served the same purpose. NOAA also determined that discrete CEs with appropriately limiting language specific to different types of management plans would be most helpful to decision makers. Accordingly, consolidating these classes of actions into a single CE for minor updates to existing national marine sanctuary management plans clarified the CE's scope and applicability for decision makers. NOAA proposes to explicitly limit the use of this CE by not allowing the category to be applied to actions that are amendments or changes to a management plan that affect sanctuary boundaries or to new sanctuary management plans. The National Marine Sanctuaries Act (16 U.S.C. 1431
[A5.] “Updates to existing National Estuarine Research Reserve (NERR) management plans, provided that the update does not change NERR boundaries or add or significantly change allowable uses, uses requiring a permit, or restrictions on uses. This CE does not apply to new NERR management plans, or to the execution of any specific action subsequently funded to support the updated NERR management plan.”
NOAA proposes to consolidate components of two CEs from the 1999 NOA: 6.03a.3(b)(1) and 6.03a.3(b)(2). NOAA realized in implementing NEPA since 1999 that there were several very similar CEs that frequently served the same purpose. NOAA also determined that discrete CEs with appropriately limiting language specific to different types of management plans would be most helpful to decision makers. Accordingly, consolidating these classes of actions into a single CE for updates to existing NERR management plans clarified the CE's scope and applicability for decision makers. The CE is limited so that it may not be applied to actions where the update changes reserve boundaries and the change adds or significantly changes allowable uses requiring a permit, or restrictions on uses. Additionally the CE is limited in that it does not apply to new NERR management plans, or to the execution of any specific action subsequently funded to support the updated NERR management plan. The proposed changes and revisions do not result in a substantial change in scope or applicability from the listed CEs in the 1999 NAO.
[A6.] “Review and approval of changes to state coastal management programs under the Coastal Zone Management Act (CZMA) § 306(e) (16 U.S.C. 1455(e)) and NOAA's regulations at 15 CFR part 923.”
NOAA proposes to consolidate components of two CEs: 6.03a.3(b)(1) and 6.03a.3(b)(2). NOAA realized in implementing NEPA since 1999 that there were several very similar CEs that frequently served the same purpose. NOAA also determined that discrete CEs with appropriately limiting language specific to different types of management plans would be most helpful to decision makers. Accordingly, consolidating these classes of actions into a single CE for review and approval of changes to state coastal management programs under the CZMA 16 U.S.C. 1455(e) and NOAA's regulations at 15 CFR part 923 clarified the CE's scope and applicability for decision makers. The Working Group determined that these statutory and regulatory limitations appropriately limited the scope of the CE so that activities encompassed by the CE have no potential for significant effects on the environment under normal circumstances.
[B1.] “Issuance of permits or permit modifications under section 10(a)(1)(A) of the ESA for take, import, or export of endangered species for scientific purposes or to enhance the propagation or survival of the affected species, or in accordance with the requirements of an ESA section 4(d) regulation for threatened species.”
NOAA proposes to make minor revisions to CE 6.03e.3(b) by adding section 4(d) of the ESA to the text of the CE. The intent and purpose of Sections
[B2.] “Issuance of permits or permit amendments under section 104 of the MMPA for take or import of marine mammals for scientific research, enhancement, commercial or educational photography or public display purposes; and issuance of Letters of Confirmation under the General Authorization for scientific research involving only Level B harassment.”
NOAA proposes to revise CE 6.03f.2(a) by removing section 101(a)(1) of the MMPA from the text of the CE. The reference to section 101(a)(1) was incorrect in the 1999 version and the revision corrects this error. The proposed revision does not result in any change in the scope or applicability of the CE.
[B3.] “Issuance of, and amendments to, “low effect” Incidental Take Permits and their supporting “low effect” Habitat Conservation Plans under section 10(a)(1)(B) of the ESA.”
NOAA proposes minor text edits to revise CE 6.03e.3(d) for clarification and readability. The proposed revision does not result in a substantial change on the scope or applicability of the CE.
[B4.] “Issuance of incidental harassment authorizations under section 101(a)(5)(A) and (D) of the MMPA for the incidental, but not intentional, take by harassment of marine mammals during specified activities and for which no serious injury or mortality is anticipated.”
NOAA proposes to maintain CE 6.03f.2(b) and revise the language to clarify the proper scope and application of the CE. The 1999 NAO included an error that referred to only section 101(a)(5)(A) of the Marine Mammal Protection Act—this error has been corrected in this revision, which now properly refers to both sections 101(a)(5)(A) and 101(a)(5)(D). Additionally, the 1999 version of the CE required authorizations to be “tiered from a programmatic environmental review” and this requirement has been removed. NOAA currently reviews small take incidental harassment authorizations under NEPA without the need for a “tiering” process. Accordingly, the proposed revision does not result in a substantial change in scope or applicability from the CEs in the 1999 NAO.
NOAA proposes four new CEs—B5, B6, B7, and B8—to cover the issuance of, or amendments to general permits, special use permits, authorizations, and certifications for activities conducted within National Marine Sanctuaries. Previously, NOAA had applied CEs 6.03c.3(a), 6.03c.3(c), 6.03c.3(d), and 6.03c.(3)(i) to address these actions. The Working Group determined that proposing new CEs that specifically encompass the actions described in B5, B6, B7, B8, B9, and B10 clarified the scope and applicability of the CEs for decision makers. Each CE is limited by conditions to ensure that activities encompassed by the CEs have no potential for significant effects on the environment under normal circumstances.
[B5.] “Issuance of, or amendments to, general permits for activities that are included in established permit categories at 15 CFR part 922 and that meet the regulatory review criteria at 15 CFR part 922, that limit any potential impacts so that the proposed activity will be conducted in a manner compatible with the National Marine Sanctuaries Act's primary objective of resource protection.”
[B6.] “Issuance of, or amendments to, special use permits for activities in a national marine sanctuary that are necessary to either establish conditions of access to and use of any sanctuary resource or promote public use and understanding of a sanctuary resource and must be conducted in a manner that does not destroy, cause the loss of, or injure sanctuary resources in accordance with the National Marine Sanctuaries Act.”
[B7.] “Issuance of or amendments to, authorizations for activities allowed by a valid federal, regional, state, local or tribal government approval (
[B8.] “Issuance of, or amendments to certifications for pre-existing activities authorized by a valid federal, regional, state, local, or tribal government approval (
[B9.] “Issuance of, or amendments to Papahānaumokuākea Marine National Monument (as established by Presidential Proclamation 8031) permits for activities that are included in established permit categories (50 CFR part 404) and that meet the regulatory review criteria at (50 CFR 404.11), that limit any potential impacts so that the proposed activity will be conducted in a manner compatible with the monument's primary objective of resource protection.”
NOAA proposes a new CE to cover the issuance of, or amendments to Papahānaumokuākea Marine National Monument permits for activities that are included in established permit categories under 50 CFR part 404 and that meet the regulatory review criteria under 50 CFR 404.11.
[B10.] “Issuance of, or amendments to, Papahānaumokuākea Marine National Monument special ocean use permits for activities or use of the monument that are engaged in to generate revenue or profits for one or more of the persons associated with the activity or use, and do not destroy, cause the loss of, or injure monument resources.”
NOAA proposes a new CE to cover the issuance of, or amendments to Papahānaumokuākea Marine National Monument special ocean use permits for activities or use of the monument that are engaged in to generate revenue or profits for one or more of the persons associated with the activity or use, and do not destroy, cause the loss of, or injure monument resources.
[B11.] “Issuance of Exempted Fishing Permits (EFPs) under the authority of the Magnuson-Stevens Act and Scientific Research Permits (SRPs) and other permits for research that may impact species regulated under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (MSA) and the Atlantic Tunas Convention Act (ATCA). This includes permitted research of limited size, magnitude or duration with negligible individual or cumulative impacts, which requires temporary relief of fishery management regulations.”
NOAA proposes a new CE to cover the issuance of, or amendments to permits or authorizations for activities that are conducted within Marine National Monuments other than Papahānaumokuākea that are limited in scope so that the potential impacts of the proposed activities will be conducted in a manner compatible with a monument's primary objective of resource protection, and do not destroy, cause the loss of, or injure monument resources.
[B12.] “Issuance of Exempted Fishing Permits (EFPs) under the authority of
NOAA proposes a new CE to cover the issuance of Exempted Fishing Permits (EFPs) under the authority of the Magnuson-Stevens Act and Scientific Research Permits (SRPs) and other permits for research that may impact species regulated under the authority of the Magnuson-Stevens Fishery Conservation and Management Act (MSA) and the Atlantic Tunas Convention Act (ATCA). These revisions are intended to encompass activities regarding the issuance of EFPs and SRPs for research activities within the scope of the CE and conducted for the benefit of fisheries and the environment.
[C1.] “Habitat restoration actions, provided that such action: (1) Transplants only organisms currently or formerly present at the site or in its immediate vicinity (if transplant is a component of the action); (2) does not require substantial placement of fill or dredging; (3) does not involve any removal of debris, excavation, or conditioning of soils unless such removal of debris, excavation, or conditioning of soils is geographically limited to the impact area such that site conditions will not impede or negatively alter natural processes, is in compliance with all permit and disposal requirements,), and will not impact critical aquifers or recharge areas; and (4) does not involve an added risk of human or environmental exposure to toxic or hazardous substances, pathogens, or radioactive materials.
If applicable, limitations and mitigation measures identified in the NOAA Restoration Center Programmatic Environmental Impact Statement for Habitat Restoration Actions must be followed. This CE includes, but is not limited to, response or restoration actions under CERLCA, OPA, or NMSA, if such actions are intended to restore an ecosystem, habitat, biotic community, or population of living resources to a determinable pre-impact condition prior to the incident leading to the response or restoration.”
NOAA proposes to revise the version of CE 6.03b.2 by removing the condition that actions encompassed by this CE “are intended to restore an ecosystem, habitat, biotic community, or population of living resources to a determinable pre-impact condition.” NOAA determined that removing the requirement “(1) are intended to restore an ecosystem, habitat, biotic community, or population of living resources to a determinable pre-impact condition” clarified the applicability of this CE. Previously, the condition limited the CE's application to circumstances where NOAA was able to determine the pre-impact condition of the resource to be restored and this created confusion as to the scope and applicability of the CE. NOAA also added criteria that limit the scope of the CE. These four limitations were developed and reviewed by the Working Group and included to ensure that this category of actions is properly limited in context and intensity such that there is no potential for individual or cumulative significant effects on the human environment under normal circumstances. Finally, NOAA added the requirement that, if applicable, limitations and mitigation measures identified in the NOAA Restoration Center Programmatic Environmental Impact Statement for Habitat Restoration Actions (June 2015) (RC PEIS) must be followed.
[D1.] “Financial activities for the following financial services: (1) Loans for purchase, refinancing, or reconstruction of fishing vessels and purchase or refinancing of individual fishing quota through the Fisheries Finance Program; (2) Deferred tax program provided to fishermen to construct, reconstruct, or acquire fishing vessels through the Capital Construction Fund Program; and (3) Compensation to fishermen for economic and property losses caused by oil and gas obstructions on the U.S. Outer Continental Shelf under the Fishermen's Contingency Fund.”
NOAA proposes to break out a portion of CE 6.03c.3(b) to explicitly cover only the limited financial activities for specific financial services under the Fisheries Finance Program, the Capital Construction Fund Program, and the Fisherman's Contingency Fund. The Working Group determined that for the vast majority of financial assistance and financial services actions, decision makers should look at whether the underlying activity to be funded falls within one of the established CEs. The activities addressed in proposed D1, however, while appropriate for a CE, were not separately addressed in any of the other NOAA CEs and thus are proposed here as a separate financial activities category. The proposed revision clarifies the scope and applicability of the CE.
[D2.] “Provision of a grant, a contract or other financial assistance to a State, Fishery Management Council or Marine Fisheries Commission under 16 U.S.C. 1881a(d).”
NOAA proposes to break out a portion of CE 6.03c.3(d) to explicitly cover the provision of a grant, contract, or other financial assistance to a State, Fishery Management Council or Marine Fisheries Commission under 16 U.S.C. 1881a(d). Similar to the activities addressed in D1, the Working Group determined that the specific provision of funding pursuant to 16 U.S.C. 1881(a)(d) was appropriately addressed in a CE and not otherwise covered by other NOAA proposed CEs. The proposed revision clarifies the scope and applicability of the CE.
NOAA proposes to break out a portion of CEs 6.03c.3(a) and 6.03c.3(d) to explicitly cover a variety of research activities with no potential for individual or cumulative significant effects under normal circumstances. The Working Group determined that it would be more appropriate to address research programs and projects with more specificity than the existing 1999 CE, which broadly covers all “research programs or projects of limited size and duration or with only short-term, minor effects on the human environment.” Instead, after an internal scoping process evaluating the types of research activities that were routinely and appropriately relying on the existing CE, the Working Group developed the following categories of activities in proposed CEs E1-E8. For each of the proposed research CEs, the Working Group proposed limitations appropriate to the category of activities to ensure that the activities covered by each CE have no potential for significant effects on the environment under normal circumstances.
[E1.] “Activities conducted in laboratories and facilities where research practices and safeguards prevent environmental impacts.”
[E2.] “Social science projects and programs, including economic, political science, human geography, demography, and sociology studies, including information collection activities in support of studies.”
[E3.] “Activities to collect aquatic, terrestrial, and atmospheric data in a non-destructive manner.”
[E4.] “Activities that survey or observe living resources in the field with little to no potential to adversely affect the environment or interfere with organisms or habitat.”
[E5.] “Activities involving invasive techniques or methods that are conducted for scientific purposes, when such activities are conducted in accordance with all applicable provisions of the Endangered Species Act, Marine Mammal Protection Act, Migratory Bird Treaty Act, and Magnuson-Stevens Fishery Conservation and Management Act. Such activities will be limited to impacting living resources on a small scale relative to the size of the populations, and limited to methodologies and locations to ensure that there are no long-term adverse impacts to benthic habitats, essential fish habitat, critical habitat, or listed species.”
[E6.] “Research that involves the development and testing of new and modified fishing gear and technology in order to reduce adverse effects from fishing gear on non-target species.”
[E7.] “Collection of data and biological samples on fishing vessels or dockside as part of previously authorized commercial and/or recreational fishing activities.”
[E8.] “Biological, chemical, or toxicological research conducted in closed system mesocosm/aquaculture facilities that are conducted according to recommended protocols that provide containment and disposal of chemicals, toxins, non-native species, etc., in compliance with established Federal and state regulatory guidelines, and best management practices.”
[F1.] “Siting, construction (or modification), and operation of support buildings and support structures (including, but not limited to, trailers and prefabricated buildings) within or contiguous to an already developed area (where active utilities and currently used roads are readily accessible).”
NOAA proposes a new CE to cover activities to place and operate trailers, modular buildings, storage buildings, or shipping units within or contiguous to an already developed area.
[F2.] “In-kind replacement of personal property and fixtures and other components of real property when such activities do not result in a substantial change in the existing construction footprint. In-kind replacement includes installation of new components to replace outmoded components if the replacement does not result in a substantial change to the design capacity, or function of the facility.”
NOAA proposes to make minor revisions to CE 6.03c.3(e) by breaking out a component of this CE into a separate CE. NOAA's use of the language
[F3.] “(a) Routine repair, maintenance, and improvement of real and personal property, where such activities are required to maintain and preserve buildings, structures, infrastructures, vehicles, and equipment in a condition suitable to be used for its designed purpose.
(b) New construction, expansion and/or improvement of facilities where all of the following conditions are met:
(1) The site is in a developed area and/or a previously disturbed site;
(2) The structure and proposed use are compatible with applicable Federal, Tribal, State, and local planning and zoning standards and consistent with Federally approved State coastal management programs and the National Historic Preservation Act;
(3) The proposed use will not substantially increase the number of motor vehicles, marine vessels, or aircraft at the facility or in the area;
(4) The site and scale of construction or improvement are consistent with those of existing, adjacent, or nearby buildings;
(5) The construction or improvement will not result in uses that exceed existing infrastructure capacities (
(6) The construction or improvement will not result in operational uses that adversely affect the surrounding community (
(7) The community-valued view sheds are not adversely affected.
(c) Installation, repair, maintenance, and enhancement of public access facilities and infrastructure, if the activity:
(1) Is small-scale and nondestructive;
(2) Is consistent with applicable right-of-way conditions and approved land use plans; and
This CE does not apply where the project must be submitted to the National Capital Planning Commission (NCPC) for review and NCPC determines that it does not have an applicable Categorical Exclusion.”
NOAA proposes to break out and merge several portions of the following CEs: 6.03c.3(c) “minor improvements to an existing site (
[F4]. “Routine groundskeeping and landscaping activities where ground disturbance is limited to previously disturbed areas (
NOAA proposes to make minor revisions to CE 6.03c.3(e) by breaking out a portion of this CE into a separate CE. These types of actions are already covered in the portion of CE 6.03c.3(e) in “grounds-keeping activities.” The CE is limited to activities where ground disturbance is limited to previously disturbed areas. The proposed revisions do not result in a substantial change in scope or applicability from the CE in the 1999 NAO.
[F5.] “Installation, operation, maintenance, improvements, repair, upgrade, removal, and/or replacement of instruments or instrument systems in or on:
1. An existing structure or object (
2. On previously disturbed (
3. On undisturbed ground, if the equipment installation, operation, and removal will require no or minimal ground disturbance.”
Microwave/radio communications towers and antennas must be limited to 200 feet in height without guy wires. NOAA proposes a new CE to cover activities of installing, operating, repairing, maintaining, upgrading, removing and/or replacing instruments or instrument systems in or on an existing structure or object, or on previously disturbed ground or on undisturbed ground that involve either no or minimal ground disturbance.
[F6.] “The determination that real property is excess to the needs of the Agency, when the real property is excessed in conformity with General Services Administration procedures or is legislatively authorized to be excessed.”
NOAA proposes a new CE to cover declarations of real property as excess in conformance with General Services Administration procedures or as legislatively authorized.
[F7.] “The disposal, demolition or removal of real property and related improvements, buildings and structures, including associated site restoration,
NOAA proposes a new CE to cover the disposal, demolition or removal of real property and related improvements, buildings and structures, including associated restoration, and the disposal of property and debris in accordance with all applicable Agency procedures.
[G1.] “Routine administrative actions such as (1) program planning, direction and evaluation, (2) administrative tasks, services and support including personnel and fiscal management, advisory services, document and policy preparation, and records management, and (3) development, establishment, and revisions to documents including, but not limited to interagency agreements, memoranda of understanding, memoranda of agreement, cooperative agreements, and university agreements. This CE does not include any associated activities proposed in these documents beyond the administrative task of creating and establishing the document. Actions subsequently funded by or undertaken pursuant to the approved documents may require additional NEPA review at the time those actions are proposed.”
NOAA proposes to break out a portion of CE 6.03c.3(d) to explicitly cover program planning, direction and evaluation; administrative tasks; development, establishment and revisions to administrative documents, including interagency agreements, memoranda of understanding, memoranda of agreement, cooperative agreements, and university agreements. Many of these types of activities are already covered in the portion of the 1999 NAO 6.03c.3(d) in “program planning and budgeting, including strategic planning and operational planning . . . executive direction; administrative services.” The proposed revision to break out a portion of the 1999 CE does not result in a significant change in scope or applicability from the CE in the 1999 NAO.
[G2.] “Routine movement of mobile assets, such as vessels and aircraft, for homeport reassignments or repair/overhaul, where no new support facilities are required.”
NOAA proposes to break out a portion of CE 6.03c.3(d) to explicitly cover routine movement of mobile assets. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(d) in “ship and aircraft operations.” The CE is limited to the routine movement of mobile assets for homeport reassignments or repair/overhaul, where no new support facilities to ensure that activities encompassed by the CE have no potential for significant effects on the environment under normal circumstances.
[G3.] “Topographic, bathymetric, land use and land cover, geological, hydrologic mapping, charting, and surveying services that do not involve major surface or subsurface land disturbance and involve no permanent physical, chemical, or biological change to the environment.”
NOAA proposes to break out and revise a portion of CE 6.03c.3(d) to cover certain mapping and surveying services and activities. Many of these types of activities are already covered in the portion of the 1999 NAO 6.03c.3(d) in “mapping, charting, and surveying services.” The CE is limited to activities that do not involve major surface or subsurface land disturbance and involve no permanent physical, chemical, or biological change to environment. The Working Group determined these limitations were necessary to ensure the activities encompassed by the CE have no potential for significant effects on the environment under normal circumstances.
[G4.] “Basic environmental services and monitoring, such as weather observations, communications, analyses, and predictions; environmental satellite operations and services; digital and physical environmental data and information services; air and water quality observations and analysis, and IT operations. All such activities must be conducted within existing facilities.”
[G4.] “Basic environmental services and monitoring, such as weather observations, communications, analyses, and predictions; environmental satellite operations and services; digital and physical environmental data and information services; air and water quality observations and analysis, and IT operations. All such activities must be conducted within existing facilities.”
NOAA proposes to break out a portion of CE 6.03c.3(d) to explicitly cover environmental satellite and environmental data and information service activities, environmental service activities, and air quality observations and analysis activities. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(d) in “basic environmental services and monitoring, such as weather observations, communications, analyses, and predictions; environmental satellite services; environmental data and information services;” and “air quality observations and analysis.” The proposed revision to break out a portion of the 1999 CE does not result in any change in scope of applicability from the CE in the 1999 NAO.
[G5.] “Enforcement operations conducted under legislative mandate such as the MSA, ESA, MMPA, the Lacey Act Amendments of 1981 (Lacey), and/or the National Marine Sanctuaries Act. This does not include bringing judicial or administrative civil or criminal enforcement actions which are outside the scope of NEPA in accordance with 40 CFR 1508.18(a).”
NOAA proposes to break out a portion of CE 6.03c.3(d) to explicitly cover enforcement operations. These types of actions are already covered in the portion of the 1999 NAO 6.03c.3(d) in “enforcement operations.” As noted in the language of the CE, 40 CFR 1508.18(a) provides that major federal actions subject to NEPA do not include “bringing judicial or administrative civil or criminal enforcement actions.” Accordingly, this CE only covers those enforcement operations outside of this scope that would not otherwise be excluded from NEPA. The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO.
[G6.] “Actions that change the NEXRAD radar coverage patterns that do not lower the lowest scan elevation and do not result in direct scanning of previously non-scanned terrain by the NEXRAD main beam.”
NOAA proposes no substantive changes to CE 6.03c.3(h). The phrase “actions that” was added for grammatical reasons. The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO.
[G7.] “Preparation of policy directives, rules, regulations, and guidelines of an administrative, financial, legal, technical, or procedural nature, or for which the environmental effects are too broad, speculative or conjectural to lend themselves to meaningful analysis and will be subject later to the NEPA process, either collectively or on a case-by-case basis.”
NOAA proposes to break out a portion of CE 6.03c.3(i) to explicitly cover policy directives, order, regulations, and guidance. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(i) in “preparation of regulations, Orders, manuals or other guidance that implement, but do not substantially change these documents”
[G8.] “Activities that are educational, informational, or advisory to other agencies, public and private entities, visitors, individuals, or the general public, including training exercises and simulations.”
NOAA proposes to break out a portion of CE 6.03c.3(i) to explicitly cover educational, informational, advisory, and consultative activities. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(i) in “activities which are educational, informational, advisory, or consultative to other agencies, public and private entities, visitors, individuals or the general public.” The Working Group determined that expressly including training exercises and simulations in the text of the CE clarified its scope and applicability for decision makers. The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO.
[G9.] “Actions taken to identify, determine sources of, assess, prevent, reduce, remove, dispose, or recycle marine debris when removal is undertaken in a non-destructive manner and actions are in accordance with Federal, State, and local laws and regulations for environmental protection, and where all relevant regulatory consultation, and/or permit requirements have been satisfied.”
NOAA proposes a new CE to cover actions taken to identify, determine sources of, assess, prevent, reduce, remove, dispose, or recycle marine debris. The CE is limited by the requirement that actions encompassed by the CE must be undertaken in a non-destructive manner and in accordance with Federal, State, and local laws and regulations for environmental protection and all relevant regulatory consultation and/or permit requirements have been satisfied.
[H1.] “Procurement of labor, equipment, materials, data and software needed to execute mission requirements in accordance with applicable procurement regulations, executive orders, and policies. This includes, but is not limited to, procurement of mobile and portable equipment that is stored in existing structures or facilities.”
NOAA proposes to break out a portion of CE 6.03c.3(e) and broaden the coverage of the CE to include activities to procure labor, equipment, materials, and software necessary to execute NOAA's mission, including, but not limited to the purchase of mobile and portable equipment to be stored in existing structures or facilities. A portion of these activities are already covered in the portion of the 1999 NAO 6.0303.c(e) in “procurement contracts for NEPA documents.”
[H2.] “Procurement of space by purchase or lease of or within an existing facility or structure in accordance with applicable procurement regulations, executive orders, and policies when there is no change in the general type of use, no new construction of buildings or utilities, and minimal change in design from the previous occupancy level.”
NOAA proposes to break out a portion of CE 6.03c.3(e) to explicitly cover procurement by purchase or lease of space within a previously occupied structure. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(e) in “acquisitions of space within an existing previously occupied structure, either by purchase or lease, where no change in the general type or use and minimal change from previous occupancy level is proposed.” The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO.
[H3.] “Outgranting of government-controlled property in accordance with applicable regulations, executive orders, and policies to a Federal entity for any purpose consistent with the existing land or facility use or to a non-Federal entity, when the use will remain substantially the same.”
NOAA proposes to break out a portion of the CE in the 1999 NAO 6.03c.3(e) to explicitly cover outgranting of government-controlled space. These types of activities are already covered in the portion of the 1999 NAO 6.03c.3(e) in “out-lease or license of government-controlled space, or sublease of government-leased space to a non-Federal tenant when the use will remain substantially the same.” The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO; the change in terminology from “out-lease” to outgranting is intended to more accurately capture the type of action covered.
[H4.] “Acquisition of real property (including fee simple estates, leaseholds, and easements) that is not acquired through condemnation of a lease interest, and will not result in significant change in use and does not involve construction or modification.”
NOAA proposes to break out a portion of the CE in the 1999 NAO 6.03c.3(e) to explicitly cover procurement and lease of land. These types of activities are already covered in the portion of the 1999.
NAO 6.03c.3(e) in “acquisition of land which is not in a floodplain or other environmentally sensitive area and does not result in condemnation.” NOAA proposes to remove the portion of the CE explicitly stating “which is not in a floodplain or other environmentally sensitive area.” NOAA revised its extraordinary circumstances to include environmental, historic, or cultural unique areas and floodplains, and therefore no longer required the text to be explicit within this CE. The proposed revision to break out a portion of the 1999 CE does not result in any change in scope or applicability from the CE in the 1999 NAO.
[H5.] “Granting easements or rights of entry to use NOAA controlled property for activities that, if conducted by NOAA, could be categorically excluded. Grants of easements or rights-of-way for the use of NOAA controlled real property complementing the use of existing rights-of-way or real property use for use by vehicles (not to include significant increases in vehicle loading); electrical, telephone, and other transmission and communication lines; water, wastewater, stormwater, and irrigation pipelines, pumping stations, and facilities; and similar utility and transportation uses.”
NOAA proposes to create a new categorical exclusion to encompass the activity of granting an easement or right of entry to use NOAA-controlled property for activities that could be categorically excluded if conducted by NOAA.
[H6.] “Relocation of employees into existing Federally-owned or commercially leased office space within the same metropolitan area not involving a substantial increase in the number of motor or other vehicles at a facility.”
NOAA proposes to break out a portion of CE 6.03c.3(e) to explicitly cover relocation of employees. These types of actions are already covered in the portion of the 1999 NAO 9.03c.3(e) in “relocation of employees into existing Federally-owned or commercially
[H7.] “Transferring real property to a non-Federal entity, an agency other than GSA, as well as to States, local agencies and Indian Tribes, including return of public domain lands to the Department of the Interior.”
NOAA proposes a new CE to cover the transfer of real property to a federal agency other than the General Services Administration as well as to a non-Federal entity, including States, local agencies, and Indian tribes. This proposed CE also applies to the return of public domain lands to the Department of the Interior.
National Marine Fisheries Service (NMFS), National Oceanic and Atmospheric Administration (NOAA), Commerce.
Notice of a listing determination.
We, NMFS, have completed our review of the status of eastern North Pacific harbor seals (
This listing determination is made as of November 17, 2016.
This finding and supporting information are available on our Web page at:
Mandy Migura, NMFS Alaska Region, (907) 271-1332; Jon Kurland, NMFS Alaska Region, (907) 586-7638; or Lisa Manning, NMFS Office of Protected Resources, (301) 427-8466.
On November 19, 2012, we received a petition submitted by the Center for Biological Diversity (CBD) to list the harbor seals in Iliamna Lake, Alaska as a threatened or endangered species under the ESA, and to designate critical habitat concurrent with listing. CBD asserted that the harbor seals found in Iliamna Lake constitute a DPS of Pacific harbor seals and contended that the seals in Iliamna Lake face threats warranting protection as a listed species under the ESA. Iliamna Lake is the largest freshwater lake in Alaska and is connected to the Bristol Bay region of the Bering Sea by the Kvichak River.
On May 17, 2013 (78 FR 29098), we found that the petition presented substantial information indicating that listing the seals in Iliamna Lake under the ESA may be warranted, and we requested comments from the public to inform our status review, and to help us determine whether these seals should be listed as threatened or endangered. To assist with our status review, we convened a Biological Review Team (BRT), composed of federal scientists with expertise in marine mammal biology and marine mammal genetics, to review the available information about the status of the species, and provide an assessment regarding the seals in Iliamna Lake. The BRT compiled information about the harbor seals in Iliamna Lake in a DPS Report (Boveng
In this notice, we announce our finding that the petitioned action to list harbor seals in Iliamna Lake under the ESA as either threatened or endangered is not warranted because the seals do not constitute a distinct population segment (DPS) and thus are not a separate “species,” as the ESA defines that term. Speficically, while we conclude that the seals are a discrete population, the best scientific and commercial data available suggest that they are not significant to the greater taxon to which they belong,
Section 3 of the ESA defines a “species” as “any subspecies of fish or wildlife or plants, and any distinct population segment of any species of vertebrate fish or wildlife which interbreeds when mature.” Section 3 of the ESA further defines an endangered species as “any species which is in danger of extinction throughout all or a significant portion of its range” and a threatened species as one “which is likely to become an endangered species within the foreseeable future throughout all or a significant portion of its range.” Thus, we interpret an “endangered species” to be one that is presently in danger of extinction. A “threatened species,” on the other hand, is not presently in danger of extinction, but is likely to become so in the foreseeable future. In other words, the primary statutory difference between a threatened and endangered species is the timing of when a species may be in danger of extinction, either presently (endangered) or in the foreseeable future (threatened).
Under section 4(a)(1) of the ESA, we must determine whether a species is threatened or endangered because of any one or a combination of the following factors: (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) inadequacy of existing regulatory mechanisms; or (E) other natural or human-made factors affecting its continued existence. We must make this determination based solely on the best scientific and commercial data available after conducting a review of the status of the species and taking into account those efforts being made by states or foreign governments to protect the species.
The first step in determining whether the harbor seals in Iliamna Lake warrant listing under the ESA is to assess if they meet the ESA's definition of “species.” Although there has been speculation
The U.S. Fish and Wildlife Service (USFWS) and NMFS (the “Services”) adopted the Policy Regarding the Recognition of Distinct Vertebrate Population Segments under the ESA (the DPS Policy, 61 FR 4722; February 7, 1996) to clarify the Services' interpretation of the term “distinct population segment” for the purposes of listing, delisting, and reclassifying vertebrates under the ESA. The DPS Policy establishes two criteria that must be met for a population or group of populations to be considered a DPS: (1) The population segment must be discrete in relation to the remainder of the species (or subspecies) to which it belongs; and (2) the population segment must be significant to the remainder of the species (or subspecies) to which it belongs. In this case, harbor seals in Iliamna Lake would need to be both discrete from and significant to the eastern North Pacific subspecies of harbor seals (
If the seals in Iliamna Lake were found to meet the DPS criteria, we would then conduct a status review and determine whether they are threatened or endangered because of any one or a combination of the factors from section 4(a)(1) of the ESA. Such a determination would be based solely on the best scientific and commercial data available. Here, because we concluded that the seal population in Iliamna Lake is not a DPS, we did not conduct a status review of the population under section 4(a)(1) of the ESA.
Harbor seals (
On average, harbor seals reach sexual maturity at the age of five for both females and males; however, females exhibit a larger range of age at maturity (Calkins and Pitcher 1979). The variation depends on population size and trend, body condition, and prey resources (Pitcher and Calkin 1979; Mclaren and Smith 1985; Atkinson 1997). Harbor seals in the eastern North Pacific subspecies also exhibit natural variation in the timing of pupping, ranging from March to September (Bigg 1969; Temte
Harbor seals molt annually following pupping (Pitcher and Calkins 1979). Molting usually lasts 1-2 months, during which time seals spend a large amount of time hauled-out (Pitcher and Calkins 1979; Daniel
Harbor seals are considered opportunistic foragers and feed on a wide variety of prey found in marine, estuarine, and fresh waters (Carretta
Harbor seals are one of the most widespread pinniped species and are found throughout the northern hemisphere, ranging from temperate to polar regions. As of 2008, the worldwide harbor seal population was estimated between 350,000 and 500,000 mature individuals (Thompson and Härkönen 2008). Currently, there are five recognized subspecies of harbor seals:
The harbor seals found in Iliamna Lake are classified as part of the subspecies
Eastern North Pacific harbor seals in Alaska are divided into 12 separate stocks under the Marine Mammal Protection Act; however, these stocks do not represent taxonomic delineations, and all 12 stocks are part of the subspecies
Aerial surveys of harbor seals in Iliamna Lake have primarily been conducted in the summer and have consistently documented fewer than 350 animals (Mathisen and Kline 1992; Small 2001; Withrow and Yano 2009; Burns
Harbor seals typically inhabit near-shore coastal waters, but are well known for their use of estuaries and rivers, and have been recorded over 200 kilometers (km) upstream (
Harbor seals are often described as a sedentary, non-migratory species, with considerable site fidelity to one or a few haul-outs, with large scale movements being rare. Traditional thinking is that harbor seals generally stay within 50 km of a primary haul-out site (
There is also variation in individual movements of harbor seals within a population, with some seals traveling great distances seasonally while others stay within a smaller area year-round. Womble and Gende (2013) noted that some harbor seals in Glacier Bay, Alaska, were residents year-round whereas others were migratory. For the migrating harbor seals, there was a high degree of site fidelity back to Glacier Bay the following pupping/breeding season despite the extensive migration away from the breeding area during the post-breeding season (Womble and Gende 2013). Lesage
No harbor seals in Iliamna Lake have been satellite tagged, thus there are no data available about harbor seals movements in Iliamna Lake comparable to those discussed in the preceding paragraphs. Data on habitat use and movements of harbor seals in Iliamna Lake are from aerial surveys documenting locations where harbor seals were hauled-out (
While harbor seals are known to haul-out on ice, recent aerial surveys have documented few seals hauled-out during winter surveys in Iliamna Lake. For example, an aerial survey flown in April 2010, when the lake was almost completely frozen-over, documented only 11 seals; observers reported they “did not see any areas that could support the several hundred seals that have been documented in the summer” (Withrow
Conclusions drawn from recent aerial surveys suggest that some harbor seals may be year-round residents of Iliamna Lake whereas other harbor seals may seasonally migrate to and from the lake (Burns
No scientific data are available to determine whether enough fish remain in Iliamna Lake to support hundreds of seals during winter. Some LTK indicates that the lake may not have sufficient food available to support the number of seals observed in summer months on a year-round basis. A local seal hunter recently noted that two seals harvested during two consecutive winters in the lake had not “one drop of food in the stomach or intestines” (Burns
Alternatively, there may be adequate abundance of prey available in the lake year-round, but some seals could leave the lake in winter for other reasons. In the St. Lawrence estuary, a study of satellite-tagged harbor seals found that seals left summer haul-out areas when solid ice formed within the bays of the estuary despite “evidence of high abundance of potential prey for harbor seals in the estuary during winter” (Lesage
Whether seals migrate seasonally between Iliamna Lake and Bristol Bay has not been scientifically investigated, with the exception of a few recent aerial surveys of Iliamna Lake and the Kvichak River. Aerial surveys of the Kvichak River (five complete or partial river surveys conducted from 2008-2013) have failed to document harbor seal presence in the river (Burns
Harbor seals are an important resource for Alaska Native communities surrounding Iliamna Lake. Harbor seals are not only a food source, but also provide materials that can be used for clothing, handicrafts, and cultural traditions. Reports of harvesting harbor seals by indigenous people around Iliamna Lake date back to the early 1800s and LTK suggests that seals have inhabited the lake for many centuries (Fall
As described above, only species, subspecies, and DPSs are eligible for listing as a threatened or endangered species under the ESA. A DPS is a population or group of populations of a vertebrate species that meet both the “discreteness” and “significance” criteria of our DPS policy (61 FR 4722; February 7, 1996). If a population segment is found to be discrete and significant, it is a DPS and is considered a “species” under the ESA. If the population is not both discrete and significant, it does not meet the criteria for designation as a DPS and does not qualify as a “species” as defined by the ESA; thus, we need not evaluate its status relative to the factors in section 4(a)(1) of the ESA because it cannot be listed as a threatened or endangered species. Our assessment first addresses the discreteness of the harbor seals found in Iliamna Lake, and then addresses whether these seals are significant to
As discussed above, we know from formal scientific studies and LTK that at least some harbor seals are present in the lake year-round;
We first sought to determine whether the harbor seal population in Iliamna Lake is discrete in relation to the remainder of the taxon to which it belongs (
Although seals are found predominantly in the northeast region of Iliamna Lake, the most recent studies indicate harbor seals are found throughout Iliamna Lake, in rivers draining into the lake (Iliamna, Newhalen, and Gilbralter rivers), and throughout the Kvichak River (Alvarez 2013; Burns
Physical factors that could impede harbor seal passage in the Kvichak River include shallow braided sandbars and ice cover during winter. Although poorly adapted for travel on land, harbor seals in other areas have been suspected to cross land up to 0.15 km long and on inclines as steep as 25 degrees to get from one body of water to another (COSEWIC 2007), so it is reasonable to assume harbor seals have the capability to cross shallow braided sandbars in the Kvichak River.
Millions of sockeye salmon enter Iliamna Lake from marine waters annually via the Kvichak River along with other species of anadromous salmon. Also, another marine mammal species has been reported to travel to Iliamna Lake via the Kvichak River. Beluga whales, which are less agile and much larger than harbor seals, have been documented in the Kvichak River (Frost
Individual BRT members were not in agreement regarding the scientific support for discreteness due to physical factors, but concluded “no strong evidence was found either for or against marked separation by physical barriers between harbor seals in Iliamna Lake and those in Bristol Bay” (Boveng
The concentration and availability of salmon to seals in Iliamna Lake in the summer may account for perceived differences reported by LTK in size and taste of seals in Iliamna Lake compared to seals in Bristol Bay. For example, several respondents of a recent LTK survey indicated that the “physical size of the seals grows every year following the salmon runs” (Burns
The timing of pupping for eastern North Pacific harbor seals ranges from March to September (Bigg 1969; Temte
Jemison and Kelly (2001) and Reijnders
Individual BRT members were not all in agreement regarding the degree of scientific support for discreteness based upon marked separation due to physiological factors. Regarding differences in physiological traits such as pelage coloration or texture and seal size and taste, the BRT report stated “whether any of these differences truly reflect physiological differences or separation is not clear, and the BRT was unaware of any documentation that these traits are heritable and would indicate separation or novel genetic diversity” (Boveng
When we considered all the evidence currently available to us, including the lack of direct measures of physiological factors, the possibility that perceived differences in seals' appearance may be the result of natural individual variation, the imprecision of estimating pupping dates due to limited data, the potential overlap of pupping seasons between Iliamna Lake and Bristol Bay, and the large timeframe (March to September) for typical pupping times across the eastern North Pacific harbor seal taxon, we concluded that the available information is too weak for us to make a determination that there is separation based on physiological factors. As such, based on the available evidence, we find that harbor seals in Iliamna Lake are not markedly separated from other harbor seals of the subspecies
Hauser
Stable isotope analyses of whiskers and muscle tissue can provide some insights about harbor seal diets from several months prior to the date the samples were collected. Samples collected from a small number of subsistence harvested harbor seals from Iliamna Lake provide preliminary evidence that those specific seals consumed freshwater fish during the previous winter (Burns
If ecological factors prevented harbor seals in Iliamna Lake from mixing with other harbors seals during mating season, then there could be marked separation as a result of lack of opportunities for interbreeding. However, when considering the timing of the annual ice melt in the Kvichak River and Iliamna Lake, the sockeye salmon runs into Iliamna Lake, and the presumed mating seasons of seals in Bristol Bay and in Iliamna Lake, the BRT concluded that the timing of these events would not preclude opportunities for interbreeding by seals migrating from Bristol Bay to Iliamna Lake (Boveng
The BRT members were in general agreement regarding the degree of scientific support for discreteness based upon marked separation due to ecological factors, and concluded there
Previously we mentioned that harbor seals commonly follow anadromous prey into freshwater environments, such as rivers and lakes. Thus, we do not consider the mere presence of harbor seals in Iliamna Lake to be a behavioral adaptation suggestive of marked separation from harbor seals in the marine environment. However, some Alaska Natives in the Iliamna Lake region, including subsistence hunters, have postulated that the seals overwinter in the lake by using under-ice air gaps and haul-outs (Burns
The Lacs des Loups Marins harbor seal population has shown evidence of modifying typical harbor seal behavior and adapting to its environment. It is postulated that, because no pups have been observed being born on the ice during that species' pupping time period (April, when the lakes are frozen), the Lacs des Loups Marins harbor seals have learned and adapted to their situation by whelping in under-ice shelters similar to subnivean birth lairs (snow caves) used by ringed seals (Consortium Gilles Shooner & Associes
The BRT members were in general agreement regarding the degree of scientific support for discreteness based upon marked separation due to behavioral factors, as determined by selection of pupping locations far from those in Bristol Bay, and the ambiguity regarding the degree of migration and breeding dispersal (if any). Their judgment suggests behavioral separation is possible, but the available evidence is not strong, or is contradicted by other evidence. Our review of behavioral factors indicates that the observed harbor seal behaviors in Iliamna Lake are not uncommon; harbor seals in Iliamna Lake have not been documented to display behaviors outside the range of normal harbor seal behaviors (
Genetic samples have been collected and analyzed from 13 harbor seals in Iliamna Lake collected in six years from 1996 through 2012. The mitochondrial DNA (mtDNA) analysis revealed that 11 of 13 seals sampled from Iliamna Lake exhibited the same mtDNA haplotype (O'Corry-Crowe 2013), meaning all 11 seals had the same group of genes inherited from their female parent. The remaining two DNA samples did not yield results for this test. This specific mtDNA haplotype (Pvit-Hap#7) is the most common haplotype found in harbor seals sampled from Bristol Bay and is observed in roughly 21 percent of harbor seals from the Egegik and Ugashik regions of Bristol Bay (Burns
The identification of only one mtDNA haplotype in harbor seals from Iliamna Lake appears to suggest unusually low genetic diversity. For comparison, 76 harbor seals sampled from the Egegik
In addition to examining the existing genetic diversity of the samples, analyses were conducted to examine the extent of genetic differentiation between harbor seals sampled in Iliamna Lake from those sampled in the Egegik and Ugashik regions of eastern Bristol Bay. The results of analyses examining genetic differentiation using both mtDNA and nDNA suggest that the harbor seals sampled in Iliamna Lake were genetically differentiated from harbor seals sampled in the Egegik and Ugashik regions of eastern Bristol Bay (Burns
O'Corry-Crowe (2013) identifies several limitations of the findings for the Iliamna Lake samples. He cautions that the sample size is extremely small and that questions regarding the patterns of kinship among the collected samples remain unresolved (
The genetic data available suggest the harbor seals sampled in Iliamna Lake have low mtDNA diversity, possess the most common mtDNA haplotype found in Bristol Bay harbor seals, and are genetically differentiated from harbor seals sampled in the Egegik and Ugashik regions of eastern Bristol Bay. Given the concerns about the limited nature of the available genetic information previously discussed here and by O'Corry-Crowe (2013), ambiguity remains regarding the degree of separation, and hence discreteness, of harbor seals in Iliamna Lake. However, in the absence of more samples collected from a greater number of seals in Iliamna Lake and the Kvichak River, to include the potential migration season, and/or completion of additional tests such as those recommended by O'Corry-Crowe (2013), we consider the existing genetic results to be the best available data upon which to base our determination. These genetic results support a decision that harbor seals in Iliamna Lake are markedly separated from harbor seals in eastern Bristol Bay, and by assumption, from the remainder of the taxon.
We find the available evidence for discreteness based on physical, physiological, or ecological factors to be unconvincing. The available evidence based on behavioral factors is not conclusive, but the selection of pupping locations distant from other known pupping locations could be construed as a behavior and indicate marked separation as a result of the selection of pupping sites limiting the potential for interbreeding. The strongest evidence for discreteness derives from 13 genetic samples collected from seals in Iliamna Lake. Analyses of these samples strongly indicate the seals from Iliamna Lake are genetically differentiated from seals sampled in two locations within Bristol Bay (Ugashik and Egegik), the nearest concentration of seals to Iliamna Lake with genetic data available. Genetic comparisons of samples for the entire taxon do not exist, but this region within Bristol Bay was expected to provide the most stringent comparison for discreteness if there is breeding dispersal between the two regions. The BRT was in strong agreement that the genetic data reflect marked separation, although the BRT acknowledged that the mechanism of such separation is unknown and the data are limited. It is possible that the limited available genetic data may accurately represent the situation in both Iliamna Lake and all of Bristol Bay, or that additional genetic analysis from
Having determined that resident seals from Iliamna Lake are likely discrete, at
In carrying out the significance examination per our DPS policy (61 FR 4722; February 7, 1996), we are to consider available scientific evidence of the population's importance to the taxon to which it belongs. This consideration may include, but is not limited to, the following: (1) Persistence of the discrete population segment in an ecological setting unusual or unique for the taxon; (2) evidence that loss of the discrete population segment would result in a significant gap in the range of the taxon; (3) evidence that the discrete population segment represents the only surviving natural occurrence of a taxon that may be more abundant elsewhere as an introduced population outside its historic range; or (4) evidence that the discrete population segment differs markedly from other populations of the species in its genetic characteristics.
This determination, however, is highly fact specific and may consider factors besides those enumerated above. Further, significance of the discrete population segment is not necessarily determined by existence of one of these classes of information standing alone. Information analyzed under these and any other applicable considerations is evaluated relative to the biological and ecological importance of the discrete population to the taxon as a whole. Accordingly, all relevant and available biological and ecological information is analyzed. As we explained in the DPS policy, “the principal significance to be considered in a potential DPS will be the significance to the taxon to which it belongs” (61 FR 4722, 4724; February 7, 1996). Finally,we assessed the biological and ecological significance of the seals in Iliamna Lake to the
The diet of harbor seals in Iliamna Lake is consistent with what we would expect for the species occupying a freshwater system dominated by anadromous salmon. Hauser
We also considered whether the habitat available for use by seals in Iliamna Lake is unusual or unique. Harbor seals commonly use reefs, sand and gravel beaches, sand and mud bars, island beaches, and ice (glacial ice, pan ice, sea ice, or icebergs) as haul-out sites. Harbor seals in Iliamna Lake are known to haul-out on rocky and sandy substrates, sand bars, small islands, and ice near pressure cracks or polynas (Burns
Smith and Horonowitsch (1987) studied the ice at one location within the Lacs des Loups Marins and documented what they refer to as “shoreline ice-steps” which they speculated could be used as breathing chambers for over-wintering seals in the lake. LTK suggests the presence and use of similar under-ice haul-outs in Iliamna Lake (Burns
Harbor seals have the broadest distribution and occur in more different habitats than any other pinniped species (Burns 2002; COSEWIC 2007), and are frequently and commonly observed in freshwater systems (Burns 2002). Mansfield (1967) provides information about sightings of harbor seals in rivers and lakes in Arctic Canada (referencing Doutt 1942 and Harper 1961 for detailed summaries of Arctic harbor seals' freshwater distribution), indicating that harbor seals have “a strong liking for fresh water” and are often found in estuaries and freshwater habitats “far from the sea.” Beck
Year-round persistence of harbor seals in a lake is less common. Besides the unknown number of harbor seals
The BRT considered whether the persistence of the population of harbor seals in this setting is important to the taxon as a whole (see discussion in Boveng
As previously discussed, some local residents of the Iliamna Lake region have suggested they think the harbor seals harvested from Iliamna Lake taste, look, or feel different (
The use of air gaps under the ice in winter is a potential adaptation to freshwater life in sub-Arctic regions, and is only documented among harbor seals in one location (
The BRT members were in strong agreement that harbor seals persisting year-round and breeding in a freshwater lake that freezes over almost completely nearly every year is unique for the subspecies
The loss of harbor seals in Iliamna Lake would not have a detrimental impact to other harbor seal populations
The BRT was in strong agreement that the evidence is clear that the loss of the Iliamna Lake segment would not result in a significant gap in the range of the taxon, and we agree.
There is no strong evidence to indicate the existence of phenotypic differences between harbor seals in Iliamna Lake and those in other portions of the taxon's range. Although there have been some LTK reports that the seals in Iliamna Lake may taste different or have pelage of varying appearance from seals in Bristol Bay, there have been no studies assessing whether these perceived differences are the result of significant differences in genetics. The BRT members did not reach consensus regarding this issue, with a slight preponderance of opinion favoring the conclusion that the genetic characteristics of seals in Iliamna Lake did not convey significance to these seals in regards to
Individual BRT members were not in agreement regarding the degree of scientific support overall for or against the significance of seals in Iliamna Lake to the
Based on the best scientific and commercial data available, we find the evidence for marked separation of harbor seals in Iliamna Lake from the remainder of the taxon based on physical, physiological, ecological or behavioral factors to be unconvincing or
Per the second component of our DPS Policy, we are to consider available scientific evidence of the discrete population's importance to the taxon to which it belongs (61 FR 4722; February 7, 1996). Our review of the best available information suggests the only characteristic which may make this population of harbor seals unique within its taxon is the fact that they persist year-round in a freshwater system which freezes over to some degree in most winters. While that characteristic is unique within the subspecies
Under our DPS Policy, both the discreteness and significance elements must be met to qualify as a DPS. Our review has determined that the seals persisting year-round in Iliamna Lake are discrete but not significant; therefore, the harbor seals in Iliamna Lake do not qualify as a DPS and are not a listable entity under the ESA.
In assessing whether the actions in the petition are warranted, we reviewed the best available scientific and commercial information available, including the BRT report, the petition and literature cited in the petition, published and grey literature relevant to the topic, correspondence with experts in academic and government institutions, documentation of LTK, and public comments. On the basis of this review, we have determined that harbor seals in Iliamna Lake meet the criteria for discreteness but do not meet the criteria for significance. As such, the harbor seals in Iliamna Lake do not meet all the criteria necessary to constitute a DPS, and thus are not a listable entity under the ESA. Therefore, we find that the petitioned actions to list the harbor seals in Iliamna Lake as a threatened or endangered species under the ESA, and to designate critical habitat, are not warranted.
In our 90-day finding (78 FR 29098; May 17, 2013), we indicated we were commencing a status review of the harbor seals in Iliamna Lake. To assist our evaluation of whether the seals in Iliamna Lake constitute a DPS, the BRT prepared a report which compiled background information about the harbor seals in Iliamna Lake and evaluated the scientific information relevant to the DPS criteria (Boveng
In some instances, where we find a petitioned action is not warranted because the petitioned population does not constitute a “species” under the ESA, we have initiated a status review of a related or larger population (
A complete list of all references cited herein is available upon request (see
The authority for this action is the Endangered Species act of 1973, as amended (16 U.S.C. 1531
Consumer Product Safety Commission
Notice.
It is the policy of the Commission to publish settlements which it provisionally accepts under the Consumer Product Safety Act in the
Any interested person may ask the Commission not to accept this agreement or otherwise comment on its contents by filing a written request with the Office of the Secretary by December 2, 2016.
Persons wishing to comment on this Settlement Agreement should send written comments to the Comment 17-C0001, Office of the Secretary, Consumer Product Safety Commission, 4330 East-West Highway, Room 820, Bethesda, Maryland 20814-4408.
Philip Z. Brown, Trial Attorney, Division of Compliance, Office of the General Counsel, Consumer Product Safety Commission, 4330 East-West Highway, Bethesda, Maryland 20814-4408; telephone (301) 504-7645.
The text of the Agreement and Order appears below.
1. In accordance with the Consumer Product Safety Act, 15 U.S.C. 2051−2089 (“CPSA”) and 16 CFR 1118.20, PetSmart, Inc. (“PetSmart”), and the United States Consumer Product Safety Commission (“Commission”), through its staff, hereby enter into this Settlement Agreement (“Agreement”). The Agreement and the incorporated attached Order resolve staff's charges set forth below.
2. The Commission is an independent federal regulatory agency, established pursuant to, and responsible for, the enforcement of the CPSA, 15 U.S.C. 2051−2089. By executing the Agreement, staff is acting on behalf of the Commission, pursuant to 16 CFR 1118.20(b). The Commission issues the Order under the provisions of the CPSA.
3. PetSmart is a corporation, organized and existing under the laws of the state of Delaware, with its principal place of business in Phoenix, AZ.
4. Between April 2009 and September 2013, PetSmart imported and offered for sale in the United States, approximately 127,444 “Great Choice” or “Top Fin” brand 1.75 gallon, brandy snifter-style glass fish bowls (“Fish Bowls” or “Subject Products”) .
5. The Fish Bowls are a “consumer product,” “distribut[ed] in commerce,” as those terms are defined or used in sections 3(a)(5) and (8) of the CPSA, 15 U.S.C. 2052(a)(5) and (8). PetSmart is an “importer,” “manufacturer” and “retailer” of the Fish Bowls, as such terms are defined in sections 3(a)(11) and (13) of the CPSA, 15 U.S.C. 2052(a)(11) and (13).
6. The Fish Bowls contain a defect which could create a substantial product hazard and create an unreasonable risk of serious injury because they can crack, shatter, or break during normal use, posing a laceration hazard to consumers.
7. Between August 2011 and January 2014, PetSmart received at least 19 incident reports of Fish Bowls cracking, breaking, or shattering during normal use, which, in at least 12 instances, resulted in serious injuries, including deep lacerations requiring stitches and severed tendons necessitating surgery.
8. PetSmart received at least three reports of consumers sustaining serious injuries during normal use of the Fish Bowls between August 2011 and September 2011 but neither initiated an investigation into the Subject Products in response to these reports of serious injury nor immediately reported to the Commission.
9. In May 2013, after receiving additional reports, including two reports of serious injuries to consumers, PetSmart initiated an investigation and evaluation of the defect and risk associated with the Fish Bowls. That investigation, which concluded in July 2013, identified deficiencies in the thickness and distribution of the glass in the Fish Bowls. During its investigation, PetSmart continued to receive reports of serious injury caused by the Fish Bowls. Firms may conduct a reasonably expeditious investigation, not normally exceeding 10 days, to evaluate their reporting obligations.
10. PetSmart stopped sale of the Fish Bowls in September 2013. At the time PetSmart stopped sale of the Fish Bowls, PetSmart had received at least 12 reports of consumers being injured during normal use of the Subject Products.
11. PetSmart did not file a Full Report with the Commission until January 31, 2014, pursuant to 15 U.S.C. 2064(b). PetSmart and the Commission jointly announced a recall of 10,200 Fish Bowls on April 24, 2014.
12. PetSmart's Full Report contained information on only 10,211 Fish Bowls imported and sold between February 2013 and September 2013. However, information produced by PetSmart during staff's civil penalty investigation revealed that PetSmart had actually sold a total of 91,500 Fish Bowls between March 2010 and September 2013 that posed the same laceration hazard. PetSmart and the Commission jointly announced an expanded recall of 91,500 Fish Bowls on November 17, 2015.
13. By the date of the expanded recall, PetSmart received at least 32 reports of Fish Bowls cracking, breaking or shattering during normal use, including 18 reports of injury. PetSmart received at least six of these reports of injury after the first recall.
14. Despite having information that the Fish Bowls contained a defect and created an unreasonable risk of serious injury, PetSmart did not notify the Commission immediately of such defect or risk, as required by sections 15(b)(3) and (4) of the CPSA, 15 U.S.C. 2064(b)(3) and (4), in violation of section 19(a)(4) of the CPSA, 15 U.S.C. 2068(a)(4).
15. Because the information in PetSmart's possession constituted actual and presumed knowledge, PetSmart knowingly violated section 19(a)(4) of the CPSA, 15 U.S.C. 2068(a)(4), as the term “knowingly” is defined in section 20(d) of the CPSA, 15 U.S.C. 2069(d).
16. Pursuant to Section 20 of the CPSA, 15 U.S.C. 2069, PetSmart is subject to civil penalties for its knowing violation of section 19(a)(4) of the CPSA, 15 U.S.C. 2068(a)(4).
17. PetSmart's January 31, 2014 Full Report identified the Subject Products as 10,211 Fish Bowls, sold between February 2013 and September 2013, which posed a laceration hazard to consumers. The Full Report did not identify an additional 81,300 units of Subject Products that were sold prior to February 2013 that posed the same hazard and had been the subject of incident and injury reports received by PetSmart.
18. By failing to identify the correct amount and distribution dates of the Subject Products in PetSmart's Full Report, PetSmart knowingly misrepresented the scope of consumer products subject to an action required under section 15 of the CPSA. As a result of PetSmart's misrepresentation, the April 24, 2014 CPSC press release announcing the recall inaccurately stated that “[a]bout 10,200” Fish Bowls were affected by the hazard posed by the Fish Bowls. An expansion of the recall was announced on November 17, 2015.
19. By knowingly misrepresenting the scope of consumer products subject to an action under section 15 of the CPSA, PetSmart knowingly violated section 19(a)(13) of the CPSA, 15 U.S.C. 2068(a)(13), as the term “knowingly” is defined in section 20(d) of the CPSA, 15 U.S.C. 2069(d).
20. Pursuant to section 20 of the CPSA, 15 U.S.C. 2069, PetSmart is subject to civil penalties for its knowing violation of section 19(a)(13) of the CPSA, 15 U.S.C. 2068(a)(13).
21. PetSmart's settlement of this matter does not constitute an admission of staff's charges in paragraphs 4 through 20 above.
22. Between November 2013 and January 2014, PetSmart corresponded with CPSC staff regarding certain Fish
23. Following this correspondence, in January 2014, PetSmart provided the Commission with its report under section 15(b) of the CPSA, 15 U.S.C. 2064(b) concerning PetSmart's receipt of complaints and incident reports about the Fish Bowls. PetSmart's report provided information related only to Fish Bowls manufactured for sale in 2013, consistent with its communications to CPSC staff. CPSC staff did not ask PetSmart anything further regarding Fish Bowls sold prior to 2013.
24. On April 24, 2014, in conjunction with the Commission, PetSmart voluntarily announced a recall of Fish Bowls sold at PetSmart between February 2013 and September 2013.
25. PetSmart conducted the April 24, 2014, voluntary recall of the Fish Bowls, as well as the section 15(b) reporting, out of an abundance of caution and without PetSmart having concluded that the Fish Bowls contained a defect, posed a substantial product hazard, or created an unreasonable risk of serious injury or death.
26. On November 17, 2015, in conjunction with the Commission, PetSmart voluntarily expanded the recall of Fish Bowls to include units sold at PetSmart between March 2010 and February 2013. PetSmart disputes Staff's allegation that PetSmart had information that the Fish Bowls manufactured prior to 2013 contained a defect and created an unreasonable risk of serious injury.
27. PetSmart denies Staff's allegations that PetSmart knowingly misrepresented the scope of consumer products subject to an action under section 15 of the CPSA and that PetSmart knowingly violated section 19(a)(13).
28. Under the CPSA, the Commission has jurisdiction over the matter involving the Fish Bowls and over PetSmart.
29. The parties enter into the Agreement for settlement purposes only. The Agreement does not constitute an admission by PetSmart or a determination by the Commission that PetSmart violated the CPSA's reporting requirements.
30. In settlement of staff's charges, and to avoid the cost, distraction, delay, uncertainty, and inconvenience of protracted litigation or other proceedings, PetSmart shall pay a civil penalty in the amount of four million, two hundred fifty thousand dollars ($4,250,000) within thirty (30) calendar days after receiving service of the Commission's final Order accepting the Agreement. All payments to be made under the Agreement shall constitute debts owing to the United States and shall be made by electronic wire transfer to the United States via:
31. All unpaid amounts, if any, due and owing under the Agreement, shall constitute a debt due and immediately owing by PetSmart to the United States, and interest shall accrue and be paid by PetSmart at the federal legal rate of interest set forth at 28 U.S.C. 1961(a) and (b) from the date of Default, until all amounts due have been paid in full (hereinafter “Default Payment Amount” and “Default Interest Balance”). PetSmart shall consent to a Consent Judgment in the amount of the Default Payment Amount and Default Interest Balance, and the United States, at its sole option, may collect the entire Default Payment Amount and Default Interest Balance, or exercise any other rights granted by law or in equity, including, but not limited to, referring such matters for private collection, and PetSmart agrees not to contest, and hereby waives and discharges any defenses to, any collection action undertaken by the United States, or its agents or contractors, pursuant to this paragraph. PetSmart shall pay the United States all reasonable costs of collection and enforcement under this paragraph, respectively, including reasonable attorney's fees and expenses.
32. After staff receives this Agreement executed on behalf of PetSmart, staff shall promptly submit the Agreement to the Commission for provisional acceptance. Promptly following provisional acceptance of the Agreement by the Commission, the Agreement shall be placed on the public record and published in the
33. This Agreement is conditioned upon, and subject to, the Commission's final acceptance, as set forth above, and it is subject to the provisions of 16 CFR 1118.20(h). Upon the later of: (i) Commission's final acceptance of this Agreement and service of the accepted Agreement upon PetSmart, and (ii) the date of issuance of the final Order, this Agreement shall be in full force and effect, and shall be binding upon the parties.
34. Effective upon the later of: (i) the Commission's final acceptance of the Agreement and service of the accepted Agreement upon PetSmart, and (ii) and the date of issuance of the final Order, for good and valuable consideration, PetSmart hereby expressly and irrevocably waives and agrees not to assert any past, present, or future rights to the following, in connection with the matter described in this Agreement: (i) an administrative or judicial hearing; (ii) judicial review or other challenge or contest of the Commission's actions; (iii) a determination by the Commission of whether PetSmart failed to comply with the CPSA and the underlying regulations; (iv) a statement of findings of fact and conclusions of law; and (v) any claims under the Equal Access to Justice Act.
35. PetSmart represents and agrees that it has enhanced its compliance program to ensure compliance with the CPSA with respect to any consumer product imported, manufactured, distributed or sold by the Firm and will maintain said compliance program. PetSmart represents that the ongoing compliance program contains: (i) written standards, policies and procedures including those designed to ensure that information that may relate to or impact CPSA compliance (including information obtained by quality control personnel) is conveyed effectively to personnel responsible for CPSA compliance, whether or not an injury is referenced; (ii) a mechanism for confidential employee reporting of compliance-related questions or concerns to either a compliance officer or to another senior manager with authority to act as necessary; (iii) effective communication of company compliance-related policies and procedures regarding the CPSA to all applicable employees through training programs or otherwise; (iv) management oversight of and responsibility for compliance; and (v) retention of all CPSA compliance-related records for at
36. PetSmart represents and agrees that it has designed and implemented internal controls and procedures designed to ensure that, with respect to all consumer products imported, manufactured, distributed or sold by PetSmart: (i) information required to be disclosed by PetSmart to the Commission is recorded, processed and reported in accordance with applicable law; (ii) all reporting made to the Commission is timely, truthful, complete, accurate and in accordance with applicable law; and (iii) prompt disclosure is made to PetSmart's management of any significant deficiencies or material weaknesses in the design or operation of such internal controls that are reasonably likely to affect adversely, in any material respect, PetSmart's ability to record, process and report to the Commission in accordance with applicable law.
37. Upon reasonable request of staff, PetSmart shall provide written documentation of its internal controls and procedures, including, but not limited to, the effective dates of the procedures and improvements thereto. PetSmart shall cooperate fully and truthfully with staff and shall, upon reasonable notice make available all non-privileged information and materials, and personnel with direct involvement in such procedures and deemed necessary by staff to evaluate PetSmart's compliance with the terms of the Agreement.
38. The parties acknowledge and agree that the Commission may publicize the terms of the Agreement and the Order.
39. PetSmart represents that the Agreement: (i) is entered into freely and voluntarily, without any degree of duress or compulsion whatsoever; (ii) has been duly authorized; and (iii) constitutes the valid and binding obligation of PetSmart, enforceable against PetSmart in accordance with its terms. PetSmart will not directly or indirectly receive any reimbursement, indemnification, insurance related payment, or other payment in connection with the civil penalty to be paid by PetSmart pursuant to the Agreement and Order. The individuals signing the Agreement on behalf of PetSmart represent and warrant that they are duly authorized by PetSmart to execute the Agreement.
40. The signatories represent that they are authorized to execute this Agreement.
41. The Agreement is governed by the laws of the United States.
42. The Agreement and the Order shall apply to, and be binding upon, PetSmart and each of its successors, transferees, and assigns; and a violation of the Agreement or Order may subject PetSmart, and each of its successors, transferees, and assigns, to appropriate legal action.
43. The Agreement and the Order constitute the complete agreement between the parties on the subject matter contained therein.
44. The Agreement may be used in interpreting the Order. Understandings, agreements, representations, or interpretations apart from those contained in the Agreement and the Order may not be used to vary or contradict their terms. For purposes of construction, the Agreement shall be deemed to have been drafted by both of the parties and shall not, therefore, be construed against any party, for that reason, in any subsequent dispute.
45. The Agreement may not be waived, amended, modified, or otherwise altered, except as in accordance with the provisions of 16 CFR 1118.20(h). The Agreement may be executed in counterparts.
46. If any provision of the Agreement or the Order is held to be illegal, invalid, or unenforceable under present or future laws effective during the terms of the Agreement and the Order, such provision shall be fully severable. The balance of the Agreement and the Order shall remain in full force and effect, unless the Commission and PetSmart agree in writing that severing the provision materially affects the purpose of the Agreement and the Order.
Upon consideration of the Settlement Agreement entered into between PetSmart, Inc. (“PetSmart”), and the U.S. Consumer Product Safety Commission (“Commission”), and the Commission having jurisdiction over the subject matter and over PetSmart, and it appearing that the Settlement Agreement and the Order are in the public interest, it is:
ORDERED that the Settlement Agreement be, and is, hereby, accepted; and it is
FURTHER ORDERED that PetSmart shall comply with the terms of the Settlement Agreement and shall pay a civil penalty in the amount of four million, two hundred fifty thousand dollars ($4,250,000), within thirty (30) days after service of the Commission's final Order accepting the Settlement Agreement. The payment shall be made by electronic wire transfer to the Commission via:
Provisionally accepted and provisional Order issued on the 14th day of November, 2016.
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j. Shell Energy North America (US), L.P. (Shell Energy) filed its request to use the Traditional Licensing Process on October 3, 2016. Shell Energy provided public notice of its request on October 13, 2016. In a letter dated November 9, 2016, the Director of the Division of Hydropower Licensing approved Shell Energy's request to use the Traditional Licensing Process.
k. With this notice, we are designating Shell Energy as the Commission's non-federal representative for carrying out informal consultation pursuant to section 7 of the Endangered Species Act and section 305(b) of the Magnuson-Stevens Fishery Conservation and Management Act; and consultation pursuant to section 106 of the National Historic Preservation Act.
l. Shell Energy filed a Pre-Application Document (PAD; including a proposed process plan and schedule) with the Commission, pursuant to 18 CFR 5.6 of the Commission's regulations.
m. A copy of the PAD is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site (
n. Register online at
Take notice that the following hydroelectric applications have been filed with the Commission and are available for public inspection:
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The Commission strongly encourages electronic filing. Please file scoping comments using the Commission's eFiling system at
The Commission's Rules of Practice and Procedure require all interveners filing documents with the Commission to serve a copy of that document on each person on the official service list for the project. Further, if an intervener files comments or documents with the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, they must also serve a copy of the document on that resource agency.
k. These applications are not ready for environmental analysis at this time.
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The Upper Beaver Falls Project consists of: (1) A 328-foot-long, 25-foot-high concrete gravity dam with an uncontrolled overflow spillway; (2) a 48-acre reservoir with a storage capacity of 800 acre-feet at elevation 799.4 feet North American Vertical Datum of 1988 (NAVD 88); (3) a 17-foot-high, 26.5-foot-wide, 27.5-foot-long intake structure with a steel trash rack with 2 5/8-inch clear spacing; (4) a 90-foot-long, 16-foot-wide, 8-foot-high concrete penstock; (5) a powerhouse containing one turbine-generator with a nameplate rating of 1,500 kilowatts (kW); (6) a tailrace excavated in the riverbed; (7) a 2,120-foot-long, 2.4-kilovolt (kV) overhead and underground transmission line connecting to an existing substation; and (8) other appurtenances. The project generates about 8,685 megawatt-hours (MWh) annually.
The Lower Beaver Falls Hydroelectric Project consists of: (1) A 400-foot-long concrete gravity dam with a maximum height of 14 feet, including: (i) A 240-foot-long non-overflow section containing an 8-foot-wide spillway topped with flashboards ranging from 6 to 8 inches in height and (ii) a 160-foot-long overflow section with an ice sluice opening; (2) a 4-acre reservoir with a storage capacity of 27.9 acre-feet at a normal elevation of 769.6 feet NAVD 88; (3) an intake structure with a steel trash rack with 1 3/4-inch clear spacing, integral with a powerhouse containing two 500-kW turbine and generator units; (4) a tailrace; (5) a 505-foot-long, 2.4-kV transmission line connected to the Upper Beaver Falls powerhouse; and (6) appurtenant facilities. The project generates about 5,617 MWh annually.
The Lower Beaver Falls Project is located approximately 600 feet downstream of the Upper Beaver Falls Project. The dams and existing project facilities for both projects are owned by the applicant. The applicant proposes
m. A copy of the application is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
You may also register online at
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FERC staff will conduct one agency scoping meeting and one public meeting. The agency scoping meeting will focus on resource agency and non-governmental organization (NGO) concerns, while the public scoping meeting is primarily for public input. All interested individuals, organizations, and agencies are invited to attend one or both of the meetings, and to assist the staff in identifying the scope of the environmental issues that should be analyzed in the EA. The times and locations of these meetings are as follows:
Copies of the Scoping Document (SD1) outlining the subject areas to be addressed in the EA were distributed to the parties on the Commission's mailing list. Copies of the SD1 will be available at the scoping meeting or may be viewed on the web at
The Applicant and FERC staff will conduct a project Environmental Site Review beginning at 1:00 p.m. on December 13, 2016. All interested individuals, organizations, and agencies are invited to attend. All participants should meet at the Upper Beaver Falls Project facility, located at 9692 New York State Route 126, Castorland, New York. All participants are responsible for their own transportation to the site and during the site visit. Anyone with questions about the Environmental Site Review should contact Mr. Jeff Kirch, Northern New York Regional Operator for Algonquin Power (Beaver Falls) LLC, at 315-783-5854 or
At the scoping meetings, the staff will: (1) Summarize the environmental issues tentatively identified for analysis in the EA; (2) solicit from the meeting participants all available information, especially quantifiable data, on the resources at issue; (3) encourage statements from experts and the public on issues that should be analyzed in the EA, including viewpoints in opposition to, or in support of, the staff's preliminary views; (4) determine the resource issues to be addressed in the EA; and (5) identify those issues that require a detailed analysis, as well as those issues that do not require a detailed analysis.
The meetings are recorded by a stenographer and become part of the formal record of the Commission proceeding on the projects.
Individuals, organizations, and agencies with environmental expertise and concerns are encouraged to attend the meeting and to assist the staff in defining and clarifying the issues to be addressed in the EA.
The staff of the Federal Energy Regulatory Commission (FERC or Commission) has prepared an environmental assessment (EA) for the Northern Lights 2017 Expansion Project, proposed by Northern Natural Gas Company (Northern) in the above-referenced docket. Northern requests authorization to construct, operate, and maintain new natural gas facilities in Sherburne, Isanti, and Rice counties, Minnesota, to provide for approximately 76,000 dekatherms per day to serve increased markets for industrial, commercial, and residential uses.
The EA assesses the potential environmental effects of the construction and operation of the Northern Lights 2017 Expansion Project in accordance with the requirements of the National Environmental Policy Act. The FERC staff concludes that approval of the proposed project, with appropriate mitigating measures, would not constitute a major federal action significantly affecting the quality of the human environment.
The Northern Lights 2017 Expansion Project includes the following facilities:
• Approximately 2 miles of 8-inch-diameter pipeline loop
• approximately 2.8 miles of 12-inch-diameter pipeline loop in Isanti County; and
• an additional 15,900-horsepower compression unit at Northern's existing Faribault Compressor Station in Rice County.
The FERC staff mailed copies of the EA to federal, state, and local government representatives and agencies; elected officials; environmental and public interest groups; Native American tribes; potentially affected landowners and other interested individuals and groups; and newspapers and libraries in the project area. In addition, the EA is available for public viewing on the FERC's Web site (
Any person wishing to comment on the EA may do so. Your comments should focus on the potential environmental effects, reasonable alternatives, and measures to avoid or lessen environmental impacts. The more specific your comments, the more useful they will be. To ensure that the Commission has the opportunity to consider your comments prior to making its decision on this project, it is important that we receive your comments in Washington, DC on or before on or before Friday, December 9, 2016.
For your convenience, there are three methods you can use to file your comments to the Commission. In all instances, please reference the project docket number (CP16-472-000) with your submission. The Commission encourages electronic filing of comments and has expert staff available to assist you at (202) 502-8258 or
(1) You can file your comments electronically using the eComment feature on the Commission's Web site (
(2) You can also file your comments electronically using the eFiling feature on the Commission's Web site (
(3) You can file a paper copy of your comments by mailing them to the following address: Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888 First Street NE., Room 1A, Washington, DC 20426.
Any person seeking to become a party to the proceeding must file a motion to intervene pursuant to Rule 214 of the Commission's Rules of Practice and Procedures (18 CFR 385.214).
Additional information about the proposed project is available from the Commission's Office of External Affairs, at (866) 208-FERC, or on the FERC Web site (
In addition, the Commission offers a free service called eSubscription which allows you to keep track of all formal issuances and submittals in specific dockets. This can reduce the amount of time you spend researching proceedings by automatically providing you with notification of these filings, document summaries, and direct links to the documents. Go to
In accordance with the National Environmental Policy Act of 1969 and the Federal Energy Regulatory Commission's (Commission) regulations, 18 CFR part 380 (Order No. 486, 52 FR 47897), the Office of Energy Projects has reviewed the application for a new license for the Williams Hydroelectric Project, located on the Kennebec River in Somerset County, Maine, and has prepared an Environmental Assessment (EA). The project does not occupy any federal land.
The EA contains the staff's analysis of the potential impacts of the project and concludes that licensing the project, with appropriate environmental protective measures, would not constitute a major federal action that would significantly affect the quality of the human environment.
A copy of the EA is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site at
You may also register online at
Any comments should be filed within 30 days from the date of this notice. The Commission strongly encourages electronic filing. Please file comments using the Commission's eFiling system at
For further information, contact Amy Chang at (202) 502-8250 or
Take notice that on October 28, 2016, Texas Eastern Transmission, LP (Texas Eastern), 5400 Westheimer Court, Houston, Texas 77056, filed an application pursuant to section 7(b) of the Natural Gas Act (NGA) and Part 157 of the Commission's Regulations requesting authority to abandon a total of approximately 165 miles of its Line 1 pipeline that has been previously removed from active gas service, along with other associated facilities, in Ohio, West Virginia and Pennsylvania. Texas Eastern states that the facilities proposed for abandonment are not required to meet current firm service obligations and that their abandonment will eliminate the need for future operating and maintenance expenditures.
The filing may be viewed on the web at
Any questions concerning this application should be directed to Lisa A. Connolly, General Manager, Rates and Certificates, Texas Eastern Transmission, LP, P.O. Box 1642, Houston, Texas 77251, phone: (713) 627-4102, Fax: (713) 627-5947 or email:
Pursuant to section 157.9 of the Commission's rules, 18 CFR 157.9, within 90 days of this Notice the Commission staff will either: Complete its environmental assessment (EA) and place it into the Commission's public record (eLibrary) for this proceeding, or issue a Notice of Schedule for Environmental Review. If a Notice of Schedule for Environmental Review is issued, it will indicate, among other milestones, the anticipated date for the Commission staff's issuance of the final environmental impact statement (FEIS) or EA for this proposal. The filing of the EA in the Commission's public record for this proceeding or the issuance of a Notice of Schedule will serve to notify federal and state agencies of the timing for the completion of all necessary reviews, and the subsequent need to complete all federal authorizations within 90 days of the date of issuance of the Commission staff's FEIS or EA.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before the comment date stated below, file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit 5 copies of filings made with the Commission and must mail a copy to the applicant and to every other party in the proceeding. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in determining the appropriate action to be taken, but the filing of a comment alone will not serve to make the filer a party to the proceeding. The Commission's rules require that persons filing comments in opposition to the project provide copies of their protests only to the party or parties directly involved in the protest.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commenters will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commenters will not be required to serve copies of filed documents on all other parties. However, the non-party commenters will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
The Commission strongly encourages electronic filings of comments, protests and interventions in lieu of paper using the “eFiling” link at
Take notice that on October 31, 2016, Florida Gas Transmission Company, LLC (FGT), 1300 Main Street, Houston, Texas 77002, filed in Docket No. CP17-8-000 an application pursuant to section 7(c) of the Natural Gas Act (NGA) for authorization to construct and operate: (i) 13.17 miles of 12-inch-diameter pipeline and a meter station in Matagorda and Wharton Counties, Texas; (ii) 11.01 miles of 16-inch-diameter pipeline and a meter station in Jefferson County, Texas; (iii) 0.5 miles of pipeline and a meter station in Acadia Parish, Louisiana; (iv) a meter station in Calcasieu Parish, Louisiana; and (v) to modify station piping at Compressor Station 6 in Orange County, Texas (East-West Project). The East-West Project is designed to deliver 275 million British thermal units per day of firm service. The estimated cost of the proposed project is approximately $68.9 million, all as more fully set forth in the application which is on file with the Commission and open to public inspection. The filing is available for review at the Commission in the Public Reference Room or may be viewed on the Commission's Web site web at
Any questions concerning this application may be directed to Stephen
Pursuant to section 157.9 of the Commission's rules, 18 CFR 157.9, within 90 days of this Notice the Commission staff will either: Complete its environmental assessment (EA) and place it into the Commission's public record (eLibrary) for this proceeding; or issue a Notice of Schedule for Environmental Review. If a Notice of Schedule for Environmental Review is issued, it will indicate, among other milestones, the anticipated date for the Commission staff's issuance of the EA for this proposal. The filing of the EA in the Commission's public record for this proceeding or the issuance of a Notice of Schedule for Environmental Review will serve to notify federal and state agencies of the timing for the completion of all necessary reviews, and the subsequent need to complete all federal authorizations within 90 days of the date of issuance of the Commission staff's EA.
There are two ways to become involved in the Commission's review of this project. First, any person wishing to obtain legal status by becoming a party to the proceedings for this project should, on or before the comment date stated below file with the Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, a motion to intervene in accordance with the requirements of the Commission's Rules of Practice and Procedure (18 CFR 385.214 or 385.211) and the Regulations under the NGA (18 CFR 157.10). A person obtaining party status will be placed on the service list maintained by the Secretary of the Commission and will receive copies of all documents filed by the applicant and by all other parties. A party must submit seven copies of filings made in the proceeding with the Commission and must mail a copy to the applicant and to every other party. Only parties to the proceeding can ask for court review of Commission orders in the proceeding.
However, a person does not have to intervene in order to have comments considered. The second way to participate is by filing with the Secretary of the Commission, as soon as possible, an original and two copies of comments in support of or in opposition to this project. The Commission will consider these comments in determining the appropriate action to be taken, but the filing of a comment alone will not serve to make the filer a party to the proceeding. The Commission's rules require that persons filing comments in opposition to the project provide copies of their protests only to the party or parties directly involved in the protest.
Persons who wish to comment only on the environmental review of this project should submit an original and two copies of their comments to the Secretary of the Commission. Environmental commentors will be placed on the Commission's environmental mailing list, will receive copies of the environmental documents, and will be notified of meetings associated with the Commission's environmental review process. Environmental commentors will not be required to serve copies of filed documents on all other parties. However, the non-party commentors will not receive copies of all documents filed by other parties or issued by the Commission (except for the mailing of environmental documents issued by the Commission) and will not have the right to seek court review of the Commission's final order.
The Commission strongly encourages electronic filings of comments, protests and interventions in lieu of paper using the “eFiling” link at
Environmental Protection Agency (EPA).
Notice.
EPA has submitted the following information collection request (ICR) to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (PRA): “Notification of Chemical Exports—TSCA Section 12(b)” and identified by EPA ICR No. 0795.15 and OMB Control No. 2070-0030. The ICR, which is available in the docket along with other related materials, provides a detailed explanation of the collection activities and the burden estimate that is only briefly summarized in this document. EPA has addressed the comments received in response to the previously provided public review opportunity issued in the
Comments must be received on or before December 19, 2016.
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPPT-2015-0435, to both EPA and OMB as follows:
• To EPA online using
• To OMB via email to
EPA's policy is that all comments received will be included in the 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. Do not submit electronically any information you consider to be CBI or other information whose disclosure is restricted by statute.
Colby Lintner, Environmental Assistance Division (7408M), Office of Pollution Prevention and Toxics, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001; telephone number: (202) 554-1404; email address:
Under PRA, 44 U.S.C. 3501
EPA will disclose information that is covered by a claim of confidentiality only to the extent permitted by, and in accordance with, the procedures in TSCA section 14 and 40 CFR part 2.
44 U.S.C. 3501
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency has submitted an information collection request (ICR), “NESHAP for Boat Manufacturing (40 CFR part 63, subpart VVVV) (Renewal)” (EPA ICR No. 1966.06, OMB Control No. 2060-0546), to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before December 19, 2016.
Submit your comments, referencing Docket ID Number EPA-HQ-OECA-2013-0339, to: (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI), or other information whose disclosure is restricted by statute.
Patrick Yellin, Monitoring, Assistance, and Media Programs Division, Office of Compliance, Mail Code 2227A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-2970; fax number: (202) 564-0050; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Environmental Protection Agency (EPA).
Notice of a public meeting, new Designated Federal Officer and NDWAC membership.
The U.S. Environmental Protection Agency (EPA) is announcing a meeting of the National Drinking Water Advisory Council (NDWC), as authorized under the Safe Drinking Water Act. The meeting is scheduled for December 6 and 7, 2016. EPA is also announcing Ms. Tracey Ward as EPA's new Designated Federal Officer (DFO) for the NDWAC, Ms. Carrie Lewis as the NDWAC Chairperson, and Ms. June Anne Swallow, P.E., as a new member of NDWAC. The NDWAC typically considers issues associated with drinking water protection and public drinking water systems. During this meeting, the NDWAC will focus discussions on developing recommendations for the EPA Administrator on the Lead and Copper National Primary Drinking Water Regulation—Long Term Revisions.
The meeting on December 6, 2016, will be held from 9:30 a.m. to 4:15 p.m., eastern time; and December 7, 2016, from 8:30 a.m. to noon, eastern time.
The public meeting will be held in the City of Washington, District of Columbia. The exact location of the meeting will be noticed in the
For more information about this meeting or to request written materials, contact Tracey M. Ward of the Office of Ground Water and Drinking Water, U.S. Environmental Protection Agency, by phone at (202) 564-3796 or by email at
To ensure adequate time for public involvement, individuals or organizations interested in presenting an oral statement should notify Tracey M. Ward by November 22, 2016, by email at
Office of Environmental Information, Environmental Protection Agency (EPA).
Notice of amended Privacy Act system of records final.
The FOIA Request and Appeal File system of records is being amended to include all information and data elements that are being collected by the Environmental Protection Agency (EPA) and participating agencies as it relates to FOIA requests, appeals and responses. This information is being removed from the Federal Docket Management System (FDMS) system of records and being added to the FOIA Request and Appeal File (EPA-9) system of records. The FOIA Request and Appeal File system of records is also being amended to provide an additional routine use for the system. The additional routine use being added to this system of records, will allow the National Archives and Records Administration (NARA), Office of Government Information Services (OGIS), and the EPA to share information in the FOIA Request and Appeal File system in order to mediate and resolve disputes between requesters and administrative agencies without delay. OGIS will work directly with each agency using FOIAonline to access case level information that is not
Records are stored in a secure, password protected electronic system that utilizes security hardware and software to include multiple firewalls, active intruder detection and role-based accessed controls. Additional safeguards vary by participating agencies. EPA also has records from the period prior to its use of the FOIAonline system which are stored in file folders in lockable file cabinets. The FOIA Request and Appeal File system is maintained under the authority of the Freedom of Information Act, 5 U.S.C. 552.
Persons wishing to comment on this system or records notice must do so by December 27, 2016.
Submit your comments, identified by Docket ID No. EPA-HQ-OEI-2015-0758, by one of the following methods:
Larry Gottesman, FOIA, Library and Accessibility Division, Office of Environmental Information, Office, (202) 566-2162, U.S. EPA, Office of Environmental Information, MC 2282T, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
The Freedom of Information Act (FOIA) Request and Appeal File (EPA-9) system contains a copy of each FOIA request and appeal received by the EPA and a copy of all correspondence related to the request, including name, affiliation address, telephone numbers, and other information about a requester. FOIAonline is managed and used by the EPA and other agencies to process, track and respond to FOIA requests and appeals. The FOIAonline system provides the EPA and partner agencies with a secure, password protected Web site to electronically receive, process, track and store requests from the public for federal records; post responsive records to a Web site; collect data for annual reporting requirements to the Department of Justice and manage internal FOIA administration activities. In addition, the FOIA system allows the public to submit and track FOIA requests and appeals; access requests and responsive records online and obtain the status of requests filed with the EPA and partner agencies. FOIAonline is a software application used by the EPA and other agencies. Social security numbers and other types of personally identifiable information may be provided in requests or in responsive documents. In some cases, agencies may require this information to fulfill a request. All participating agencies will ensure that sensitive PII is not made publicly available. The name of a FOIA requester may be publicly available and searchable by the public based on an agency's policies. With the exception of a requester's name, any other personally identifiable information provided by a requester during the process of completing the online request form or creating an online account (
Freedom of Information Act (FOIA) Request and Appeal File.
EPA's National Computer Center located at 109 T.W. Alexander Drive, Durham, NC 27709.
Freedom of Information Act, 5 U.S.C. 552.
To provide the public a single location to submit and track FOIA requests and appeals filed with the EPA and participating agencies, to manage internal FOIA administration activities and to collect data for annual reporting requirements to the Department of Justice.
All persons requesting information or filing appeals under the Freedom of Information Act.
A copy of each Freedom of Information Act (FOIA) request received by the EPA and other participating agencies and a copy of all correspondence related to the request, including individuals' names, mailing addresses, email addresses, phone numbers, social security numbers, dates of birth, alias(es) used by the requester, alien numbers assigned to travelers crossing national borders, requesters' parents' names, user names and passwords for registered users, FOIA tracking numbers, dates requests are submitted and received, related appeals and agency responses. Records also include communications with requesters, internal FOIA administrative documents (
General routine uses A, E, F, G, H, K, and L apply to this system. Records may also be disclosed to:
1. Another federal agency (a) with an interest in the record in connection with a referral of a Freedom of Information Act (FOIA) request to that agency for its views or decision on disclosure, or (b) in order to obtain advice and recommendations concerning matters on which the agency has specialized experience or particular competence that may be useful to an agency in making required determinations under the FOIA.
2. To the National Archives and Records Administration, Office of Government Information Services (OGIS), to the extent necessary to fulfill its responsibilities in 5 U.S.C. 552(h), to review administrative agency policies, procedures and compliance with the Freedom of Information Act (FOIA), and to facilitate OGIS' offering of mediation services to resolve disputes between persons making FOIA requests and administrative agencies.
Records are stored in file folders in lockable file cabinets. Records are also stored in a secure, password protected electronic system that utilizes security hardware and software to include multiple firewalls, active intruder detection and role-based accessed controls. Additional safeguards vary by participating agencies.
Requests are retrieved from the system by numerous data elements and key word searches, including name, agency, dates, subject, FOIA tracking number and other information retrievable with full-text searching capability.
Each federal agency handles its records in accordance with its records schedule as approved by NARA. FOIA records are covered under NARA General Record Schedule 14—Information Services Records unless a participating agency's records are managed under other record schedules approved by NARA.
Computer records are maintained in a secure, password protected computer system. Paper records are maintained in lockable file cabinets. All records are maintained in secure, access-controlled areas or buildings.
Tim Crawford,
Individuals seeking access to their own personal information in this system of records is required to provide adequate identification (
Requests for correction or amendment must identify the record to be changed and the corrective action sought. Requests must be submitted to the agency contact indicated on the initial document for which the related contested record was submitted.
Any individual who wants to know whether this system of records contains a record about him or her, should make a written request to the EPA Privacy Officer, MC 2822T, 1200 Pennsylvania Avenue NW., Washington, DC 20460.
None.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency has submitted an information collection request (ICR), “NSPS for Magnetic Tape Coating Facilities (40 CFR part 60, subpart SSS) (Renewal)” (EPA ICR No. 1135.12, OMB Control No. 2060-0171), to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before December 19, 2016.
Submit your comments, referencing Docket ID EPA-HQ-OECA-2013-0318, to: (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change, including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI), or other information whose disclosure is restricted by statute.
Patrick Yellin, Monitoring, Assistance, and Media Programs Division, Office of Compliance, Mail Code 2227A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-2970; fax number: (202) 564-0050; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Environmental Protection Agency (EPA).
Notice.
The U.S. Environmental Protection Agency (EPA) is publishing a final list of contaminants that are currently not subject to any proposed or promulgated national primary drinking water regulation. These contaminants are known or anticipated to occur in public water systems and may require regulation under the Safe Drinking Water Act (SDWA). This list is the Fourth Contaminant Candidate List (CCL 4) published by EPA since the SDWA amendments of 1996. This Final CCL 4 includes 97 chemicals or chemical groups and 12 microbial contaminants.
For information on chemical contaminants contact Meredith Russell, Office of Ground Water and Drinking Water, Standards and Risk Management Division, at (202) 564-0814 or email
The Final CCL 4 will not impose any requirements on anyone. Instead, this action notifies interested parties of the EPA's Final CCL 4 of unregulated drinking water contaminants and provides a summary of the major comments received on the February 4, 2015, Draft CCL 4
EPA has established a docket for this action under Docket ID No. EPA-HQ-OW-2012-0217. Although listed in the index, some information is not publicly available,
You may access this
The Safe Drinking Water Act (SDWA), as amended in 1996, requires EPA to publish a list every five years of currently unregulated contaminants that may pose risks for drinking water (referred to as the Contaminant Candidate List, or CCL). This list is subsequently used to make regulatory determinations on whether or not to regulate at least five contaminants from the CCL with national primary drinking water regulations (NPDWRs) ((SDWA section 1412(b)(1)). The purpose of today's action is to present EPA's final list of contaminants on the CCL 4, a summary of the major public comments received on the Draft CCL 4 and EPA's responses. Today's action only addresses the Final CCL 4. Regulatory Determination (RD) for contaminants on the CCL is a separate agency action.
Under the 1996 amendments to SDWA, Congress established a risk-based approach for determining which contaminants would become subject to drinking water standards. The approach includes three components, the CCL, the Unregulated Contaminant Monitoring Rule (UCMR), and RD. In preparing the CCL, EPA screens and evaluates unregulated contaminants to identify those that may require future drinking water regulations. Inclusion on the CCL does not mean that any particular contaminant will necessarily be regulated in the future. The UCMR provides a mechanism to obtain nationally representative occurrence data for unregulated contaminants. The data provided by UCMR is one of the primary sources of occurrence information used to evaluate contaminants in the RD process.
Under the RD process, EPA evaluates UCMR and other occurrence data along with health effects data for contaminants on the CCL to see which ones present the greatest public health concern and have sufficient information for the agency to make a regulatory determination. EPA must make regulatory determinations for at least five contaminants listed on the CCL every five years. Today's action addresses only the CCL 4 and not the UCMR or RD stages of the SDWA contaminant regulatory development process.
Section 1412(b)(1) of the SDWA, as amended in 1996, requires EPA to publish the CCL every five years. The SDWA specifies that the list must include contaminants that are not subject to any proposed or promulgated NPDWRs, are known or anticipated to occur in public water systems (PWSs), and may require regulation under the SDWA. The unregulated contaminants considered for listing shall include, but not be limited to, hazardous substances identified in section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, and substances registered as pesticides under the Federal Insecticide, Fungicide, and Rodenticide Act.
The SDWA directs the agency to consider the health effects and occurrence information for unregulated contaminants to identify those contaminants that present the greatest public health concern related to exposure from drinking water. The statute further directs the agency to take into consideration the effect of contaminants upon subgroups that comprise a meaningful portion of the general population (such as infants, children, pregnant women, the elderly and individuals with a history of serious illness or other subpopulations) that are identifiable as being at greater risk of
Section 1445(a)(2) of the SDWA mandates that EPA promulgate regulations (known as the Unregulated Contaminant Monitoring Rule or UCMR) to establish criteria for a monitoring program for unregulated contaminants. This section, as amended in 1996, requires that once every five years, EPA issue a list of no more than 30 unregulated contaminants to be monitored by PWSs. SDWA requires that EPA enter the monitoring data into the agency's publicly available National Contaminant Occurrence Database. EPA's UCMR program must ensure that systems serving a population larger than 10,000 people, as well as a nationally representative sample of PWSs serving 10,000 or fewer people, are required to monitor.
Section 1412(b)(1)(B)(ii) of the SDWA, as amended in 1996, requires EPA at five year intervals, to make determinations of whether or not to regulate no fewer than five contaminants from the CCL. EPA evaluates the CCL contaminants with sufficient health effects and occurrence information to determine whether a regulation is required or not required. The 1996 SDWA Amendments specify three criteria to determine whether a contaminant may require regulation:
• The contaminant may have an adverse effect on the health of persons;
• the contaminant is known to occur or there is a substantial likelihood that the contaminant will occur in PWSs with a frequency and at levels of public health concern; and
• in the sole judgment of the Administrator, regulation of such contaminant presents a meaningful opportunity for health risk reduction for persons served by PWSs.
If EPA determines that these three statutory criteria are met and makes a final determination to regulate a contaminant, the agency has 24 months to publish a proposed maximum contaminant level goal
A brief summary of CCL 1, CCL 2, Regulatory Determination 1 (RD 1) and Regulatory Determination 2 (RD 2) was published in the
The CCL 3 included 104 chemicals or chemical groups and 12 microbiological contaminants. In developing the CCL 3, EPA implemented an improved process from the process used for CCL 1 and CCL 2. This new process built on evaluations used for previous CCLs and was based on substantial expert input and recommendations from the National Academy of Sciences' National Research Council (NRC) and the National Drinking Water Advisory Council (NDWAC). EPA used a multi-step CCL process to identify contaminants for inclusion on the Final CCL 3. The key steps included:
• Identifying a broad universe of potential drinking water contaminants (called the CCL 3 Universe). EPA initially considered approximately 7,500 potential chemical and microbial contaminants (more information on the identification of the CCL 3 Universe can be found in USEPA, 2009a and USEPA, 2009b).
• Applying screening criteria to the universe, EPA identified almost 600 of those contaminants that should be further evaluated (the preliminary CCL or PCCL) based on a contaminant's potential to occur in PWSs and the potential for public health concern (more information on the CCL 3 screening process can be found in USEPA, 2009c and USEPA, 2009d).
• Selecting the final list of 116 contaminants from the PCCL to include on the CCL based on more detailed evaluation of occurrence and health effects and expert judgment as well as public input (this step of the CCL 3 process is called the classification process and more information can be found in USEPA, 2009e and USEPA, 2009f).
The CCL 3 interpreted the criterion that contaminants are known or anticipated to occur in public water systems broadly. In evaluating this criterion, EPA considered not only public water system monitoring data, but also data on concentrations in ambient surface and ground waters, releases to the environment (
EPA published the Announcement of Final Regulatory Determinations for Contaminants on CCL 3 in the
This section provides an overview of the process used for the Third Regulatory Determination (RD 3). A summary of the process can be found in the
The purpose of the first phase, the Data Availability Phase, was to determine if the agency may have sufficient data to characterize the potential health effects and known or likely occurrence in drinking water. With regard to sufficient health effects data used to identify potential adverse health effect(s), the agency considered whether a peer reviewed health risk assessment was available or in process from an EPA or a comparable non-EPA source. In regard to sufficient occurrence data, the agency considered the availability of nationally representative finished water data and whether other finished water data were available that indicated known and/or likely occurrence in PWSs. After conducting the health and occurrence data availability assessments, the agency identified those contaminants and contaminant groups that meet the following Phase 1 data availability criteria:
(a) A peer reviewed health assessment is available or in process, and
(b) A widely available analytical method for monitoring exists, and
(c) Either nationally representative finished water occurrence data are available, or other finished water occurrence data shows occurrence at levels greater than one-half of the CCL 3 health reference level (HRL).
If a contaminant met these three criteria, it was placed on a “short list” and proceeded to Phase 2. From the 116 CCL 3 contaminants, the agency identified a short list of 37 contaminants (35 CCL 3 contaminants and two non-CCL 3 contaminants
During the second phase, the Data Evaluation Phase, the agency further evaluated each of the 37 contaminants on the short list to identify those that had sufficient data (or were expected to have sufficient data) for EPA to assess the three statutory criteria listed in section I.D.4 of this notice.
To identify the contaminants that present the greatest public health concern, the agency specifically focused its efforts on identifying those contaminants or contaminant groups that are occurring or have substantial likelihood to occur at levels and frequencies of public health concern, based on the best available peer reviewed data. In addition to health and occurrence information data assessed in Phase 1, the agency collected additional health and occurrence data and more thoroughly evaluated this information to identify a list of contaminants that should proceed to Phase 3. If the agency found that sufficient data were not available or not likely to be available to evaluate the three statutory criteria during the first and second phases, then the contaminant was not considered a candidate for making a regulatory determination during the current cycle, and the agency will conduct research, collect information or find other avenues to fill the data and information gaps. For these contaminants, additional data that becomes available in the future may be considered for future CCLs and RDs.
If sufficient data were available for a contaminant to characterize the potential health effects and known or likely occurrence in drinking water, the contaminant was evaluated against the three statutory criteria (listed in section I.D.4) in the third phase of the process, the Regulatory Determination Assessment Phase.
The Final CCL 4 includes 97 chemicals or chemical groups and 12 microbes listed in Exhibit 1. Exhibit 1 also shows chemical abstract service registry numbers (CASRNs) of the contaminants on the Final CCL 4 and their status across other EPA programs related to CCL (
The Draft CCL 4 was published in the
EPA carried forward all contaminants listed on CCL 3 to the Draft CCL 4 with the exception of perchlorate, for which the agency made a positive regulatory determination, and the five CCL 3 contaminants with preliminary regulatory determinations at that time, pending their final regulatory determinations. This carry forward process is consistent with that previously used in CCL 2. The agency took this approach based on the following considerations: (1) In developing the CCL 3, the agency implemented a robust process recommended by the NRC and the NDWAC to screen and score the universe of potential contaminants; (2) EPA used the best available, peer reviewed data and information to evaluate contaminants for CCL 3; and (3) Carrying forward CCL 3 contaminants allowed the agency to focus resources on evaluating contaminants nominated by the public for CCL 4 and review new data for CCL 1 or CCL 2 contaminants with previous negative regulatory determinations (68 FR 42897, July 18, 2003 (USEPA, 2003); 73 FR 44251, July 30, 2008 (USEPA, 2008b)). Carrying forward CCL 3 contaminants also allowed EPA to focus resources on UCMR 3 monitoring and analysis and RD 3 analyses.
EPA sought public nominations in a
Four nominated contaminants were already covered by a proposed or existing NPDWR and were not eligible for the CCL 4 since the SDWA specifies that the CCL only include those contaminants without any proposed or promulgated NPDWRs. Seven of the nominated contaminants were on CCL 3 and were carried forward to the Draft CCL 4. EPA reviewed the nominations and supporting information to determine if any new data were provided that had not been previously evaluated for CCL 3. The agency also collected and evaluated additional data for the nominated contaminants, when it was available, including the seven nominated contaminants carried forward from CCL 3. The additional data was obtained from both updated CCL 3 data sources and from new data sources that were not available at the time the agency finalized CCL 3. These data sources are listed in the “Data Sources for the Contaminant Candidate List 4” support document (USEPA, 2016c).
Nominated contaminants with new data were screened and scored using the same process used in CCL 3. Through this analysis, EPA added manganese and nonylphenol to the Draft CCL 4 because, as discussed in more detail in the Draft CCL 4
EPA evaluated the 20 contaminants from CCL 1 and CCL 2 for which the agency made negative regulatory determinations. EPA collected and evaluated new or updated data for the previous negative regulatory determination chemicals. Since RD 3 was recently published using the best available data, EPA did not include the RD 3 negative regulatory determinations in this evaluation. The agency concluded there was not sufficient new information for 19 of the 20 contaminants with previous negative regulatory determinations to justify including them on the Draft CCL 4. Because commenters also did not identify such information, EPA has not included these contaminants on the Final CCL 4. EPA added manganese, a previous negative regulatory determination from RD 1, to the Draft and Final CCL 4 as previously discussed in section III.B.
EPA requested comment on the Draft CCL 4 and how to further improve upon the selection process developed for CCL 3 as a tool for future CCLs. The agency received 27 public comment letters on the Draft CCL 4. EPA considered all public comments and evaluated the data and information provided by commenters in selecting the Final CCL 4. EPA used the same process used in the CCL 3 to screen and score any contaminants with new data or information provided by commenters. EPA prepared responses to all public comments that are in the “Comment Response Document for the Fourth Drinking Water Contaminant Candidate List (Categorized Public Comments)” document, which is available in the docket for this action (USEPA, 2016f).
Based on the analyses conducted as a result of public comments, EPA determined not to list three cancelled pesticides (disulfoton, fenamiphos, and molinate) on the Final CCL 4 that were included on the Draft CCL 4 because, as discussed more fully in the following sections, these chemicals are not known or anticipated to occur in PWSs and are not anticipated to require regulation. With the exception of these three pesticides, all of the contaminants listed on the Draft CCL 4 are listed on the Final CCL 4.
A summary of some of the key public comments received, recommendations from EPA's Science Advisory Board (SAB) on the CCL 4, and EPA's responses are provided in this section. Data used to evaluate the contaminants for the CCL 4 can be found in the Contaminant Information Sheets (CISs) for the Final Fourth Contaminant Candidate List (CCL 4) (USEPA, 2016e), which can be found in the docket for this action available at
The EPA SAB and its Drinking Water Committee (DWC) reviewed the Draft CCL 4 and provided recommendations to the Administrator on January 11, 2016, in their report “Review of the EPA's Draft Fourth Drinking Water Contaminant Candidate List (CCL 4)
The SAB's recommendations and comments on the overall CCL 4 process and documentation are summarized in the following bullet points:
• The SAB stated that the general protocol used to evaluate contaminants on the CCL 4 is well described and conceptually clear. They concluded the transparency and clarity of the process has improved since CCL 3 was finalized.
• The SAB said that the documentation for CCL 4 lacked specific information necessary in order to follow the decision-making process for listing an individual contaminant on the Draft CCL 4. Specific suggestions to improve transparency and clarity of the support documents include:
○ Develop a summary table that consolidates summary information on all carried forward and nominated contaminants.
○ Display results of the CCL 4 screening and classification process in a manner that explicitly outlines the scoring schemes used and the scientific rationale in applying the selection criteria.
○ Provide examples for both microbial and chemical contaminants that display the process of how contaminants were included on or eliminated from the Draft CCL 4.
○ Clearly describe and improve the process for removing contaminants from prior CCLs, where appropriate, when such lists serve as the basis for a new CCL.
○ Explain the evaluation of CCL contaminants during the RD process.
• The SAB recommended that EPA should utilize data from UCMR 3 monitoring as it becomes available.
• The SAB stated that the CCL 4 list includes a number of contaminants carried forward from the CCL 3 without providing a sense of the relative priority of the listed chemicals. The SAB recommended EPA prioritize the list to inform future regulatory decision-making and to help researchers focus their efforts.
The agency has updated the technical support documents for the CCL 4 to increase the transparency of its decisions relative to the contaminants included on the Final CCL 4. For instance, the CIS support document provides examples showing the criteria and process for including or excluding chemical and microbial contaminants from the CCL 4. Additionally, a summary table in the same support document presents factors used to determine how the CCL 4 contaminants were selected. The agency also summarizes the process used to evaluate contaminants under RD 3 in section I.E.3 of this notice.
While EPA agrees with the SAB about the importance of using UCMR data to inform the CCL, the agency does not believe it is appropriate to use preliminary UCMR 3 data to make final CCL 4 decisions. The UCMR 3 data set was not finalized within the timeframe for use and analysis under CCL 4. The UCMR 3 monitoring period ended in December 2015 and results are reported to EPA through 2016. After the monitoring period is completed, the results undergo review for quality assurance and are subject to change following further review by the analytical laboratory, the PWS, the State and EPA. The agency will perform further analysis of both the health effects and occurrence of contaminants monitored under UCMR 3 during the RD 4 and CCL 5 development process.
EPA identified the current occurrence, health effects and analytical methods data needs of CCL 4 contaminants for RD 4 evaluations in section V of this notice. This data needs table is presented to provide a sense of relative priority for listed contaminants by identifying those contaminants likely to have sufficient data for further evaluation under the next RD and those that have research needs. As the agency continues to evaluate contaminants on the CCL 4, EPA will work with agency and non-EPA scientists to develop and collect the best available science to support decision-making for future determinations.
EPA received comments, both in support of and against the carry forward of contaminants from the CCL 3 to the Draft CCL 4. One commenter asked for more information on the decision to carry forward CCL 3 contaminants to the Draft CCL 4. Commenters not in support of the carry forward of CCL 3 contaminants thought EPA should reassess the science on all the CCL 3 contaminants. One commenter also thought EPA should limit the number of contaminants on the CCL so that research for the contaminants could be completed between one CCL and the next. One commenter supported the carry forward approach because the CCL 3 contaminants already have data available that shows there may be a potential public health impact. They also suggested that EPA should continue to evaluate these contaminants until enough data are collected to support a regulatory determination.
EPA does not agree that the CCL should be limited to a certain number of contaminants. The CCL identifies contaminants that are “known, or anticipated to occur in PWSs,” and is the first step in identifying contaminants that may require regulation. Some of the contaminants on the list may have sufficient information to make regulatory determinations in the near term and some of the contaminants on the list need additional data in order to determine the appropriate agency action. While the SDWA does not limit the CCL to a particular number of contaminants, the agency recognizes the need to communicate data needs for contaminants included on the Final CCL 4. Therefore, EPA has provided a summary of the current data needs for RD 4 evaluations in section V of this notice. The agency will continue to evaluate data needs through the RD 4 process and will continue to work with internal and external researchers to discuss research needs and priorities.
EPA received comments that several contaminants listed based on
Considering the comments received on the Draft CCL 4, in future CCLs, EPA may refine analyses to consider if physical and chemical properties can be incorporated into the evaluations of contaminants listed based on environmental release data for occurrence.
EPA received comments supporting the inclusion of cyanotoxins on the CCL 4. Some comments requested that cyanotoxins be listed by individual toxins rather than including cyanotoxins as a group on the Final CCL 4 in order to prioritize research on health effects, analytical methods, occurrence and treatment. Comments specifically requested listing the key variants of microcystins, cylindrospermopsin, anatoxin-a, saxitoxin and euglenophycin.
EPA received a comment supporting the inclusion of perfluorooctanoic acid (PFOA) and perfluorooctane sulfonic acid (PFOS) on the CCL 4. EPA also received comments that PFOS and/or PFOA should not be listed on the Final CCL 4. The commenter supporting inclusion of these chemicals on the CCL 4 cited their persistence in the environment and toxicological effects as reasons to include them on the Final CCL 4, and encouraged EPA to consider these chemicals for drinking water regulation. Commenters supporting removal of PFOA and/or PFOS from the CCL 4 cited the low frequency of detections of PFOA and/or PFOS under the UCMR 3 monitoring as of January 2015. Additional reasons cited by commenters that these chemicals should not be listed on the Final CCL 4 are the voluntary efforts by manufacturers to reduce emissions and work towards elimination of these chemicals from products.
As discussed in the summary of EPA responses to the SAB in this section (IV.A) of the notice, EPA did not use preliminary UCMR 3 monitoring results for the CCL 4.
EPA acknowledges the industry commitments to voluntarily reduce the use and production of PFOA and PFOS; however, there are still a limited number of ongoing uses of PFOA and PFOS. Additionally, these chemicals are persistent in the environment and in the human body, which indicates they may be present in water or migrate to drinking water sources even after uses and production have been reduced or ceased, and therefore potential exposure may still be of concern.
In May 2016, EPA released lifetime health advisories for PFOA and PFOS (USEPA, 2016i, available in the docket for today's action) and Health Effects Support Documents based on the agency's assessment of the latest peer reviewed science. The health advisories provide federal, state, tribal and local officials with information on the health risks of these chemicals, occurrence,
In accordance with the SDWA, EPA will consider the occurrence data from the final UCMR 3 data set, along with the peer reviewed health effects assessments supporting the May 2016 PFOA and PFOS Health Advisories, to make a regulatory determination whether or not PFOA and PFOS require NPDWRs.
Several public commenters requested that specific pesticides be removed from the Final CCL 4. EPA agrees with commenters that three of these pesticides (disulfoton, fenamiphos, and molinate) should not be listed on the Final CCL 4; therefore, EPA is removing them from the Final CCL 4. The evaluation of these three pesticides is summarized in the following paragraphs.
EPA received a comment from the public that disulfoton should not be included on the Final CCL 4. The commenter noted that disulfoton had zero or very few detections nationally on any previous round of UCMR monitoring and therefore does not warrant national regulation.
EPA is not including disulfoton on the Final CCL 4 because it is not known or anticipated to occur in drinking water. Disulfoton likely has low potential for public health concern based on its cancellation status, zero detections in PWSs (from UCMR 1 data), and very few detections in ambient water from a large number of sites sampled (by the USGS NAWQA program).
EPA received a comment from the public that fenamiphos should not be included on the Final CCL 4. The commenter stated that the registrant for fenamiphos agreed to cancel all uses, and all existing stocks are to be used by October 6, 2017. The commenter stated that very limited uses remain of products containing fenamiphos in the U.S. and use will be discontinued after 2017.
In summary, due to its registration cancellation status, significant decline in usage (based on estimated data from 1992-2013), moderate persistence in the environment, and the prohibition of existing stocks (effective after October 6, 2017), EPA does not anticipate fenamiphos to occur in PWSs or to require regulation, therefore, it is not included on the Final CCL 4.
EPA received a comment from the public that molinate should not be included on the Final CCL 4. The commenter noted that molinate had zero or very few detections nationally on any previous round of UCMR monitoring and therefore does not warrant national regulation.
EPA received four comments that support the inclusion of manganese and two comments that do not support the inclusion of manganese on CCL 4. Commenters supporting the inclusion of manganese on CCL 4 cited recent studies that showed neurological effects in children and infants exposed to excess manganese via drinking water. Commenters also noted manganese frequently occurs in water and should be included on CCL 4 so that national occurrence data can be obtained through UCMR monitoring. Commenters who did not support the inclusion of manganese on the CCL 4 cited that the primary route of human exposure to manganese is through food, not drinking
EPA also agrees with the commenters assertion that manganese is known to occur in PWSs. EPA has included the occurrence data used to evaluate manganese in the CIS for this contaminant. This data includes USGS monitoring of ambient water, as well as drinking water data from several states. The data indicates that manganese is known to occur in public drinking water supply wells and supports the previous information from the National Inorganics and Radionuclides Survey (NIRS). EPA has proposed to monitor manganese under UCMR 4.
EPA has reviewed all of the current data submitted by commenters on the manganese health effects and found that the existing 2004 Health Advisory could warrant an update. Since manganese is not a regulated contaminant in drinking water, the Secondary Maximum Contaminant Level of 0.05 mg/L is not mandatory and does not require monitoring. The current IRIS assessment for manganese dates to 1995 (USEPA, 1995b) and the Health Advisory to 2004. The Agency for Toxic Substances and Disease Registry 2012 Toxicological Profile did not establish guidelines that applied to oral exposures and the Institute of Medicine (2001) provides Tolerable Upper Intake Levels for developmental lifestages and adults. The database of health effects studies for oral manganese exposures has expanded considerably since the last EPA assessment, therefore manganese is a good candidate for re-evaluation. EPA intends to evaluate the new toxicological findings and UCMR 4 monitoring data and will use this information in future regulatory decision-making, and to revise the current Health Advisory, if appropriate. More detailed evaluations of the routes of exposure usually occur in the regulatory determination and regulatory development processes.
EPA received two comments supporting the inclusion of nonylphenol and three comments that nonylphenol should not be included on the Final CCL 4. The commenters supporting inclusion of nonylphenol on the CCL 4 cited new health effects and occurrence data as reasons to include them on the Final CCL 4 and stated that EPA has adequate justification to include nonylphenol on the CCL based on this information. The commenters requesting that nonylphenol not be included on the Final CCL 4 cited a surface water monitoring study from 2002 and industry efforts to reduce surfactant usage as reasons nonylphenol should not be listed on the Final CCL 4. The main use of nonylphenol is in the manufacture of nonylphenol ethoxylates, which have been used in a wide range of industrial applications and consumer products including laundry detergents, cleaners, degreasers, paints and coatings and other uses (79 FR 59186, October 1, 2014 (USEPA, 2014d)).
EPA received comments arguing that the follow-through on the microbes listed in previous CCLs has been inadequate, that EPA should identify high priority pathogens on the CCL 4 and identify information gaps and barriers to obtaining information associated with each pathogen. EPA received comments requesting an open process for prioritizing and collecting information, to adopt a collaborative method development process and to rank microbes by treatability. EPA also received comments to focus priorities on distribution and plumbing system biofilm concerns and to evaluate microbial contaminants in the context of diverse water supplies such as drinking water sources from water reuse treatment facilities.
The EPA's Office of Water coordinates with EPA's Office of Research and Development to discuss research needs and priorities. Research on distribution system and premise plumbing biofilm concerns has been incorporated into EPA's strategic research plan. EPA acknowledges the comments on diverse water supplies and method development and will consider these comments as it develops future research priorities.
EPA received comments supporting the proposed inclusion of
EPA disagrees that HPC should be included on CCL 4. The group of HPC usually includes a diverse group of microorganisms that are part of the natural environment in water. Available epidemiological evidence shows no relationship between gastrointestinal illness and HPC bacteria in drinking water (Calderon, 1988; Calderon and Mood, 1991; Payment et al., 1997; Bartram J et al., 2003). Thus, EPA considers the potential health risk of HPC bacteria in drinking water as likely negligible and is not including HPC on the Final CCL 4. In addition, HPC bacteria are addressed under the Surface Water Treatment Rule as a treatment technique where they can be monitored in lieu of a disinfectant residual because HPC is an alternative method of determining disinfectant residual levels.
EPA received comments not supporting the proposed inclusion of
After the listing process, the CCL 4 contaminants will be further evaluated in a separate action called Regulatory Determination 4 (RD 4). The process used to previously evaluate CCL 3 contaminants under RD 3 is described in section I.E.3 of this notice. EPA anticipates using a similar process to evaluate CCL 4 contaminants under RD 4, although it is possible that some modifications may be made to this process. In the initial phases of this process, EPA determines if sufficient data are available to meet the three RD criteria set forth in SDWA section 1412(b)(1) and previously outlined in section I.D.4 of this notice. If sufficient data are available to meet all three statutory criteria, a regulatory determination may be made. As discussed in section I.D.4, SDWA requires EPA to make regulatory determinations every five years on at least five CCL contaminants.
The SAB and other commenters have recommended additional prioritization of the CCL 4 contaminants to communicate research needs, help focus efforts for researchers, and inform future regulatory decision-making. EPA acknowledges that many contaminants on the CCL 4 have substantial data and information needs to fulfill in order for the agency to make a regulatory determination in accordance with SDWA 1412 (b)(1)(A). These current data needs are described in the following section, and are presented in Exhibit 2. By identifying those contaminants that need additional research and information, EPA is communicating to stakeholders both research priorities and gaps for these contaminants.
EPA assessed the data and information gathered on the CCL 4 contaminants and generated a table (Exhibit 2) to help identify data/information needs for further evaluation under RD 4. To develop this table, EPA began with the information contained in the data availability/Phase 1 table included in Appendix D of the Protocol for the RD 3 (USEPA, 2014b), which describes the status of the best available occurrence data and health effects assessments for CCL 3 contaminants. EPA updated the occurrence data needs for CCL 4 contaminants by including which contaminants were monitored on the UCMR 3, and updated the health effects data needs based on available EPA or other non-EPA peer reviewed assessments as of May 2016. Since manganese and nonylphenol were nominated and added to the CCL 4 (not carried forward from CCL 3), data collected under CCL 4 was included in the Contaminant Information Sheets (USEPA, 2016e) for these contaminants and was used to assess the data needs. EPA characterized each chemical contaminant included on the Final CCL 4 based on their health effects, occurrence and analytical methods data needs.
EPA then categorized contaminants into six categories depending upon the availability of their occurrence data and health assessment. Contaminants in Group A have nationally representative finished drinking water data and a peer reviewed health assessment and are likely to have sufficient data available to be placed on a short list for further assessment under RD 4. Contaminants in Group B have finished drinking water data that is not nationally representative and peer reviewed health assessments. These contaminants may have sufficient data to be placed on a short list for further assessment under RD 4, particularly if the non-nationally representative occurrence data shows detections at levels of public health concern. Contaminants in groups C, D, E, and F of Exhibit 2 that lack either a peer reviewed health assessment or finished water data have more substantial data needs and are unlikely to have sufficient information to allow further assessment under the RD 4. For these contaminants, EPA plans to identify them as research priorities and work to fill their research needs such as evaluating the potential for monitoring under the UCMR or identifying those contaminants as priorities for health effects research. The health effects and occurrence data sources used to classify data needs are featured in Appendix 6 of the CISs for the Final Fourth CCL in the docket (USEPA, 2016e). The following sections describe the types of data or information gaps outlined in Exhibit 2 and provide examples.
Under the RD process, EPA relies on external peer-reviewed health assessments to determine if and at what level a contaminant “may have an adverse effect on the health of persons.” Health effects data sources evaluated for
As shown in Exhibit 2, EPA categorized the health effects data needs in the following way:
1. If a peer reviewed health assessment is available or is in the process of being revised, the contaminant is considered to have health effects data available.
2. If a peer reviewed health assessment is not available, then the contaminant is considered to not have health effects data currently available.
For RD evaluations, the occurrence data availability assessment is used to identify contaminants that may have sufficient data and information to characterize their status as known or likely to occur in PWSs. EPA uses data from many sources to evaluate occurrence for contaminants considered for RD (see Appendix C of USEPA, 2014b for occurrence data sources evaluated under RD 3). For this evaluation, EPA prefers to have nationally representative finished drinking water occurrence data, but finished drinking water data that are not nationally representative may also be used to determine if the contaminant occurs frequently at levels of public health concern. In addition, the agency evaluates supplemental sources of information (
• Finished drinking water occurrence data that are nationally representative are available.
○ Data sources may include UCMRs (
• Finished drinking water occurrence data that are not nationally representative are available. These data may include:
○ Finished water assessments by federal agencies (
○ State-level finished water monitoring data.
○ Research performed by institutions and universities (
○ Various reports from the Centers for Disease Control and the scientific literature for microbes.
• Finished drinking water occurrence data are not available.
○ The best available data sources may include environmental release data (such as TRI data or pesticide application data) or ambient water data.
EPA has also indicated with a footnote in the occurrence data column, highlighting which contaminants are proposed for monitoring under the UCMR 4 from 2018-2020. Therefore, although some of the contaminants that may be monitored under UCMR 4 are shown in this table as currently having data gaps for occurrence (
To conduct nationally representative drinking water occurrence studies that could support a regulatory determination, EPA needs to have an analytical method that is suitable for the drinking water matrix and is robust enough to be used by many laboratories to conduct national studies and/or compliance monitoring. For the purpose of CCL 4, EPA assessed the status of the development of analytical methods for drinking water and determined estimated reporting levels for each contaminant. EPA also assessed method sensitivity with respect to the HRL for the chemical contaminants. Method sensitivity is measured by using method specific reporting levels, lowest concentration minimum reporting levels, and promulgated minimum reporting level. While there are many methods for monitoring the CCL 4 pathogens available from scientific papers and consensus organizations, not all of them may be appropriate for use in drinking water or for a national monitoring effort. Of the CCL 4 pathogens, only enterovirus and caliciviruses have an EPA-approved method for drinking water. The status of drinking water analytical methods for the CCL chemical contaminants, as of May 2016, is presented in Exhibit 2. EPA categorized the analytical method needs in the following way:
• An EPA drinking water method, with estimated reporting levels that are adequate for analysis relative to the current HRL or health assessment is available.
• An EPA drinking water method is available but the minimum reporting level (MRL) does not allow for quantitation of the contaminant at a concentration below the current HRL. These methods are denoted in Exhibit 2 by “(MRL>HRL)”.
• An EPA drinking water method is currently being developed.
• An EPA drinking water method is not available.
Although not shown in Exhibit 2, EPA also considers other government and consensus methods (
The CCL process is critical to shaping the future direction of the drinking water program. The agency will continue to gather information and evaluate contaminants on the CCL 4 to make regulatory determinations for at least five contaminants. The agency will also continue to refine the CCL process and gather more data to identify contaminants for CCL 5. EPA will continue to work to prioritize contaminants on the CCL 4, both for RD and for additional research and data collection.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency has submitted an information collection request (ICR), “NSPS for Secondary Brass and Bronze Production (40 CFR part 60, subpart M), Primary Copper Smelters (40 CFR part 60, subpart P), Primary Zinc Smelters (40 CFR part 60, subpart Q), Primary Lead Smelters (40 CFR part 60, subpart R), Primary Aluminum Reduction Plants (40 CFR part 60, subpart S), and Ferroalloy Production Facilities (40 CFR part 60, subpart Z) (Renewal)” (EPA ICR No. 1604.11, OMB Control No. 2060-0110), to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before December 19, 2016.
Submit your comments, referencing Docket ID Number EPA-HQ-OECA-2013-0334, to: (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute.
Patrick Yellin, Monitoring, Assistance, and Media Programs Division, Office of Compliance, Mail Code 2227A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-2970; fax number: (202) 564-0050; email address:
Supporting documents, which explain in detail the information that the EPA will be collecting, are available in the public docket for this ICR. The docket can be viewed online at
Second, the previous ICR incorrectly estimated that all four primary aluminum reduction plants subject to Subpart S would need to submit performance test results every month. This estimate is incorrect because only two out of four sources are required to perform monthly performance tests, and the other two sources are allowed to perform an annual performance test. Therefore, the requirement to submit performance test results was reduced to once per year for two sources, which consequently reduced the total labor hours for Subpart S.
There is, however, a small adjustment increase in the total labor hours for Subparts P, Q, R, and Z due to a change in assumption; this ICR assumes all existing sources will need to re-familiarize with the regulation each year, even when the burden for Subpart R is now zero due to Doe Run no longer being a primary lead smelter.
Environmental Protection Agency (EPA).
Notice.
The Environmental Protection Agency has submitted an information collection request (ICR), “NESHAP for Metal Can Manufacturing Surface Coating (40 CFR part 63, subpart KKKK) (Renewal)” (EPA ICR No. 2079.06, OMB Control No. 2060-0541), to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act (44 U.S.C. 3501
Additional comments may be submitted on or before December 19, 2016.
Submit your comments, referencing Docket ID Number EPA-HQ-OECA-2013-0345, to: (1) EPA online using
EPA's policy is that all comments received will be included in the public docket without change, including any personal information provided, unless the comment includes profanity, threats, information claimed to be Confidential Business Information (CBI), or other information whose disclosure is restricted by statute.
Patrick Yellin, Monitoring, Assistance, and Media Programs Division, Office of Compliance, Mail Code 2227A, Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460; telephone number: (202) 564-2970; fax number: (202) 564-0050; email address:
Supporting documents which explain in detail the information that the EPA will be collecting are available in the public docket for this ICR. The docket can be viewed online at
Equal Employment Opportunity Commission.
Notice; publication of notices of systems of records, and proposed new systems of records.
This notice proposes one new system of records, changes to a number of existing systems of records, and removes obsolete systems of records. This notice republishes all of EEOC's notices for its systems of records subject to the Privacy Act in one issue of the
The changes to the existing systems of records are effective on November 17, 2016. The proposed new system of records will become effective, without further notice, on January 17, 2017 unless comments dictate otherwise.
Comments on this notice may be submitted to the EEOC in three ways; please use only one.
• Comments and attachments may be submitted online at
• Hard copy comments may be submitted to Bernadette Wilson, Acting Executive Officer, Executive Secretariat, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
• The Executive Secretariat also will accept documents totaling six or fewer pages by facsimile (“fax”) machine. This limitation is necessary to assure access to the equipment. The telephone number of the fax receiver is
Subject to the conditions noted above, the EEOC will post online at
Copies of this notice are available in the following alternate formats: Large print, braille, electronic file on computer disk, and audio-tape. Copies may be obtained from the Publications Center by calling 1-800-699-3362.
Thomas J. Schlageter, Assistant Legal Counsel, (202) 663-4668 (voice), Kathleen Oram, Senior Attorney (202) 663-4681 (voice), or Savannah Marion, (202) 663-4909 or (202) 663-7026 (TDD).
The Equal Employment Opportunity Commission last published its Privacy Act systems notices in 2002. The Commission proposes one new system of records to cover Freedom of Information Act and Privacy Act records. EEOC previously covered these records in its general correspondence system of records. The Commission is deleting EEOC-6 Employee Assistance Program records and EEOC-14 Employee Parking records because it no longer collects and keeps those records and is replacing EEOC-6 with the new Freedom of Information Act and Privacy Act Records system. The Employee Assistance Program records are now maintained by the Department of Health and Human Services, and Employee Parking records are maintained by a private building management company. In addition, the Commission is amending a number of its systems to recognize more widespread electronic storage, and remove requirements that persons submit social security numbers when requesting records. The Commission is adding a statement of general routine uses to include two new routine uses permitting disclosure of records from all of its systems of records for suspected or confirmed breach notification and response. The Commission is removing three obsolete routine uses from its Claims Collection Records notice and one routine use from its Internal Harassment Inquires Records notice. EEOC is adding a new routine use to its two Discrimination Case Files systems of records, a new routine use to its Internal Harassment Inquiries system of records, and one new routine use to its Office of Inspector General system of records. Finally, the Commission has amended several system notices to reflect current office names and has amended Appendix A to reflect current addresses of Commission offices. To ensure that users will have a copy of the current text of each of its system notices, the Commission is publishing the complete text of all of its systems notices.
A brief description of the major changes follows:
The proposed universal routine uses, the routine uses in the one new system of records noted above and the proposed new routine uses in two existing systems meet the compatibility criteria since the information involved is collected for the purpose of the applicable routine uses. We anticipate that any disclosure pursuant to these routine uses will not result in any unwarranted adverse effects on personal privacy.
A complete list of all EEOC systems of records is published below. The complete text of the notices follows.
For the Commission.
Universal Routine Uses.
EEOC-1 Age Discrimination in Employment Act, Equal Pay Act, and Section 304 of the Government Employee Rights Act Discrimination Case Files.
EEOC-2 Attorney Referral List.
EEOC-3 Title VII, Americans with Disabilities Act, and Genetic Information Nondiscrimination Act
EEOC-4 Biographical Files.
EEOC-5 Correspondence and Communications.
EEOC-6 Freedom of Information Act and Privacy Act Records
EEOC-7 Employee Pay and Leave Records.
EEOC-8 Employee Travel and Reimbursement Records.
EEOC-9 Claims Collection Records.
EEOC-10 Grievance Records.
EEOC-11 Adverse Actions Against Nonpreference Eligibles in the Excepted Service Records
EEOC-12 Telephone Call Detail Records.
EEOC-13 Employee Identification Cards.
EEOC-14 Reserved
EEOC-15 Internal Harassment Investigation Files.
EEOC-16 Office of Inspector General Investigative Files.
EEOC-17 Defensive Litigation Files.
EEOC-18 Reasonable Accommodation Records.
EEOC-19 Revolving Fund Registrations.
EEOC-20 RESOLVE Program Records.
EEOC-21 Emergency Management Records.
EEOC-22 EEOC Personnel Security Records.
EEOC/GOVT-1 Equal Employment Opportunity in the Federal Government Complaint and Appeal Records.
a. To appropriate agencies, entities, and persons when: (1) EEOC suspects or has confirmed that there has been a breach of the system of records; (2) EEOC has determined that as a result of the suspected or confirmed breach there is a risk of harm to individuals, the agency (including its information systems, programs, and operations), or the Federal government; and (3) the disclosure made to such agencies, entities, and persons is reasonably necessary to assist in connection with EEOC's efforts to respond to the suspected or confirmed breach or to prevent, minimize, or remedy such harm.
b. To another Federal agency or Federal entity when information from this system of records is reasonably necessary to assist the recipient agency or entity in (1) responding to a suspected or confirmed breach or (2) preventing, minimizing, or remedying the risk of harm to individuals, the agency (including its information systems, programs, and operations), or the Federal government.
Age Discrimination in Employment Act, Equal Pay Act, and Section 304 of the Government Employee Rights Act Discrimination Case Files.
Field Office where the charge or complaint of discrimination was filed (see Appendix A). Records of complaints filed under section 321 of the Government Employees Rights Act of 1991 are located in the Office of Federal Operations 131 M Street NE., Washington, DC 20507, after a hearing has been requested.
Persons other than federal employees and applicants who file charges or complaints with EEOC alleging that an employer, employment agency or labor organization has violated the Age Discrimination in Employment Act of 1967 or the Equal Pay Act of 1963, or who file complaints under section 304 of the Government Employees Rights Act of 1991.
This system contains the records compiled during the investigation of age and equal pay discrimination cases and during the investigation and hearing of complaints filed under section 304 of the Government Employees Rights Act of 1991. These records include:
a. Documents submitted by charging party or complainant such as charge of discrimination, personal interview statement, and correspondence.
b. Documents submitted by employer such as statement of position, correspondence, statements of witnesses, documentary evidence such as personnel files, records of earnings, employee benefit plans, seniority list, job titles and descriptions, applicant data, organizational charts, collective bargaining agreements, and petitions to revoke or modify subpoenas.
c. Records gathered and generated by EEOC in the course of its investigation and, in complaints filed under section 304 of the Government Employees Rights Act of 1991, during the hearing, such as letters of referral to state fair employment practices agencies, correspondence with state fair employment practices agencies, witness statements, investigator's notes, investigative plan, report of initial and exit interview, investigator's analyses of evidence and charge, subpoenas, decisions and letters of determination, conciliation agreements, correspondence and any additional evidence gathered during the course of the investigation.
5 U.S.C. 301; 29 U.S.C. 209, 211, 623, 626; 42 U.S.C. 2000e-16c; 44 U.S.C. 3101; 2 U.S.C. 1220.
This system is maintained for the purpose of enforcing the prohibitions against employment discrimination contained in the Age Discrimination in Employment Act, the Equal Pay Act and section 304 of the Government Employees Rights Act of 1991.
These records and information in these records may be used:
a. To disclose pertinent information to a federal, state, or local agency or third party as may be appropriate or necessary to perform the Commission's functions under the Age Discrimination in Employment Act, Equal Pay Act, or section 304 of the Government Employee Rights Act of 1991.
b. To disclose information contained in these records to state and local agencies administering state or local fair employment practices laws.
c. To disclose non-confidential and non-privileged information from closed ADEA/EPA case files (a file is closed when the Commission has terminated its investigation and has decided not to sue) to the employer where a lawsuit has been filed against the employer involving that information, to other employees of the same employer who have been notified by the Commission of their right under 29 U.S.C. 216 to file a lawsuit on their own behalf, and their representatives.
d. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of a party to the charge.
e. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
f. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
g. To disclose information to officials of state or local bar associations or disciplinary boards or committees when they are investigating complaints against attorneys in connection with their representation of a party before EEOC.
h. To disclose to a Federal agency in the executive, legislative, or judicial branch of government, in response to its request for information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
i. To disclose information to other federal agencies in accordance with Memoranda of Understanding or similar agreements between EEOC and other agencies that provide for coordination, cooperation, and confidentiality of documents in EEOC's employment discrimination enforcement efforts.
These records are maintained in file folders and electronically.
These records are retrievable by charging party name, employer name, and charge number.
Paper records are maintained in a secured area to which only authorized personnel have access. Access to and use of these records is limited to those persons whose official duties require such access. The premises are locked when authorized personnel are not on duty. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
All private sector charge files not designated for permanent retention will be retained for three years following the fiscal year in which they were closed. (For example, if a charge was closed on March 31, 2014, in FY 2014, the three-year retention period would begin on October 1, 2014, which is the first day of FY 2015.) These non-permanent files will be retained for one year in the EEOC field office where the charge of discrimination was filed. Afterwards, the non-permanent files will be transferred to the Federal Records Center (FRC). The FRC will destroy the files after the three-year retention period is met. Permanent files will be retained in the field office for three years and then transferred to FRC. FRC will transfer the files to the National Archives and Records Administration (NARA) for permanent retention when eligible.
Closed non-permanent private sector charge files that are the subject of Freedom of Information Act (FOIA) requests are retained for six years after the FOIA response is provided. The files will be transferred to FRC one year after completion of all actions taken under FOIA/Privacy Act. Alternatively, the files may be included as part of the permanent files retained by the EEOC field office.
Closed private sector charge files that are the subject of a Section 83 request are retained for six years after the Section 83 response is provided. The files will be transferred to FRC one year after completion of all actions taken under FOIA. Alternatively, the files may be included as part of the permanent files retained by the EEOC field office.
Director of the office in the field where the charge was filed (see Appendix A). Director of the Office of Field Programs, 131 M Street NE., Washington, DC 20507. Director of the Office of Federal Operations, 131 M Street NE., Washington, DC 20507 (only for complaints filed under section 321 of the Government Employees Right Act of 1991).
This system is exempt under 5 U.S.C. 552a(k)(2) from subsections (c)(3), (d), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I) and (f) of the Act.
Attorney Referral List.
All District Offices (see Appendix A).
Attorneys who represent plaintiffs in employment discrimination litigation.
This system contains attorneys' names, business addresses and telephone numbers, the nature and amount of their civil rights litigation experience; their state and federal bar admissions; whether the attorneys have the capacity and desire to handle class actions; whether the attorneys charge consultation fees (and how much); whether the attorneys will waive the consultation fee; the types of fee arrangements the attorneys will accept; and whether the attorney speaks a foreign language fluently.
42 U.S.C. 2000e-4(g); 44 U.S.C. 3101.
This system is maintained for the purpose of providing charging parties, upon their request, with information about local attorneys who represent plaintiffs in employment discrimination litigation.
These records and information in these records may be used:
a. To refer charging parties to attorneys who handle litigation of employment discrimination lawsuits.
b. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
Stored on prepared forms, on index cards and electronically.
Indexed alphabetically by names of the attorneys.
Access to this system of records is restricted to EEOC personnel who have a legitimate use for the information. This system is stored in filing cabinets. Access to electronic records is limited, through use of access codes and entry logs, to those whose official duties require access.
Files are reviewed and updated annually.
Regional Attorney at each District Office (see Appendix A).
Inquiries concerning this system of records should be addressed to the appropriate system manager. It is necessary to furnish the following information: (1) Full name of the individual whose records are requested; (2) mailing address to which the reply should be sent.
Same as above.
Same as above.
The individual on whom the record is maintained.
Title VII, Americans with Disabilities Act, and Genetic Information Nondiscrimination Act Discrimination Case Files.
Field Office where the charge of discrimination was filed (see Appendix A).
Persons, other than federal employees and applicants, who file charges alleging that an employer, employment agency, labor organization or joint labor-management apprenticeship committee has violated Title VII of the Civil Rights Act of 1964, the Americans with Disabilities Act of 1990, Title II of the Genetic Information Nondiscrimination Act of 2008 (GINA), or any combination of the three.
This system contains records compiled during the investigation of race, color, religion, sex, national origin, disability, and genetic information discrimination cases. These records include:
a. Documents submitted by charging party, such as a charge of discrimination, a personal interview statement, medical records, and correspondence.
b. Documents submitted by employer such as position statement, correspondence, statements of witnesses, documentary evidence such as personnel files, records of earnings, EEO data, employee benefit plans, seniority lists, job titles and descriptions, applicant data, organizational charts, collective bargaining agreements, and petition to revoke or modify subpoenas.
c. Records gathered and generated by EEOC in the course of its investigation such as letters to state or local fair employment practice agencies, correspondence with state fair employment practice agencies, witness statements, investigator's notes, investigative plan, investigator's analysis of the evidence and charge, report of initial and exit interviews, copy of deferral to state, subpoenas, decisions and letters of determination, analysis of deferral agency action, conciliation agreements, correspondence, and any additional evidence gathered during the course of the investigation.
5 U.S.C. 301; 42 U.S.C. 2000e-5, -8 and -9; 42 U.S.C. 12117; 44 U.S.C. 3101, 42 U.S.C. 2000ff-10.
This system is maintained for the purpose of enforcing the prohibitions against employment discrimination contained in Title VII of the Civil Rights Act of 1964, the Americans with Disabilities Act of 1990, and Title II of the Genetic Information Nondiscrimination Act of 2008
These records and information in these records may be used:
a. To disclose pertinent information to a federal, state, or local agency or third party as may be appropriate or necessary to perform the Commission's functions under Title VII of the Civil Rights Act of 1964, the Americans with Disabilities Act of 1990, or Title II of the Genetic Information Nondiscrimination Act of 2008.
b. To disclose information contained in these records to state and local agencies administering state or local fair employment practices laws.
c. To disclose non-confidential or non-privileged information contained in these records to the following persons after a notice of right to sue has been issued:
1. Aggrieved persons and their attorneys in case files involving Commissioner Charges provided that such persons have been notified of their status as aggrieved persons;
2. Persons or organizations filing on behalf of an aggrieved person provided that the aggrieved person has given written authorization to the person who filed on his or her behalf to act as the aggrieved person's agent for this purpose, and their attorneys;
3. Employers and their attorneys, provided that the charging party or aggrieved person has filed suit under Title VII, the Americans with Disabilities Act, Title II of the Genetic Information Nondiscrimination Act of 2008, or any combination of the three.
d. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of a party to the charge.
e. To disclose pertinent information to the appropriate federal, state, or local agencies responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
f. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
g. To disclose information to officials of disciplinary boards or committees under the control of a state or local government when they are investigating complaints against attorneys in connection with their representation of a party before EEOC.
h. To disclose to a Federal agency in the executive, legislative, or judicial branch of government, in response to its request for information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
i. To disclose information to other federal agencies in accordance with Memoranda of Understanding or similar agreements between EEOC and other agencies that provide for coordination, cooperation, and confidentiality of documents in EEOC's employment discrimination enforcement efforts.
These records are maintained in file folders and electronically.
These records are retrievable by charging party name, employer name, and charge number.
Paper records are maintained in a secured area to which only authorized personnel have access. Access to and use of these records is limited to those persons whose official duties require such access. The premises are locked when authorized personnel are not on duty. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
All private sector charge files not designated for permanent retention will be retained for three years following the fiscal year in which they were closed. (For example, if a charge was closed on March 31, 2014, in FY 2014, the three-year retention period would begin on October 1, 2014, which is the first day of FY 2015.) These non-permanent files will be retained for one year in the EEOC field office where the charge of discrimination was filed. Afterwards, the non-permanent files will be transferred to the Federal Records Center (FRC). The FRC will destroy the files after the three-year retention period is met. Permanent files will be retained in the field office for three years and then transferred to FRC. FRC will transfer the files to the National Archives and Records Administration (NARA) for permanent retention when eligible.
Closed non-permanent private sector charge files that are the subject of Freedom of Information Act (FOIA) requests are retained for six years after the FOIA response is provided. The files will be transferred to FRC one year after completion of all actions taken under FOIA/Privacy Act. Alternatively, the files may be included as part of the permanent files retained by the EEOC field office.
Closed private sector charge files that are the subject of a Section 83 request are retained for six years after the Section 83 response is provided. The files will be transferred to FRC one year after completion of all actions taken under FOIA/Privacy Act. Alternatively, the files may be included as part of the permanent files retained by the EEOC field office.
Director of the office in the field where the charge was filed (see Appendix A). Director of the Office of Field Programs, 131 M Street NE., Washington, DC 20507.
This system is exempt under 5 U.S.C. 552a(k)(2) from subsections (c)(3), (d), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I), and (f) of the Act.
Biographical Files.
Office of Communications and Legislative Affairs, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Current and former Commissioners, General Counsels and Commission officials.
Includes for each the name, date and place of birth, education, employment history, and other biographical information.
44 U.S.C. 3101, 42 U.S.C. 2000e-4.
This system is maintained for the purpose of providing information about EEOC officials to members of the Congress and the public.
These records and information in these records may be used
a. To answer public and congressional inquiries regarding EEOC Commissioners, General Counsels and Commission officials.
Stored electronically.
Indexed by last name of the Commissioner, General Counsel or Commission official.
Files are kept in the Office of Communications and Legislative Affairs, which is locked evenings, weekends, and holidays.
Maintained permanently.
Director, Office of Communications and Legislative Affairs, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Inquiries concerning this system of records should be addressed to the system manager. All inquiries should furnish the full name of the individual and the mailing address to which the reply should be mailed.
Same as above.
Same as above.
The individual to whom the record pertains.
Correspondence and Communications.
All locations listed in appendix A and all headquarters offices, 131 M Street NE., Washington, DC 20507.
Charging parties, members of the general public, members of Congress and current and former federal employees who seek information or assistance from EEOC.
a. Inquiries from members of Congress, the White House and members of the general public, including current and former federal employees.
b. EEOC responses to the above inquiries.
c. Computer tracking system indicating the dates inquiries are received, to whom and when they are assigned for response and the dates they are answered.
44 U.S.C. 3101; 42 U.S.C. 2000e-4.
This system is maintained for the purpose of responding to inquiries from members of Congress and the public seeking information or assistance.
These records and information in these records may be used:
a. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office at the request of the individual.
b. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
These records are maintained in file cabinets and electronically.
Computer entries are retrievable by name of author of a letter, by subject, by key word, by reference number, by name of person to whom assigned, and by dates assigned, due, and answered.
These records are kept in a secured area to which only authorized personnel have access. Access to and use of these records is limited to those persons whose official duties require such access. The premises are locked when authorized personnel are not on duty. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
Records are maintained for three years from the date of the last communication and then destroyed. Tracking system information is maintained in the computer for four years.
Director of each Commission office in the field and Headquarters office. (See Appendix A.)
Inquiries concerning this system of records should be addressed to the system manager. All inquiries should furnish the full name of the individual and the mailing address to which the reply should be mailed.
Same as above.
Same as above.
Members of Congress, their staffs, the White House, charging parties, members of the general public, current and former federal employees.
Freedom of Information Act and Privacy Act Records.
Field Office where Freedom of Information Act or Privacy Act request was submitted (see Appendix A); Office of Legal Counsel, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Persons who submit Freedom of Information Act (FOIA) and Privacy Act requests and administrative appeals to the Equal Employment Opportunity Commission (EEOC); and persons whose requests and/or records have been submitted to EEOC by other agencies.
This system consists of records created or compiled in response to FOIA or Privacy Act requests and administrative appeals, including the original requests and administrative appeals, responses to such requests and administrative appeals, all related memoranda, correspondence, notes and other related or supporting documentation, and, in some instances, copies of requested records and records under administrative appeal.
5 U.S.C. 301; 44 U.S.C. 3101; 5 U.S.C 552; and 5 U.S.C. 552a.
This system is maintained for the purpose of processing requests and administrative appeals under the FOIA, and access and amendment requests and administrative appeals under the Privacy Act; for the purpose of participating in litigation regarding agency action on such requests and appeals; and for the purpose of assisting EEOC in carrying out any other responsibilities under the FOIA and the Privacy Act.
These records and information in these records may be used:
a. To provide information to a federal, state, local, or foreign agency or entity for the purpose of consulting with that agency or entity to enable the EEOC to make a determination as to the propriety of access to, or correction of, information, or for the purpose of verifying the identity of an individual or the accuracy of information submitted by an individual who has requested access to or amendment of information.
b. To provide information to a federal agency or entity that furnished the record or information for the purpose of permitting that agency or entity to make a decision as to access to, or correction of, the record or information.
c. To provide information to a submitter or subject of a record or information in order to obtain assistance to EEOC in making a determination as to access or amendment.
d. To provide information to the National Archives and Records Administration, Office of Government Information Services (OGIS), to the extent necessary to fulfill its responsibilities under 5 U.S.C. 552(h) to review federal agency policies, procedures, and compliance with the FOIA, and to facilitate OGIS's offering of mediation services to resolve disputes between persons making FOIA requests and federal agencies.
e. To provide information to contractors, experts, consultants, students, and others performing or working on a contract, service, or other assignment for the federal government, when necessary to accomplish an agency function related to this system of records.
f. To provide information to a congressional office from the record of the individual in response to an inquiry from that congressional office made at the request of that individual.
g. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
h. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, when the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
i. To disclose in response to a request for discovery or for appearance of a witness, information that is relevant to the subject matter involved in the pending judicial or administrative proceeding.
None.
Records in this system are stored on paper and/or in electronic form.
Records are retrieved by the name of the requester or appellant; the number assigned to the request or appeal; and, in some instances, the name of the attorney representing the requester or appellant or the name of the EEOC personnel assigned to handle such requests and appeals.
Information in this system is safeguarded in accordance with applicable laws, rules, and policies, including EEOC's automated systems security and access policies. Records and electronic equipment are maintained in buildings with restricted access. The required use of password protection identification features and other system protection methods also restrict access. Access is limited to those EEOC officers and employees who have an official need for access to perform their duties.
Records are retained and disposed of in accordance with the National Archives and Records Administration's General Records Schedule 14.
Director of the field office where the Freedom of Information Act or Privacy Act request was submitted (see Appendix A) or the Legal Counsel, 131 M Street NE., Washington, DC 20507.
Inquiries concerning this system of records should be addressed to the system manager. All inquiries should furnish the full name of the individual and the mailing address or email address to which the reply should be mailed.
Same as above.
Same as above.
Individuals who submit initial requests and administrative appeals pursuant to the FOIA and the Privacy Act; the agency records searched in the process of responding to such requests and appeals; EEOC personnel assigned to handle such requests and appeals; and other agencies or entities that have referred to EEOC requests concerning EEOC records.
Employee Pay and Leave Records.
All locations listed in Appendix A.
Current and former employees of EEOC.
Time and attendance records; leave records (includes employee name, branch or office, pay period ending, leave and overtime used during the pay period); requests for leave (earned or advance) or leave of absence; requests for an authorization of overtime; annual attendance record (indicates name, social security number, service computation date, hours and dates worked and taken as leave, pay plan, salary and occupation code, grade, leave earned and used); thrift savings plan participation, deductions for Medicare, FICA, taxes, life, health, and long term care insurance, union contributions, charitable contributions, savings allotments and bond issuance and bond balance.
5 U.S.C. 301; 44 U.S.C. 3101.
The records in this system are maintained in accordance with the requirements set forth by statutes, regulations and guidance from the Office of Personnel Management, the General Services Administration, and the Thrift Savings Board. They are maintained for the purpose of providing salaries and other benefits to EEOC employees.
These records and information in these records may be used:
a. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
b. To provide a copy of an employee's Department of the Treasury Form W-2, Wage and Tax Statement, to the state, city or other local jurisdiction which is authorized to tax the employee's compensation. The record will be provided in accordance with a withholding agreement between the state, city, or other jurisdiction and the Department of Treasury pursuant to 5 U.S.C. 5516, 5517 or 5520, or in response to a written request from an appropriate official of the taxing jurisdiction. The request must include a copy of the applicable statute or ordinance authorizing the taxation of compensation and should indicate whether the authority of the jurisdiction to tax the employee is based on place of residence, place of employment, or both.
c. To disclose copies of executed city tax withholding certificates to a city pursuant to a withholding agreement between the city and the Department of the Treasury (5 U.S.C. 5520) in response to a written request from an appropriate city official.
d. To disclose the social security number only, in the absence of a withholding agreement, to a taxing jurisdiction that has furnished this agency with evidence of its independent authority to compel disclosure of the social security number, in accordance with section 7 of the Privacy Act, 5 U.S.C. 552a note.
e. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
f. To disclose to an agency in the executive, legislative, or judicial branch or the District of Columbia's Government information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, the letting of a contract, the issuance of a license, grant, or other benefits by the requesting agency, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
g. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
h. To disclose to the Office of Personnel Management in accordance with the agency's responsibility for evaluation and oversight of Federal personnel management.
i. To disclose to officers and employees of the Department of the Interior in connection with
j. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
k. To disclose information to the Office of Child Support Enforcement, Administration for Children and Families, Department of Health and Human Services Federal Parent Locator system (FPLS) and Federal Tax Offset system for use in locating individuals and identifying their income sources to establish paternity, establish and modify orders of support and for enforcement action.
l. To disclose information to the Office of Child Support Enforcement for release to the Social Security Administration for verifying social security numbers in connection with the operation of the FPLS by the Office of Child Support Enforcement.
m. To disclose information to the Office of Child Support Enforcement for release to the Department of Treasury for purposes of administering the Earned Income Tax Credit Program (Section 32, Internal Revenue Code of 1986) and verifying a claim with respect to employment in a tax return.
Disclosures may be made from this system to consumer reporting agencies as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f)) or the Federal Claims Collection Act of 1966 (31 U.S.C. 3701(a)(3)).
Stored electronically and in file folders.
Indexed by an assigned employee code.
Access to these records is limited to employees whose official duties require such access.
The records are destroyed after three years.
Director of each Commission Office (See Appendix A).
Inquiries concerning this system of records should be addressed to the system manager. It is necessary to furnish the following information: (1) Name and (2) mailing address to which the response is to be sent.
Official personnel folder, data submitted by employees and data submitted by the offices where the individuals are or were employed.
Employee Travel and Reimbursement Records.
All locations listed in Appendix A.
Current and former employees.
Includes travel orders, travel vouchers, records of travel advances, amounts owed the agency by employees for travel and other purposes, amounts payable to the employee for travel and other purposes, payments made to the employees for travel and other reimbursable transactions, and a record of the difference between the cost of official travel as estimated in the travel order and the amount actually expended by the employee.
31 U.S.C. 3512, 44 U.S.C. 3101.
These records are maintained in accordance with the General Service Administration's regulations for the purpose of allowing EEOC employees to travel for official business and reimbursing travel expenses.
These records and information in these records may be used:
a. To disclose pertinent information to the appropriate Federal, State, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
b. To disclose to an agency in the executive, legislative, or judicial branch or the District of Columbia's Government, information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, the letting of a contract, the issuance of a license, grant, or other benefits by the requesting agency, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
c. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
d. To disclose to the Office of Personnel Management in accordance with the agency's responsibility for evaluation and oversight of Federal personnel management.
e. To disclose to officers and employees of the Department of the Interior in connection with administrative services provided to this agency under agreement with DOI.
f. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
g. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
Disclosures may be made from this system to consumer reporting agencies as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f)) or the Federal Claims Collection Act of 1966 (31 U.S.C. 3701(a)(3)).
Stored on prepared forms and electronically.
Indexed alphabetically by name and/or chronologically by event and name. Access to and use of these records is limited to those persons whose official duties require such access. Personnel screening is employed to prevent unauthorized disclosure. Files are stored electronically and in standard cabinets, safes, and secured rooms. Access to electronic records is limited,
These records are destroyed in accordance with GSA General Records Schedule 2.
Director, Finance and Systems Services Division, Office of the Chief Financial Officer, EEOC, 131 M Street NE., Washington, DC 20507.
Employees of the Commission wishing to know whether information about them is maintained in this system of records should address inquiries to the Director of the Office where employed (see Appendix A). The individual should provide his or her full name, date of birth, and mailing address.
Same as above.
Same as above.
Bills, receipts, and claims presented by employees and original data generated by the Commission.
Claims Collection Records.
These records are located in the Finance and Systems Services Division, Office of Chief Financial Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Any individual who is indebted to the United States as a result of his or her interaction or financial activities with the Commission or another federal agency including, but not limited to, any current or former Commission employee.
This system contains:
Debtor Files. These files contain information and evidence on the identity and location of the individual who is subject to a claim, the origin and amount of the indebtedness, decisions and determinations regarding a claim, actions taken to collect a claim, and the results of those actions. Depending on the status of a claim, a case file may include such records as documents evidencing indebtedness, written demands for payment, required notices, financial statements, medical disability statements, agency investigative reports, credit reports, written agreements for payment, intra-agency and inter-agency memoranda of consultation and opinion on the collection action, documentation resulting from a hearing, requests for waiver, requests for reconsideration, written determinations and decisions, certifications of indebtedness by this or another agency, counterclaims, judgments, and documents evidencing payment or compromise of the debt.
5 U.S.C. 301, 5514, 5522, 5584, 5705, 5724(f); 15 U.S.C. 1692; 26 U.S.C. 6331; 31 U.S.C. 3701, 3702, 3711, 3716, 3717, 3718, 3719; 44 U.S.C. 3101; 4 CFR parts 91-93, 101-105.
This system is maintained for the purpose of collecting debts owed the United States by individuals as a result of their interaction with the Commission or another federal agency. The debts are collected in accordance with the Commission's regulatory debt collection procedures, which include salary offset, administrative offset, Federal income tax refund offset, and wage garnishment.
These records and information in these records may be used:
a. To disclose information to appropriate officials and employees of the Department of Justice for the purposes of litigation and forced collection on administratively uncollected debts.
b. To disclose information to appropriate officials of the Department of the Treasury and the Office of Management and Budget to provide reports on debt collection activities.
c. To disclose information to another federal agency for the purpose of collecting a debt owed to the Commission by an individual through EEOC's debt collection procedures undertaken by the other agency upon proper certification or evidence of the debt owed from the Commission.
d. To disclose information to another federal agency for the purpose of collecting a debt owed to that agency by an individual through EEOC's debt collection procedures undertaken by the Commission upon proper certification or evidence of the debt owed from the other agency.
e. To disclose a debtor's name and identification number to the Secretary of the Treasury or his or her designee for the purpose of obtaining the debtor's mailing address from the IRS.
f. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
g. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
h. To disclose to an agency in the executive, legislative, or judicial branch or the District of Columbia's government in response to its request, or at the initiation of the agency maintaining the records, information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, the letting of a contract, the issuance of a license, grant, or other benefit by the requesting agency, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
i. To disclose to officers and employees of the Department of the Interior Business Center, in connection with administrative services provided to this agency under agreement with DOI.
These records are maintained in file folders and electronically.
These records are indexed by the name of the individual.
Records are maintained and stored in file cabinets in a secured area and electronically to which only authorized personnel have access. Access to and use of these records is limited to those persons whose official duties require such access.
Individual case files are usually retained for two years after the claim is collected. Case records on individuals whose delinquent debts are reported to consumer reporting agencies are
Director, Finance and Systems Services Division, Office of Chief Financial Officer Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Under the Debt Collection Act, individuals are notified if claims collection records are maintained on them in accordance with statutory procedures for debt collection. Individuals may also contact the System Manager in order to obtain notification of claims collection records on themselves.
Individuals must provide their full names under which records may be maintained, and a mailing address to which a reply should be sent.
Same as above.
Same as above.
Information in this system of records is provided by or from:
a. The individual on whom the record is maintained;
b. Other Federal agencies;
c. Personnel, payroll, travel records, contract records, or other records;
d. Administrative hearings;
e. Court records.
Grievance Records.
These records are located in the Office of the Chief Human Capital Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507, and in other headquarter offices and offices in the field where the grievances were filed (see Appendix A).
Current or former EEOC employees who have submitted grievances to the EEOC, or pursuant to a negotiated procedure.
The system contains all documents related to the grievance, including statements of witnesses, reports of interviews and hearings, examiners' findings and recommendations, a copy of the original and final decision, and related correspondence and exhibits. This system includes files and records of internal grievance and arbitration systems that EEOC has or may establish through negotiations with recognized labor organizations.
5 U.S.C. 301; 44 U.S.C. 3101; 5 U.S.C. 7121.
These records result from EEOC employees' grievances, filed under the Commission's administrative grievance procedures or the formal grievance procedures contained in section 7121 of the Civil Service Reform Act.
These records and information in these records may be used:
a. To disclose information to any source from which additional information is requested in the course of processing a grievance, to the extent necessary to identify the individual, inform the source of the purpose(s) of the request, and identify the type of information requested.
b. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
c. To disclose to an agency in the executive, legislative, or judicial branch or the District of Columbia's government, information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, the letting of a contract, the issuance of a license, grant, or other benefits by the requesting agency, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
d. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
e. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
f. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
g. To disclose in response to a request for discovery or for appearance of a witness, information that is relevant to the subject matter involved in a pending judicial or administrative proceeding.
h. To provide information to officials of labor organizations recognized under the Civil Service Reform Act when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting work conditions.
These records are maintained in file folders and electronically.
These records are retrieved by grievance numbers and the names of the individuals on whom they are maintained.
These records are maintained in lockable metal filing cabinets to which only authorized personnel have access. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
These records are shredded or burned 3 years after closing the case.
If the grievance is pending at or was never raised beyond the Step 1 or Step 2 level, the system manager is the office director, administrative officer, or district resource manager. (See Appendix A.) For grievances that were raised beyond Step 2, the system manager is the Chief Human Capital Officer, EEOC, 131 M Street NE., Washington, DC 20507.
It is required that individuals submitting grievances be provided a copy of the record under the grievance process. They may, however, contact the agency personnel or designated office where the action was processed regarding the existence of such records
Same as above.
Same as above.
Information in this system of records is provided:
a. By the individual on whom the record is maintained;
b. By testimony of witnesses;
c. By agency officials;
d. From related correspondence from organizations or persons.
Records of Adverse Actions Against Nonpreference Eligibles in the Excepted Service.
These records are located in Office of Chief Human Capital Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507 or in the headquarters and offices in the field in which the actions have been taken.
Current or former nonpreference-eligible, excepted service Equal Employment Opportunity Commission (EEOC) employees against whom an adverse action has been proposed or taken and who have not completed two years of current and continuous service in the same or similar positions. [This system covers only those adverse action files not covered by OPM/GOVT-3.]
This system contains records and documents on the processing of adverse actions for employees who are nonpreference eligible in the excepted service and who do not have two years of continuous service in their positions. The records include copies of the notice of proposed action, materials relied on by the agency to support the reasons in the notice, replies by the employee, statements of witnesses, reports, and agency decisions.
44 U.S.C. 3101.
These records result from the proposal, processing, and documentation of adverse actions taken by the Commission against nonpreference-eligible, excepted service EEOC employees.
These records and information in records may be used:
a. To provide information to officials of labor organizations recognized under 5 U.S.C. Chapter 71 when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting work conditions.
b. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, when the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
c. To disclose information to any source from which additional information is requested for processing any of the covered actions or in regard to any appeal or administrative review procedure, to the extent necessary to identify the individual, inform the source of the purpose(s) of the request, and identify the type of information requested.
d. To disclose information to a federal agency, in response to its request, in connection with the hiring or retention of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, or the classifying of jobs, to the extent that the information is relevant and necessary to the requesting agency's decision on the matter.
e. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
f. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
g. To disclose, in response to a request for discovery or for appearance of a witness, information that is relevant to the subject matter involved in a pending judicial, or administrative proceeding.
h. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in the investigation or settlement of a grievance, complaint, or appeal filed by an employee.
These records are maintained in file folders and electronically.
These records are retrieved by the names of the individuals on whom they are maintained.
These records are maintained in locked metal filing cabinets to which only authorized personnel have access. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
Records documenting an adverse action are disposed of 4 years after the closing of the case.
Chief Human Capital Officer, and Directors of offices in the field (see Appendix A).
Individuals receiving notice of a proposed action are provided access to all documents supporting the notice. They may also contact the personnel office where the action was processed regarding the existence of such records on them. They must furnish the following information for their records to be located and identified:
a. Name
b. Approximate date of closing of case and kind of action taken
c. Organizational component involved.
Same as above.
Same as above.
Information in this system of records is provided:
a. By the individual on whom the record is maintained
b. By witnesses
c. By agency officials.
Telephone Call Detail Records.
Telecommunications Manager, Customer Services Management
Individuals (generally EEOC employees) who made telephone calls from EEOC telephones, individuals who received telephone calls from, or charged to, EEOC telephones., and individuals who are assigned U.S. government phone cards by EEOC.
Records relating to the use of EEOC telephones and government phone cards to make calls; records indicating the assignment of telephone numbers to employees; records relating to the location of telephones.
44 U.S.C. 3101.
These records are maintained for the purpose of keeping an account of telephone calls made from EEOC telephones and ensuring that phone calls and card charges are made for official business only.
These records and information from these records may be used:
a. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
b. To disclose to representatives of the General Services Administration or the National Archives and Records Administration who are conducting records management inspections under the authority of 44 U.S.C. 2904 and 2906.
c. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
d. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where the disclosing agency becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
e. To disclose to an agency in the executive, legislative, or judicial branch or the District of Columbia's government in response to its request, or at the initiation of the EEOC, information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, the letting of a contract, the issuance of a license, grant or other benefits by the requesting agency, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
f. To disclose to a telecommunications company providing telecommunications support to permit servicing the account.
These records are maintained in file folders and electronically.
Records are retrieved by employee name or identification number and by name of recipient of telephone call or telephone number.
Records are maintained and stored in file cabinets in a secured area to which only authorized personnel have access. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
Records are disposed of as provided in the National Archives and Records Administration's General Records Schedule 12.
Telecommunications Manager, Customer Services Management Division, Office of Information Technology, EEOC, 131M Street NE., Washington DC, 20507 and the Directors of the field offices listed in Appendix A.
Inquiries concerning this system of records should be addressed to the system manager. It is necessary to provide the following information: (1) Name; (2) telephone number (office number if Commission employee); (3) mailing address to which response is to be sent.
Same as above.
Same as above.
Telephone assignment records; call detail listings; results of administrative inquiries relating to assignment of responsibilities for placement of specific local and long distance calls. on government phone card bills
Employee Identification Cards.
Operations Services Division, Office of the Chief Human Capital Officer, EEOC, 131 M Street NE., Washington DC 20507, and each of the field offices in Appendix A.
Current EEOC employees, and other individuals who require regular, ongoing access to EEOC facilities or information technology systems including, but not limited to, federal employees, contractors, interns, volunteers, and individuals formerly in any of these positions. This system does not apply to occasional or short-term visitors.
Records maintained on individuals issued identification cards, including Personal Identification Verification (PIV) cards, by EEOC include the following information: Full name; signature; social security number; date of birth; photograph; fingerprints; hair color; eye color; height; weight; office of assignment; telephone number; copy of background investigation form; card issue and expiration dates; personal identification number; results of background investigation; PIV request form; PIV registrar approval signature; PIV card serial number; and a list of all persons who possess current identification cards. In addition, for office locations permitting access by proximity cards, numbered proximity cards and a list of all persons with their assigned proximity card numbers, all doors controlled by the proximity cards, and all persons permitted access to each door.
44 U.S.C. 3101; 41 CFR 101-20.3. 5 U.S.C. 301; Federal Information Security Act (Pub. L. 104-106, 5113); Electronic Government Act (Pub. L. 104-347, 203); Homeland Security Presidential Directive (HSPD) 12, Policy for Common Identification Standard for Federal Employees and Contractors, August 27, 2004; and Office of Personnel Management Memorandum,
These records are maintained for the purpose of ensuring that EEOC offices and information systems are secure and that only authorized individuals have access to those offices and systems.
These records and information from these records may be used:
a. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
b. To disclose to other government agencies and to the public whether an individual is a current employee of the EEOC.
c. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
d. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
e. To disclose information to agency contractors who have been engaged to assist the agency in the performance of a contract or other activity related to this system of records and who need to have access to the records in order to perform their activity.
f. To notify another federal agency when, or verify whether, a PIV card is no longer valid.
These records are maintained in paper files and in electronic media.
Records are retrieved by name, social security number, other ID number, PIV card serial number, photograph, or fingerprint.
Records are maintained and stored in file cabinets in a secured area to which only authorized personnel have access. Access to electronic records is limited, through use of usernames and passwords, to those whose official duties require access.
Records are destroyed not later than five years after the separation or transfer of the employee. In accordance with HSPD-12, PIV cards are deactivated within 18 hours of cardholder separation, loss of card, or expiration. The information on PIV cards is maintained in accordance with General Records Schedule 11, Item 4. PIV cards are destroyed by cross-cut shredding no later than 90 days after deactivation.
Director, Operations Services Division, Office of the Chief Human Capital Officer, EEOC, 131 M Street NE., Washington DC 20507, and the Directors of the field offices listed in Appendix A.
Inquiries concerning this system of records should be addressed to the system manager. It is necessary to provide the following information: (1) Name; (2) date of birth; and (3) mailing address to which the response is to be sent.
Same as above.
Same as above.
Information contained in this system is obtained from the employee or contractor; other federal agencies; contract employer; or former employer.
Reserved
Internal Harassment Inquiries.
Office of the Chief Human Capital Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Current or former EEOC employees, contractors, applicants, interns, and volunteers who have submitted complaints or reports of harassment under EEOC Order 560.005, Prevention and Elimination of Harassment in the Workplace, and current and former EEOC employees, contractors, applicants, interns, and volunteers who have been accused of harassment under that Order.
The system contains all documents related to a complaint or report of harassment, including statements of witnesses, reports of interviews, investigator's and Coordinator's findings and recommendations, final decisions and corrective action taken, and related correspondence and exhibits.
29 U.S.C. 633a; 29 U.S.C. 791; 42 U.S.C. 2000e-16; 44 U.S.C. 3101; Exec. Order No. 11478, 34 FR 12985; Exec. Order No. 13087, 63 FR 30097.
These records are maintained for the purpose of conducting internal investigations into allegations of harassment brought by current or former EEOC employees, contractors, applicants, interns, and volunteers and taking appropriate action in accordance with EEOC Order 560.005.
These records and information in these records may be used:
a. To disclose information as necessary to any source from which additional information is requested in the course of processing a complaint or report of harassment made pursuant to EEOC Order 560.005.
b. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, when the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
c. To disclose information to another federal agency, to a court, or to a party in ligation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
d. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
e. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
f. To disclose to the individual who filed the complaint or report of harassment and to the alleged harasser
g. To provide to officials of labor organizations recognized under the Civil Service Reform Act information to which they are statutorily entitled when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting work conditions.
h. To provide to the alleged harasser information in the event of a disciplinary hearing.
These records are maintained in file folders and electronically.
These records are cross-indexed by the name of the individual who files a complaint or report of harassment, the name of the alleged victim of harassment, if any, and the name of the alleged harasser. The records may be retrieved by any of the above three indexes.
The records are maintained in locked metal filing cabinets to which only authorized personnel have access. Access to electronic records is limited, through use of logins and passwords, to those whose official duties require access.
These records are maintained for one year after the complaint or report of harassment is closed and then transferred to the Federal Records Center where they are destroyed after three years.
Harassment Coordinator, Office of Chief Human Capital Officer, EEOC, 131 M Street NE., Washington, DC 20507.
This system is exempt under 5 U.S.C. 552a(k)(2) from subsections (c)(3), (d), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I) and (f) of the Act.
Office of Inspector General Investigative Files.
Office of Inspector General (OIG), Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Individuals who are subjects of investigations by the Office of Inspector General relating to the programs and operations of the Equal Employment Opportunity Commission. Subject individuals include, but are not limited to, current and former employees; current and former agents or employees of contractors and subcontractors in their personal capacity, where applicable; and other individuals whose actions affect the EEOC, its programs or operations.
Correspondence relating to the investigation; internal staff memoranda; copies of subpoenas issued during the investigation, affidavits, statements from witnesses, transcripts of testimony taken during the investigation, and accompanying exhibits; documents, notes, investigative notes, staff working papers, draft materials, and other documents and records relating to the investigation; opening reports, progress reports, and closing reports; video and audio recordings; and other investigatory information or data relating to the alleged or suspected criminal, civil, or administrative violations or similar wrongdoing by subject individuals.
The Inspector General Act of 1978, as amended, 5 U.S.C. App. 3.
Pursuant to the Inspector General Act of 1978, as amended, this system of records is maintained for the purpose of: (1) Documenting the conduct and outcome of investigations by the OIG and other investigative agencies regarding EEOC programs and operations; (2) reporting the results of investigations to other Federal agencies, other public authorities or professional organizations which have the authority to bring criminal prosecutions, or civil or administrative actions, or to impose other disciplinary sanctions; (3) maintaining a record of the activities which were the subject of investigations; (4) reporting investigative findings to other components of EEOC for their use in operating and evaluating their programs or operations, and in the imposition of civil or administrative sanctions; (5) coordinating relationships with other Federal agencies, state and local governmental agencies and nongovernmental entities in matters relating to the statutory responsibilities of the OIG; and (6) acting as a repository and source for information necessary to fulfill the reporting requirements of the Inspector General Act, 5 U.S.C. App. 3.
a. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation or order, where the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
b. To disclose information to any source, private or governmental, to the extent necessary to secure from such source information relevant to and in furtherance of a legitimate OIG investigation, audit, evaluation, or other inquiry.
c. To disclose information to agencies, offices or establishments of the executive, legislative, or judicial branches of the Federal or state governments:
(1) Where such agency, office, or establishment has an interest in an individual for employment purposes, including a security clearance or determination as to access to classified information, and needs to evaluate the individual's qualifications, suitability, or loyalty to the United States Government, or access to classified information or restricted areas, or
(2) Where such agency, office, or establishment conducts an investigation of the individual for purposes of granting a security clearance, or for making a determination of qualifications, suitability or loyalty to the United States Government, or access to classified information or restricted areas, or
(3) Where the records or information in those records is relevant and necessary to a decision with regard to the hiring or retention of an employee or disciplinary or other administrative action concerning an employee.
d. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
e. To disclose information to a Congressional office from the record of an individual in response to an inquiry from the Congressional office made at the written request of that individual.
f. To private contractors who have been retained by OIG to perform any functions or analyses that facilitate or are relevant to an OIG investigation, audit, inspection, or inquiry.
g. To disclose information to authorized officials of the Council of Inspectors General for Integrity and Efficiency (CIGIE), the Department of Justice, and the Federal Bureau of Investigation for the purpose of conducting qualitative assessment reviews of the Office of Inspector General's investigative operations.
h. To disclose information to authorized officials of the CIGIE for their preparation of reports to the President and Congress on the activities of the Inspectors General.
i. To disclose to an agency, organization or individual for the purpose of performing audit or oversight operations as authorized by law, including peer reviews, but only such information as is necessary and relevant to such audit or oversight operation.”
Information in this system is stored manually in file folders and electronically.
The records are retrieved by the name of the subject of the investigation or by a unique control number assigned to each investigation.
Information is stored in locked file cabinets in a secured space. Access to electronic records is limited through the use of logins and passwords to those whose official duties require access.
Records are held for five (5) years and then retired to the Federal Records Center.
Inspector General, Equal Employment Opportunity Commission, P.O. Box 18858, Washington, DC 20036-8858.
Defensive Litigation Files.
External Defensive Litigation Files are located in the Office of Legal Counsel, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507. Internal Defensive Litigation Files are located in the Office of General Counsel, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Individuals who have filed civil or administrative litigation against EEOC and individuals who have given sworn testimony, affidavits, or declarations under penalty of perjury in such actions. External cases are brought by members of the public; internal cases are brought by applicants, current, and former EEOC employees.
This system contains all documents related to external and internal litigation brought against the Commission. These records include:
a. Documents submitted or filed by plaintiffs, grievants, and EEO complainants to prosecute civil or administrative litigation against the EEOC, such as complaints, grievances, unfair labor practice claims, motions, and briefs.
b. Documents submitted by the EEOC to defend the action against it such as an answer to a civil complaint or a motion to dismiss or for summary judgment, and a reply to an administrative EEO complaint, grievance, or unfair labor practice.
c. Administrative determinations at issue in the litigation such as final agency EEO decisions, final grievance decisions, final decisions on personnel actions, final agency administrative dispositions of tort claims, and agency determinations under the Freedom of Information Act.
d. Discovery and investigatory materials such as witness statements, affidavits, declarations under penalty of perjury, correspondence, records, exhibits, and other documentary evidence.
e. Litigation materials, such as attorney work product, attorney notes, hearing transcripts, legal memoranda, and related correspondence and exhibits.
f. Final judgments, orders, decisions, decrees, and settlement agreements.
44 U.S.C. 3101.
These records are maintained for the purpose of defending EEOC in litigation brought against it by current and former employees (internal files), charging parties, respondents and members of the public (external files).
These records and information in these records may be used:
a. To disclose pertinent information as may be appropriate or necessary for the Commission to defend itself in a civil action or administrative proceeding, or to seek enforcement of a settlement, order, or final decision involving the same or a similar matter.
b. To provide information to a congressional office in response to an inquiry from the congressional office made at the request of a party to the administrative or civil proceeding to which the record pertains.
c. To disclose pertinent information to an appropriate federal court, agency, or administrative body responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation, or in order to seek enforcement or clarification of an order or decision for or against the EEOC to which the record pertains.
d. To disclose information to another federal agency or to a court when the government is a party to the judicial or administrative proceeding.
e. To disclose, in response to an order, information that is relevant to a pending judicial or administrative proceeding.
External defensive litigation files are maintained in a locked filing system in the Office of Legal Counsel. Internal defensive litigation files are maintained in a locked filing system in the Office of General Counsel. Information identifying existing external and internal defensive litigation files is maintained electronically.
External Defensive Litigation records are cross-indexed by name of the plaintiff, and Office of Legal Counsel reference number. Internal Defensive Litigation records are maintained by
External Defensive Litigation paper records maintained at EEOC headquarters are kept in locked cabinets in the Office of Legal Counsel. Internal Defensive Litigation paper records maintained at EEOC headquarters are kept in locked cabinets in the Office of General Counsel. Access to and use of these records is limited to those persons whose official duties require such access. The premises are locked evenings, weekends, and holidays. Paper records which have been retired are maintained at the Federal Records Center. Access to electronic External and Internal Defensive Litigation records is limited through use of passwords to those whose official duties require access, input, and retrieval of information.
Two years after the date of closure of the underlying civil or administrative action (
The System Manager for External Defensive Litigation files is the Assistant Legal Counsel, Advice & Litigation Division, Office of Legal Counsel, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507. The System Manager for Internal Defensive Litigation files is the Assistant General Counsel for Internal Litigation Services, Office of General Counsel, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Any person wanting to know whether this system of records contains information about him or her should contact the System Manager. Such person should provide his or her full name and mailing address to which a response is to be sent, and forum, filing date, and docket number of the action involved, if available.
The records described herein are compiled in reasonable anticipation of a civil action or proceeding. Pursuant to section (d)(5) of the Privacy Act of 1974, as amended, 5 U.S.C. 552a(d)(5), an individual is precluded from access to such records.
Same as the Notification Procedures above.
Plaintiffs, grievants, complainants, aggrieved individuals, current and former EEOC employees.
Reasonable Accommodation Records
Office of the Chief Human Capital Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Current and former EEOC employees and applicants who have requested reasonable accommodations under the Rehabilitation Act of 1973.
Requests for reasonable accommodations; medical records; notes or records made during consideration of requests; decisions on requests; records made to implement or track decisions on requests.
The Rehabilitation Act of 1973, 29 U.S.C. 791; E.O. 13164.
This system is maintained for the purpose of considering, deciding, and implementing requests for reasonable accommodation made by EEOC employees and applicants.
a. To disclose information to medical personnel to meet a bona fide medical emergency.
b. To disclose information to another Federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a Federal agency when the Government is a party to the judicial or administrative proceeding.
c. To disclose information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
d. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
Maintained in locked file cabinets and electronically.
Indexed by name of employee or applicant and office location.
Files are maintained in locked cabinets. Access is restricted to EEOC personnel whose official duties require such access. Access to computerized records is limited, through use of logins and passwords, to those whose official duties require access.
These records will be maintained in the Office of the Human Capital Officer for the longer of an employee's tenure with EEOC or 5 years. Thereafter, they will be destroyed.
Disability Program Manager, Office of the Chief Human Capital Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Any person wanting to know whether this system of records contains information about him or her should contact the System Manager. Such person should provide his or her full name, position title and office location at the time the accommodation was requested, and mailing address to which a response is to be sent.
Same as the Notification Procedures above.
Same as the Notification Procedures above.
Information contained in this system is obtained from the current or former employee, the Office of the Chief Human Capital Officer, and management officials.
Revolving Fund Registrations.
Revolving Fund Division, Office of Field Programs, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Individuals who register for or attend EEOC Revolving Fund programs, courses and conferences and who purchase publications and products.
The system contains the names, job titles, company, organization or agency names, business addresses and phone numbers, email addresses, any reasonable accommodation requested, and attendance or purchase dates. Some of the records may contain payment information, the industry of the company, and the size of the establishment.
42 U.S.C. 2000e-4(k).
These records are maintained for the purpose of administering Revolving Fund programs and publicizing future programs.
These records and information in these records may be used:
a. To send mailings to registrants and attendees advertising future Revolving Fund programs.
b. To provide information to a congressional office from the record of the individual in response to an inquiry from that congressional office made at the request of that individual.
c. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
These records are maintained electronically.
These records are indexed by the names of the registrants or attendees, by company, organization, or agency name.
Access to and use of these records is limited, through use of access codes and entry logs, to those whose official duties require access.
These records are kept indefinitely.
Director, Revolving Fund Division, Office of Field Programs, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Inquiries concerning this system of records should be addressed to the system manager. All inquiries should furnish the full name of the individual and the mailing address to which the reply should be mailed.
Same as above.
Same as above.
Information contained in this system is obtained from the registrant or attendee.
RESOLVE Program Records.
RESOLVE Program, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Current and former EEOC employees who request alternative dispute resolution during the counseling or investigative process of their EEO complaints against EEOC, as well as EEOC employees who contact the RESOLVE program for alternative dispute resolution of disputes occurring in their EEOC employment.
The system contains the records generated in the course of receiving and attempting to resolve disputes brought to the RESOLVE program, including, as appropriate, intake interview notes, mediation scheduling notices, the mediator's outcome form, and settlement agreements.
5 U.S.C. 571-574; 44 U.S.C. 3101; 29 CFR part 1614.
These records are maintained for the purpose of administering EEOC's RESOLVE Program, which provides a forum for the informal resolution of a variety of workplace disputes as an alternative to the formal procedures that employees traditionally use to resolve disputes.
These records and information in these records may be used:
a. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, when the EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
b. To provide information to a congressional office from the record of the individual in response to an inquiry from that congressional office made at the request of that individual.
c. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
These records are maintained in file folders and electronically.
These records are indexed by the names of the employee.
The records are maintained in locked metal filing cabinets to which only authorized personnel have access. Access to and use of electronic records is limited, through use of logins and passwords, to those whose official duties require access.
These records are maintained for one year after the complaint or dispute matter brought to RESOLVE is closed and then transferred to the Federal Records Center where they are destroyed after three years.
Chief Mediation Officer, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
Inquiries concerning this system of records should be addressed to the
Same as above.
Same as above.
Information contained in this system is obtained from the current or former employee, the Office of Equal Opportunity, the Office of the Chief Human Capital Officer, management officials, union officials, and the mediator.
Emergency Management Records.
Headquarters, District, Field, Area, and Local Offices may maintain emergency contact files. The Office of the Chief Financial Officer maintains emergency management and continuity of operations (COOP) files. The Office of the Chief Human Capital Officer maintains the orders of succession, which are part of the COOP files.
EEOC employees, contractors, and other governmental and non-governmental persons essential to carrying out emergency activities.
The records, composed of emergency notification rosters and files, emergency contact information, and COOP files, may contain the following personal information: Name; office, cellular and home telephone numbers; home address; email address; primary contact name, relationship, address, cellular, work and home telephone numbers; alternate contact's name, relationship, address, cellular, work and home telephone numbers. Each office may collect a different set of information. System records may include special needs information such as medical, mobility, and transportation requirements for individuals. Additional information may include official titles and emergency assignments.
5 U.S.C. 301; 44 U.S.C. 3101; Executive Order 12565, Assignment of Emergency Preparedness Responsibilities, (Nov. 18, 1989); Presidential Decision Directive 67, Ensuring Constitutional Government and Continuity of Government Operations.
To maintain current information on EEOC employees and other persons covered by this system to allow persons with emergency management responsibilities to notify or contact them about conditions that require their urgent assistance or attention during an emergency.
These records and information in these records may be used:
a. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
b. To disclose information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
c. To disclose information to an expert, consultant or contractor in the performance of a federal government duty involving EEOC emergency management.
d. To disclose information about an individual during an emergency in order to locate or contact that individual.
These records are maintained in paper files and in electronic media.
Records are retrieved by name, organization, or location.
Records are maintained and stored in file cabinets in a secured area to which only authorized personnel have access. Access to electronic records is limited through use of logins and passwords for those whose official duties require access.
Records are destroyed one year after termination of the employment relationship or contract termination.
Headquarters, District, Field, Area, and Local Office Directors. Addresses listed in Appendix A.
Inquiries concerning this system of records should be made to the system manager. It is necessary to provide the name of the individual and the mailing address to which the response should be sent.
Same as above.
Same as above.
Information in this system is obtained from the individuals themselves, their supervisors or office.
EEOC Personnel Security Files.
Office of the Chief Human Capital Officer, Operations Services Division, Equal Employment Opportunity Commission, 131 M Street NE., Washington, DC 20507.
EEOC employees, applicants, former employees, interns, volunteers, and contractors.
Name, former names, birth date, birth place, social security number, home address, telephone numbers, employment history, residential history, education and degrees earned, names of associates and references and their contact information, citizenship, names of relatives, citizenship of relatives, names of relatives who work for the federal government, criminal history, drug use, financial information, fingerprints, summary report of investigation, results of suitability decisions, requests for appeal, witness statements, investigator's notes, tax return information, credit reports, security violations (including circumstances of violation and agency action taken).
5 U.S.C. 3101; 5 CFR parts 731, 732, and 736; Executive Orders 10450, 10865, 12333, 12356, and 13467; Homeland Security Presidential Directive 12 (HSPD 12), Policy for a Common Identification Standard for Federal Employees and Contractors,
The records in this system are used to document and support decisions regarding the suitability, eligibility, and fitness for service of applicants for EEOC employment and contract positions, including criminal background screening for interns, or volunteers, to the extent their duties require access to federal facilities, information, systems, or applications. The records may be used to document security violations and supervisory actions taken.
a. To provide information to a congressional office from the record of an individual in response to an inquiry from the congressional office made at the request of the individual.
b. Except as noted on Standard Forms 85, 85P, and 86, to disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where EEOC becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
c. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
d. To disclose information to any source or potential source from which information is requested in the course of an investigation concerning the retention of an employee or other personnel action (other than hiring), to the extent necessary to identify the individual, inform the source of the nature and purpose of the investigation, and to identify the type of information requested.
e. To disclose information to employees of contractors who have been engaged by EEOC to perform an activity related to suitability, eligibility, and fitness for service of EEOC applicants and employees.
These records are maintained in paper files and in electronic media.
Background investigation files are retrieved by name, social security number, or fingerprint.
Records are maintained and stored in file cabinets in a secured area to which only authorized personnel have access. Access to electronic records is limited through use of logins and passwords to those whose official duties require access.
These records are destroyed upon notification of death or not later than five years after separation or transfer of employee to another agency or department.
Director, Operations Services Division, Office of the Chief Human Capital Officer, EEOC, 131 M Street NE., Washington, DC 20507.
Inquiries concerning this system of records should be addressed to the system manager. It is necessary to provide the following information: (1) Name; (2) date of birth; and (3) mailing address to which response is to be sent.
Same as above.
Same as above.
Information is obtained from a variety of sources, including the employee, contractor or applicant via use of the SF-85, SF-85P, or SF-86 and personal interviews; employers' and former employers' records; FBI criminal history records and other databases; financial institutions and credit reports; interviews of witnesses, such as neighbors, friends, co-workers, business associates, teachers, landlords, or family members; tax records; and other public records. Security violation information is obtained from a variety of sources, such as guard reports, security inspections, witnesses, supervisor's reports, audit reports.
This system of records is exempt in accordance with 5 U.S.C. 552a(k)(5) from subsection (c)(3) and (d)(1) of the Privacy Act, but only to the extent that the information identifies witnesses promised confidentiality as a condition of providing information during the course of the background investigation.
Equal Employment Opportunity (EEO) in the Federal Government Complaint and Appeal Records.
Equal employment opportunity complaint files are maintained in an Office of Equal Employment Opportunity or other designated office of the agency or department where the complaint was filed. EEO hearing records are maintained in the EEOC office in the field that handles the hearing request (See Appendix A). EEO Appeal files (including appeals from final negotiated grievance decisions involving allegations of discrimination) and petitions for review of decisions of the Merit Systems Protection Board are maintained in the Office of Federal Operations, Equal Employment Opportunity Commission, 131 M St. NE., Washington, DC 20507. Applicants for federal employment and current and former federal employees who contact an EEO counselor, file complaints of discrimination or reprisal with their agency, file requests for hearings, or file appeals of EEO complaints, petitions for review of decisions of the Merit Systems Protection Board, or appeals of final decisions in negotiated grievance actions involving allegations of discrimination.
This system of records contains information or documents compiled during the pre-complaint counseling, investigation, hearing, and appeal of complaints filed under section 717 of Title VII, section 15 of the Age Discrimination in Employment Act, section 501 of the Rehabilitation Act, and the Equal Pay Act and all appeals.
42 U.S.C. 2000e-16(b) and (c); 29 U.S.C. 204(f) and 206(d); 29 U.S.C. 633(a); 29 U.S.C. 791; Reorg. Plan No. 1 of 1978, 43 FR 19607 (May 9, 1978); Exec. Order No. 12106, 44 FR 1053 (Jan. 3, 1979).
These records are maintained for the purpose of counseling, investigating, and adjudicating complaints of employment discrimination brought by applicants and current and former federal employees against federal employers.
These records and information in these records may be used:
a. To disclose pertinent information to the appropriate federal, state, or local agency responsible for investigating, prosecuting, enforcing, or implementing a statute, rule, regulation, or order, where the disclosing agency becomes aware of an indication of a violation or potential violation of civil or criminal law or regulation.
b. To disclose information to another federal agency, to a court, or to a party in litigation before a court or in an administrative proceeding being conducted by a federal agency when the government is a party to the judicial or administrative proceeding.
c. To provide information to a congressional office from the record of an individual in response to an inquiry from that congressional office made at the request of that individual.
d. To disclose to an authorized appeal grievance examiner, formal complaints examiner, administrative judge, equal employment opportunity investigator, arbitrator, or other duly authorized official engaged in investigation or settlement of a grievance, complaint, or appeal filed by an employee.
e. To disclose, in response to a request for discovery or for appearance of a witness, information that is relevant to the subject matter involved in a pending judicial or administrative proceeding.
f. To disclose information to officials of state or local bar associations or disciplinary boards or committees when they are investigating complaints against attorneys in connection with their representation of a party before EEOC.
g. To disclose to a Federal agency in the executive, legislative, or judicial branch of government, in response to its request for information in connection with the hiring of an employee, the issuance of a security clearance, the conducting of a security or suitability investigation of an individual, the classifying of jobs, or the lawful statutory, administrative, or investigative purpose of the agency to the extent that the information is relevant and necessary to the requesting agency's decision.
h. To disclose information to employees of contractors engaged by an agency to carry out the agency's responsibilities under 29 CFR part 1614.
i. To disclose information to potential witnesses as appropriate and necessary to perform the agency's functions under 29 CFR part 1614.
These records are maintained in file folders and electronically.
These records are indexed by the names of the individuals on whom they are maintained.
Access to and use of these records are limited to those persons whose official duties require such access.
These records are maintained for one year after resolution of the case and then transferred to the Federal Records Center where they are destroyed after three years.
Within the agency or department where the complaint of discrimination was filed, the system manager is the Director of the Office of Equal Employment Opportunity or other official designated as responsible for the administration and enforcement of equal employment opportunity laws and regulations within the agency or department.
Where an individual has requested a hearing, the system manager of hearing records is the Director of the Office of Field Programs, 131 M Street NE., Washington, DC 20507.
Where an EEO complaint or final negotiated grievance decision has been appealed to EEOC or an individual has petitioned EEOC for review of a decision of the Merit Systems Protection Board, the system manager of the appeal or petition file is the Director, Office of Federal Operations, 131 M Street NE., Washington, DC
Pursuant to subsection (k)(2) of the Privacy Act, 5 U.S.C. 552a(k)(2), this system of records is exempt from subsections (c)(3), (d), (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I) and (f) of the Act.
Federal Communications Commission.
Notice.
The Commission announces renewal of charter, appointment of members, designation of chairperson, and 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.
January 27, 2017, 9:00 a.m. to 4:00 p.m.
Federal Communications Commission, Commission Meeting Room TW-C305, 445 12th Street SW., Washington, DC 20554.
Scott Marshall, Designated Federal Officer of the Committee at: 202-418-2809 (voice or relay) or
This is a summary of the Commission's document DA 16-1230, released October 31, 2016 announcing the charter renewal, appointment of members, designation of chairperson, and the Agenda, Date, and Time of the Committee's first Meeting under its renewed charter.
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. The Committee may consider issues including, but not limited to, the following topics:
• Consumer protection and education;
• Implementation of Commission rules and consumer participation in the FCC rulemaking process; and,
• The impact of new and emerging communication technologies (including availability and affordability of broadband service and Universal Service programs).
In November 2000, the Committee was initially established for a period of two (2) years from the original charter date. Following expiration of the original charter, the Committee was subsequently renewed several times. On October 14, 2016, the Committee held the final meeting of its most recent term, and thereafter, the Committee's charter, and all member appointments, terminated. The charter was renewed on October 21, 2016, for another two-year term, the ninth such renewal. This renewal is necessary and in the public interest. The Committee will operate in accordance with the provisions of the Federal Advisory Committee Act, 5 U.S.C. App. 2 (1988). Each meeting of the Committee will be open to the public. A notice of each meeting will be published in the
During the Committee's ninth term, it is anticipated that the Committee will meet in Washington, DC for a minimum of three (3) one-day plenary meetings per year. In addition, as needed, working groups or subcommittees will be established to facilitate the Committee's work between meetings of the full Committee. Meetings will be fully accessible to individuals with disabilities.
Members must be willing to commit to a two (2) year term of service, and should be willing and able to attend a minimum of three (3) one-day plenary committee meetings per year in Washington, DC. Committee members are also expected to participate in deliberations of at least one (1) working group or subcommittee.
In anticipation of the renewal of the Committee's charter, by a Public Notice (DA 16-657) released June 14, 2016, the
After a review of the applications received, Chairman Tom Wheeler hereby appoints twenty-nine (29) members to the Committee. Of these, seventeen (17) represent interests of general consumers, two (2) represent interests of people with disabilities, six (6) represent interest of industry, one (1) represents minority interests, two (2) represent interests of quasi-government/regulators, and one (1) represents interests of seniors. The Committee's membership is designed to be representative of the Commission's many constituencies, and the diversity of the selected members will provide a balanced point of view as required by the Federal Advisory Committee Act. In addition, Chairman Wheeler designates Eduard Bartholme representing Call For Action as Chairperson of the Committee. All appointments and reappointments are effective October 21, 2016, and shall terminate October 21, 2018, or when the Committee is terminated, whichever is earlier.
The Committee's roster by organization name and primary representative is as follows:
At its January 27, 2017, meeting, the Committee will consider administrative and procedural matters relating to its functions. The Committee may receive briefings from commission staff on issues of interest to the Committee. A limited amount of time will be available on the agenda for comments from the public. If time permits, the public may ask questions of presenters via the email address
The meeting is open to the public and the site is fully accessible to people using wheelchairs or other mobility aids. Sign language interpreters, open captioning, assistive listening devices, and Braille copies of the agenda and committee roster will be provided on site. Meetings of the Committee are also broadcast live with open captioning over the Internet from the FCC Live Web page at
Other reasonable accommodations for people with disabilities 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
For further information contact the Designated Federal Officer of the Committee, Scott Marshall, at 202-418-2809 (voice or relay) or
Federal Communications Commission.
Notice.
This document announces the date of the next meeting of the Commission's Disability Advisory Committee (Committee or DAC). The meeting is open to the public. During this meeting, members of the Committee will receive and discuss summaries of activities and recommendations from its subcommittees.
The Committee's next meeting will take place on Tuesday, December 6, 2016, from 9:00 a.m. to approximately 3:30 p.m. (EST).
Federal Communications Commission, 445 12th Street SW.,
Elaine Gardner, Consumer and Governmental Affairs Bureau: (202) 418-0581 (voice); email:
The Committee was established in December 2014 to make recommendations to the Commission on a wide array of disability matters within the jurisdiction of the Commission, and to facilitate the participation of people with disabilities in proceedings before the Commission. The Committee is organized under, and operated in accordance with, the provisions of the Federal Advisory Committee Act (FACA). The Committee held its first meeting on March 17, 2015.
At its December 6, 2016 meeting, the Committee is expected to receive and consider: Reports on the activities of its Communications and Emergency Communications Subcommittees; a report and recommendation from its Technology Transitions Subcommittee regarding the accessibility of the Internet of Things; a report and recommendation from its Video Programming Subcommittee on video description services; and a report and four recommendations from its Relay & Equipment Distribution Subcommittee regarding: Videomail-to-text services for Video Relay Services consumers who are Deaf-Blind; mobile device support for USB connectivity to Braille displays; best practices for the development and testing of Augmentative-Alternative Communication (AAC) devices; and the portability of ten-digit telephone numbers and associated features from one IP-enabled relay provider to another. The Committee also anticipates presentations from Commission staff on recent activities, and a presentation on the future of television. A limited amount of time may be available on the agenda for comments and inquiries from the public. The public may comment or ask questions of presenters via the email address
The meeting site is fully accessible to people using wheelchairs or other mobility aids. Sign language interpreters, open captioning, and assistive listening devices will be provided on site. Other reasonable accommodations for people with disabilities are available upon request. If making a request for an accommodation, please include a description of the accommodation you will need and tell us how to contact you if we need more information. Make your request as early as possible by sending an email to
To request materials in accessible formats for people with disabilities (Braille, large print, electronic files, audio format), send an email to
Pursuant to the provisions of the “Government in the Sunshine Act” (5 U.S.C. 552b), notice is hereby given that at 10:28 a.m. on Tuesday, November 15, 2016, the Board of Directors of the Federal Deposit Insurance Corporation met in closed session to consider matters related to the Corporation's supervision, corporate, and resolution activities.
In calling the meeting, the Board determined, on motion of Vice Chairman Thomas M. Hoenig, seconded by Director Richard Cordray (Director, Consumer Financial Protection Bureau), concurred in by Director Thomas J. Curry (Comptroller of the Currency) and Chairman Martin J. Gruenberg, that Corporation business required its consideration of the matters which were to be the subject of this meeting on less than seven days' notice to the public; that no earlier notice of the meeting was practicable; that the public interest did not require consideration of the matters in a meeting open to public observation; and that the matters could be considered in a closed meeting by authority of subsections (c)(2), (c)(4), (c)(6), (c)(8), (c)(9)(A)(ii), (c)(9)(B), and (c)(10) of the “Government in the Sunshine Act” (5 U.S.C. 552b(c)(2), (c)(4), (c)(6), (c)(8), (c)(9)(A)(ii), (c)(9)(B), and (c)(10).
The Commission hereby gives notice of the filing of the following agreements under the Shipping Act of 1984. Interested parties may submit comments on the agreements to the Secretary, Federal Maritime Commission, Washington, DC 20573, within twelve days of the date this notice appears in the
By Order of the Federal Maritime Commission.
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 December 12, 2016.
1.
The notificants listed below have applied under the Change in Bank Control Act (12 U.S.C. 1817(j)) and § 225.41 of the Board's Regulation Y (12 CFR 225.41) to acquire shares of a bank or bank holding company. The factors that are considered in acting on the notices are set forth in paragraph 7 of the Act (12 U.S.C. 1817(j)(7)).
The notices are available for immediate inspection at the Federal Reserve Bank indicated. The notices also will be available for inspection at the offices of the Board of Governors. Interested persons may express their views in writing to the Reserve Bank indicated for that notice or to the offices of the Board of Governors. Comments must be received not later than December 1, 2016.
1.
Board of Governors of the Federal Reserve System, November 10, 2016.
Federal Trade Commission (FTC or Commission).
Notice.
The information collection requirements described below will be submitted to the Office of Management and Budget (OMB) for review, as required by the Paperwork Reduction Act (PRA). The FTC seeks public comments on its proposal to extend, for three years, the current PRA clearance for its portion of the information collection requirements contained in the Consumer Financial Protection Bureau's Regulation O (the Mortgage Assistance Relief Services Rule). The FTC shares enforcement of Regulation O with the Consumer Financial Protection Bureau (CFPB). This clearance expires on January 31, 2017.
Comments must be received on or before January 17, 2017.
Interested parties may file a comment online or on paper by following the instructions in the Request for Comments part of the Supplementary Information section below. Write “Regulation O, PRA Comment, FTC File No. P134812” on your comment, and file your comment online at
Requests for copies of the collection of information and supporting documentation should be addressed to Rebecca Unruh, Attorney, Division of Financial Practices, Bureau of Consumer Protection, Federal Trade Commission, 600 Pennsylvania Avenue NW., CC-10232, Washington, DC 20580, (202) 326-3365.
Title X of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), Public Law 111-203, 124 Stat. 1376 (2010), transferred the Commission's rulemaking authority under the mortgage provisions in section 626 of the 2009 Omnibus Appropriations Act, as amended,
Regulation O contains information requirements that have been approved by OMB under the PRA, 44 U.S.C. 3501
In commercial communications for a general audience, MARS providers are required to make the following disclosure:
(1) “(Name of company) is not associated with the government and our service is not approved by the government or your lender”; and
(2) In some instances, that “[e]ven if you accept this offer and use our service, your lender may not agree to change your loan.”
In addition, MARS providers must disclose to consumers, in any subsequent commercial communication directed to a specific consumer, the following information:
(1) That “You may stop doing business with us at any time. You may accept or reject the offer of mortgage assistance we obtain from your lender [or servicer]. If you reject the offer, you do not have to pay us. If you accept the offer, you will have to pay us (insert amount or method for calculating the amount) for our services”;
(2) That “(Name of company) is not associated with the government and our service is not approved by the government or your lender”; and
(3) In some instances, that “[e]ven if you accept this offer and use our service, your lender may not agree to change your loan.”
Furthermore, MARS providers are required to disclose to consumers in all communications in which the provider represents that the consumer should temporarily or permanently discontinue payments, in whole or in part, the following information:
“If you stop paying your mortgage, you could lose your home and damage your credit rating.”
Finally, after a provider has obtained an offer of mortgage assistance relief from the lender or servicer and presented the consumer with a written agreement incorporating the offer, the MARS provider must disclose the following:
(1) “This is an offer of mortgage assistance relief service from your lender [or servicer]. You may accept or reject the offer. If you accept the offer, you will have to pay us [same amount as disclosed pursuant to § 1015.4(b)(1)] for our services”; and
(2) A description of all “material differences” between the terms, conditions, and limitations of the consumer's current mortgage and those associated with the offer for mortgage relief, provided in a written notice from the consumer's lender or servicer.
Regulation O also requires that the disclosures be “clear and prominent,” as defined specific to the media used.
These disclosures are necessary for the following reasons:
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Regulation O's recordkeeping requirements pertain to records that are customarily kept in the ordinary course of business, such as copies of contracts and consumer files containing the name
Because the FTC and CFPB share enforcement authority for this rule, the FTC is seeking clearance for one-half of the following estimated PRA burden that the FTC attributes to the disclosure and recordkeeping requirements under Regulation O. The potential entities providing MARS services are varied, and there are no ways to formally track them. By extension, there is no clear path to track how many affected individual entities have newly entered and departed from one year to the next or from one triennial PRA clearance cycle to the next. However, based on law enforcement experience and the CFPB's recent analysis conducted after the MARS Rule was restated as Regulation O, the FTC estimates that Regulation O affects roughly 107 MARS providers.
The above hours estimate is based on the assumption that compliance with all MARS disclosures requires 6 hours of labor annually.
Commission staff assumes that a compliance officer or equivalent will prepare the required disclosures for 6 hours annually at an hourly rate of $33.26.
Based on the CFPB's analysis, the FTC assumes that each of the estimated 107 MARS providers bears an additional $550 in material fees for acquiring relevant legal and technical compliance information, for a total additional burden of $58,850, of which the FTC assumes half, or $29,425.
Under the PRA, 44 U.S.C. 3501-3521, federal agencies must obtain approval from OMB for each collection of information they conduct or sponsor. “Collection of information” means agency requests or requirements that members of the public submit reports, keep records, or provide information to a third party. 44 U.S.C. 3502(3); 5 CFR 1320.3(c). As required by section 3506(c)(2)(A) of the PRA, the FTC is providing this opportunity for public comment before requesting that OMB extend the existing paperwork clearance for the regulations noted herein.
Pursuant to Section 3506(c)(2)(A) of the PRA, the FTC invites comments on:
(1) Whether the disclosure and recordkeeping requirements are necessary, including whether the information will be practically useful;
(2) the accuracy of our burden estimates, including whether the methodology and assumptions used are valid;
(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. All comments should be filed as prescribed in the
You can file a comment online or on paper. Write “Regulation O, PRA Comment, FTC File No. P134812” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the public Commission Web site, at
Because your comment will be made public, you are solely responsible for making sure that your comment does not include any sensitive personal information, such as a Social Security number, date of birth, driver's license number or other state identification number or foreign country equivalent, passport number, financial account number, or credit or debit card number. You are also solely responsible for making sure that your comment does not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, do not include any “[t]rade secret or any commercial or financial information which is . . . privileged or confidential,” as discussed in section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2). In particular, do not include competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.
If you want the Commission to give your comment confidential treatment, you must file it in paper form, with a request for confidential treatment, and you must follow the procedure explained in FTC Rule 4.9(c), 16 CFR 4.9(c). Your comment will be kept confidential only if the FTC General Counsel grants your request in accordance with the law and the public interest. Postal mail addressed to the Commission is subject to delay due to heightened security screening. As a result, the Commission encourages you to submit your comments online. To make sure that the Commission considers your online comment, you must file it at
If you file your comment on paper, write “Regulation O, PRA Comment, FTC File No. P134812” on your comment and on the envelope, and mail it to the following address: Federal Trade Commission, Office of the Secretary, 600 Pennsylvania Avenue NW., Suite CC-5610, (Annex J), Washington, DC 20580, or deliver your comment to the following address: Federal Trade Commission, Office of the Secretary, Constitution Center, 400 7th Street SW., 5th Floor, Suite 5610,
The FTC Act and other laws that the Commission administers permit the collection of public comments to consider and use in this proceeding as appropriate. The Commission will consider all timely and responsive public comments that it receives on or before January 17, 2017. You can find more information, including routine uses permitted by the Privacy Act, in the Commission's privacy policy, at
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Notice with comment period.
The Centers for Disease Control and Prevention (CDC), as part of its continuing efforts to reduce public burden and maximize the utility of government information, 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. This notice invites comment on Zika Virus Associated Neurologic Illness Case Control Study. This collection intends to identify potential risk factors for the development of severe neurologic illnesses using a case-control investigation.
Written comments must be received on or before January 17, 2017.
You may submit comments, identified by Docket No. CDC-2016-0107 by any of the following methods:
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To request more information on the proposed project or to obtain a copy of the information collection plan and instruments, contact the Information Collection Review Office, Centers for Disease Control and Prevention, 1600 Clifton Road NE., MS-D74, Atlanta, Georgia 30329; phone: 404-639-7570; Email:
Under the Paperwork Reduction Act of 1995 (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. In addition, the PRA also requires Federal agencies to provide a 60-day notice in the
Comments are invited on: (a) Whether the proposed collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the proposed collection of information; (c) ways to enhance the quality, utility, and clarity of the information to be collected; (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; and (e) estimates of capital or start-up costs and costs of operation, maintenance, and purchase of services to provide information. Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; to develop, acquire, install and utilize technology and systems for the purpose of collecting, validating and verifying information, processing and maintaining information, and disclosing and providing information; to train personnel and to be able to respond to a collection of information, to search data sources, to complete and review the collection of information; and to transmit or otherwise disclose the information.
Zika Virus Associated Neurologic Illness Case Control Study—New—National Center for Emerging and Zoonotic Infectious Diseases (NCEZID), Centers for Disease Control and Prevention (CDC).
There is an urgent public health need to understand the potential association between neurological illness and Zika Virus (ZIKV) infection. Currently, increased numbers of neurologic illness cases have been reported in ZIKV-affected contexts, but it is not known if this is due to ZIKV, another etiologic agent, or some combination/interaction thereof. The Puerto Rico Department of Health (PRDH) is establishing neurologic illness surveillance and defining baseline incidence toward investigating the association between neurologic illness and ZIKV infection in Puerto Rico. More broadly, the results of this investigation would be relevant to other ZIKV-affected contexts, serving toward enabling clinical and/or public health action to manage and prevent additional cases.
A case-control investigation will be conducted to identify potential risk factors for the development of neurological illness. As part of the investigation, blood specimens will be collected from cases and matched controls to evaluate for antibodies against several pathogens known to cause neurological illness (
This information collection request is a continuation on the work begun under the following Emergency Clearance: OMB 0920-1106 (Expiration date 9/30/16). Specifically, beginning in March 2016, CDC collaborated with the PRDH on the collection of very similar data for a Guillain-Barre syndrome case-control
Under this request, case and control interviews similar to those conducted under the previously approved information collection will be conducted using the questionnaire developed by the investigation team. All cases and controls will be asked questions about activities, antecedent signs and symptoms of illness, and exposures in the two months prior to onset of neurologic illness for cases and the same time period for their matched controls. A calendar will be used to orient cases and controls to the time period of interest.
As in the previously approved information collection activities, sera, urine, and saliva will be collected from cases and controls at the time of interview using standard techniques. The sera will be tested for antibodies against suspected infectious pathogens, such as ZIKV, dengue virus, chikungunya virus, influenza virus, human immunodeficiency virus, and Leptospira species bacteria. Urine specimens will be tested by rRT-PCR to identify ZIKV, dengue virus, or chikungunya virus.
If any residual specimens are available from cases, those will also be obtained and undergo testing for infectious pathogens. It is not expected that matched controls will have any previously collected clinical specimens; however, in cases where controls had specimens collected while seeking medical care for an acute illness experienced within two months of GBS symptom onset of the matching case, these specimens will also be collected and tested for evidence of infection with the aforementioned pathogens.
Residual samples will be stored after infectious testing is complete at the U.S. CDC with an identification number for possible additional testing for GBS-associated biological markers or other infectious pathogens as clinically indicated. If a participant does not provide consent to store the specimens, all specimens for that participant will be destroyed once testing for infectious disease pathogens has been completed. As with cases, written consent will also be obtained to review controls' medical records, where applicable and available, using a standardized chart abstraction form. Diagnostic test results will be securely transmitted from CDC to PRDH, which will then transmit diagnostic test results to participants by telephone or mail, as they prefer.
Data analysis will focus on potential demographic, environmental, and/or medical risk factors for developing neurologic illness, as well as laboratory evidence for infection with the aforementioned pathogens.
The total number of estimated annualized burden hours for this project is 90. There are no other costs to respondents other than their time.
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Notice with comment period.
The Centers for Disease Control and Prevention (CDC), as part of its continuing efforts to reduce public burden and maximize the utility of government information, 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. This notice invites comment on a proposed information collection project entitled “ZEN Colombia Study: Zika in Pregnant Women and Children in Colombia.” This collection intends to identify risk factors for Zika virus (ZIKV) infection in pregnant women and their infants, assess the risk for adverse maternal, fetal, and infant outcomes associated with ZIKV infection and, assess modifiers of the risk for adverse outcomes among pregnant women and their infants following ZIKV infection.
Written comments must be received on or before January 17, 2017.
You may submit comments, identified by Docket No. CDC-2016-0106 by any of the following methods:
•
•
To request more information on the
Under the Paperwork Reduction Act of 1995 (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. In addition, the PRA also requires Federal agencies to provide a 60-day notice in the
Zika virus (ZIKV) infection is a mosquito-borne flavivirus transmitted by
Although the clinical presentation of ZIKV infection is typically mild, ZIKV infection in pregnancy can cause microcephaly and related brain abnormalities when fetuses are exposed
As the spectrum of adverse health outcomes related to ZIKV infection continues to grow, large gaps remain in our understanding of ZIKV infection in pregnancy. These include the full spectrum of adverse health outcomes in pregnant women, fetuses, and infants associated with ZIKV infection; the relative contributions of sexual transmission and mosquito-borne transmission to occurrence of infections in pregnancy; variability in the risk of adverse fetal outcomes by gestational week of maternal infection or symptoms of infection. There is an urgency to fill these large gaps in our understanding given the rapidity of the epidemic's spread and the severe health outcomes associated with ZIKV to date.
Colombia's Instituto Nacional de Salud (INS) began surveillance for ZIKV in 2015, reporting the first autochthonous transmission in October 2015 in the north of the country. As of August 2016, Colombia has reported over 102,000 suspected ZIKV cases, over 18,000 of them among pregnant women. With a causal link established between ZIKV infection in pregnancy and microcephaly, there is an urgent need to understand how ZIKV transmission can be prevented; the full spectrum of adverse maternal, fetal, and infant health outcomes associated with ZIKV infection; and risk factors for occurrence of these outcomes. To answer these questions, INS and the U.S. Centers for Disease Control and Prevention (CDC) will follow 5,000 women enrolled in the first trimester of pregnancy, their male partners, and their infants, in two to four cities in Colombia where ZIKV transmission is currently ongoing.
The primary objectives of the study are to (1) Identify risk factors for ZIKV infection in pregnant women and their infants. These include behaviors such as use of mosquito-bite prevention measures or condoms, and factors associated with maternal-to-child transmission; (2) Assess the risk for adverse maternal, fetal, and infant outcomes associated with ZIKV infection and; (3) Assess modifiers of the risk for adverse outcomes among pregnant women and their infants following ZIKV infection. This includes investigating associations with gestational age at infection, presence of ZIKV symptoms, extended viremia, mode of transmission, prior infections or immunizations, and co-infections.
Pregnant women will be recruited in the first trimester of pregnancy at participating clinics in Colombia's private and public health care systems and followed through their pregnancy, delivery, and immediate postpartum period. Study visits will coincide with routine prenatal care clinic visits (monthly), and at these visits, mothers will be monitored for incident ZIKV infection by collection of blood. In addition, women will be asked to complete a questionnaire about behavioral, sexual, environmental, or other risk factors for ZIKV or adverse pregnancy outcomes and a ZIKV symptoms questionnaire. In between clinic visits (approximately two weeks after the clinic visit), a home visit will be conducted where a urine sample from the pregnant woman will be collected. Mothers will complete a ZIKV symptom questionnaire at the time of the home visit. Fetal ultrasound evaluation will occur once per trimester. If ZIKV is detected during pregnancy, monthly fetal ultrasounds will be conducted and women will provide
Male partners will be recruited via their pregnant partners around the time of their pregnant partners' enrollment into the study. At enrollment, men will complete a baseline questionnaire and ZIKV symptom questionnaire and provide a blood sample. Urine samples in men will be collected at home every 2 weeks through the second trimester of pregnancy to monitor for incident ZIKV infection. Men will complete a ZIKV symptom questionnaire at the time of each specimen collection. If a man becomes symptomatic, he will be asked to provide a blood sample at the clinic for ZIKV testing. If ZIKV is detected, semen collection at home will be scheduled every two weeks until there are 2 consecutive negative tests, or the end of pregnancy. In addition, if a man's at-home urine sample is positive, he will again be asked to participate in semen collection at home every two weeks until there are 2 consecutive negative tests, or the end of pregnancy.
All newborns of mothers participating in the study will be followed from birth to 6 months of age. A blood sample will be collected at delivery or no later than 3 days after delivery. Urine samples and information on infant's symptoms will be collected every 2 weeks at home visits to monitor for ZIKV infection in infancy. Additionally, any infant health conditions or results from medical testing during this 6-month period conducted as part of routine clinical care will be abstracted from medical records.
INS and CDC will use the study results to guide their recommendations to prevent ZIKV infection; to improve counseling of patients about risks to themselves, their pregnancies, their partners, and their infants; and to help agencies prepare to provide services to affected children and families.
Centers for Disease Control and Prevention (CDC), Department of Health and Human Services (HHS).
Notice with comment period.
The Centers for Disease Control and Prevention (CDC), as part of its continuing efforts to reduce public burden and maximize the utility of government information, 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. This notice invites comment on “Data Calls for the Laboratory Response Network” collected from its members concerning their capacity to respond to public health threat emergencies.
Written comments must be received on or before January 17, 2017.
You may submit comments, identified by Docket No. CDC-2017-0109 by any of the following methods:
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To request more information on the proposed project or to obtain a copy of the information collection plan and instruments, contact the Information Collection Review Office, Centers for Disease Control and Prevention, 1600 Clifton Road NE., MS-D74, Atlanta, Georgia 30329; phone: 404-639-7570; Email:
Under the Paperwork Reduction Act of 1995 (PRA) (44 U.S.C. 3501-3520), Federal agencies must obtain approval from the Office of
Data Calls for the Laboratory Response Network, (OMB Control No. 0920-0881 exp. 4/30/2017)—Extension—National Center for Emerging and Zoonotic Infectious Diseases (NCEZID), Centers for Disease Control and Prevention (CDC).
The Laboratory Response Network (LRN) was established by the Department of Health and Human Services, Centers for Disease Control and Prevention (CDC) in accordance with Presidential Decision Directive 39, which outlined national anti-terrorism policies and assigned specific missions to Federal departments and agencies. The LRN's mission is to maintain an integrated national and international network of laboratories that can respond to acts of biological, chemical, or radiological terrorism and other public health emergencies. Federal, state and local public health laboratories voluntarily join the LRN.
The LRN Program Office maintains a database of information for each member laboratory that includes contact information as well as staff and equipment inventories. However, semiannually or during emergency response the LRN Program Office may conduct a Special Data Call to obtain additional information from LRN Member Laboratories in regards to biological or chemical terrorism preparedness.
LRN has used the currently approved generic information collection plan twice during the last three years. Once in 2014, LRN surveyed its members to ascertain which, if any, labs would be willing to test clinical specimens for Ebola virus.
The information gathered led to an emergency deployment of a new Ebola assay for LRN members. It is critical for the LRN to know which labs have equipment to support an agent specific assay during an emergency. In 2015, LRN surveyed members via broadcast email asking how many facilities had a specific version of an instrument. The information was used to help the LRN program office determine if new procedures should be written and made available to members to support the instrument in question.
Special Data calls may be conducted via queries that are distributed by broadcast emails or by survey tools (
This is a request for a three year extension to this generic clearance.
The only cost to respondents is their time to respond to the data call. Authorizing legislation comes from Section 301 of the Public Health Service Act.
Centers for Medicare & Medicaid Services (CMS), HHS.
Correction of notice.
This document corrects the information provided for [Document Identifier: CMS-10169] titled “Durable Medical Equipment, Prosthetics, Orthotics, and Supplies (DMEPOS) Competitive Bidding Program; Change of Ownership Forms.”
William N. Parham, III, (410) 786-4669.
In the October 14, 2016, issue of the
In the October 14, 2016, notice, the information provided in the first column under paragraph 2, on page 71101, inadvertently published information in the “Use” section that pertained to an older iteration of the information collection request. This notice corrects the language found in the “Use” section under the 2nd paragraph on page 71101 of the October 14th notice. All of the other information contained in the October 14, 2016, notice is correct. The related public comment period remains in effect and ends December 13, 2016.
In FR Doc. 2016-24910 of October 14, 2016 (81 FR 71100), on page 71101, the language beginning with the word “
Based on the passage of MACRA, we put forth proposed additions to § 414.412, “Submission of bids under a competitive bidding program,” to add a new paragraph (h) that would allow CMS to implement section 1847(a)(1)(G) of the Act, as amended by section 522(a) of MACRA, to state that an entity may not submit a bid for a CBA unless, as of the deadline for bid submission, the entity has obtained a bid surety bond for the CBA.
We are now seeking approval to update our burden estimates to all Forms to account for the consolidation of all rounds in Round 2019. For Round 2019 and the proposed rule, CMS will publish a slightly modified version of Form A so that suppliers will be better able to identify and understand the new requirement related to surety bonds. We have made no changes to Forms B, C, D, Change of Ownership (CHOW) Contract Supplier Notification and Purchaser Forms, and Subcontracting Disclosure Form. However, the burden has been adjusted to account for the increase in the number of respondents due to the consolidation of all CBAs into Round 2019 under this ICR. We intend to continue use of these Forms on an ongoing basis.
Centers for Medicare & Medicaid Services, HHS.
Notice.
The Centers for Medicare & Medicaid Services (CMS) is announcing an opportunity for the public to comment on CMS' intention to collect information from the public. Under the Paperwork Reduction Act of 1995 (the PRA), federal agencies are required to publish notice in the
Comments must be received by January 17, 2017.
When commenting, please reference the document identifier or OMB control number. To be assured consideration, comments and recommendations must be submitted in any one of the following ways:
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To obtain copies of a supporting statement and any related forms for the proposed collection(s) summarized in this notice, you may make your request using one of following:
1. Access CMS' Web site address at
2. Email your request, including your address, phone number, OMB number, and CMS document identifier, to
3. Call the Reports Clearance Office at (410) 786-1326.
Reports Clearance Office at (410) 786-1326.
This notice sets out a summary of the use and burden associated with the following information collections. More detailed information can be found in each collection's supporting statement and associated materials (see
Under the PRA (44 U.S.C. 3501-3520), federal agencies must obtain approval from the Office of Management and Budget (OMB) for each collection of information they conduct or sponsor. The term “collection of information” is defined in 44 U.S.C. 3502(3) and 5 CFR 1320.3(c) and includes agency requests
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National Institutes of Health, HHS.
Notice.
The invention listed below is owned by an agency of the U.S. Government and is available for licensing in the U.S. to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing.
Licensing information may be obtained by communicating with the indicated licensing contact at the Technology Transfer and Intellectual Property Office, National Institute of Allergy and Infectious Diseases, 5601 Fishers Lane, Rockville, MD 20852; tel. 301-496-2644. A signed Confidential Disclosure Agreement will be required to receive copies of unpublished scientific data.
Technology description follows.
This technology is available for licensing for commercial development in accordance with 35 U.S.C. 209 and 37 CFR part 404, as well as for further development and evaluation under a research collaboration.
• Vaccines
• Broad/universal protection against influenza viruses
• does not require reformulating vaccine each year as is currently necessary with vaccines available on the market
• can potentially provide protection against novel influenza viruses that may arise in the future, including potentially pandemic influenza viruses
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.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App), notice is hereby given of the following meetings.
The meetings will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
National Institutes of Health. HHS.
Notice.
The invention listed below is owned by an agency of the U.S. Government and is available for licensing and/or co-development in the U.S. to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing and/or co-development.
Invention Development and Marketing Unit, Technology Transfer Center, National Cancer Institute, 9609 Medical Center Drive, Mail Stop 9702, Rockville, MD 20850-9702.
Information on licensing and co-development research collaborations, and copies of the U.S. patent applications listed below may be obtained by contacting: Attn. Invention Development and Marketing Unit, Technology Transfer Center, National Cancer Institute, 9609 Medical Center Drive, Mail Stop 9702, Rockville, MD, 20850-9702, Tel. 240-276-5515 or email
Technology description follows.
Scientists in NCI's Laboratory of Human Carcinogenesis have identified a 14-gene signature that is predictive of response to TACE. The “TACE Navigator Gene Signature Assay,” based on a Nanostring Technologies platform, is useful in identifying those HCC patients, prior to treatment, who will respond to and have the greatest survival benefit following TACE. The signature can also identify patients who need additional/alternative therapeutic modalities.
This invention is owned by an agency of the U.S. Government and is available for licensing and/or co-development in the U.S., in accordance with 35 U.S.C. 209 and 37 CFR part 404, to achieve expeditious commercialization of results of federally-funded research and development. Foreign patent applications are filed on selected inventions to extend market coverage for companies and may also be available for licensing and/or co-development.
Pursuant to section 10(d) of the Federal Advisory Committee Act, as amended (5 U.S.C. App.), notice is hereby given of the following meeting.
The meeting will be closed to the public in accordance with the provisions set forth in sections 552b(c)(4) and 552b(c)(6), Title 5 U.S.C., as amended. The grant applications and the discussions could disclose confidential trade secrets or commercial property such as patentable material, and personal information concerning individuals associated with the grant applications, the disclosure of which would constitute a clearly unwarranted invasion of personal privacy.
Fish and Wildlife Service, Interior.
Notice of availability; notice of permit application; request for comments.
We, the U.S. Fish and Wildlife Service (Service), received an incidental take permit application from Na Pua Makani Power Partners, LLC, pursuant to the Endangered Species Act of 1973, as amended (ESA). The requested permit would authorize the take of one threatened and six endangered species caused by covered activities associated with a wind energy generation project on the island of Oahu, Hawaii. The permit application included the proposed Na Pua Makani Wind Energy Project Habitat Conservation Plan (HCP), which described the activities that may result in the incidental taking of listed species, and the measures the applicant will take to minimize, mitigate, and monitor for adverse impacts to the covered species. The applicant modified the proposed action in the HCP in response to public comments and the modified HCP is available for public review pursuant to this notice. The Service also announces the availability of a Supplemental Final Environmental Impact Statement (SEIS) addressing the modified proposed action in accordance with the requirements of the National Environmental Policy Act of 1969 (NEPA). If issued, the ITP would authorize incidental take of the covered species that may occur as a result of the construction and operation of the Na Pua Makani Wind Energy Project (Project) over a 21-year period. We are making the permit application package, including the modified HCP and SEIS, available for public review and comment.
To ensure consideration, written comments must be received from interested parties no later than December 19, 2016.
The Service's decision on issuance of an ITP will occur no sooner than 30 days after the publication of the U.S. Environmental Protection Agency's notice of the SEIS in the
To request further information or submit written comments, please use one of the following methods, and note that your information request or comments are in reference to the Na Pua Makani Wind Energy Project HCP.
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Ms. Jodi Charrier or Mr. Aaron Nadig, U.S. Fish and Wildlife Service (see
The Na Pua Makani Power Partners, LLC (applicant) a subsidiary of Champlin Hawaii Wind Holdings, LLC, is requesting an ITP for a 21-year permit term to authorize take of the threatened Newell's shearwater (
The applicant proposes to construct and operate the wind energy generation project on approximately 707 acres of public and private lands near the town of Kahuku on the island of Oahu, Hawaii. The proposed project, as modified, would have a generating capacity of up to approximately 25 megawatts (MW) and would supply wind-generated electricity to the Hawaii Electric Company. The project would consist of up to nine wind turbine generators (WTG), one permanent un-guyed lattice-frame meteorological tower, up to 4.9 miles of new and existing access roads, an operations and maintenance facility, electrical collection and interconnection infrastructure, an electrical substation, and a temporary laydown area. The applicant is considering a variety of WTG models, each ranging from 427 feet to 656 feet in height, and having up to 3.3 MW of generating capacity. The applicant would select the most appropriate WTG models prior to construction. The SEIS analyzes whether there would be any different impacts to the covered species and other environmental resources from the modified proposed action.
To offset anticipated take associated with construction and operation of the project over a period of 21 years, the applicant is proposing mitigation measures on Oahu that include: (1) Funding research to support effective management of Newell's shearwaters; (2) fencing and predator control to conserve the Hawaiian goose at James Campbell National Wildlife Refuge; (3) a combination of bat research and native forest restoration and management to increase Hawaiian hoary bat habitat; (4) acoustic surveys to document occupancy of the affected area by the Hawaiian hoary bat; and (5) fencing and public outreach at Hamakua Marsh to benefit conservation of the Hawaiian stilt, Hawaiian coot, Hawaiian moorhen, and Hawaiian duck.
The development of the HCP and the proposed issuance of an ITP under this plan are Federal actions that trigger the need for compliance with NEPA (42 U.S.C. 4321
Under the no-action alternative, the proposed project would not be constructed, the proposed HCP would not be implemented, and no ITP would be issued. The proposed action alternative is construction and operation of the project, consisting of between 8 and 10 wind turbines, implementation of the HCP, and issuance of the ITP. In response to public comments on the draft EIS related to visual impacts and consideration of fewer turbines with larger generating capacities, a modified proposed action option with a reduced maximum number of turbines consisting of only nine turbines with larger generating capacities and taller dimensions was added to the final EIS. The modified proposed action option also includes implementation of the HCP and issuance of the ITP. The larger wind energy generation project alternative would include the construction and operation of a larger generation facility of up to 42 MW. This alternative would consist of up to 12 WTGs, each with a generating capacity of up to 3.3 MW, implementation of an HCP, and issuance of the ITP.
In accordance with NEPA (40 CFR 1502.14(e)), the Service has identified the proposed action (alternative 2) including the modified proposed action option (alternative 2a) as the preferred alternative. Under NEPA, the “agency's preferred alternative” is a preliminary indication of the Federal responsible official's preference of action, which is chosen from among the alternatives analyzed in an EIS. It is the alternative which the agency believes would fulfill its statutory mission and responsibilities, giving consideration to economic, environmental, technical and other factors (43 CFR 46.420(d)). The preferred alternative is not a final agency decision; rather, it is an indication of the agency's preference. The final agency decision is presented in the Record of Decision.
Based on input from the public, the Service has concluded that providing an additional opportunity for public review of the modified HCP and SEIS would further the purposes of the ESA and NEPA. The SEIS provides the public with an opportunity to review and comment on the effects of the Modified Proposed Action Alternative (the refined project design with fewer but larger wind turbines). Clarification on the following topics is also included in the SEIS:
• The effect of the modified proposed action option on estimates of incidental take of threatened and endangered species (see SEIS Section 4.11—Threatened and Endangered Species);
• Traffic and associated impacts along the Kahuku Agricultural Park Interior Roadway, accessing the DLNR portion of the wind farm site (see SEIS Section 4.17—Traffic); and
• Best available science regarding wind turbines and public health (see SEIS Section 4.18—Public Health and Safety).
The Environmental Protection Agency (EPA) is charged under section 309 of the Clean Air Act to review all Federal agencies' EISs and to comment on the adequacy and the acceptability of the environmental impacts of proposed actions described in the EISs.
EPA also serves as the repository (EIS database) for EISs prepared by Federal agencies and provides notice of their availability in the
For more information, see
The draft EIS began as a joint document between the Service and The State of Hawaii's Department of Land and Natural Resources (DLNR). Due to differences in procedural requirements, the environmental process diverged after the draft EIS was published and the project incorporated the modified proposed action alternative.
In May of 2013, the applicant began holding community meetings, small focus group meetings with stakeholders, and individual meetings with community leaders and legislators to discuss the proposed project and engage the public in the project's planning and design.
On November 5, 2013, the Service published a notice of intent (NOI) to prepare a draft EIS in the
Utilizing public scoping comments, we prepared a draft EIS to analyze the effects of project alternatives on the human environment. The Service published a notice of availability (NOA) of the draft EIS in the
The State of Hawaii's environmental impact statement preparation notice (EISPN) was distributed to interested parties for review between December 23, 2013, and January 23, 2014, and again between November 8 and December 8, 2014 (republished to reflect the addition of a second access into the project site). During the initial public scoping period for the EISPN, three public scoping meetings were held at Kahuku Community Center: On November 13, 2013, January 10, 2014, and November 19, 2014. In addition to the public meetings, a media advisory was sent out prior to each meeting. DLNR hosted a public hearing at the Kahuku Community Center on June 4, 2015. The draft EIS was published in the State of Hawaii Office of Environmental Quality Control's
We will evaluate the permit application, associated documents, and public comments in reaching a final decision on whether the application meets the requirements of section 10(a) of the ESA (16 U.S.C. 1531
We provide this notice in accordance with the requirements of section 10(c) of the ESA and its implementing regulations (50 CFR 17.22 and 17.32), and NEPA and its implementing regulations (40 CFR 1506.6).
Fish and Wildlife Service, Interior.
Notice; request for comments.
We (U.S. Fish and Wildlife Service) will ask the Office of Management and Budget (OMB) to approve the information collection (IC) described below. As required by the Paperwork Reduction Act of 1995 and as part of our continuing efforts to reduce paperwork and respondent burden, we invite the general public and other Federal agencies to take this opportunity to comment on this IC. This IC is scheduled to expire on January 31, 2017. We 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.
To ensure that we are able to consider your comments on this IC, we must receive them by January 17, 2017.
Send your comments on the IC to the Information Collection Clearance Officer, U.S. Fish and Wildlife Service, MS BPHC, 5275 Leesburg Pike, Falls Church, VA 22041-3803 (mail); or
To request additional information about this IC, contact Tina Campbell at
The Migratory Bird Treaty Act (16 U.S.C. 703
The regulations at 50 CFR 20.134 outline the application and approval processes for new types of nontoxic shot. When considering approval of a candidate material as nontoxic, we must ensure that it is not hazardous in the
We invite comments concerning this information collection on:
• Whether or not the collection of information is necessary, including whether or not the information will have practical utility;
• The accuracy of our estimate of the burden for this collection of information;
• Ways to enhance the quality, utility, and clarity of the information to be collected; and
• Ways to minimize the burden of the collection of information on respondents.
Comments that you submit in response to this notice are a matter of public record. We will include or summarize each comment in our request to OMB to approve this IC. 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.
Bureau of Land Management, Interior.
Notice of public meeting.
In accordance with the Federal Land Policy and Management Act (FLPMA) and the Federal Advisory Committee Act of 1972 (FACA), the U.S. Department of the Interior, Bureau of Land Management (BLM) Eastern Montana Resource Advisory Council (RAC) will meet as indicated below.
The Eastern Montana Resource Advisory Council meeting will be held on December 15, 2016, in Miles City, Montana. When determined, the meeting location and times will be announced in a news release.
Mark Jacobsen, Public Affairs Specialist, BLM Eastern Montana/Dakotas District, 111 Garryowen Road, Miles City, Montana 59301; (406) 233-2831;
The 15-member council advises the Secretary of the Interior through the BLM on a variety of planning and management issues associated with public land management in eastern Montana. At this meeting, topics will include: An Eastern Montana/Dakotas District report, Billing Field Office and Miles City Field Office manager reports, a travel management, recreation planning, individual RAC member reports and other issues the council may raise. All meetings are open to the public and the public may present written comments to the council. Each formal RAC meeting will have time allocated for hearing public comments. Depending on the number of persons wishing to comment and time available, the time for individual oral comments may be limited. Individuals who plan to attend and need special assistance, such as sign language interpretation, tour transportation or other reasonable accommodations should contact the BLM as provided above.
43 CFR 1784.4-2.
U.S. International Trade Commission.
Notice.
Notice is hereby given that the U.S. International Trade Commission has determined not to review a final initial determination (“ID”) issued by the presiding administrative law judge (“ALJ”), finding a violation of section 337 of the Tariff Act of 1930, as amended. The Commission has also set a schedule for briefing on remedy, the public interest, and bonding.
Robert Needham, Office of the General Counsel, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 708-5468. Copies of non-confidential documents filed in connection with this investigation are or will be available for inspection during official business hours (8:45 a.m. to 5:15 p.m.) in the Office of the Secretary, U.S. International Trade Commission, 500 E Street SW., Washington, DC 20436, telephone (202) 205-2000. General
The Commission instituted this investigation on September 1, 2015, based on a complaint filed by SawStop, LLC, and SD3, LLC (together, “SawStop”). 80 FR 52791-92 (Sept. 1, 2015). The amended complaint alleged violations of section 337 of the Tariff Act of 1930, as amended, 19 U.S.C. 1337, in the importation into the United States, the sale for importation, and the sale within the United States after importation of certain table saws incorporating active injury mitigation technology and components thereof by reason of infringement of certain claims of United States Patent Nos. 7,225,712 (“the '712 patent”); 7,600,455 (“the '455 patent”); 7,610,836 (“the '836 patent”); 7,895,927 (“the '927 patent”); 8,011,279 (“the '279 patent”); and 8,191,450 (“the '450 patent”). The notice of investigation named as respondents Robert Bosch Tool Corp. of Mount Prospect, Illinois, and Robert Bosch GmbH of Baden-Wuerttemberg, Germany (together, “Bosch”).
The Commission terminated the investigation with respect to the '836 and '450 patents based on SawStop's withdrawal of allegations concerning those patents. Order No. 8 (Mar. 10, 2016),
On January 27, 2016, SawStop moved for a summary determination that it satisfied the economic prong of the domestic industry requirement. On February 8, 2016, Bosch indicated that it did not oppose the motion. On March 22, 2016, the ALJ granted the unopposed motion and determined that SawStop satisfied the economic prong of the domestic industry requirement. Order No. 10 (Mar. 22, 2016),
On September 9, 2016, the ALJ issued his final initial determination finding a violation of section 337 with respect to the '927 and '279 patents, and no violation of section 337 with respect to the '712 and '455 patents. Specifically, he found that Bosch did not directly or contributorily infringe the '712 and '455 patents, but found that Bosch's REAXX table saw directly infringed the '927 and '279 patents and that Bosch's activation cartridges contributorily infringed the '927 and '279 patents. He also found that Bosch had failed to show that any of the patent claims were invalid, and that SawStop satisfied the domestic industry requirement with respect to all four patents. Based on these findings, the ALJ recommended that a limited exclusion order issue against Bosch, that a cease and desist order issue against Robert Bosch Tool Corp., and that the bond during the period of Presidential review be set at zero percent. He also recommended that the scope of the exclusion order and cease and desist order specifically cover the contributorily infringing activation cartridges.
On September 26, 2016, SawStop and Bosch each petitioned for review of the ID. On October 4, 2016, the parties opposed each other's petitions. Having examined the record of this investigation, including the ALJ's final ID, the petitions for review, and the responses thereto, the Commission has determined not to review the final ID.
In connection with the final disposition of this investigation, the Commission may (1) issue an order that could result in the exclusion of the subject articles from entry into the United States, and/or (2) issue a cease and desist order that could result in the respondent being required to cease and desist from engaging in unfair acts in the importation and sale of such articles. Accordingly, the Commission is interested in receiving written submissions that address the form of remedy, if any, that should be ordered. If a party seeks exclusion of an article from entry into the United States for purposes other than entry for consumption, the party should so indicate and provide information establishing that activities involving other types of entry either are adversely affecting it or likely to do so. For background,
If the Commission contemplates some form of remedy, it must consider the effects of that remedy upon the public interest. The factors the Commission will consider include the effect that an exclusion order and/or a cease and desist order would have on (1) the public health and welfare, (2) competitive conditions in the U.S. economy, (3) U.S. production of articles that are like or directly competitive with those that are subject to investigation, and (4) U.S. consumers. The Commission is therefore interested in receiving written submissions that address the aforementioned public interest factors in the context of this investigation. The Commission is particularly interested in briefing on the following issues:
1. The parties dispute whether SawStop would be able to satisfy the market demand for table saws with active injury mitigation technology if the Commission issues a remedy against Bosch. Please discuss whether SawStop would be able to satisfy that demand quantitatively and qualitatively. How could remedial orders be tailored to address any concerns about the ability of SawStop (or other suppliers) to satisfy demand?
2. Bosch requests that any Commission remedial order have a service and repair provision allowing Bosch to import and sell replacement parts, including its activation cartridges. Please discuss whether such a provision is appropriate.
If the Commission orders some form of remedy, the U.S. Trade Representative, as delegated by the President, has 60 days to approve or disapprove the Commission's action.
Persons filing written submissions must file the original document electronically on or before the deadlines stated above and submit 8 true paper copies to the Office of the Secretary by noon the next day pursuant to section 210.4(f) of the Commission's Rules of Practice and Procedure (19 CFR 210.4(f)). Submissions should refer to the investigation number (“Inv. No. 337-TA-965”) in a prominent place on the cover page and/or the first page. (
Any person desiring to submit a document to the Commission in confidence must request confidential treatment. All such requests should be directed to the Secretary to the Commission and must include a full statement of the reasons why the Commission should grant such treatment.
The authority for the Commission's determination is contained in section 337 of the Tariff Act of 1930, as amended (19 U.S.C. 1337), and in part 210 of the Commission's Rules of Practice and Procedure (19 CFR part 210).
By order of the Commission.
Bureau of Alcohol, Tobacco, Firearms and Explosives, Department of Justice.
60-Day notice.
The Department of Justice (DOJ), Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), will submit the following information collection request to the Office of Management and Budget (OMB) for review and approval in accordance with the Paperwork Reduction Act of 1995.
Comments are encouraged and will be accepted for 60 days until January 17, 2017.
If you have additional comments, particularly with respect to the estimated public burden or associated response time, have suggestions, need a copy of the proposed information collection instrument with instructions, or desire any additional information, please contact Renee Reid, Chief, Personnel Security Branch, either by mail at Bureau of Alcohol, Tobacco, Firearms and Explosives (ATF), Washington, DC 20226, or by email at
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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The United States Department of Justice, on behalf of the Environmental Protection Agency (“United States”), proposes to enter into an Administrative Settlement Order on Consent and Bona Fide Prospective Purchaser Agreement (“BFPP Agreement”) with Star Forge, LLC (“Purchaser”) regarding real property located at 8531 East Marginal Way South in Seattle, Washington (the “Property”). The Property is located in and part of the “Lower Duwamish Waterway Superfund Site” (the “LDW Site”). Under the BFPP Agreement, Purchaser agrees to perform a removal action in accordance with the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), 42 U.S.C. 9601-9675, at the Property. Additionally, Purchaser agrees to pay $500,000 to an escrow account to be established by Purchaser and dedicated to the ongoing cleanup of the LDW Site.
The proposed BFPP Agreement helps to ensure the timely performance of all response actions EPA has selected for the Property by specifying that the Purchaser cooperate with the United States to satisfy remaining obligations under an existing Administrative Order between EPA, the current owner of the Property (Jorgensen Forge Corporation, in bankruptcy), and an adjoining landowner. The BFPP Agreement also requires Purchaser to institute and abide by appropriate institutional controls at the Property and requires Purchaser to exercise due care in its future operations to ensure that those operations will not exacerbate or contribute to existing contamination.
In exchange, EPA provides the Buyer with a covenant not to sue for response costs, and potential response costs, incurred in connection with existing contamination at the Facility. The BFPP expressly reserves EPA's rights against the Purchaser for any activities that result in new releases of hazardous substances or aggravation of existing contamination at or from the Property. The proposed settlement, including the $500,000 payment, represents fair consideration for the covenant provided to the Purchaser, given the Purchaser's limited potential liability for existing contamination.
The publication of this notice opens a period for public comment on the proposed Administrative Settlement and Bona Fide Prospective Purchaser Agreement. Comments should be addressed to the Assistant Attorney General, Environment and Natural Resources Division, and should refer to
During the public comment period, the proposed Settlement Agreement and Bona Fide Prospective Purchaser Agreement may be examined and downloaded at this Justice Department Web site:
Please enclose a check or money order for $ 5.25 (25 cents per page reproduction cost, excluding attachments) payable to the United States Treasury.
On November 10, 2016, the Department of Justice lodged a proposed Consent Decree with the United States District Court for the Northern District of Illinois in the lawsuit entitled
Under the proposed Consent Decree lodged with the Northern District of Illinois (“Lemont Refinery Consent Decree”), CITGO will install low nitrogen oxide burners on three heaters at one of its refineries in Lemont, Illinois (“Lemont Refinery”); comply with a stringent limit for particulate matter emissions from the Lemont Refinery's fluid catalytic cracking unit; develop and implement operation and maintenance plans to improve operations and prevent violations at the Lemont Refinery's sulfur recovery plant; implement a flare minimization and flare efficiency program; implement an enhanced leak detection and repair program; and use carbon canisters to control benzene emissions from purged process fluids and samples. CITGO also will implement a $650,000 fence line monitoring supplemental environmental project and a $350,000 “green lighting” supplemental environmental project at the local school district. As a mitigation project, CITGO will control a benzene waste stream that it is not otherwise required to control at a cost of approximately $1.14 million. CITGO will pay a civil penalty of $1,955,000.
Under the proposed First Amendment to Consent Decree lodged with the Southern District of Texas (“First Amendment”), a consent decree that the Southern District of Texas entered in 2005 (“2005 Consent Decree”) that covered six refineries that CITGO then owned will be amended to terminate all provisions therein related to the Lemont Refinery. CITGO demonstrated to EPA that it had complied with the vast majority of the 2005 Consent Decree provisions related to the Lemont Refinery and CITGO agreed to have the remaining few, outstanding provisions transferred to the new, stand-alone Lemont Refinery Consent Decree filed in the Northern District of Illinois. Under the First Amendment, CITGO will also pay a stipulated penalty of $323,500, split equally between the United States and Illinois, for alleged violations of the 2005 Consent Decree at the Lemont Refinery.
The publication of this notice opens a period for public comment on the Lemont Refinery Consent Decree and
During the public comment period, the Lemont Refinery Consent Decree and the First Amendment may be examined and downloaded at this Justice Department Web site:
For the Lemont Refinery Consent Decree, please enclose a check or money order for $68.00 (25 cents per page reproduction cost) payable to the United States Treasury. For the First Amendment to the 2005 Consent Decree, please enclose a check or money order for $2.00 (25 cents per page reproduction cost) payable to the United States Treasury. For both, one check or money order in the amount of $70.00 can be enclosed.
Employee Benefits Security Administration, U.S. Department of Labor.
Notice of Proposed Temporary Exemption.
This document contains a notice of pendency before the Department of Labor (the Department) of a proposed temporary individual exemption from certain prohibited transaction restrictions of the Employee Retirement Income Security Act of 1974, as amended (ERISA), and the Internal Revenue Code of 1986, as amended (the Code). The proposed temporary exemption, if granted, would affect the ability of certain entities with specified relationships to UBS AG (UBS) to continue to rely upon the relief provided by Prohibited Transaction Class Exemption 84-14.
This proposed temporary exemption will be effective for the period beginning on the Conviction Date, and ending on the earlier of: The date that is twelve months following the Conviction Date; or the effective date of a final agency action made by the Department in connection with Exemption Application No. D-11907, an application for long-term exemptive relief for the covered transactions described herein.
Written comments and requests for a public hearing on the proposed exemption should be submitted to the Department within five days from the date of publication of this
Comments should state the nature of the person's interest in the proposed exemption and the manner in which the person would be adversely affected by the exemption, if granted. A request for a hearing can be requested by any interested person who may be adversely affected by an exemption. A request for a hearing must state: (1) The name, address, telephone number, and email address of the person making the request; (2) the nature of the person's interest in the exemption and the manner in which the person would be adversely affected by the exemption; and (3) a statement of the issues to be addressed and a general description of the evidence to be presented at the hearing. The Department will grant a request for a hearing made in accordance with the requirements above where a hearing is necessary to fully explore material factual issues identified by the person requesting the hearing. A notice of such hearing shall be published by the Department in the
All written comments and requests for a public hearing concerning the proposed exemption should be directed to the following addresses: Office of Exemption Determinations, Employee Benefits Security Administration, Suite 400, U.S. Department of Labor, 200 Constitution Avenue NW., Washington, DC 20210, Attention: Application No. D-11863. Interested persons may also submit comments and/or hearing requests to EBSA via email to
Mr. Brian Mica of the Department, telephone (202) 693-8402. (This is not a toll-free number.)
The Department is publishing this proposed temporary exemption in order to protect ERISA-covered plans and IRAs from certain costs and/or investment losses for up to one year, that may arise to the extent entities with a corporate relationship to UBS lose their ability to rely on PTE 84-14 as of the Conviction Date, as described below. Elsewhere in the
This proposed temporary exemption would provide relief from certain of the restrictions set forth in sections 406 and 407 of ERISA. If granted, no relief from a violation of any other law would be provided by this proposed temporary exemption.
Furthermore, the Department cautions that the relief in this proposed temporary exemption would terminate immediately if, among other things, an entity within the UBS corporate structure is convicted of a crime described in Section I(g) of PTE 84-14 (other than the Convictions described below) during the effective period of the proposed temporary exemption, if granted. While such an entity could apply for a new exemption in that circumstance, the Department would not be obligated to grant the exemption. The terms of this proposed temporary exemption have been specifically designed to permit plans to terminate their relationships in an orderly and cost effective fashion in the event of an additional conviction or a determination that it is otherwise prudent for a plan to terminate its relationship with an entity covered by the proposed temporary exemption.
The proposed temporary exemption has been requested by the Applicants pursuant to section 408(a) of the Act and section 4975(c)(2) of the Code, and in accordance with the procedures set forth in 29 CFR part 2570, subpart B (76 FR 66637, 66644, October 27, 2011). Effective December 31, 1978, section 102 of the Reorganization Plan No. 4 of 1978, 5 U.S.C. App. 1 (1996), transferred the authority of the Secretary of the Treasury to issue administrative exemptions under section 4975(c)(2) of the Code to the Secretary of Labor. Accordingly, this notice of proposed exemption is being issued solely by the Department.
1. UBS
2. The operational structure of UBS and its affiliates (collectively, the UBS Group) consists of a Corporate Center function and five business divisions: Wealth Management; Wealth Management Americas; Retail & Corporate; Asset Management; and the Investment Bank.
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7. The Department notes that the rules set forth in section 406 of the Employee Retirement Income Security Act of 1974, as amended (ERISA) and section 4975(c) of the Internal Revenue Code of 1986, as amended (the Code) proscribe certain “prohibited transactions” between plans and related parties with respect to those plans, known as “parties in interest.”
8. Prohibited Transaction Exemption 84-14 (PTE 84-14)
9. However, Section I(g) of PTE 84-14 prevents an entity that may otherwise meet the definition of QPAM from utilizing the exemptive relief provided by PTE 84-14, for itself and its client plans, if that entity or an “affiliate”
10. UBS Asset Management (Americas) Inc., UBS Realty Investors LLC, UBS Hedge Fund Solutions LLC, and UBS O'Connor LLC are affiliates of UBS, AG (UBS)
11. The Applicants represent further that the UBS QPAMs provide investment management services to 36 ERISA plan and IRA clients through separately-managed accounts and pooled funds. These ERISA plan clients are all large plans and several have more than 500,000 participants and beneficiaries. Collectively, the UBS QPAMs currently manage approximately $22.1 billion of ERISA Plan and IRA assets (excluding ERISA Plan and IRA assets invested in pooled funds that are not plan asset funds). Several types of investment strategies are used by the UBS QPAMs to invest ERISA plan and IRA assets. These strategies include investments of approximately $3.3 billion in alternative investments/hedge funds, $835 million in equity investments, $8.6 billion in fixed income, $2.2 billion in multi-asset investments, $5.8 billion in derivative investments and $1.4 billion in real estate investments.
12. The DOJ determined that, prior to and after UBS signed the LIBOR NPA on December 18, 2012, certain employees of UBS engaged in fraudulent and deceptive currency trading and sales practices in conducting certain FX market transactions via telephone, email and/or electronic chat, to the detriment of UBS's customers.
13. According to the Factual Basis for Breach, the FX Misconduct included the addition of undisclosed markups to certain FX transactions. In that regard, sales staff misrepresented to customers on certain transactions that markups were not being added, when in fact they were.
14. The Factual Basis for Breach explains that for certain limit orders, UBS personnel would use a price level different from the one specified by the customers, without the customers' knowledge, to “track” certain limit orders. This practice was done to obtain an undisclosed markup on the trade for UBS if the market hit both the customer's limit price and UBS's altered tracking price. Additionally, the practice also subjected customers to the potential that their limit orders would be delayed or not filled when the market hit the customer's limit price but not UBS's altered tracking price.
15. The Factual Basis for Breach also details how certain customers obtaining quotes and placing trades over the phone would, on occasion, request an “open-line” so they could hear the conversation regarding price quotes between the UBS trader and salesperson. Certain of these customers had an expectation the price they heard from the trader did not include a sales markup for their transaction currency. While on certain “open-line” conversations, UBS traders and salespeople used hand signals to fraudulently conceal markups from these customers.
16. The Factual Basis for Breach describes how, from about October 2011 to at least January 2013, a UBS FX trader conspired with other financial services firms acting as dealers in the FX spot market, by agreeing to restrain competition in the purchase and sale of the Euro/U.S. dollar currency pair. To achieve this, among other things, the conspirators: (i) Coordinated the trading of the Euro/U.S. dollar currency pair in connection with the European Central Bank and the World Markets/Reuters benchmark currency “fixes;” and (ii) refrained from certain trading behavior by withholding offers and bids when one conspirator held an open risk position. They did this so that the price of the currency traded would not move in a direction adverse to the conspirator with an open risk position.
17. The Factual Basis for Breach explains that in determining that UBS was in breach of the LIBOR NPA, the DOJ considered UBS's FX Misconduct described above in light of UBS's obligation under the LIBOR NPA to commit no further crimes. The DOJ also took into account UBS's three recent prior criminal resolutions
18. The Statement of Facts (SOF) in Exhibit 3 of the Plea Agreement describes the circumstances of UBS's scheme to defraud counterparties to interest rate derivatives transactions, by secretly manipulating benchmark interest rates to which the profitability of those transactions was tied. According to the SOF, LIBOR is a benchmark interest rate used in financial markets worldwide, namely on exchanges and in over-the-counter markets, to settle trades for futures, options, swaps, and other derivative financial instruments. In addition, LIBOR is often used as a reference rate for mortgages, credit cards, student loans, and other consumer lending products. LIBOR and the other benchmark interest rates play a fundamentally important role in
19. Each business day the LIBOR average benchmark interest rates are calculated and published by Thomson Reuters, acting as agent for the British Bankers' Association (BBA), for ten currencies (including the United States Dollar, the British Pound Sterling, and the Japanese Yen) and for various maturities (ranging from overnight to twelve months). The calculation for a given currency is based upon rate submissions from a panel of banks for that currency (the Contributor Panel). In general terms, LIBOR is the rate at which the Contributor Panel member could borrow funds. According to the BBA, the Contributor Bank Panel must submit the rate considered by the bank's cash management staff, and not the bank's personnel responsible for derivative trading, as the rate the bank could borrow unsecured inter-bank funds in the London money market, without reference to rates contributed by other Contributor Panel banks. Additionally, a Contributor Panel bank may not contribute a rate based on the pricing of any derivative financial instrument. Once each Contributor Panel bank has submitted its rate, the contributed rates are ranked and averaged, discarding the highest and lowest 25%, to formulate the LIBOR “Fix” for that particular currency and maturity. Since 2005, UBS has been a member of the Contributor Panels for the Dollar LIBOR, Yen LIBOR, Euro LIBOR, Swiss Franc LIBOR, and Pound Sterling LIBOR.
20. UBS has also been a member of the Contributor Panel for the Euro Interbank Offered Rate (Euribor) since 2005. The European Banking Federation (EBF) oversees the Euribor reference rate which is the rate expected to be offered by one prime bank to another for Euro interbank term deposits within the Euro zone. The Euribor Contributor Panel bank rate submissions are ranked, and the highest and lowest 15% of all the submissions are excluded from the calculation. The Euribor fix is then formulated using the average of the remaining rate submissions.
21. In addition, UBS was also a member of the Contributor Panel for the Euroyen TIBOR from at least 2005 until 2012. The Japanese Bankers Association (JBA) oversees the TIBOR reference rate. Yen deposits maintained in accounts outside of Japan are referred to as “Euroyen” and the prevailing lending market rates between prime banks in the Japan Offshore Market is Euroyen TIBOR. Euroyen TIBOR is calculated by averaging the rate submissions of Contributor Panel members after discarding the two highest and lowest rate submissions. The Euroyen TIBOR rates and the Contributor Panel members' rate submissions are made available worldwide.
22. The SOF also describes the wide-ranging and systematic efforts, practiced nearly on a daily basis, by several UBS employees to manipulate YEN LIBOR in order to benefit UBS's trading positions through internal manipulation within UBS, by using cash brokers to influence other Contributor Panel banks' Yen LIBOR submissions, and by colluding directly with employees at other Contributor Panel banks to influence those banks' Yen LIBOR submissions.
23. The SOF provides that, at various times from at least 2001 through June 2010, certain UBS derivatives traders manipulated submissions for various interest rate benchmarks, and colluded with employees at other banks and cash brokers to influence certain benchmark rates to benefit their trading positions. The SOF explains that the UBS derivatives traders directly and indirectly exercised improper influence over UBS's submissions for LIBOR, Euroyen TIBOR and Euribor. In this regard, those UBS derivatives traders requested, and sometimes directed, that certain UBS benchmark interest submitters submit a particular benchmark interest rate contribution or a higher, lower, or unchanged rate for LIBOR, Euroyen TIBOR, and Euribor that would be beneficial to the traders. These UBS traders' requests for favorable benchmark rates submissions were regularly accommodated by the UBS submitters.
24. The SOF also details how cash brokers
25. UBS acknowledges that the SOF is true and correct and that the wrongful acts taken by the participating employees in furtherance of the misconduct set forth above were within the scope of their employment at UBS. Furthermore, UBS acknowledges that the participating employees intended, at least in part, to benefit UBS through the actions described above.
26. The 2013 Conviction caused the UBS QPAMs to violate Section I(g) of PTE 84-14. On September 13, 2013, the Department granted PTE 2013-09, which allows the UBS QPAMs to rely on the relief provided in PTE 84-14, notwithstanding the 2013 Conviction of UBS Securities Japan.
27. The 2016 Conviction will cause the UBS QPAMs to violate Section I(g) of PTE 84-14, once a judgment of conviction is entered by the District Court. As a consequence, the UBS QPAMs will not be able to rely upon the exemptive relief provided by PTE 84-14 for a period of ten years as of the 2016 Conviction Date. Furthermore, the 2016 Conviction will also cause Section I(h) of PTE 2013-09 to be violated, as of the 2016 Conviction Date. UBS QPAMs will become ineligible for the relief provided by PTE 84-14 as a result of both the 2013 Conviction and 2016 Conviction. Therefore, the Applicants request a single, new exemption that provides relief for the UBS QPAMs to rely on PTE 84-14 notwithstanding the 2013 Conviction and the 2016 Conviction, effective as of the 2016 Conviction Date.
28. The Department is proposing a temporary exemption herein to allow the UBS QPAMs to rely on PTE 84-14 notwithstanding the Convictions, subject to a comprehensive suite of protective conditions designed to protect the rights of the participants and beneficiaries of the ERISA-covered plans and IRAs that are managed by
This proposed temporary exemption will allow the Department sufficient time to contemplate whether or not to grant the five-year exemption without risking the sudden loss of exemptive relief for the UBS QPAMs upon entry of a judgment of conviction in Case Number 3:15-00076-RNC.
29. Finally, excluding the Convictions and the FX Misconduct, UBS represents that it currently does not have a reasonable basis to believe there are any pending criminal investigations involving the Applicants or any of their affiliated companies that would cause a reasonable plan or IRA customer not to hire or retain the institution as a QPAM. Furthermore, this proposed temporary exemption will not apply to any other conviction(s) of UBS or its affiliates for crimes described in Section I(g) of PTE 84-14. The Department notes that, in such event, the Applicants and their ERISA-covered plan and IRA clients should be prepared to rely on exemptive relief other than PTE 84-14 for any prohibited transactions entered into after the date of such conviction(s), withdraw from any arrangements that solely rely on PTE 84-14 for exemptive relief; or avoid engaging in any such prohibited transactions in the first place.
30. The Applicants represent that UBS took extensive remedial actions and implemented internal control procedures before, during, and after the LIBOR investigations and FX Misconduct, in order to reform its compliance structure and strengthen its corporate culture. UBS represents that it undertook the following structural reforms and compliance enhancements:
31. Furthermore, the Applicants represent that UBS took disciplinary action against forty-four individuals in connection with the LIBOR misconduct, and against sixteen individuals in connection with the FX Misconduct. The individuals involved in the disciplinary actions included traders, benchmark submitters, compliance personnel, salespeople and managers. The disciplinary actions encompassed the termination or separation of thirty employees and also included financial consequences, such as forfeiture of deferred compensation, loss of bonuses and bonus reductions.
32. The Applicants represent that the requested exemption is in the interest of affected plans and their participants and beneficiaries because it will enable ERISA plan and IRA clients to have the opportunity to enter into transactions
33. The Applicants represent that, if the exemption request is denied, and ERISA plan and IRA clients leave the UBS QPAMs, these clients would typically incur transition costs associated with identifying appropriate replacement investment managers and liquidating and re-investing the assets currently managed by the UBS QPAMs. The Applicants estimate that the aggregate transition costs for liquidating and re-investing of each asset class for UBS's ERISA plan and IRA clients would be approximately $280 million.
The Applicants represents in addition to these transition costs, the ERISA plan client would pay substantially more in fees than it is currently paying if it had to obtain all these services from a variety of different providers.
34. The Applicants have proposed certain conditions it believes are protective of ERISA-covered plans and IRAs with respect to the transactions described herein. The Department has determined to revise and supplement the proposed conditions so that it can make its required finding that the requested temporary exemption is protective of the rights of participants and beneficiaries of affected plans and IRAs.
35. Several of these conditions underscore the Department's understanding, based on the Applicants' representations, that the affected UBS QPAMs were not involved in the FX Misconduct or the misconduct that is the subject of the Convictions. For example, the temporary exemption, if granted as proposed, mandates that the UBS QPAMs (including their officers, directors, agents other than UBS, and employees of such UBS QPAMs) did not know of, have reason to know of, or participate in: (1) The FX Misconduct; or (2) the criminal conduct that is the subject of the Convictions. For purposes of this requirement, “participate in” includes an individual's knowing or tacit approval of the FX Misconduct and the misconduct that is the subject of the Convictions. Under this the proposed temporary exemption, the term “Convictions” includes the 2013 Conviction and the 2016 Conviction. The term “2013 Conviction” means the judgment of conviction against UBS Securities Japan Co. Ltd. in Case Number 3:12-cr-00268-RNC in the U.S. District Court for the District of Connecticut for one count of wire fraud in violation of Title 18, United Sates Code, sections 1343 and 2 in connection with submission of YEN London Interbank Offered Rates and other benchmark interest rates. The term “2016 Conviction” means the anticipated judgment of conviction against UBS AG in Case Number 3:15-cr-00076-RNC in the U.S. District Court for the District of Connecticut for one count of wire fraud in violation of Title 18, United States Code, Sections 1343 and 2 in connection with UBS's submission of Yen London Interbank Offered Rates and other benchmark interest rates between 2001 and 2010. Furthermore, for all purposes under the proposed temporary exemption, “conduct” of any person or entity that is the “subject of [a] Conviction” encompasses any conduct of UBS and/or their personnel, that is described in the Plea Agreement, (including Exhibits 1 and 3 attached thereto), the plea agreement entered into between UBS Securities Japan and the Department of Justice Criminal Division, on December 19, 2012, in connection with Case Number 3:12-cr-00268-RNC the December 19, 2012 (and attachments thereto), and other official regulatory or judicial factual findings that are a part of this record. The proposed temporary exemption defines the FX Misconduct as the conduct engaged in by UBS personnel described in Exhibit 1 of the Plea Agreement entered into between UBS AG and the Department of Justice Criminal Division, on May 20, 2015 in connection with Case Number 3:15-cr-00076-RNC filed in the U.S. District Court for the District of Connecticut.
36. Further, the UBS QPAMs (including their officers, directors, agents other than UBS, and employees of such UBS QPAMs) may not have received direct compensation, or knowingly have received indirect compensation, in connection with: (1) The FX Misconduct; or (2) the criminal conduct that is the subject of the Convictions.
37. The Department expects the UBS QPAMs to rigorously ensure that the individuals associated with the misconduct will not be employed or knowingly engaged by such QPAMs. In this regard, the proposed temporary exemption mandates that the UBS QPAMs will not employ or knowingly engage any of the individuals that participated in: (1) The FX Misconduct or (2) the criminal conduct that is the subject of the Convictions. For purposes of this condition, “participated in” includes an individual's knowing or tacit approval of the behavior that is the subject of the FX Misconduct or the
38. The UBS QPAMs must comply with each condition of PTE 84-14, as amended, with the sole exceptions of the violations of Section I(g) of PTE 84-14 that are attributable to the Convictions. Further, any failure of the UBS QPAMs to satisfy Section I(g) of PTE 84-14 must result solely from the Convictions.
39. No relief will be provided by this proposed temporary exemption to the extent a UBS QPAM exercised its authority over the assets of any plan subject to Part 4 of Title I of ERISA (an ERISA-covered plan) or section 4975 of the Code (an IRA) in a manner that it knew or should have known would: Further the FX Misconduct or the criminal conduct that is the subject of the Convictions; or cause the UBS QPAM, its affiliates or related parties to directly or indirectly profit from the FX Misconduct or the criminal conduct that is the subject of the Convictions. The conduct that is the subject of the Convictions includes that which is described in the Plea Agreement (including Exhibits 1 and 3 attached thereto) and the plea agreement entered into between UBS Securities Japan and the Department of Justice Criminal Division, on December 19, 2012, in connection with Case Number 3:12-cr-00268-RNC (and attachments thereto). The FX Misconduct engaged in by UBS personnel includes that which is described in Exhibit 1 of the Plea Agreement (Factual Basis for Breach) entered into between UBS AG and the Department of Justice Criminal Division, on May 20, 2015 in connection with Case Number 3:15-cr-00076-RNC filed in the US District Court for the District of Connecticut. Further, no relief will be provided to the extent UBS, or UBS Securities Japan, provides any discretionary asset management services to ERISA-covered plans or IRAs or otherwise act as a fiduciary with respect to ERISA-covered plan or IRA assets.
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43. The audit condition requires that, to the extent necessary for the auditor, in its sole opinion, to complete its audit and comply with the conditions for relief described herein, and as permitted by law, each UBS QPAM and, if applicable, UBS, will grant the auditor
44. The auditor's engagement must specifically require the auditor to determine whether each UBS QPAM has complied with the Policies and Training conditions described herein, and must further require the auditor to test each UBS QPAM's operational compliance with the Policies and Training.
45. On or before the end of the relevant period described in Section I(i)(1) for completing the audit, the auditor must issue a written report (the Audit Report) to UBS and the UBS QPAM to which the audit applies that describes the procedures performed by the auditor during the course of its examination. The Audit Report must include the auditor's specific determinations regarding: The adequacy of the UBS QPAM's Policies and Training; the UBS QPAM's compliance with the Policies and Training; the need, if any, to strengthen such Policies and Training; and any instance of the respective UBS QPAM's noncompliance with the written Policies and Training. Any determination by the auditor regarding the adequacy of the Policies and Training and the auditor's recommendations (if any) with respect to strengthening the Policies and Training of the respective UBS QPAM must be promptly addressed by such UBS QPAM, and any action taken by such UBS QPAM to address such recommendations must be included in an addendum to the Audit Report. Any determination by the auditor that the respective UBS QPAM has implemented, maintained, and followed sufficient Policies and Training must not be based solely or in substantial part on an absence of evidence indicating noncompliance. In this last regard, any finding that the UBS QPAM has complied with the requirements under this subsection must be based on evidence that demonstrates the UBS QPAM has actually implemented, maintained, and followed the Policies and Training required by this proposed temporary exemption.
46. Furthermore, the auditor must notify the respective UBS QPAM of any instance of noncompliance identified by the auditor within five (5) business days after such noncompliance is identified by the auditor, regardless of whether the audit has been completed as of that date. This proposed temporary exemption requires that certain senior personnel of UBS review the Audit Report, make certain certifications, and take various corrective actions. In this regard, the General Counsel, or one of the three most senior executive officers of the UBS QPAM to which the Audit Report applies, must certify in writing, under penalty of perjury, that the officer has reviewed the Audit Report and this proposed temporary exemption; addressed, corrected, or remedied any inadequacy identified in the Audit Report; and determined that the Policies and Training in effect at the time of signing are adequate to ensure compliance with the conditions of this proposed temporary exemption and with the applicable provisions of ERISA and the Code.
47. The Risk Committee, the Audit Committee, and the Corporate Culture and Responsibility Committee of UBS's Board of Directors are provided a copy of each Audit Report; and a senior executive officer of UBS's Compliance and Operational Risk Control function must review the Audit Report for each UBS QPAM and must certify in writing, under penalty of perjury, that such officer has reviewed each Audit Report. In order to create a more transparent record in the event that the proposed temporary relief is granted, each UBS QPAM must provide its certified Audit Report to the Department no later than 45 days following its completion. The Audit Report will be part of the public record regarding this proposed temporary exemption. Furthermore, each UBS QPAM must make its Audit Report unconditionally available for examination by any duly authorized employee or representative of the Department, other relevant regulators, and any fiduciary of an ERISA-covered plan or IRA, the assets of which are managed by such UBS QPAM.
48. Additionally, each UBS QPAM and the auditor must submit to the Department any engagement agreement entered into pursuant to the engagement of the auditor under this proposed temporary exemption; and any engagement agreement entered into with any other entity retained in connection with such QPAM's compliance with the Training or Policies conditions of this proposed temporary exemption no later than six (6) months after the date of the Conviction Date (and one month after the execution of any agreement thereafter). Finally, if the temporary exemption is granted, the auditor must provide the Department, upon request, all of the workpapers created and utilized in the course of the audit, including, but not limited to: The audit plan; audit testing; identification of any instance of noncompliance by the relevant UBS QPAM; and an explanation of any corrective or remedial action taken by the applicable UBS QPAM.
In order to enhance oversight of the compliance with the temporary exemption UBS must notify the Department at least 30 days prior to any substitution of an auditor, and UBS must demonstrate to the Department's satisfaction that any new auditor is independent of UBS, experienced in the matters that are the subject of the proposed temporary exemption and capable of making the determinations required of this proposed temporary exemption.
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50. Within four (4) months of the effective date of this proposed temporary exemption, each UBS QPAM will provide a notice of its obligations under Section I(j) to each ERISA-covered plan and IRA client for which the UBS QPAM provides asset management or other discretionary fiduciary services.
51. Certain conditions of the proposed temporary exemption are directed UBS and UBS Securities Japan. In this regard, UBS must impose internal procedures, controls, and protocols on UBS Securities Japan to: (1) Reduce the likelihood of any recurrence of conduct that that is the subject of the 2013 Conviction, and (2) comply in all material respects with the Business Improvement Order, dated December 16, 2011, issued by the Japanese Financial Services Authority. Additionally, UBS must comply in all material respects with the audit and monitoring procedures imposed on UBS by the United States Commodity Futures Trading Commission Order, dated December 19, 2012.
52. Each UBS QPAM must maintain records necessary to demonstrate that the conditions of this proposed temporary exemption have been met, for six (6) years following the date of any transaction for which such UBS QPAM relies upon the relief in the proposed temporary exemption.
53. The proposed temporary exemption requires that, during the effective period of this temporary exemption UBS: (1) Immediately discloses to the Department any Deferred Prosecution Agreement (a DPA) or Non-Prosecution Agreement (an NPA) that UBS or an affiliate enters into with the U.S. Department of Justice, to the extent such DPA or NPA involves conduct described in Section I(g) of PTE 84-14 or section 411 of ERISA; and (2) immediately provides the Department any information requested by the Department, as permitted by law, regarding the agreement and/or the conduct and allegations that led to the agreements.
54. The Applicants represents that the proposed temporary exemption is administratively feasible because it does not require any monitoring by the Department but relies on an independent auditor to determine that the exemption conditions are being complied with. Furthermore, the requested temporary exemption does not require the Department's oversight because, as a condition of this proposed temporary exemption, neither UBS nor UBS Securities Japan will provide any fiduciary or QPAM services to ERISA covered plans and IRAs.
Written comments and/or requests for a public hearing on the proposed temporary exemption should be submitted to the Department within five (5) days from the date of publication of this Federal Register Notice. Given the short comment period, the Department will consider comments received after such date, in connection with its consideration of more permanent relief.
The attention of interested persons is directed to the following:
(1) The fact that a transaction is the subject of an exemption under section 408(a) of the Act and/or section 4975(c)(2) of the Code does not relieve a fiduciary or other party in interest or disqualified person from certain other provisions of the Act and/or the Code, including any prohibited transaction provisions to which the exemption does not apply and the general fiduciary responsibility provisions of section 404 of the Act, which, among other things, require a fiduciary to discharge his duties respecting the plan solely in the interest of the participants and beneficiaries of the plan and in a prudent fashion in accordance with section 404(a)(1)(B) of the Act; nor does it affect the requirement of section 401(a) of the Code that the plan must operate for the exclusive benefit of the employees of the employer maintaining the plan and their beneficiaries;
(2) Before an exemption may be granted under section 408(a) of the Act and/or section 4975(c)(2) of the Code, the Department must find that the exemption is administratively feasible, in the interests of the plan and of its participants and beneficiaries, and protective of the rights of participants and beneficiaries of the plan;
(3) The proposed temporary exemption will be supplemental to, and not in derogation of, any other provisions of the Act and/or the Code, including statutory or administrative exemptions and transitional rules. Furthermore, the fact that a transaction is subject to an administrative or statutory exemption is not dispositive of whether the transaction is in fact a prohibited transaction; and
(4) The proposed temporary exemption will be subject to the express condition that the material facts and representations contained in the application are true and complete, and that the application accurately describes all material terms of the transaction which is the subject of the exemption.
The Department is considering granting a temporary exemption under the authority of section 408(a) of the Employee Retirement Income Security Act of 1974, as amended (ERISA or the Act), and section 4975(c)(2) of the Internal Revenue Code of 1986, as amended (the Code), and in accordance with the procedures set forth in 29 CFR
If the proposed temporary exemption is granted, certain entities with specified relationships to UBS, AG (hereinafter, the UBS QPAMs as further defined in Section II(b)) shall not be precluded from relying on the exemptive relief provided by Prohibited Transaction Exemption 84-14 (PTE 84-14),
(a) The UBS QPAMs (including their officers, directors, agents other than UBS, and employees of such UBS QPAMs) did not know of, have reason to know of, or participate in: (1) The FX Misconduct; or (2) the criminal conduct that is the subject of the Convictions (for the purposes of this Section I(a), “participate in” includes the knowing or tacit approval of the FX Misconduct or the misconduct that is the subject of the Convictions);
(b) The UBS QPAMs (including their officers, directors, agents other than UBS, and employees of such UBS QPAMs) did not receive direct compensation, or knowingly receive indirect compensation, in connection with: (1) The FX Misconduct; or (2) the criminal conduct that is the subject of the Convictions;
(c) The UBS QPAMs will not employ or knowingly engage any of the individuals that participated in: (1) The FX Misconduct or (2) the criminal conduct that is the subject of the Convictions (for purposes of this Section I(c), “participated in” includes the knowing or tacit approval of the FX Misconduct or the misconduct that is the subject of the Convictions);
(d) A UBS QPAM will not use its authority or influence to direct an “investment fund” (as defined in Section VI(b) of PTE 84-14) that is subject to ERISA or the Code and managed by such UBS QPAM, to enter into any transaction with UBS or UBS Securities Japan or engage UBS or UBS Securities Japan to provide any service to such investment fund, for a direct or indirect fee borne by such investment fund, regardless of whether such transaction or service may otherwise be within the scope of relief provided by an administrative or statutory exemption;
(e) Any failure of the UBS QPAMs to satisfy Section I(g) of PTE 84-14 arose solely from the Convictions;
(f) A UBS QPAM did not exercise authority over the assets of any plan subject to Part 4 of Title I of ERISA (an ERISA-covered plan) or section 4975 of the Code (an IRA) in a manner that it knew or should have known would: Further the FX Misconduct or the criminal conduct that is the subject of the Convictions; or cause the UBS QPAM, its affiliates or related parties to directly or indirectly profit from the FX Misconduct or the criminal conduct that is the subject of the Convictions;
(g) UBS and UBS Securities Japan will not provide discretionary asset management services to ERISA-covered plans or IRAs, nor will otherwise act as a fiduciary with respect to ERISA-covered plan or IRA assets;
(h)(1) Each UBS QPAM must immediately develop, implement, maintain, and follow written policies and procedures (the Policies) requiring and reasonably designed to ensure that:
(i) The asset management decisions of the UBS QPAM are conducted independently of UBS's corporate management and business activities, including the corporate management and business activities of the Investment Bank division and UBS Securities Japan;
(ii) The UBS QPAM fully complies with ERISA's fiduciary duties and with ERISA and the Code's prohibited transaction provisions, and does not knowingly participate in any violation of these duties and provisions with respect to ERISA-covered plans and IRAs;
(iii) The UBS QPAM does not knowingly participate in any other person's violation of ERISA or the Code with respect to ERISA-covered plans and IRAs;
(iv) Any filings or statements made by the UBS QPAM to regulators, including but not limited to, the Department of Labor, the Department of the Treasury, the Department of Justice, and the Pension Benefit Guaranty Corporation, on behalf of ERISA-covered plans or IRAs are materially accurate and complete, to the best of such QPAM's knowledge at that time;
(v) The UBS QPAM does not make material misrepresentations or omit material information in its communications with such regulators with respect to ERISA-covered plans or IRAs, or make material misrepresentations or omit material information in its communications with ERISA-covered plan and IRA clients;
(vi) The UBS QPAM complies with the terms of this temporary exemption; and
(vii) Any violation of, or failure to comply with, an item in subparagraph (ii) through (vi), is corrected promptly upon discovery, and any such violation or compliance failure not promptly corrected is reported, upon the discovery of such failure to promptly correct, in writing, to appropriate corporate officers, the head of compliance and the General Counsel (or their functional equivalent) of the relevant UBS QPAM, the independent auditor responsible for reviewing compliance with the Policies, and an appropriate fiduciary of any affected ERISA-covered plan or IRA that is independent of UBS; however, with respect to any ERISA-covered plan or IRA sponsored by an “affiliate” (as defined in Section VI(d) of PTE 84-14) of UBS or beneficially owned by an employee of UBS or its affiliates, such fiduciary does not need to be independent of UBS. A UBS QPAM will not be treated as having failed to develop, implement, maintain, or follow the Policies, provided that it corrects any instance of noncompliance promptly when discovered or when it reasonably should have known of the noncompliance (whichever is earlier), and provided that it adheres to the reporting requirements set forth in this subparagraph (vii);
(2) Each UBS QPAM must immediately develop and implement a program of training (the Training), conducted at least annually, for all relevant UBS QPAM asset/portfolio management, trading, legal, compliance, and internal audit personnel. The Training must:
(i) Be set forth in the Policies and at a minimum, cover the Policies, ERISA and Code compliance (including applicable fiduciary duties and the prohibited transaction provisions), ethical conduct, the consequences for not complying with the conditions of this temporary exemption (including any loss of exemptive relief provided
(ii) Be conducted by an independent professional who has been prudently selected and who has appropriate technical training and proficiency with ERISA and the Code;
(i)(1) Each UBS QPAM submits to an audit conducted by an independent auditor, who has been prudently selected and who has appropriate technical training and proficiency with ERISA and the Code, to evaluate the adequacy of, and the UBS QPAM's compliance with, the Policies and Training described herein. The audit requirement must be incorporated in the Policies. The audit must cover the twelve month period that begins on the Conviction Date, and must be completed no later than six (6) months after the twelve month period. For time periods prior to the Conviction Date and covered under PTE 2013-09, the audit requirements in Section (g) of PTE 2013-09 will remain in effect;
(2) To the extent necessary for the auditor, in its sole opinion, to complete its audit and comply with the conditions for relief described herein, and as permitted by law, each UBS QPAM and, if applicable, UBS, will grant the auditor unconditional access to its business, including, but not limited to: Its computer systems; business records; transactional data; workplace locations; training materials; and personnel;
(3) The auditor's engagement must specifically require the auditor to determine whether each UBS QPAM has developed, implemented, maintained, and followed the Policies in accordance with the conditions of this temporary exemption and has developed and implemented the Training, as required herein;
(4) The auditor's engagement must specifically require the auditor to test each UBS QPAM's operational compliance with the Policies and Training. In this regard, the auditor must test a sample of each QPAM's transactions involving ERISA-covered plans and IRAs sufficient in size and nature to afford the auditor a reasonable basis to determine the operational compliance with the Policies and Training;
(5) On or before the end of the relevant period described in Section I(i)(1) for completing the audit, the auditor must issue a written report (the Audit Report) to UBS and the UBS QPAM to which the audit applies that describes the procedures performed by the auditor during the course of its examination. The Audit Report must include the auditor's specific determinations regarding: The adequacy of the UBS QPAM's Policies and Training; the UBS QPAM's compliance with the Policies and Training; the need, if any, to strengthen such Policies and Training; and any instance of the respective UBS QPAM's noncompliance with the written Policies and Training described in Section I(h) above. Any determination by the auditor regarding the adequacy of the Policies and Training and the auditor's recommendations (if any) with respect to strengthening the Policies and Training of the respective UBS QPAM must be promptly addressed by such UBS QPAM, and any action taken by such UBS QPAM to address such recommendations must be included in an addendum to the Audit Report (which addendum is completed prior to the certification described in Section I(i)(7) below). Any determination by the auditor that the respective UBS QPAM has implemented, maintained, and followed sufficient Policies and Training must not be based solely or in substantial part on an absence of evidence indicating noncompliance. In this last regard, any finding that the UBS QPAM has complied with the requirements under this subsection must be based on evidence that demonstrates the UBS QPAM has actually implemented, maintained, and followed the Policies and Training required by this temporary exemption;
(6) The auditor must notify the respective UBS QPAM of any instance of noncompliance identified by the auditor within five (5) business days after such noncompliance is identified by the auditor, regardless of whether the audit has been completed as of that date;
(7) With respect to each Audit Report, the General Counsel, or one of the three most senior executive officers of the UBS QPAM to which the Audit Report applies, must certify in writing, under penalty of perjury, that the officer has reviewed the Audit Report and this temporary exemption; addressed, corrected, or remedied any inadequacy identified in the Audit Report; and determined that the Policies and Training in effect at the time of signing are adequate to ensure compliance with the conditions of this proposed temporary exemption and with the applicable provisions of ERISA and the Code;
(8) The Risk Committee, the Audit Committee, and the Corporate Culture and Responsibility Committee of UBS's Board of Directors are provided a copy of each Audit Report; and a senior executive officer of UBS's Compliance and Operational Risk Control function must review the Audit Report for each UBS QPAM and must certify in writing, under penalty of perjury, that such officer has reviewed each Audit Report;
(9) Each UBS QPAM must provide its certified Audit Report, by regular mail to: The Department's Office of Exemption Determinations (OED), 200 Constitution Avenue NW., Suite 400, Washington, DC 20210, or by private carrier to: 122 C Street NW., Suite 400, Washington, DC 20001-2109, no later than 45 days following its completion. The Audit Report will be part of the public record regarding this temporary exemption. Furthermore, each UBS QPAM must make its Audit Report unconditionally available for examination by any duly authorized employee or representative of the Department, other relevant regulators, and any fiduciary of an ERISA-covered plan or IRA, the assets of which are managed by such UBS QPAM;
(10) Each UBS QPAM and the auditor must submit to OED: (A) Any engagement agreement entered into pursuant to the engagement of the auditor under this proposed temporary exemption; and (B) any engagement agreement entered into with any other entity retained in connection with such QPAM's compliance with the Training or Policies conditions of this temporary exemption no later than six (6) months after the Conviction Date (and one month after the execution of any agreement thereafter);
(11) The auditor must provide OED, upon request, all of the workpapers created and utilized in the course of the audit, including, but not limited to: The audit plan; audit testing; identification of any instance of noncompliance by the relevant UBS QPAM; and an explanation of any corrective or remedial action taken by the applicable UBS QPAM; and
(12) UBS must notify the Department at least 30 days prior to any substitution of an auditor, except that no such replacement will meet the requirements of this paragraph unless and until UBS demonstrates to the Department's satisfaction that such new auditor is independent of UBS, experienced in the matters that are the subject of the temporary exemption and capable of making the determinations required of this temporary exemption;
(j) Effective as of the Conviction Date, with respect to any arrangement, agreement, or contract between a UBS QPAM and an ERISA-covered plan or IRA for which such UBS QPAM provides asset management or other discretionary fiduciary services, each UBS QPAM agrees:
(1) To comply with ERISA and the Code, as applicable with respect to such ERISA-covered plan or IRA; to refrain from engaging in prohibited transactions that are not otherwise exempt (and to promptly correct any inadvertent prohibited transactions); and to comply with the standards of prudence and loyalty set forth in section 404 of ERISA, as applicable;
(2) Not to require (or otherwise cause) the ERISA-covered plan or IRA to waive, limit, or qualify the liability of the UBS QPAM for violating ERISA or the Code or engaging in prohibited transactions;
(3) Not to require the ERISA-covered plan or IRA (or sponsor of such ERISA-covered plan or beneficial owner of such IRA) to indemnify the UBS QPAM for violating ERISA or engaging in prohibited transactions, except for violations or prohibited transactions caused by an error, misrepresentation, or misconduct of a plan fiduciary or other party hired by the plan fiduciary who is independent of UBS;
(4) Not to restrict the ability of such ERISA-covered plan or IRA to terminate or withdraw from its arrangement with the UBS QPAM (including any investment in a separately managed account or pooled fund subject to ERISA and managed by such QPAM), with the exception of reasonable restrictions, appropriately disclosed in advance, that are specifically designed to ensure equitable treatment of all investors in a pooled fund in the event such withdrawal or termination may have adverse consequences for all other investors as a result of an actual lack of liquidity of the underlying assets, provided that such restrictions are applied consistently and in like manner to all such investors;
(5) Not to impose any fees, penalties, or charges for such termination or withdrawal with the exception of reasonable fees, appropriately disclosed in advance, that are specifically designed to prevent generally recognized abusive investment practices or specifically designed to ensure equitable treatment of all investors in a pooled fund in the event such withdrawal or termination may have adverse consequences for all other investors, provided that such fees are applied consistently and in like manner to all such investors;
(6) Not to include exculpatory provisions disclaiming or otherwise limiting liability of the UBS QPAM for a violation of such agreement's terms, except for liability caused by an error, misrepresentation, or misconduct of a plan fiduciary or other party hired by the plan fiduciary who is independent of UBS and its affiliates; and
(7) To indemnify and hold harmless the ERISA-covered plan or IRA for any damages resulting from a violation of applicable laws, a breach of contract, or any claim arising out of the failure of such UBS QPAM to qualify for the exemptive relief provided by PTE 84-14 as a result of a violation of Section I(g) of PTE 84-14 other than the Convictions;
(8) Within four (4) months of the effective date of this temporary exemption each UBS QPAM will: Provide a notice of its obligations under this Section I(j) to each ERISA-covered plan and IRA for which a UBS QPAM provides asset management or other discretionary fiduciary services;
(k) The UBS QPAMs comply with each condition of PTE 84-14, as amended, with the sole exceptions of the violations of Section I(g) of PTE 84-14 that are attributable to the Convictions;
(l) UBS imposes its internal procedures, controls, and protocols on UBS Securities Japan to: (1) Reduce the likelihood of any recurrence of conduct that that is the subject of the 2013 Conviction, and (2) comply in all material respects with the Business Improvement Order, dated December 16, 2011, issued by the Japanese Financial Services Authority;
(m) UBS complies in all material respects with the audit and monitoring procedures imposed on UBS by the United States Commodity Futures Trading Commission Order, dated December 19, 2012;
(n) Each UBS QPAM will maintain records necessary to demonstrate that the conditions of this temporary exemption have been met, for six (6) years following the date of any transaction for which such UBS QPAM relies upon the relief in the temporary exemption;
(o) During the effective period of this temporary exemption UBS: (1) Immediately discloses to the Department any Deferred Prosecution Agreement (a DPA) or Non-Prosecution Agreement (an NPA) that UBS or any of its affiliates enters into with the U.S. Department of Justice, to the extent such DPA or NPA involves conduct described in Section I(g) of PTE 84-14 or section 411 of ERISA; and (2) immediately provides the Department any information requested by the Department, as permitted by law, regarding the agreement and/or the conduct and allegations that led to the agreement; and
(p) A UBS QPAM will not fail to meet the terms of this proposed temporary exemption solely because a different UBS QPAM fails to satisfy a condition for relief under this proposed temporary exemption described in Sections I(c), (d), (h), (i), (j), (k), and (n).
(a) The term “Convictions” means the 2013 Conviction and the 2016 Conviction. The term “2013 Conviction” means the judgment of conviction against UBS Securities Japan Co. Ltd. in Case Number 3:12-cr-00268-RNC in the U.S. District Court for the District of Connecticut for one count of wire fraud in violation of Title 18, United Sates Code, sections 1343 and 2 in connection with submission of YEN London Interbank Offered Rates and other benchmark interest rates. The term “2016 Conviction” means the anticipated judgment of conviction against UBS AG in Case Number 3:15-cr-00076-RNC in the U.S. District Court for the District of Connecticut for one count of wire fraud in violation of Title 18, United States Code, Sections 1343 and 2 in connection with UBS's submission of Yen London Interbank Offered Rates and other benchmark interest rates between 2001 and 2010. For all purposes under this proposed temporary exemption, “conduct” of any person or entity that is the “subject of [a] Conviction” encompasses any conduct of UBS and/or their personnel, that is described in the Plea Agreement, (including Exhibits 1 and 3 attached thereto), and other official regulatory or judicial factual findings that are a part of this record
(b) The term “UBS QPAM” means UBS Asset Management (Americas) Inc., UBS Realty Investors LLC, UBS Hedge Fund Solutions LLC, UBS O'Connor LLC, and any future entity within the Asset Management or the Wealth Management Americas divisions of UBS AG that qualifies as a “qualified professional asset manager” (as defined in Section VI(a)
(c) The term “UBS” means UBS AG.
(d) The term “Conviction Date” means the date that a judgment of
(e) The term “FX Misconduct” means the conduct engaged in by UBS personnel described in Exhibit 1 of the Plea Agreement (Factual Basis for Breach) entered into between UBS AG and the Department of Justice Criminal Division, on May 20, 2015 in connection with Case Number 3:15-cr-00076-RNC filed in the U.S. District Court for the District of Connecticut.
(f) The term “UBS Securities Japan” means UBS Securities Japan Co. Ltd, a wholly-owned subsidiary of UBS incorporated under the laws of Japan.
(g) The term “Plea Agreement” means the Plea Agreement (including Exhibits 1 and 3 attached thereto) entered into between UBS AG and the Department of Justice Criminal Division, on May 20, 2015 in connection with Case Number 3:15-cr-00076-RNC filed in the U.S. District Court for the District of Connecticut.
Employment and Training Administration (ETA), Labor.
Notice of availability for comment of an environmental assessment
Building 1 (Administration/Education Building) and Building 2 (Gymnasium)and Building 5 (Cafeteria) at the Gulfport JCC, originally built as the 33rd Avenue High School, were completed in 1954 and are considered eligible for the National Register of Historic Places (NRHP). These buildings (Buildings 1, 2, and 5) sustained extensive damage during Hurricane Katrina and have not been rehabilitated. The Gulfport JCC has been operating at reduced student capacity in the remaining three buildings and eight modular buildings. DOL proposes to redevelop the Gulfport Job Corps Center (JCC) so that it can provide training for the 280-student capacity for which it was originally designed.
Submittal of public comments must be received no later than December 19, 2016.
Comments can be submitted by email to Marsha Fitzhugh at
Marsha Fitzhugh, Division of Facilities and Asset Management, 200 Constitution Avenue NW., Room N-4463, Washington, DC 20210, 202-693-3099.
The Preferred Alternative would retain the historic appearance of the Building 1 (Administration/Education Building) and Building 2 (Gymnasium) façades while providing modern facilities behind the façades. Building 5 (Cafeteria) would be demolished and replaced by a new, modern cafeteria, and a new building would be constructed for vocational training for shop-related trades and for storage and maintenance.
Pursuant to the Council on Environmental Quality Regulations (40 CFR part 1500-08) implementing procedural provisions of the National Environmental Policy Act (NEPA), the Department of Labor, ETA, in accordance with 29 CFR 11.11(d) is announcing the availability of an Environmental Assessment (EA) that has been prepared for the Restoration or Replacement of Buildings at the Gulfport Job Corps Center located at 3300 20th Street, Gulfport, MS 39501.
This EA will be available at the Gulfport Public Library, 1708 25th Avenue, Gulfport, MS 39501 and at
Signed in Washington, DC.
Office of the Assistant Secretary for Policy, Chief Evaluation Office, Department of Labor.
Notice.
The Department of Labor (DOL), as part of its continuing effort to reduce paperwork and respondent burden, conducts a preclearance consultation program to provide the general public and Federal agencies with an opportunity to comment on proposed and/or continuing collections of information in accordance with the Paperwork Reduction Act of 1995 (PRA95) [44 U.S.C. 3506(c)(2)(A)]. This program helps to ensure that requested data can be provided in the desired format, reporting burden (time and financial resources) is minimized, collection instruments are clearly understood, and the impact of collection requirements on respondents is properly assessed.
Currently, the Department of Labor is soliciting comments concerning the collection of data about the Evaluation of Strategies Used in TechHire and Strengthening Working Families Initiative Grant Programs. A copy of the proposed Information Collection Request (ICR) can be obtained by contacting the office listed below in the addressee section of this notice.
Written comments must be submitted to the office listed in the addressee section below on or before January 17, 2017.
You may submit comments by either one of the following methods:
Christina Yancey by email at
I.
The goal of the impact study is to provide rigorous evidence on the effectiveness of strategies used in the TechHire and SWFI grant programs. The impact study will consist of both a randomized controlled trial (RCT) and a quasi-experimental design (QED) evaluation. Six grantees will be selected to participate in an RCT. Eligible program applicants will be randomly assigned to either a program group that is offered the program or a control group that is not. The RCT will collect baseline data on key demographics and other characteristics through a random assignment intake form, employment and earnings outcomes through unemployment insurance (UI), wage record data from the National Directory of New Hires (NDNH), or, as needed, UI records from state agencies, and follow up surveys of study participants at about 6 and 18 to 24 months after random assignment. The follow up surveys will provide additional outcome measures such as employment stability and quality, completion of training, and involvement with the criminal justice system.
The QED will include all 53 TechHire and SWFI grantees and use the pooled RCT control group as the comparison group using propensity score matching. The QED will collect data from an existing MIS and UI wage record data from NDNH and/or state agencies. It will also use data from the implementation study (described below) in an effort to analyze how variation in program impacts correlates with implementation factors.
A key goal of the implementation study is to provide systematic information on all of the grantees and link the findings to impacts. For all 53 grantees, the implementation study will review grantee applications, conduct web-based surveys with grantees and partners, conduct semi-structured telephone interviews with grantees and partners, and collect data on individual participants through an existing grantee quarterly reports MIS. Additionally, for the 6 grantees in the RCT, the implementation study will include two rounds of field visits involving a mix of observations, interviews, and case file reviews. This will provide critical context for understanding the impact findings from the RCT.
This
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* Evaluate whether the proposed collection of information is necessary for the proper performance functions of the agency, including whether the information will have practical utility;
* evaluate the accuracy of the agency's burden estimate of the proposed information collection, including the validity of the methodology and assumptions;
* enhance the quality, utility, and clarity of the information to be collected; and
* minimize the burden of the collection of information on those who are to respond, including through the use of appropriate automated, electronic, mechanical, or other technological collection techniques or other forms of information technology—for example, permitting electronic submissions of responses.
Comments submitted in response to this request will be summarized and/or included in the request for Office of Management and Budget approval of the information collection request; they will also become a matter of public record.
Occupational Safety and Health Administration (OSHA), Labor.
Notice of renewal of the ACCSH Charter.
The Secretary of Labor has renewed the Charter of the Advisory Committee on Construction Safety and Health (ACCSH) for two years. The current ACCSH Charter will expire on November 17, 2016.
Mr. Damon S. Bonneau, Office of Construction Services, Directorate of Construction, Occupational Safety and Health Administration, Room N-3468, U.S. Department of Labor, 200 Constitution Avenue NW., Washington, DC 20210; telephone (202) 693-2020 (TTY (877) 889-5627); email:
ACCSH is a continuing advisory committee established under Section 107 of the Contract Work Hours and Safety Standards Act (Construction Safety Act (CSA)) (40 U.S.C. 3704(d)(4)), to advise the Secretary and the Assistant Secretary of Labor for Occupational Safety and Health in the formulation of construction safety and health standards as well as on policy matters arising under the CSA and the Occupational Safety and Health Act of 1970 (OSH Act) (29 U.S.C. 651
In accordance with the Federal Advisory Committee Act (FACA), as amended (5 U.S.C. App. 2 § 14(b)(2)), and its implementing regulations (41 CFR 102-3
David Michaels, Ph.D., MPH, Assistant Secretary of Labor for Occupational Safety and Health, directed the preparation of this notice under the authority granted by 29 U.S.C. 656; 40 U.S.C. 3704; 5 U.S.C. App. 2; 29 CFR parts 1911 and 1912; 41 CFR 102-3; and Secretary of Labor's Order No. 1-2012 (77 FR 3912, Jan. 25, 2012).
National Aeronautics and Space Administration.
Notice of meeting.
In accordance with the Federal Advisory Committee Act, as amended, the National Aeronautics and Space Administration (NASA) announces a meeting of the NASA Advisory Council.
Wednesday, November 30, 2016, 10:30 a.m.-6:30 p.m., Local Time.
The NASA AERO Institute, 38256 Sierra Highway, Palmdale, CA 93550
Ms. Marla King, NAC Administrative Officer, NASA Headquarters, Washington, DC 20546, (202) 358-1148.
This meeting will be open to the public up to the capacity of the meeting room. This meeting is also available telephonically and by WebEx. You must use a touch-tone phone to participate in this meeting. Any interested person may dial the toll-free number 1-888-831-6084 or toll number 1-312-470-7172, Passcode: 4690949 followed by the # sign. If dialing in, please “mute” your phone. To join via WebEx, the link is
Attendees will be required to sign a register. It is imperative that the meeting be held on this date to accommodate the scheduling priorities of the key participants.
In accordance with the Federal Advisory Committee Act (Pub. L. 92-463, as amended), the National Science Foundation (NSF) announces the following meeting:
In accordance with the Federal Advisory Committee Act (Pub., L. 92-463, as amended), the National Science Foundation (NSF) announces its intent to hold proposal review meetings throughout the year. The purpose of these meetings is to provide advice and recommendations concerning proposals submitted to the NSF for financial support. The agenda for each of these meetings is to review and evaluate proposals as part of the selection process for awards. The review and evaluation may also include assessment of the progress of awarded proposals. The majority of these meetings will take place at NSF, 4201 Wilson Blvd., Arlington, Virginia 22230.
These meetings will be closed to the public. The proposals being reviewed include information of a proprietary or confidential nature, including technical information; financial data, such as salaries; and personal information concerning individuals associated with the proposals. These matters are exempt under 5 U.S.C. 552b(c), (4) and (6) of the Government in the Sunshine Act. NSF will continue to review the agenda and merits of each meeting for overall compliance of the Federal Advisory Committee Act.
These closed proposal review meetings will not be announced on an individual basis in the
Nuclear Regulatory Commission.
Request for action; receipt.
The U.S. Nuclear Regulatory Commission (NRC) is giving notice that, by petition dated July 14, 2016, and submitted by Mr. Lochbaum (the petitioner) on behalf of the Union of Concerned Scientists, the petitioner has requested that the NRC take action with regard to Diablo Canyon Power Plant, Units 1 and 2 (DCPP). The petitioner's requests are included in the
Please refer to Docket ID NRC-2016-0237 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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Margaret M. Watford, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; telephone: 301-415-1233, email:
On July 14, 2016, the petitioner requested that the NRC take action with regard to DCPP (ADAMS Accession No. ML16196A294). The petitioner requested the NRC to issue a Demand for Information pursuant to section 2.204 of title 10 of the
As a basis for this request, the petitioner states that the NRC's numerous requests for additional information during the license amendment process constitute prima facie evidence that PG&E violated 10 CFR 50.9 due to the incomplete and inaccurate information in the original license amendment request.
The request is being treated pursuant to 10 CFR 2.206 of the Commission's regulations and has been referred to the Director of the Office of Nuclear Reactor Regulation. The petitioner submitted supplemental information (ADAMS Accession No. ML16215A109) and addressed the Petition Review Board via teleconference on August 2, 2016, to discuss the petition; the transcript of that meeting is an additional supplement to the petition (ADAMS Accession No. ML16232A570). The results of that discussion were considered in the Board's determination regarding the petitioner's request for enforcement action and in establishing the schedule for the review of the petition. The Director determined that the petitioner's request for enforcement action at DCPP met the criteria for review under the 10 CFR 2.206 process. The NRC will take appropriate action on this petition within a reasonable time.
For the Nuclear Regulatory Commission.
Nuclear Regulatory Commission.
Application for indirect transfer of license; opportunity to comment, request a hearing, and petition for leave to intervene.
The U.S. Nuclear Regulatory Commission (NRC) received and is considering approval of an indirect license transfer application filed by Wolf Creek Nuclear Operating Company (WCNOC) on July 22, 2016. The WCNOC is the licensed operator of Wolf Creek Generating Station (WCGS). Kansas City Power and Light Company (KCP&L) and Kansas Gas and Electric Company (KG&E) are two of the three non-operating owner licensees, each holding 47 percent undivided interest in WCGS and 47 percent of the stock of WCNOC. The KCP&L is a subsidiary of Great Plains Energy Incorporated (Great Plains) and KG&E is a subsidiary of Westar Energy Incorporated (Westar). The indirect license transfer will result from the proposed merger of Great Plains and Westar, with Westar as wholly-owned subsidiary of Great Plains.
Comments must be filed by December 19, 2016. A request for a hearing must be filed by December 7, 2016.
You may submit comments by any of the following methods (unless this document describes a different method for submitting comments on a specific subject):
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For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Balwant K. Singal, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-3016, email:
Please refer to Docket ID NRC-2016-0234 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-2016-0234 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
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment submissions into ADAMS.
The NRC is considering the issuance of an order under § 50.80 of title 10 of the
No physical changes to the WCGS or operational changes are being proposed in the application.
The NRC's regulations at 10 CFR 50.80 state that no license, or any right thereunder, shall be transferred, directly or indirectly, through transfer of control of the license, unless the Commission gives its consent in writing. The Commission will approve an application for the indirect transfer of a license, if the Commission determines that the proposed merger will not affect the qualifications of the licensee to hold the license, and that the transfer is otherwise consistent with applicable provisions of law, regulations, and orders issued by the Commission.
Within 30 days from the date of publication of this notice, persons may submit written comments regarding the license transfer application, as provided for in 10 CFR 2.1305. The Commission will consider and, if appropriate, respond to these comments, but such comments will not otherwise constitute part of the decisional record. Comments should be submitted as described in the
Within 20 days after the date of publication of this notice, any person (petitioner) whose interest may be affected by this action may file a request for a hearing and a petition to intervene (petition) with respect to the action. Petitions shall be filed in accordance with the Commission's “Agency Rules of Practice and Procedure” in 10 CFR part 2. Interested persons 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 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 petitioner; (2) the nature of the petitioner's right under the Act to be made a party to the proceeding; (3) the nature and extent of the 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 petitioner's interest. The petition must also set forth the specific contentions which the 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 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 to support its position on the issue. 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 proceeding. The contention must be one which, if proven, would entitle the petitioner to relief. A 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 with respect to resolution of that person's admitted contentions consistent with the NRC's regulations, policies, and procedures.
Petitions for leave to intervene must be filed no later than 20 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 20-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) through (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 7, 2016. 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 set forth in this section, except that under 10 CFR 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. Details regarding the opportunity to make a limited appearance will be provided by the presiding officer if such sessions are scheduled.
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 (hereinafter “petition”), 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, as amended at 77 FR 46562, August 3, 2012). 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
Once a participant has obtained a digital ID certificate and a docket has been created, the participant can then submit a petition. Submissions should be in Portable Document Format (PDF). Additional guidance on PDF submissions is 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 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 stating why there is good cause for not filing electronically and 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, 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
The Commission will issue a notice or order granting or denying a hearing request or intervention petition, designating the issues for any hearing that will be held and designating the
Presiding Officer. A notice granting a hearing will be published in the
For further details with respect to this application, see the application dated July 22, 2016.
For the Nuclear Regulatory Commission.
Peace Corps.
60-day notice and request for comments.
The Peace Corps will be submitting the following information collection request to the Office of Management and Budget (OMB) for review and approval. The purpose of this notice is to allow 60 days for public comment in the
Submit comments on or before January 17, 2017.
Comments should be addressed to Denora Miller, FOIA/Privacy Act Officer. Denora Miller can be contacted by telephone at 202-692-1236 or email at
Denora Miller at Peace Corps address above.
Pursuant to Section 19(b)(1)
The Exchange proposes to amend the NYSE Arca Options Fee Schedule (“Fee Schedule”). The Exchange proposes to implement the fee change effective November 3, 2016. 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.
The purpose of this filing is to amend the Fee Schedule effective November 3, 2016. Specifically, the Exchange proposes to (i) modify the qualification for Tier 6 of Customer and Professional Customer Monthly Posting Credit Tiers and Qualifications in Penny Pilot Issues (the “Posting Tiers”); and (ii) modify one aspect of the Customer and Professional Customer Incentive Program.
Currently, to qualify for Tier 6 of the Posting Tiers, OTP Holders and OTP Firms (“OTPs”) must execute at least 0.50% of Total Industry Customer equity and ETF option ADV (“TCADV”) from Customer and Professional Customer posted orders in all issues (“the options component”), plus executed ADV of 0.70% of U.S. equity market share posted and executed on NYSE Arca Equity Market (“the equity component”). OTPs that achieve Tier 6 are eligible to receive a $0.48 credit applied to posted electronic Customer and Professional Customer executions in Penny Pilot Issues.
In addition, the Customer and Professional Customer Incentive Program (“the Incentive Program”), which provides OTPs six alternatives to earn additional posting credits ranging from $0.01 to $0.05, currently affords OTPs the ability to earn an additional $0.03 credit on Customer and Professional Customer Posting Credits by meeting the same 0.70% minimum qualification of the equity component as set forth in Tier 6.
The Exchange is proposing to modify Tier 6 of the Posting Tiers by reducing the options component from 0.50% TCADV to 0.35% TCADV, while increasing the threshold of the equity component from 0.70% to 0.80% of U.S.
In addition, to maintain parity with the Incentive Program that likewise offers a credit when an OTP meets the same 0.70% minimum qualification of the equity component as set forth in current Tier 6, the Exchange similarly proposes to increase this qualification basis. Specifically, the Exchange proposes to increase the equity threshold alternative from 0.70% to 0.80% of U.S. equity market share posted and executed on NYSE Arca Equity Market qualification in order for OTPs to qualify to earn an additional $0.03 credit.
The Exchange believes that the proposal to modify Tier 6 of the Posting Tiers by reducing the option component, while increasing the equity component would encourage greater participation on both the options and equity exchanges. The Exchange likewise believes that the proposed change to the Incentive Program would operate to maintain parity with the similar, alternative incentives offered by the Exchange and would also encourage participation in the NYSE Arca Equity Market.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
The Exchange believes that the proposed to modifications to the qualifications for Tier 6 of the Posting Tiers, and the similar adjustment to the Incentive Program, are reasonable, equitable, and not unfairly discriminatory because the changes are designed to attract additional Customer and Professional Customer electronic equity and ETF option volume to the Exchange, which would benefit all participants by offering greater price discovery, increased transparency, and an increased opportunity to trade on the Exchange. The Exchange believes that adjusting the methods for achieving the credits available on the Exchange (
For these reasons, the Exchange believes that the proposal is consistent with the Act.
In accordance with Section 6(b)(8) of the Act,
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. Because competitors are free to modify their own fees and credits in response, and because market participants may readily adjust their order routing practices, the degree to which fee changes in this market may impose any burden on competition is extremely limited. For the reasons described above, the Exchange believes that the proposed rule change reflects this 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 Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On September 13, 2016, NASDAQ BX, Inc. (“BX”) and The Nasdaq Stock Market LLC (“Nasdaq”) (individually, an “Exchange,” and together, the “Exchanges”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchanges are proposing to amend the behavior of Post-Only Orders when they interact with resting Non-Displayed Orders, and the behavior of Orders with Midpoint Pegging in a crossed market. The Exchanges' proposals are substantively identical in many respects. Therefore, the description below describes the proposals jointly but notes material differences where applicable.
Currently, BX and Nasdaq Rules 4702(b)(4)(A) provide that, if the adjusted price
• On Nasdaq if (i) it is priced below $1.00 and the value of price improvement associated with executing against an Order on the Nasdaq Book (as measured against the original limit price of the Order) equals or exceeds the sum of fees changed for such execution and the value of any rebate that would be provided if the Order posted to the Nasdaq Book and subsequently provided liquidity, or (ii) it is priced at $1.00 or more and the value of price improvement associated with executing against an Order on the Nasdaq Book (as measured against the original limit price of the Order) equals or exceeds $0.01 per share;
• on BX, if (i) it is priced at $1.00 or more,
Currently, BX and Nasdaq Rules 4702(b)(4)(A) also provide that, if the Post-Only Order would not lock or cross a Protected Quotation but would lock or cross an Order on the respective Exchange's Book, the Post Only Order
• On Nasdaq if (i) it is priced below $1.00 and the value of price improvement associated with executing against an Order on the Nasdaq Book equals or exceeds the sum of fees charged for such execution and the value of any rebate that would be provided if the Order posted to the Nasdaq Book and subsequently provided liquidity, or (ii) it is priced at $1.00 or more and the value of price improvement associated with executing against an Order on the Nasdaq Book equals or exceeds $0.01 per share;
• on BX, if (i) it is priced at $1.00 or more,
Currently, Nasdaq Rule 4702(b)(5)(A) provides that, if the NBBO is crossed, a Midpoint Peg Post-Only Order
The Commission received a comment letter opposing Nasdaq's proposal and a response letter from Nasdaq.
Regarding Nasdaq's proposal, the commenter specifically questions whether allowing Post-Only Orders to lock Non-Displayed Orders would help or enhance price discovery.
In response to these comments, Nasdaq states that its proposal to modify the processing of Post-Only Orders under a narrow set of conditions would ensure that the market operates as efficiently as possible, reduce information leakage, and improve execution quality.
After careful review, the Commission finds that the proposed rule changes, as modified by Amendments No. 1, are consistent with the requirements of the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission notes that the Exchanges believe that the proposals related to the interaction between Post-Only Orders and Non-Displayed Orders would help to reduce the information leakage that can occur when a Post-Only Order re-prices to avoid locking or crossing the price of a Non-Displayed Order resting on the respective Exchange's book.
The Commission notes that the Exchanges' proposals to discontinue pricing and executing Midpoint Peg Post-Only Orders (Nasdaq only) and Orders with Midpoint Pegging when the NBBO is crossed would reflect that the midpoint of a crossed market is not a clear and accurate indication of a valid price and would avoid mispriced executions. The Commission also notes that this proposed behavior is similar to the rules of other exchanges.
Based on the foregoing and the Exchanges' representations, the Commission believes that the proposed rule changes, as modified by Amendments No. 1, are consistent with the Act.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to adopt a Decommission Extension Fee for receipt of the NYSE Order Imbalances market data product. The proposed 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 adopt a Decommission Extension Fee for receipt of the NYSE Order Imbalances market data product,
NYSE Order Imbalances is an NYSE-only market data feed of real-time order imbalances that accumulate prior to the opening of trading on the Exchange and prior to the close of trading on the Exchange. The Exchange distributes information about these imbalances in real-time at specified intervals prior to the opening and closing auction each day.
As part of the Exchange's efforts to regularly upgrade systems to support more modern data distribution formats and protocols as technology evolves,
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes that adopting an extension fee for subscribers of NYSE Order Imbalances who wish to receive this data feed in the legacy format for a period of time beyond the built-in overlap period is reasonable, equitable and not unfairly discriminatory because the proposed fee would apply equally to all data recipients that currently subscribe to NYSE Order Imbalances. The Exchange believes that it is reasonable to require data recipients to pay an additional fee for taking the data feed in the legacy format beyond the period of time specifically allotted by the Exchange for data feed customers to adapt to the new XDP format at no extra cost. To that end, the extension fee is designed to encourage data recipients to migrate to the XDP format in order to continue to receive NYSE Order Imbalances in XDP as the legacy format would no longer be available after that date. The Exchange does not intend to support the legacy format at all after April 28, 2017.
The Exchange notes that NYSE Order Imbalances is entirely optional. The Exchange is not required to make NYSE Order Imbalances available or to offer any specific pricing alternatives to any customers, nor is any firm required to purchase NYSE Order Imbalances, nor is the Exchange required to offer any feed (NYSE Order Imbalances, or otherwise) in a particular format, and it is a benefit to the markets generally that NYSE update its distribution technology to make it more efficient (and at the same time eliminate less efficient forms of dissemination). Firms that do purchase NYSE Order Imbalances do so for the primary goals of using them to increase revenues, reduce expenses, and in some instances compete directly with the Exchange (including for order flow); those firms are able to determine for themselves whether NYSE Order Imbalances or any other similar products are attractively priced or not.
The decision of the United States Court of Appeals for the District of Columbia Circuit in
In fact, the legislative history indicates that the Congress intended that the market system `evolve through the interplay of competitive forces as unnecessary regulatory restrictions are removed' and that the SEC wield its regulatory power `in those situations where competition may not be sufficient,' such as in the creation of a `consolidated transactional reporting system.'
As explained below in the Exchange's Statement on Burden on Competition, the Exchange believes that there is substantial evidence of competition in the marketplace for proprietary market data and that the Commission can rely upon such evidence in concluding that the fees established in this filing are the product of competition and therefore satisfy the relevant statutory standards. In addition, the existence of alternatives to the legacy format, such as converting to XDP as soon as possible, further ensures that the Exchange cannot set unreasonable fees, or fees that are unreasonably discriminatory, when vendors and subscribers can select such alternatives.
As the
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. An
The market for proprietary data products is currently competitive and inherently contestable because there is fierce competition for the inputs necessary for the creation of proprietary data and strict pricing discipline for the proprietary products themselves. Numerous exchanges compete with one another for listings and order flow and sales of market data itself, providing ample opportunities for entrepreneurs who wish to compete in any or all of those areas, including producing and distributing their own market data. Proprietary data products are produced and distributed by each individual exchange, as well as other entities, in a vigorously competitive market. Indeed, the U.S. Department of Justice (“DOJ”) (the primary antitrust regulator) has expressly acknowledged the aggressive actual competition among exchanges, including for the sale of proprietary market data. In 2011, the DOJ stated that exchanges “compete head to head to offer real-time equity data products. These data products include the best bid and offer of every exchange and information on each equity trade, including the last sale.”
Moreover, competitive markets for listings, order flow, executions, and transaction reports provide pricing discipline for the inputs of proprietary data products and therefore constrain markets from overpricing proprietary market data. Broker-dealers send their order flow and transaction reports to multiple venues, rather than providing them all to a single venue, which in turn reinforces this competitive constraint. As a 2010 Commission Concept Release noted, the “current market structure can be described as dispersed and complex” with “trading volume . . . dispersed among many highly automated trading centers that compete for order flow in the same stocks” and “trading centers offer[ing] a wide range of services that are designed to attract different types of market participants with varying trading needs.”
If an exchange succeeds in competing for quotations, order flow, and trade executions, then it earns trading revenues and increases the value of its proprietary market data products because they will contain greater quote and trade information. Conversely, if an exchange is less successful in attracting quotes, order flow, and trade executions, then its market data products may be less desirable to customers in light of the diminished content and data products offered by competing venues may become more attractive. Thus, competition for quotations, order flow, and trade executions puts significant pressure on an exchange to maintain both execution and data fees at reasonable levels.
In addition, in the case of products that are also redistributed through market data vendors, such as Bloomberg and Thompson Reuters, the vendors themselves provide additional price discipline for proprietary data products because they control the primary means of access to certain end users. These vendors impose price discipline based upon their business models. For example, vendors that assess a surcharge on data they sell are able to refuse to offer proprietary products that their end users do not or will not purchase in sufficient numbers. Vendors will not elect to make available NYSE Order Imbalances in the legacy format unless their customers request it, and customers will not elect to pay the proposed fees unless NYSE Order Imbalances can provide value in the legacy formats by sufficiently increasing revenues or reducing costs in the customer's business in a manner that will offset the fees. The Exchange has provided customers with adequate notice that it intends to discontinue dissemination of the data feed in the legacy format. Therefore, the proposed Decommission Extension Fee would only be applicable to those customers who have a need or desire to continue to take the data feed in the legacy format beyond the period provided for migration to the XDP format. Customers who timely migrate to the XDP format to receive the data feed would not need to receive the data feed in the legacy format and therefore would not be subject to the Decommission Extension Fee at all. All of these factors operate as constraints on pricing proprietary data products.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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.
November 10, 2016.
On July 26, 2016, NYSE Arca, Inc. filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Commission has not received any comments on the proposed rule change. The Commission is publishing this notice to solicit comments on Amendment No. 2 from interested persons and is approving the proposed rule change, as modified by Amendment No. 2 thereto, on an accelerated basis.
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 Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant parts of such statements.
The Exchange proposes to list and trade shares (“Shares”) of the following under NYSE Arca Equities Rule 8.600, which governs the listing and trading of Managed Fund Shares:
The investment adviser to the Fund will be Virtus ETF Advisers LLC (the “Adviser”). The Fund's sub-adviser will be Cumberland Advisors Inc. (“Sub-Adviser”). Virtus ETF Solutions LLC will serve as the Fund's operational administrator. ETF Distributors LLC will serve as the distributor (the “Distributor”) of Fund Shares on an agency basis. The Bank of New York Mellon (the “Administrator”) will serve as the administrator, custodian, transfer agent and fund accounting agent for the Fund.
Commentary .06 to Rule 8.600 provides that, if the investment adviser to the investment company issuing Managed Fund Shares is affiliated with a broker-dealer, such investment adviser shall erect a “fire wall” between the investment adviser and the broker-dealer with respect to access to information concerning the composition and/or changes to such investment company portfolio.
According to the Registration Statement, the Fund will seek to provide a competitive level of current income exempt from federal income tax, while preserving capital. The Fund, under normal market conditions,
According to the Registration Statement, Municipal Bonds in which the Fund may invest include one or more of the following:
• General obligation bonds, which are typically backed by the full faith, credit, and taxing power of the issuer;
• revenue bonds, which are typically secured by revenues generated by the issuer;
• discount bonds, which may be originally issued at a discount to par value or sold at market price below par value;
• premium bonds, which are sold at a premium to par value;
• zero coupon bonds, which are issued at an original issue discount, with the full value, including accrued interest, paid at maturity; and
• private activity bonds, which are typically issued by or on behalf of local or state government for the purpose of financing the project of a private user.
The Fund will have no target duration for its investment portfolio, and the Sub-Adviser may target a shorter or longer average portfolio duration based on the Sub-Adviser's forecast of interest rates and view of fixed-income markets generally.
With respect to credit quality, under normal market conditions, at least 90% of the Fund's assets invested in Municipal Bonds will be in Municipal Bonds rated “A” or better by at least one major credit rating agency or, if unrated, deemed to be of comparable quality in the Adviser's opinion. From time to time, the Fund may concentrate in particular sectors; however, the Fund's investments will be diversified among a minimum of ten distinct Municipal Bond sectors.
Under normal market conditions, each Municipal Bond held by the Fund
According to the Registration Statement, under normal market conditions, at least 80% of the Fund's income will be exempt from federal income taxes. However, a significant portion of the Fund's income could be derived from securities subject to the alternative minimum tax.
While the Fund, under normal market conditions, will invest at least eighty percent (80%) of its assets in Municipal Bonds, as described above, the Fund may invest its remaining assets in other assets and financial instruments, as described below.
The Fund may invest in equity securities, both directly and indirectly through investment in shares of exchange-traded funds (“ETFs”),
The Fund may purchase taxable municipal bonds when the Sub-Adviser believes they offer opportunities for the Fund, or variable rate demand notes (VRDNs) that pay interest monthly or quarterly based on a floating rate that is reset daily or weekly based on an index of short-term municipal rates.
The Fund may invest in exchange-traded and OTC securities convertible into common stock. Such securities are the following: Convertible bonds and convertible preferred stocks.
The Fund may invest directly and indirectly in cash equivalents, namely, money market instruments that are the following: U.S. Government obligations or corporate debt obligations (including those subject to repurchase agreements); banker's acceptances
In order to maintain sufficient liquidity, to implement investment strategies or for temporary defensive purposes, the Fund may invest a significant portion of its assets in shares of one or more money market funds. Generally, money market mutual funds are registered investment companies that seek to earn income consistent with the preservation of capital and maintenance of liquidity by investing primarily in high quality money market instruments.
The Fund may invest in compliance with Section 12(d)(1)(E), (F) and (G) of the 1940 Act and the rules thereunder.
The Fund may write U.S. exchange-traded call and put options on securities, ETFs or security indexes to seek income or may purchase or write U.S. exchange-traded put or call options for hedging purposes.
The Fund may purchase securities on a when-issued basis or for settlement at a future date (forward commitment) if the Fund holds sufficient liquid assets to meet the purchase price.
Additionally, the Trust, on behalf of the Fund, has claimed an exclusion from the definition of the term “commodity pool operator” pursuant to Rule 4.5 under the Commodity Exchange Act, as amended (the “CEA”). Therefore, the Fund is not subject to regulation or registration as a commodity pool operator under the CEA.
The Fund may, from time to time, take temporary defensive positions that are inconsistent with its principal investment strategies in an attempt to respond to adverse market, economic, political or other conditions. In such circumstances, the Fund may also hold up to 100% of its portfolio in cash and cash equivalent positions.
The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), consistent with Commission guidance. The Fund will monitor its portfolio liquidity on an ongoing basis to determine whether, in light of current circumstances, an adequate level of liquidity is being maintained, and will consider taking appropriate steps in order to maintain adequate liquidity if, through a change in values, net assets, or other circumstances, more than 15% of the Fund's net assets are held in illiquid assets. Illiquid assets include securities subject to contractual or other restrictions on resale and other instruments that lack readily available markets as determined in accordance with Commission staff guidance.
The Fund will seek to qualify for treatment as a regulated investment company under the Internal Revenue Code of 1986.
The Fund's investments will be consistent with its investment objective and will not be used to provide multiple returns of a benchmark or to produce leveraged returns.
According to the Registration Statement, the Trust will issue and sell Shares of the Fund only in “Creation Units” on a continuous basis through the Distributor, at their net asset value (“NAV”) next determined after receipt, on any business day, for an order received in proper form. All orders to create Creation Units must be placed for one or more Creation Unit size aggregations of Shares (50,000 Shares per Creation Unit). The Creation Unit size is subject to change. Cash creations will be the default mechanism for creation of Shares.
However, the Fund will retain the ability to utilize an in-kind mechanism for creation of Shares, upon approval of the Distributor. In such case, the consideration for purchase of a Creation Unit of the Fund generally will consist of an in-kind deposit of “Deposit Securities” for each Creation Unit constituting a substantial replication, or a representation, of the securities included in the Fund's portfolio and a “Cash Component” computed as described below. Together, the Deposit Securities and the Cash Component constitute the “Fund Deposit”, which represents the minimum initial and subsequent investment amount for a Creation Unit of the Fund. The Cash Component is an amount equal to the difference between the NAV of the Shares (per Creation Unit) and the market value of the Deposit Securities. If the Cash Component is a positive number (
The Administrator, through the National Securities Clearing Corporation (“NSCC”), will make available on each business day, immediately prior to the opening of business on the Exchange (currently 9:30 a.m., Eastern Time), the list of the names and the required number of Shares of each Deposit Security to be included in the current Fund Deposit (based on information at the end of the previous business day) for the Fund. Such Fund Deposit will be applicable, subject to any adjustments as described below, in order to effect creations of Creation Units of the Fund until such time as the next-announced composition of the Deposit Securities is made available.
The identity and number of Shares of the Deposit Securities required for the Fund Deposit for the Fund will change as rebalancing adjustments and corporate action events occur from time to time. In addition, the Trust reserves the right to permit or require the substitution of an amount of cash—
In addition to the list of names and numbers of securities constituting the current Deposit Securities of the Fund Deposit, the Administrator, through NSCC, also will make available on each business day the estimated Cash Component, effective through and including the previous business day, per outstanding Creation Unit of the Fund.
To be eligible to place orders to create a Creation Unit of the Fund, an entity must be (i) a “Participating Party”,
All orders to create Creation Units must be received by the Distributor no later than the close of the Core Trading Session on the Exchange (ordinarily 4:00 p.m., Eastern Time), in each case on the date such order is placed in order for the creation of Creation Units to be effected based on the NAV of Shares of the Fund as next determined on such date after receipt of the order in proper form.
Shares may be redeemed only in Creation Units at their NAV next determined after receipt of a redemption request in proper form by the Distributor and the Fund through the Administrator and only on a business day. Cash redemptions will be the default mechanism for redemptions of Shares.
However, the Fund will retain the ability to utilize an in-kind mechanism for redemption of Shares, upon approval of the Distributor. In such case, the redemption proceeds for a Creation Unit generally consist of Deposit Securities, as announced by the Administrator on the business day of the request for redemption received in proper form, plus cash in an amount equal to the difference between the NAV of the Shares being redeemed, as next determined after a receipt of a request in proper form, and the value of the Deposit Securities (the “Cash Redemption Amount”), less a redemption transaction fee. In the event that the Deposit Securities have a value greater than the NAV of the Shares, a compensating cash payment equal to the differential is required to be made by or through an Authorized Participant by the redeeming shareholder.
With respect to the Fund, the Administrator, through NSCC, will make available immediately prior to the opening of business on the Exchange (currently 9:30 a.m., Eastern Time) on each business day, the Deposit Securities that will be applicable (subject to possible amendment or correction) to redemption requests received in proper form on that day. Deposit Securities received on redemption may not be identical to Deposit Securities which are applicable to creations of Creation Units.
If it is not possible to effect deliveries of the Deposit Securities, the Trust may in its discretion exercise its option to redeem such shares in cash, and the redeeming beneficial owner will be required to receive its redemption proceeds in cash. In addition, an investor may request a redemption in
The right of redemption may be suspended or the date of payment postponed with respect to the Fund (1) for any period during which the Exchange is closed (other than customary weekend and holiday closings); (2) for any period during which trading on the Exchange is suspended or restricted; (3) for any period during which an emergency exists as a result of which disposal of the Shares of the Fund or determination of the Shares' NAV is not reasonably practicable; or (4) in such other circumstance as is permitted by the Commission.
The NAV per Share for the Fund will be computed by dividing the value of the net assets of the Fund (
The pricing and valuation of portfolio securities will be determined in good faith in accordance with procedures approved by, and under the direction of, the Trust's Board of Trustees (“Board”). In determining the value of the Fund's assets, equity securities will be generally valued at market using quotations from the primary market in which they are traded. Debt securities (other than short-term investments) will be valued on the basis of broker quotes or valuations provided by a pricing service, which in determining value will utilize information regarding recent sales, market transactions in comparable securities, quotations from dealers, and various relationships between securities. Other assets, such as accrued interest, accrued dividends and cash also will be included in determining the NAV. The Fund normally will use third party pricing services to obtain portfolio security prices.
Municipal Bonds, money market instruments, convertible bonds, taxable municipal bonds, and VRDNs will generally be valued at bid prices received from independent pricing services as of the announced closing time for trading in fixed-income instruments in the respective market.
Exchange-traded equity securities, including common stocks, ETFs, preferred stocks, convertible preferred stocks and warrants, will be valued at market value, which will generally be determined using the last reported official closing or last trading price on the exchange or market on which the security is primarily traded at the time of valuation or, if no sale has occurred, at the last quoted bid price on the primary market or exchange on which they are traded. If market prices are unavailable or the Fund believes that they are unreliable, or when the value of a security has been materially affected by events occurring after the relevant market closes, the Fund will price those securities at fair value as determined in good faith using methods approved by the Trust's Board.
Equity securities traded in the OTC market, including common stocks, preferred stocks, and warrants, will be valued at the last reported sale price on the valuation date. OTC traded convertible preferred stocks will be valued based on price quotations obtained from a broker-dealer who makes markets in such securities or other equivalent indications of value provided by a third-party pricing service. Securities of money market funds will be valued at NAV.
Option contracts will be valued at their most recent sale price on the applicable exchange. If no such sales are reported, these contracts will be valued at their most recent bid price.
To the extent the assets of the Fund are invested in other open-end investment companies that are registered under the 1940 Act, the Fund's NAV will be calculated based upon the NAVs reported by such registered open-end investment companies.
Securities and assets for which market quotations are not readily available or which cannot be accurately valued using the Fund's normal pricing procedures will be valued by the Trust's Fair Value Pricing Committee at fair value as determined in good faith under policies approved by the Board. Fair value pricing may be used, for example, in situations where (i) portfolio securities, such as securities with small capitalizations, are so thinly traded that there have been no transactions for that security over an extended period of time; (ii) an event occurs after the close of the exchange on which a portfolio security is principally traded that is likely to change the value of the portfolio security prior to the Fund's NAV calculation; (iii) the exchange on which the portfolio security is principally traded closes early; or (iv) trading of the particular portfolio security is halted during the day and does not resume prior to the Fund's NAV calculation. The Board will monitor and evaluate the Fund's use of fair value pricing, and periodically reviews the results of any fair valuation under the Trust's policies.
The Fund's Web site (
The Fund will disclose on the Fund's Web site the following information regarding each portfolio holding, as applicable to the type of holding: Ticker symbol, CUSIP number or other identifier, if any; a description of the holding (including the type of holding); the identity of the security, index or other asset or instrument underlying the holding, if any; for options, the option strike price; quantity held (as measured by, for example, par value, notional value or number of shares, contracts or units); maturity date, if any; coupon rate, if any; effective date, if any; market value of the holding; and the percentage weighting of the holding in the Fund's portfolio. The Web site information will be publicly available at no charge.
In addition, a basket composition file, which includes the security names and share quantities, if applicable, required to be delivered in exchange for the Fund's Shares, together with estimates and actual cash components, will be publicly disseminated daily prior to the opening of the Exchange via the NSCC. The basket represents one Creation Unit of the Fund. The NAV of Shares of the Fund will normally be determined as of the close of the Core Trading Session on the Exchange (ordinarily 4:00 p.m., Eastern Time) on each business day. Authorized Participants may refer to the basket composition file for information regarding securities and financial instruments that may comprise the Fund's basket on a given day.
The approximate value of the Fund's investments on a per-Share basis, the Indicative Intra-Day Value (“IIV”), will be disseminated every 15 seconds during the Exchange Core Trading Session (ordinarily 9:30 a.m. to 4:00 p.m., Eastern Time). The IIV should not be viewed as a “real-time” update of NAV because the IIV will be calculated by an independent third party and may not be calculated in the exact same manner as NAV, which will be computed daily.
The IIV for the Fund will be calculated by dividing the “Estimated Fund Value” as of the time of the calculation by the total number of outstanding Shares. “Estimated Fund Value” is the sum of the estimated amount of cash held in the Fund's portfolio, the estimated amount of accrued interest owing to the Fund and the estimated value of the securities held in the Fund's portfolio, minus the estimated amount of the Fund's liabilities. The IIV will be calculated based on the same portfolio holdings disclosed on the Fund's Web site. In determining the estimated value for each of the component securities, the IIV will use last sale, market prices or other methods that would be considered appropriate for pricing securities held by registered investment companies.
Investors can also obtain the Trust's Statement of Additional Information (“SAI”), the Fund's shareholder reports, and its Form N-CSR and Form N-SAR, filed twice a year. The Trust's SAI and Shareholder Reports will be available free upon request from the Trust, and those documents and the Form N-CSR and Form N-SAR may be viewed on-screen or downloaded from the Commission's Web site at
Quotation and last sale information for the Shares and the underlying U.S. exchange-traded equity securities will be available via the Consolidated Tape Association (“CTA”) high-speed line, and from the national securities exchange on which they are listed. Price information regarding non-U.S. exchange-traded equity securities held by the Fund will be available from the exchanges trading such assets.
Quotation information from brokers and dealers or pricing services will be available for Municipal Bonds, taxable municipal bonds, convertible bonds, OTC traded convertible preferred stocks, corporate debt obligations, VRDNs, and cash equivalents. Price information for money market funds will be available from the applicable investment company's Web site and from market data vendors. Intra-day and closing price information for OTC equity securities will be available from major market data vendors. Pricing information regarding each asset class in which the Fund will invest will generally be available through nationally recognized data service providers through subscription agreements. Quotation and last sale information for exchange-traded options will be available via the Options Price Reporting Authority and from the applicable U.S. options exchange. In addition, the IIV, (which is the Portfolio Indicative Value, as defined in NYSE Arca Equities Rule 8.600(c)(3)), will be widely disseminated at least every 15 seconds during the Core Trading Session by one or more major market data vendors.
With respect to trading halts, the Exchange may consider all relevant factors in exercising its discretion to halt or suspend trading in the Shares of the Fund.
The Exchange deems the Shares to be equity securities, thus rendering trading in the Shares subject to the Exchange's existing rules governing the trading of equity securities. Shares will trade on the NYSE Arca Marketplace from 4 a.m. to 8 p.m., Eastern Time in accordance with NYSE Arca Equities Rule 7.34 (Opening, Core, and Late Trading Sessions). The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions. As provided in NYSE Arca Equities Rule 7.6, Commentary .03, the minimum price variation (“MPV”) for quoting and entry of orders in equity securities traded on the NYSE Arca Marketplace is $0.01, with the exception of securities that are priced less than $1.00 for which the MPV for order entry is $0.0001.
The Shares will conform to the initial and continued listing criteria under NYSE Arca Equities Rule 8.600. Consistent with NYSE Arca Equities Rule 8.600(d)(2)(B)(ii), the Adviser will implement and maintain, or be subject to, procedures designed to prevent the
The Exchange represents that trading in the Shares will be subject to the existing trading surveillances, administered by the Financial Industry Regulatory Authority (“FINRA”) on behalf of the Exchange, or by regulatory staff of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws. The Exchange represents that these procedures are adequate to properly monitor Exchange trading of the Shares in all trading sessions and to deter and detect violations of Exchange rules and federal securities laws applicable to trading on the Exchange.
The surveillances referred to above generally focus on detecting securities trading outside their normal patterns, which could be indicative of manipulative or other violative activity. When such situations are detected, surveillance analysis follows and investigations are opened, where appropriate, to review the behavior of all relevant parties for all relevant trading violations.
FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, will communicate as needed regarding trading in the Shares, options and certain exchange-traded equity securities with other markets and other entities that are members of the ISG, and FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, may obtain trading information regarding trading in the Shares, options and certain exchange-traded equity securities from such markets and other entities. In addition, the Exchange may obtain information regarding trading in the Shares, options and certain exchange-traded equity securities from markets and other entities that are members of ISG or with which the Exchange has in place a comprehensive surveillance sharing agreement. In addition, FINRA, on behalf of the Exchange, is able to access, as needed, trade information for certain fixed income securities held by the Fund reported to FINRA's Trade Reporting and Compliance Engine (“TRACE”). FINRA also can access data obtained from the Municipal Securities Rulemaking Board (“MSRB”) relating to municipal bond trading activity for surveillance purposes in connection with trading in the Shares.
In addition, the Exchange also has a general policy prohibiting the distribution of material, non-public information by its employees.
All statements and representations made in this filing regarding (a) the description of the portfolio, (b) limitations on portfolio holdings or reference assets, or (c) the applicability of Exchange rules and surveillance procedures shall constitute continued listing requirements for listing the Shares of the Fund on the Exchange.
The issuer has represented to the Exchange that it will advise the Exchange of any failure by the Fund to comply with the continued listing requirements, and, pursuant to its obligations under Section 19(g)(1) of the Act, the Exchange will monitor for compliance with the continued listing requirements. If the Fund is not in compliance with the applicable listing requirements, the Exchange will commence delisting procedures under NYSE Arca Equities Rule 5.5(m).
Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit Holders in an Information Bulletin (“Bulletin”) of the special characteristics and risks associated with trading the Shares. Specifically, the Bulletin will discuss the following: (1) The procedures for purchases and redemptions of Shares in Creation Unit aggregations (and that Shares are not individually redeemable); (2) NYSE Arca Equities Rule 9.2(a), which imposes a duty of due diligence on its Equity Trading Permit Holders to learn the essential facts relating to every customer prior to trading the Shares; (3) the risks involved in trading the Shares during the Opening and Late Trading Sessions when an updated IIV will not be calculated or publicly disseminated; (4) how information regarding the IIV and the Disclosed Portfolio is disseminated; (5) the requirement that Equity Trading Permit Holders deliver a prospectus to investors purchasing newly issued Shares prior to or concurrently with the confirmation of a transaction; and (6) trading information.
In addition, the Bulletin will reference that the Fund is subject to various fees and expenses described in the Registration Statement. The Bulletin will discuss any exemptive, no-action, and interpretive relief granted by the Commission from any rules under the Act. The Bulletin will also disclose that the NAV for the Shares will be calculated after 4:00 p.m., Eastern Time each trading day.
The basis under the Act for this proposed rule change is the requirement under Section 6(b)(5)
The Exchange believes that the proposed rule change is designed to prevent fraudulent and manipulative acts and practices in that the Shares will be listed and traded on the Exchange pursuant to the initial and continued listing criteria in NYSE Arca Equities Rule 8.600. The Exchange has in place surveillance procedures that are adequate to properly monitor trading in the Shares in all trading sessions and to deter and detect violations of Exchange rules and applicable federal securities laws. FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, will communicate as needed regarding trading in the Shares, options and certain exchange-traded equity securities with other markets and other entities that are members of the ISG, and FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, may obtain trading information regarding trading in the Shares, options and certain exchange-traded equity securities from such markets and other entities. In addition, the Exchange may obtain information regarding trading in
The proposed rule change is designed to promote just and equitable principles of trade and to protect investors and the public interest in that the Exchange will obtain a representation from the issuer of the Shares that the NAV per Share will be calculated daily and that the NAV and the Disclosed Portfolio will be made available to all market participants at the same time. In addition, a large amount of information is publicly available regarding the Fund and the Shares, thereby promoting market transparency. Quotation and last sale information for the Shares and the underlying U.S. exchange-traded equity securities will be available via the CTA high-speed line, and from the national securities exchange on which they are listed. The Fund will disclose on the Fund's Web site the following information regarding each portfolio holding, as applicable to the type of holding: Ticker symbol, CUSIP number or other identifier, if any; a description of the holding (including the type of holding); the identity of the security, index or other asset or instrument underlying the holding, if any; for options, the option strike price; quantity held (as measured by, for example, par value, notional value or number of shares, contracts or units); maturity date, if any; coupon rate, if any; effective date, if any; market value of the holding; and the percentage weighting of the holding in the Fund's portfolio. Moreover, prior to the commencement of trading, the Exchange will inform its Equity Trading Permit Holders in an Information Bulletin of the special characteristics and risks associated with trading the Shares. Trading in Shares of the Fund will be halted if the circuit breaker parameters in NYSE Arca Equities Rule 7.12 have been reached or because of market conditions or for reasons that, in the view of the Exchange, make trading in the Shares inadvisable. Trading in the Shares will be subject to NYSE Arca Equities Rule 8.600(d)(2)(D), which sets forth circumstances under which Shares of the Fund may be halted. In addition, as noted above, investors will have ready access to information regarding the Fund's holdings, the IIV, the Disclosed Portfolio, and quotation and last sale information for the Shares.
The proposed rule change is designed to perfect the mechanism of a free and open market and, in general, to protect investors and the public interest in that it will facilitate the listing and trading of an additional type of actively-managed exchange-traded product that principally holds municipal bonds and that will enhance competition among market participants, to the benefit of investors and the marketplace. As noted above, the Exchange has in place surveillance procedures relating to trading in the Shares and may obtain information via ISG from other exchanges that are members of ISG or with which the Exchange has entered into a comprehensive surveillance sharing agreement. In addition, as noted above, investors will have ready access to information regarding the Fund's holdings, the IIV, the Disclosed Portfolio, and quotation and last sale information for the Shares.
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 purpose of the Act. The Exchange notes that the proposed rule change will facilitate the listing and trading of an additional type of actively-managed exchange-traded product that principally holds municipal bonds and that will enhance competition among market participants, to the benefit of investors and the marketplace.
No written comments were solicited or received with respect to the proposed rule change.
After careful review, the Commission finds that the Exchange's proposal to list and trade the Shares is consistent with the Act and the rules and regulations thereunder applicable to a national securities exchange.
The Commission also finds that the proposal to list and trade the Shares on the Exchange is consistent with Section 11A(a)(1)(C)(iii) of the Act,
The approximate value of the Fund's investments on a per-Share basis, the IIV (which is the Portfolio Indicative Value, as defined in NYSE Arca Equities Rule 8.600(c)(3)), will be disseminated every 15 seconds during the Exchange Core Trading Session (ordinarily 9:30 a.m. to 4:00 p.m., Eastern Time) by one or more major market data vendors.
Information regarding market price and trading volume of the Shares will be continually available on a real-time basis throughout the day on brokers' computer screens and other electronic services. Information regarding the previous day's closing price and trading volume information for the Shares will be published daily in the financial section of newspapers. In addition, price information regarding non-U.S. exchange-traded equity securities held by the Fund will be available from the exchanges trading such assets. Quotation information from brokers and dealers or pricing services will be available for Municipal Bonds, taxable municipal bonds, convertible bonds, OTC traded convertible preferred stocks, corporate debt obligations, VRDNs, and cash equivalents. Price information for money market funds will be available from the applicable investment company's Web site and from market data vendors. Intra-day and closing price information for OTC equity securities will be available from major market data vendors. Pricing information regarding each asset class in which the Fund will invest will generally be available through nationally recognized data service providers through subscription agreements. Quotation and last-sale information for exchange-traded options will be available via the Options Price Reporting Authority and from the applicable U.S. options exchange. The Fund's Web site will include a form of the prospectus for the Fund and additional data relating to NAV and other applicable quantitative information.
The Commission further believes that the proposal to list and trade the Shares is reasonably designed to promote fair disclosure of information that may be necessary to price the Shares appropriately and to prevent trading when a reasonable degree of transparency cannot be assured. The Exchange will obtain a representation from the issuer of the Shares that the NAV per Share will be calculated daily and that the NAV and the Disclosed Portfolio will be made available to all market participants at the same time. Trading in Shares of the Fund will be halted if the circuit breaker parameters in NYSE Arca Equities Rule 7.12 have been reached or because of market conditions or for reasons that, in the view of the Exchange, make trading in the Shares inadvisable,
The Exchange represents that it has a general policy prohibiting the distribution of material, non-public information by its employees. In addition, Commentary .06 to NYSE Arca Equities Rule 8.600 further requires that personnel who make decisions on the open-end fund's portfolio composition must be subject to procedures designed to prevent the use and dissemination of material, non-public information regarding the open-end fund's portfolio. The Exchange represents that the Adviser and Sub-Adviser are not registered as broker-dealers; however, the Adviser (but not the Sub-Adviser) is affiliated with one or more broker-dealers, and the Adviser has implemented and will maintain a fire wall with respect to each such broker-dealer affiliate regarding access to information concerning the composition of, or changes to, the portfolio.
Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit Holders in a Bulletin of the special characteristics and risks associated with trading the Shares. The Exchange represents that trading in the Shares will be subject to the existing trading surveillances, administered by the FINRA on behalf of the Exchange, or by regulatory staff of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws.
The Exchange represents that it deems the Shares to be equity securities, thus rendering the trading of the Shares subject to the Exchange's existing rules governing the trading of equity securities.
In support of this proposal, the Exchange has made the following additional representations:
(1) The Shares will conform to the initial and continued listing criteria under NYSE Arca Equities Rule 8.600.
(2) The Exchange has appropriate rules to facilitate transactions in the Shares during all trading sessions.
(3) Trading in the Shares will be subject to the existing trading surveillances, administered by FINRA on behalf of the Exchange, or by regulatory staff of the Exchange, which are designed to detect violations of Exchange rules and applicable federal securities laws. The Exchange represents that these procedures are adequate to properly monitor Exchange trading of the Shares in all trading sessions and to deter and detect violations of Exchange rules and federal securities laws applicable to trading on the Exchange. These surveillances focus on detecting securities trading outside their normal patterns, which could be indicative of manipulative or other violative activity. When such situations are detected, surveillance analysis follows and investigations are opened, where appropriate, to review the behavior of all relevant parties for all relevant trading violations.
(4) FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, will communicate as needed regarding trading in the Shares, options, and certain exchange-traded equity securities with other markets and other entities that are members of the ISG, and FINRA, on behalf of the Exchange, or regulatory staff of the Exchange, may obtain trading information regarding trading in the Shares, options, and certain exchange-traded equity securities from such markets and other entities. In addition, the Exchange may obtain information regarding trading in the Shares, options, and certain exchange-traded equity securities from markets and other entities that are members of ISG or with which the Exchange has in place a comprehensive surveillance sharing agreement. In addition, FINRA, on behalf of the Exchange, is able to access, as needed, trade information for certain fixed income securities held by the Fund reported to FINRA's Trade Reporting and Compliance Engine. FINRA also can access data obtained from the Municipal Securities Rulemaking Board relating to municipal bond trading activity for surveillance purposes in connection with trading in the Shares.
(5) Prior to the commencement of trading, the Exchange will inform its Equity Trading Permit Holders in a Bulletin of the special characteristics and risks associated with trading the Shares. Specifically, the Bulletin will discuss the following: (a) The procedures for purchases and redemptions of Shares in Creation Unit aggregations (and that Shares are not individually redeemable); (b) NYSE Arca Equities Rule 9.2(a), which imposes a duty of due diligence on its Equity Trading Permit Holders to learn the essential facts relating to every customer prior to trading the Shares; (c) the risks involved in trading the Shares during the Opening and Late Trading Sessions when an updated IIV will not be calculated or publicly disseminated; (d) how information regarding the IIV and the Disclosed Portfolio is disseminated; (e) the requirement that Equity Trading Permit Holders deliver a prospectus to investors purchasing newly issued Shares prior to or concurrently with the confirmation of a transaction; and (f) trading information. The Bulletin will also discuss any exemptive, no-action, and interpretive relief granted by the Commission from any rules under the Act.
(6) For initial and continued listing, the Fund must be in compliance with Rule 10A-3 under the Act.
(7) At least 80% of the weight of the Fund's assets will be in Municipal Bonds with a modified duration of 15 years or less. With respect to credit quality, under normal market conditions, at least 90% of the Fund's assets invested in Municipal Bonds will be in Municipal Bonds rated “A” or better by at least one major credit rating agency or, if unrated, deemed to be of comparable quality in the Adviser's opinion.
(8) The Fund's Municipal Bond investments will be diversified among a minimum of ten distinct Municipal Bond sectors.
(9) Under normal market conditions, each Municipal Bond held by the Fund must be a constituent of a deal where the deal's original offering amount was at least $100 million. The Fund will hold a minimum of 75 different Municipal Bonds. No Municipal Bond held by the Fund will exceed 4% of the weight of the Fund's portfolio and no single Municipal Bond issuer will account for more than 10% of the weight of the Fund's portfolio. The Fund will hold Municipal Bonds of a minimum of 40 non-affiliated issuers diversified among issuers in at least 20 different states, with no more than 30% of the Fund's assets comprised of Municipal Bonds that provide exposure to any single state.
(10) The ETFs in which the Fund may invest will be registered under the 1940 Act and will be listed and traded in the U.S. on registered exchanges. With respect to its exchange-traded equity securities investments (including exchange-traded convertible preferred stocks and exchange-traded stocks into which convertible bonds may be converted), the Fund will normally invest in equity securities that are listed and traded on a U.S. exchange or in markets that are members of the ISG or parties to a comprehensive surveillance sharing agreement with the Exchange. In any case, not more than 10% of the net assets of the Fund in the aggregate invested in equity securities (except for money market funds) will consist of equity securities whose principal market is not a member of ISG or a market with which the Exchange does not have a comprehensive surveillance sharing agreement.
(11) The Fund may hold up to an aggregate amount of 15% of its net assets in illiquid assets (calculated at the time of investment), consistent with Commission guidance. The Fund will monitor its portfolio liquidity on an ongoing basis to determine whether, in light of current circumstances, an adequate level of liquidity is being maintained, and will consider taking appropriate steps in order to maintain adequate liquidity if, through a change in values, net assets, or other circumstances, more than 15% of the Fund's net assets are held in illiquid assets. Illiquid assets include securities subject to contractual or other restrictions on resale and other instruments that lack readily available markets as determined in accordance with Commission staff guidance.
(12) The Fund's investments will be consistent with its investment objective and will not be used to provide multiple returns of a benchmark or to produce leveraged returns.
The Exchange also represents that all statements and representations made in this filing regarding (a) the description of the portfolio, (b) limitations on portfolio holdings or reference assets, or (c) the applicability of Exchange rules
The issuer has represented to the Exchange that it will advise the Exchange of any failure by the Fund to comply with the continued listing requirements, and, pursuant to its obligations under Section 19(g)(1) of the Act, the Exchange will monitor for compliance with the continued listing requirements.
This approval order is based on all of the Exchange's representations, including those set forth above and in the Notice, and the Exchange's description of the Fund. The Commission notes that the Fund and the Shares must comply with the requirements of NYSE Arca Equities Rule 8.600 to be listed and traded on the Exchange.
For the foregoing reasons, the Commission finds that the proposed rule change is consistent with Section 6(b)(5) of the Act
Interested persons are invited to submit written data, views, and arguments concerning whether Amendment No. 2 to the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
The Commission finds good cause to approve the proposed rule change, as modified by Amendment No. 2 thereto, prior to the thirtieth day after the date of publication of notice of the filing of Amendment No. 2 in the
(1) The Fund's Municipal Bond investments will be diversified among a minimum of ten distinct Municipal Bond sectors.
(2) The Fund will limit its investments in Municipal Bonds in any single sector to 25% of the Fund's assets.
(3) Each Municipal Bond held by the Fund must be a constituent of a deal where the deal's original offering amount was at least $100 million.
(4) The Fund will hold a minimum of 75 different Municipal Bonds.
(5) No Municipal Bond held by the Fund will exceed 4% of the weight of the Fund's portfolio, and no single Municipal Bond issuer will account for more than 10% of the weight of the Fund's portfolio.
(6) The Fund will hold Municipal Bonds of a minimum of 40 non-affiliated issuers diversified among issuers in at least 20 different states, with no more than 30% of the Fund's assets comprised of Municipal Bonds that provide exposure to any single state.
The Commission believes that the addition of these investment restrictions helps to ensure that the proposed listing and trading of the Shares is consistent with the portion of Section 6(b)(5) of the Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The text of the proposed rule change is available on the Exchange's Web site (
In its filing with the Commission, the Exchange included statements concerning the purpose of and basis for the proposed rule change and discussed any comments it received on the proposed rule change. The text of these statements may be examined at the places specified in Item IV below. The Exchange has prepared summaries, set forth in sections A, B, and C below, of the most significant aspects of such statements.
The Exchange proposes to amend its Fees Schedule. Specifically, the Exchange proposes to amend its Fees Schedule with respect to waiving transaction fees incurred as a result of transactions that compress or reduce certain Clearing Trading Permit Holder (“TPH”) open positions.
By way of background, SEC Rule 15c3-1, Net Capital Requirements for Brokers or Dealers (“Net Capital Rules”), requires that every registered broker-dealer maintain certain specified minimum levels of capital. The primary purpose of these rules is to regulate the ability of broker-dealers to meet their financial obligations to customers and other creditors. All of the broker-dealers that are clearing members of the Options Clearing Corporation (“OCC”) are subject to the Net Capital Rules. However, a subset of OCC's clearing members are subsidiaries of U.S. bank holding companies and these broker-dealers, through their affiliation with their parent U.S. bank holding companies, must also comply with bank regulatory capital requirements pursuant to rule-making required under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”). Recent rule-making enacted under Dodd-Frank now requires U.S. bank holding companies to hold substantially more bank regulatory capital than would otherwise be required under the Net Capital Rules. Additionally, due to the large contract size of S&P 500 Index (“SPX”) options, open interest in certain SPX series can result in extremely large bank regulatory capital requirements, even though the positions incur minimal requirements under the Net Capital Rules. As such, transactions that would result in the closing of this open interest have a beneficial impact on the bank regulatory capital requirements of the Clearing TPH's parent company with a minimal impact on regulatory capital required under the capital rules. The Exchange notes that most of these open positions are in out-of-the-money options and certain spread positions that are essentially riskless strategies because they have little or no market exposure. Particularly, the Exchange notes that given the nature of these options, there is minimal chance for large losses to occur, yet these positions are still subject to large bank regulatory capital requirements. Exchange transaction fees, however, if not waived, could discourage market participants from closing these positions out even though those market participants may also prefer to close them rather than carry them to expiration.
The rebate of transaction fees
The Exchange believes the proposed rule change is consistent with the Securities Exchange Act of 1934 (the “Act”) and the rules and regulations thereunder applicable to the Exchange and, in particular, the requirements of Section 6(b) of the Act.
The Exchange believes providing a rebate of fees for transactions that compress certain out-of-the-money and riskless options positions is reasonable, equitable and not unfairly discriminatory because these positions would result in extremely large bank regulatory capital requirements for Clearing TPHs even though there is minimal chance for large losses to occur. Additionally, these positions have little or no economic benefit to the TPHs that hold the positions, who would likely prefer to close them but for the associated transaction fees. The fee rebate therefore allows TPHs to close out of these positions that are needlessly burdensome on themselves and Clearing TPHs.
The Exchange believes the proposed rule change is reasonable, equitable and not unfairly discriminatory because TPHs can now mitigate their regulatory capital requirements on a monthly basis, instead of quarterly. The proposed change would encourage the closing of positions at the end of each month that needlessly result in burdensome capital requirements that, once closed, would alleviate the capital requirement constraints on TPHs and improve overall market liquidity by freeing capital currently tied up in certain out-of-the-money and riskless positions. The Exchange also notes that the proposed amended requirement would apply to all TPHs seeking a rebate for these transactions.
The Exchange does not believe that the proposed rule changes will impose any burden on competition that are not necessary or appropriate in furtherance of the purposes of the Act. The Exchange does not believe that the proposed rule change will impose any burden on intramarket competition that is not necessary or appropriate in furtherance of the Act because it applies to all market participants in the same manner with positions that meet the eligible criteria. The proposed change would encourage the closing of positions, on a monthly basis, that needlessly result in burdensome capital requirements that, once closed, would alleviate the capital requirement constraints on TPHs and improve overall market liquidity by freeing capital currently tied up in certain out-of-the-money and riskless positions. The Exchange does not believe that the proposed rule change will impose any burden on intermarket competition that is not necessary or appropriate in furtherance of the purposes of the Act because the proposed rule change applies only to CBOE. To the extent that the proposed change makes CBOE a more attractive marketplace for market participants at other exchanges, such market participants are welcome to become CBOE market participants.
The Exchange neither solicited nor received comments on the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
FINRA is proposing to delay implementation of Rule 4554(b)(8). The proposed rule change would not make any other changes to FINRA rules.
The proposed rule change does not make any changes to the text of FINRA rules.
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.
In May 2016, the SEC approved Rule 4554 to further enhance FINRA's ability to reconstruct an ATS's order book and better perform its order-based surveillance, which includes surveillance for layering, quote spoofing, and mid-point pricing manipulation. To accomplish this, Rule 4554 requires ATSs to report order information for each order they receive in an NMS stock beyond that set forth in the OATS rules, such as order re-pricing events (
Rule 4554(b) requires that all ATSs report eight categories of information at the time of order receipt, including the sequence number assigned to the order event by the ATS's matching engine.
FINRA anticipates filing a proposed rule change with the SEC in the near future to extend the requirement to report a sequence number beyond order receipt because, without a sequence number on all order events, FINRA is unable to properly sequence events when a single ATS MPID reports order events in the same symbol with identical timestamps. However, because a proposed rule change has not yet been filed, FINRA is filing this proposed rule change to delay the implementation of the requirement in Rule 4554(b)(8) that ATSs report the sequence number assigned to the order event by the ATS's matching engine at the time of order receipt. FINRA will announce the implementation date for this requirement at the time it announces the implementation date for the extension of the requirement to all OATS order events.
FINRA has filed the proposed rule change for immediate effectiveness and has requested that the SEC waive the requirement that the proposed rule change not become operative for 30 days after the date of the filing, so FINRA can implement the proposed rule change immediately.
FINRA believes that the proposed rule change is consistent with the provisions of Section 15A(b)(6) of the Act,
FINRA does not believe that the proposed rule change will result in any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed delay in implementation of Rule 4554(b)(8) will reduce the burden on members by allowing additional time to implement the requirement to report the sequence number assigned to the order event by the ATS's matching engine at the time of order receipt.
Written comments were neither solicited nor received.
Because the foregoing proposed rule change does not (i) significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A)(iii) of the Act
A proposed rule change filed under Rule 19b-4(f)(6) normally does not become operative for 30 days after the date of its filing. However, Rule 19b-4(f)(6)(iii)
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 to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (the “Act”),
The Exchange proposes to amend Rule 4702 (Order Types) and Rule 4703 (Order Attributes) to add a “Trade Now” instruction to certain order types.
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.
BX proposes to amend Rules [sic] 4702 (Order Types) and Rule 4703 (Order Attributes) to add a “Trade Now” instruction to certain order types. BX will offer this functionality through its OUCH, RASH, FLITE, and FIX protocols. This instruction will provide resting orders with a greater ability to receive an execution when that resting order is locked,
When a Trade Now instruction is applied to a resting buy (sell) order, the order will execute against the available size of the locking sell (buy) order at the locked price. The following example illustrates this scenario:
• Participant A enters a Non-Display buy order for 200 shares at $0.95, and specifies the Trade Now instruction;
• Participant B enters a Post Only sell order for 100 shares at $0.95;
• The Post Only order is posted at $0.95 and locks the Non-Display order;
• The buy order will execute for 100 shares at $0.95 as the remover of liquidity.
If a buy (sell) order with the Trade Now instruction is only partially executed, the unexecuted portion of that order remains on the BX book and maintains its priority. When a Trade Now instruction is entered through the OUCH or FLITE protocol for a resting buy (sell) order and there is no locking order on the opposite side of the market, the Trade Now instruction will be ignored and the buy (sell) order will remain on the BX book, retaining its priority.
As noted above, BX is proposing to offer the Trade Now instruction for all orders that may be sent to the BX book and that are not subject to other BX rules regarding the display and execution of those orders. Accordingly, the Trade Now instruction shall not be available for Retail Price Improving Orders (Rule 4702(b)(5)) or Retail Orders (Rule 4702(b)(6)). A Retail Price Improving Order is held on the Exchange Book in order to provide liquidity at a price at least $0.001 better than the NBBO, and may execute only against a Retail Order, and only if its price is at least $0.001 better than the NBBO. A Retail Order will attempt to execute against Retail Price Improving Orders and any other orders on the Exchange Book with a price that is (i) equal to or better than the price of the Retail Order and (ii) at least $0.001 better than the NBBO. Given that Retail Price Improving Orders and Retail Orders are already subject to rules governing the handling and execution of such orders, there is not a need to implement the Trade Now instruction for these order types.
Depending on the interface being used by the participant, the Trade Now attribute may either allow the order to execute against locking interest automatically (“Reactive Trade Now”), or the participant may be required to send a Trade Now instruction to the Exchange once the order has become locked (“Non-Reactive Trade Now”). All orders that are entered through the RASH and FIX protocols with a Trade Now order attribute will be Reactive Trade Now, and those orders shall execute against locking interest automatically.
The Reactive Trade Now instruction will be available on an order-by-order basis, and will also be available as an optional port level setting. If the Reactive Trade Now setting is enabled on a specific port, all orders entered via the specific port will, by default, be designated with the Reactive Trade Now instruction. If the Reactive Trade Now setting is enabled on a specific port, participants will have the ability to designate on an order-by-order basis that a particular order entered via the specific port will not be designated with the Reactive Trade Now instruction, thereby overriding the port level setting for the order. If the Reactive Trade Now instruction is specified for an order for which the Trade Now instruction does not apply,
In contrast, orders entered through the OUCH and FLITE protocols will use the Non-Reactive Trade Now functionality, and participants must send the Trade Now instruction after the order becomes locked. If a participant enters a Non-Reactive Trade Now instruction when there is no locking interest, the instruction will be ignored by the system and the order will remain on the BX Book with the same priority.
The Non-Reactive Trade Now instruction will be available to participants on order-by-order basis. If the Non-Reactive Trade Now instruction is entered for an order for which the Trade Now instruction does not apply, the system will not invoke the Trade Now instruction for that order.
BX is offering two different variations of the Trade Now instruction to reflect the differences in behavior among participants who use the different BX protocols. For example, BX typically assumes a more active role in managing the order flow submitted by users of the RASH and FIX protocols. Allowing these participants to use the Reactive Trade Now instruction at the time of order entry will allow for the automatic execution of orders, and reflects the order flow management practices of these participants. In contrast, users of the OUCH and FLITE protocols generally assume a more active role in managing their order flow. Offering the Non-Reactive Trade Now instruction for these protocols, and its requirement that the instruction must be sent after the order becomes locked, reflects the order flow management practices of these participants.
BX notes that a similar functionality currently exists on NYSE Arca, Inc. (“NYSE Arca”), which NYSE Arca refers to as a “Non-Display Remove Modifier.” As set forth in NYSE Arca Rule 7.31, a Limit Non-Displayed Order may be
The Exchange believes that its proposal is consistent with Section 6(b) of the Act,
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. This is an optional functionality that is being offered at no charge, and which may be used equally by similarly-situated participants. Although the functionality of the Trade Now instruction will differ depending upon the protocol that is being used to access BX, BX believes that the difference in functionality reflects the different ways in which participants enter and manage their order flow.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6) thereunder.
A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”),
The Exchange proposes to amend the transaction fees at Chapter XV, Section 2 entitled “NASDAQ Options Market—Fees and Rebates,” which governs pricing for Nasdaq Participants using the NASDAQ Options Market (“NOM”), Nasdaq's facility for executing and routing standardized equity and index options. The Exchange proposes to expand certain existing rebates related to the Market Access and Routing Subsidy or “MARS,” for NOM Participants that are eligible for MARS.
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.
NOM recently filed a proposal to its MARS subsidy program,
Today, note “d” in Chapter XV, Section 2(1) provides that NOM Participants that qualify for MARS Payment Tiers 1, 2 or 3 will receive an additional $0.03 per contract Penny Pilot
*** The Customer and Professional Rebate to Add Liquidity in Penny Pilot Options will be paid as noted below. To determine the applicable percentage of total industry customer equity and ETF option average daily volume, unless otherwise stated, the Participant's Penny Pilot and Non-Penny Pilot Customer and/or Professional volume that adds liquidity will be included.
The Exchange proposes to amend note “d,” to provide that NOM Participants that qualify for MARS Payment Tiers 1, 2, 3 or 4 will receive an additional $0.03 per contract in addition to any Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity Tiers they may qualify for in that month, unless the Participant qualifies for a higher note “c” rebate, in which case the Participants would receive the appropriate note “c” rebate they qualified for in that month. The Exchange recently amended its MARS Payment Tiers to add a new tier 4 rebate.
NOM Participants that have System Eligibility and have executed the requisite number of Eligible Contracts in a month will be paid the following rebates:
The Exchange proposes to amend note “d” in Chapter XV, Section 2(1) to allow all tiers in the MARS Payment to qualify a NOM Participant for the additional $0.03 per contract incentive provided the NOM Participant qualifies for one of
Today, note “4” in Chapter XV, Section 2(1) provides that NOM Participants that qualify for MARS Payment Tiers 1, 2 or 3 will be assessed a Customer or Professional Penny Pilot Options Fee for Removing Liquidity of $0.48 per contract, excluding SPY.
The Exchange proposes to amend note “4,” to provide that NOM Participants that qualify for MARS Payment Tiers 1, 2, 3 or 4 will be assessed a Customer or Professional Penny Pilot Options Fee for Removing Liquidity of $0.48 per contract, excluding SPY. As described above, the Exchange recently amended its MARS Payment Tiers to add a new tier 4 rebate.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act,
The Commission and the courts have repeatedly expressed their preference for competition over regulatory intervention in determining prices, products, and services in the securities markets. In Regulation NMS, while adopting a series of steps to improve the current market model, the Commission highlighted the importance of market forces in determining prices and SRO revenues and, also, recognized that current regulation of the market system “has been remarkably successful in promoting market competition in its broader forms that are most important to investors and listed companies.”
Likewise, in
Further, “[n]o one disputes that competition for order flow is `fierce.' . . . As the SEC explained, `[i]n the U.S. national market system, buyers and sellers of securities, and the broker-dealers that act as their order-routing agents, have a wide range of choices of where to route orders for execution'; [and] `no exchange can afford to take its market share percentages for granted' because `no exchange possesses a monopoly, regulatory or otherwise, in the execution of order flow from broker dealers' . . . .”
The Exchange's proposal to amend note “d” in Chapter XV, Section 2(1) to permit any MARS Payment tier to qualify a NOM Participant for an additional $0.03 per contract Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity for each transaction which adds liquidity in Penny Pilot Options in that month, in addition to qualifying for Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity Tiers 1-8
The Exchange's proposal to amend note “d” in Chapter XV, Section 2(1) to permit any MARS Payment tier to qualify a NOM Participant for an additional $0.03 per contract Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity for each transaction which adds liquidity in Penny Pilot Options in that month, in addition to qualifying for Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity Tiers 1-8
The Exchange's proposal to amend note “4” in Chapter XV, Section 2(1) to permit NOM Participants to qualify for any MARS Payment tier and be assessed a Customer or Professional Penny Pilot Options, Fee for Removing Liquidity of $0.48 per contract, excluding SPY,
The Exchange's proposal to amend note “4” in Chapter XV, Section 2(1) to permit NOM Participants to qualify for any MARS Payment tier and be assessed a Customer or Professional Penny Pilot Options, Fee for Removing Liquidity of $0.48 per contract, excluding SPY, is equitable and not unfairly discriminatory because all NOM Participants are eligible to qualify for a MARS Payment, provided they have System Eligibility. All NOM Participants would therefore be eligible to qualify for the note “4” incentive if they meet the requirements.
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 terms of inter-market competition, the Exchange notes that it operates in a highly competitive market in which market participants can readily favor competing venues if they deem fee levels at a particular venue to be excessive, or rebate opportunities available at other venues to be more favorable. In such an environment, the Exchange must continually adjust its fees to remain competitive with other exchanges and with alternative trading systems that have been exempted from compliance with the statutory standards applicable to exchanges. Because competitors are free to modify their own fees in response, and because market participants may readily adjust their order routing practices, the Exchange believes that the degree to which fee changes in this market may impose any burden on competition is extremely limited. In sum, if the changes proposed herein are unattractive to market participants, it is likely that the Exchange will lose market share as a result. Accordingly, the Exchange does not believe that the proposed changes will impair the ability of members or competing order execution venues to maintain their competitive standing in the financial markets.
The Exchange's proposal to amend note “d” in Chapter XV, Section 2(1) to permit any MARS Payment tier to qualify a NOM Participant for an additional $0.03 per contract Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity for each transaction which adds liquidity in Penny Pilot Options in that month, in addition to qualifying for Penny Pilot Options Customer and/or Professional Rebate to Add Liquidity Tiers 1-8
The Exchange's proposal to amend note “4” in Chapter XV, Section 2(1) to permit NOM Participants to qualify for any MARS Payment tier and be assessed a Customer or Professional Penny Pilot Options, Fee for Removing Liquidity of $0.48 per contract, excluding SPY, does not impose an undue burden on intra-market competition because all NOM Participants are eligible to qualify for a MARS Payment, provided they have System Eligibility. All NOM Participants would therefore be eligible to qualify for the note “4” incentive if they meet the requirements.
No written comments were either solicited or received.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A)(ii) 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: (i) Necessary or appropriate in the public interest; (ii) for the protection of investors; or (iii) otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to Brent J. Fields, Secretary, Securities and Exchange Commission, 100 F Street NE., Washington, DC 20549-1090.
Copies of the submission, all subsequent amendments, all written statements with respect to the proposed rule change that are filed with the Commission, and all written communications relating to the proposed rule change between the Commission and any person, other than those that may be withheld from the public in accordance with the provisions of 5 U.S.C. 552, will be available for Web site viewing and printing in the Commission's Public Reference Room, 100 F Street NE., Washington, DC 20549, on official business days between the hours of 10:00 a.m. and 3:00 p.m. Copies of the filing also will be available for inspection and copying at the principal office of the Exchange. All comments received will be posted without change; the Commission does not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly.
All submissions should refer to File Number SR-NASDAQ-2016-152 and should be submitted on or before December 8, 2016.
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 Rule 104—Equities to delete subsection (g)(i)(A)(III) prohibiting Designated Market Makers (“DMM”) from establishing a new high (low) price on the Exchange in a security the DMM has a long (short) position during the last ten minutes prior to the close of trading. 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.
The Exchange proposes to amend Rule 104—Equities (“Rule 104”) to delete subsection (g)(i)(A)(III), which prohibits DMMs with a long (short) position in a security from making a purchase (sale) in such security during the last ten minutes prior to the close of trading that results in a new high (low) price on the Exchange in that security for that day.
Rule 104 sets forth the obligations of Exchange DMMs. Under Rule 104(a), DMMs registered in one or more securities traded on the Exchange are required to engage in a course of dealings for their own account to assist in the maintenance of a fair and orderly market insofar as reasonably practicable. Rule 104(a) also enumerates the specific responsibilities and duties of a DMM, including: (1) Maintenance of a continuous two-sided quote, which mandates that each DMM maintain a bid or an offer at the National Best Bid (“NBB”) and National Best Offer (“NBO,” together the “NBBO”) for a certain percentage of the trading day,
Rule 104(g) governs transactions by DMMs. NYSE Rule 104(g) provides that transactions on the Exchange by a DMM for the DMM's account must be effected in a reasonable and orderly manner in relation to the condition of the general market and the market in the particular stock. Rule 104(g) describes certain permitted transactions, including neutral transactions and Non-Conditional Transactions, as defined therein. Rule 104(g)(i)(A)(III) provides that, except as otherwise permitted by Rule 104, during the last ten minutes prior to the close of trading, a DMM with a long or short position in a security is prohibited from making a purchase or sale in such security that results in a new high or low price, respectively, on the Exchange for the day at the time of the DMM's transaction (“Prohibited Transactions”). Finally, Rule 104(h) addresses DMM transactions in securities that establish or increase the DMM's position. Rule 104(h)(ii) permits certain “Conditional Transactions”
The Exchange proposes to delete subsection (g)(i)(A)(III) of Rule 104.
In 2006, the Commission approved the NYSE's “hybrid market” under which Exchange systems assumed the function of matching and executing electronically-entered orders, but specialists remained the responsible broker-dealer for orders on the Exchange's limit order book.
With the increasing automation of trading and the accompanying decentralization of pricing decisions away from specialists, in 2008, the NYSE and the Exchange proposed and the Commission approved its New Market Model, which transformed specialists into DMMs, who are no longer agents for the Exchange's limit order book and whose trading activity on the Exchange is limited to proprietary trading.
In light of these developments, Rule 104(g)(i)(A)(III) has lost its original purpose and utility. The rationale behind preventing specialists from setting the price of a security on the Exchange in the final ten minutes of trading was to prevent specialists from inappropriately influencing the price of a security at the close to advantage a specialist's proprietary position.
Moreover, although Prohibited Transactions would be eliminated, DMMs would still have the obligation under Rule 104 to ensure that they do not destabilize the market when they are buying or selling to increase a position or reaching across the market during the final ten minutes of trading.
As noted, DMMs have affirmative obligations under Rule 104(a) to engage in a course of dealings for their own account to assist in the maintenance of a fair and orderly market insofar as reasonably practicable. Specifically, Rule 104(f)(ii) sets forth the DMM's obligation to act as reasonably necessary to ensure appropriate depth and maintain reasonable price variations between transactions (also known as price continuity) and prevent unexpected variations in trading. Further, under Rule 123D(a), openings and reopenings must be fair and orderly, reflecting the DMM's professional assessment of market conditions at the time, and appropriate consideration of the balance of supply and demand as reflected by orders represented in the market. The Exchange supplies DMMs with suggested Depth Guidelines for each security in which a DMM is registered, and DMMs are expected to quote and trade with reference to the Depth Guidelines.
Further, the DMM's affirmative obligation includes obligations to re-enter the market when reaching across to execute against available interest. Under Rule 104(h), DMMs that engage in Conditional Transactions must follow up with appropriate re-entry on the opposite side of the market commensurate with the size of the DMM's transaction.
Finally, DMM pricing decisions at the close would remain subject to specific DMM obligations with respect to the quality of the markets in securities to which they are assigned. In general, as noted above, transactions on the
DMM trading activity on the Exchange is actively surveiled for compliance with each of these obligations. The Exchange currently employs a suite of surveillances for trading by DMMs and other market participants in and around the close of trading. The Exchange believes that the existing DMM obligations and the Exchange's regulatory program for reviewing DMM trading provides an appropriate framework in today's market structure for ensuring that DMMs are not establishing a price to benefit their own account.
For all of the foregoing reasons, the Exchange believes that retaining Prohibited Transactions is no longer necessary.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
In particular, the Exchange believes that eliminating Rule 104(g)(III) would remove impediments to and perfect the mechanism of a free and open market and a national market system by permitting DMMs to enter trades in the last ten minutes of trading that establish a new high or low in a security even though the DMM has a position in that security. As proprietary traders without the ability to direct or influence trading or control the quote, restricting DMM trading in the final ten minutes of trading is no longer necessary.
The Exchange believes that eliminating Prohibited Transactions would not be inconsistent with the public interest and the protection of investors because DMM trading decisions going into the closing trade would continue to be evaluated from the perspective of their obligations to the marketplace, including the obligation to arrange a fair and orderly close, as set forth in Exchange rules. Further, the Exchange believes that eliminating Rule 104(g)(i)(A)(III) would not be inconsistent with the public interest and the protection of investors because existing safeguards would remain in place to ensure that DMMs do not inappropriately influence or manipulate the close, thereby establishing substantially the same result without an outright prohibition. As noted above, DMM trading would remain subject to Exchange rules, including the obligation to maintain a fair and orderly market under Rule 104. More specifically, in lieu of the obligations associated with Rule 104(g)(i)(A)(III), in the last ten minutes of trading the DMMs would be subject to the reentry obligations associated with Conditional Transactions. Accordingly, during that period, DMMs would have an obligation to reenter the market if their trading both reaches across the market and increases or establishes a position.
For the foregoing reasons, the Exchange believes that the proposal is consistent with the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change is not intended to address competitive issues but rather to eliminate redundant approvals of manual trades on its trading Floor.
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.
You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-NYSEMKT-2016-99 and should be submitted on or before December 8, 2016.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
On August 3, 2016, Financial Industry Regulatory Authority, Inc. (“FINRA”) filed with the Securities and Exchange Commission (“Commission”), pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Exchange Act”)
The proposed rule change was published for comment in the
In 2009, FINRA amended the Codes to adopt FINRA Rules 12504 and 13504 (Motions to Dismiss), and to amend FINRA Rules 12206 and 13206 (Time Limits), to establish procedures limiting motions to dismiss in arbitration.
Among other requirements, the Codes require parties to file prehearing motions to dismiss in writing, separately from the answer, and only after they file the answer.
Under the Codes, arbitrators cannot act upon a motion prior to the conclusion of the non-moving party's case in chief unless the arbitrators determine that: (1) The non-moving party previously released the claim in dispute by a signed settlement or written release,
Furthermore, the Codes impose sanctions against parties for engaging in abusive practices. For instance, if the arbitrators deny a motion to dismiss prior to the conclusion of the non-moving party's case in chief, the arbitrators must assess forum fees associated with hearing the motion against the moving party.
FINRA is proposing to amend the Codes to add an additional ground for
Specifically, FINRA is proposing to amend FINRA Rules 12504(a)(6) and 13504(a)(6) to add new paragraph (C) which would specify that arbitrators can also act upon a motion to dismiss a party or claim if they determine that the non-moving party previously brought a claim regarding the same dispute
As noted above, the Commission received four (4) comment letters on the proposed rule change,
Of the two commenters who supported the proposal, one commenter stated that the proposed amendments “would be a fair, equitable and reasonable approach and should be approved by the SEC on an expedited basis.”
A third commenter generally supported the proposal, stating that “a current ground for dismissal under the present rule, that `the non-moving party previously released the claim(s) in dispute by a signed settlement agreement and/or written release,' and the proposed additional language are in line with the same reasoning: that a final, enforceable resolution has already been reached.”
In its response, FINRA stated that it drafted the proposed amendments narrowly, in continued adherence “to the principle that motions to dismiss a claim prior to the conclusion of a party's case in chief are discouraged in arbitration.” FINRA stated that it would not reject a claim initiated against a related, but previously unnamed party, and that it would be a moving party's responsibility to demonstrate to the arbitrators that such a party is the “same party” for purposes of the proposed rule change. FINRA also expressed its intention to train its arbitrators on the rule change, emphasizing that the moving party must demonstrate that the non-moving party brought the same dispute against the same party and that the non-moving party had a full opportunity to present its claims in the earlier proceeding.
One supportive commenter noted that the Codes do not permit a claimant to file a motion for summary judgment, and suggested that this “disparity” be corrected “so that the playing field in the securities arbitration arena is level and equal for all of the participants in the forum.”
In its response, FINRA stated that it limited the grounds on which motions to dismiss could be filed based on the belief that some respondents were filing prehearing motions “routinely and repetitively in an effort to delay scheduled hearing sessions on the merits, increase investors' costs, and intimidate less sophisticated investors.” FINRA asserted that the rules were “designed to deter the inappropriate use of dispositive motions, not to provide respondents with a new vehicle to seek early dismissal of a claimant's claims.” Accordingly, FINRA declined to amend the Codes to permit parties to bring motions for summary judgment, as it believes that such an amendment would conflict with its goal of limiting dispositive motions that curtail the opportunity for parties to fully present their cases.
One commenter opposed the proposed rule change, stating that FINRA has not demonstrated a need to broaden the scope of the rule, and that “FINRA has not provided any statistical evidence as to the frequency of repeat claims being brought under circumstances that the Proposed Rule Change would remedy.”
In its response, FINRA asserted that it had demonstrated a need for the proposed rule change. According to FINRA, statistics suggest that the proposed rule change would impact a small number of cases.
With regard to the same commenter's suggestion that parties use the courts to address the issue of repeat filings, FINRA stated that parties “would be better served by having issues relating to the earlier adjudication of a dispute resolved in the forum where the claimant chose to initiate the arbitration proceeding.” According to FINRA, “[t]he moving party should not have to seek a remedy in a separate court proceeding, and the non-moving party should not be subject to additional litigation costs outside of the arbitration forum.” FINRA stated that “this is especially important for
The Commission has carefully considered the proposal, the comments received, and FINRA's response to the comments. Based on its review of the record, the Commission finds that the proposed rule change is consistent with the requirements of the Exchange Act and the rules and regulations thereunder applicable to a national securities association.
As discussed above, the proposal would amend Rules 12504(a)(6) and 13504(a)(6) to add new paragraph (C), allowing arbitrators to also act upon a motion to dismiss a party or claim if they determine that the non-moving party previously brought a claim regarding the same dispute against the same party that was fully and finally adjudicated on the merits and memorialized in an order, judgment, award, or decision. The proposed rule change would allow the arbitrators to grant a motion to dismiss relating to a particular controversy if they believe the matter was adjudicated fully even in instances where a claimant adds a new cause of action, or adds additional facts.
The Commission has considered the four (4) comment letters received on the proposed rule change,
The Commission agrees with a commenter's concern that the proposed rule change should be applied narrowly, where a claim has previously been adjudicated on the merits against the same party, and the non‐moving party has had a full and fair opportunity to argue their claims in opposition to the motion to dismiss.
The Commission also recognizes a commenter's suggestion that the FINRA Codes should permit parties to file motions for summary judgment.
The Commission further recognizes a commenter's assertion that FINRA has not demonstrated a need for the rule change.
With regard to the same commenter's suggestion that parties use the courts to address the issue of repeat filings,
To note, the Commission additionally recognizes that the FINRA Dispute Resolution Task Force (“Task Force”) reviewed the topic of motions to dismiss and recommended that FINRA amend the motions to dismiss rule in customer cases to include one additional category
The Task Force ultimately found that FINRA Rules 12504 and 13504 appeared to be working as intended to prevent the filing of frivolous motions to dismiss, but recommended that, in instances where arbitrations involve claims previously adjudicated by a court or arbitrated by an arbitration panel, respondents should be able to seek early dismissal.
Taking into consideration the comments and FINRA's responses, the Commission believes that the proposal is consistent with the Exchange Act. The Commission believes that the proposal will help protect investors and the public interest by, among other things, providing an additional ground for arbitrators to act on motions to dismiss prior to the conclusion of the claimant's case in chief in both customer and industry cases, while preserving the ability of a non-moving party to present evidence and testimony to the arbitrators concerning the merits of the motion. In addition, the Commission believes that the reasoning for the proposed new ground for dismissal is consistent with the reasoning for an existing ground for dismissal—that “the non-moving party previously released the claim(s) in dispute by a signed settlement agreement and/or written release.”
It is therefore ordered, pursuant to Section 19(b)(2) of the Exchange Act,
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934 (“Act”)
The Exchange proposes to adopt a Decommission Extension Fee for receipt of the NYSE MKT Order Imbalances market data product. The proposed 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 adopt a Decommission Extension Fee for receipt of the NYSE MKT Order Imbalances market data product,
NYSE MKT Order Imbalances is an NYSE MKT-only market data feed of real-time order imbalances that accumulate prior to the opening of trading on the Exchange and prior to the close of trading on the Exchange. The Exchange distributes information about these imbalances in real-time at specified intervals prior to the opening and closing auction each day.
As part of the Exchange's efforts to regularly upgrade systems to support more modern data distribution formats and protocols as technology evolves, beginning October 31, 2016, NYSE MKT Order Imbalances will be transmitted in a new format, Exchange Data Protocol
The Exchange believes that the proposed rule change is consistent with the provisions of Section 6 of the Act,
The Exchange believes that adopting an extension fee for subscribers of NYSE MKT Order Imbalances who wish to receive this data feed in the legacy format for a period of time beyond the built-in overlap period is reasonable, equitable and not unfairly discriminatory because the proposed fee would apply equally to all data recipients that currently subscribe to NYSE MKT Order Imbalances. The Exchange believes that it is reasonable to require data recipients to pay an additional fee for taking the data feed in the legacy format beyond the period of time specifically allotted by the Exchange for data feed customers to adapt to the new XDP format at no extra cost. To that end, the extension fee is designed to encourage data recipients to migrate to the XDP format in order to continue to receive NYSE MKT Order Imbalances in XDP as the legacy format would no longer be available after that date. The Exchange does not intend to support the legacy format at all after April 28, 2017.
The Exchange notes that NYSE MKT Order Imbalances is entirely optional. The Exchange is not required to make NYSE MKT Order Imbalances available or to offer any specific pricing alternatives to any customers, nor is any firm required to purchase NYSE MKT Order Imbalances, nor is the Exchange required to offer any feed (NYSE MKT Order Imbalances, or otherwise) in a particular format, and it is a benefit to the markets generally that NYSE MKT update its distribution technology to make it more efficient (and at the same time eliminate less efficient forms of dissemination). Firms that do purchase NYSE MKT Order Imbalances do so for the primary goals of using them to increase revenues, reduce expenses, and in some instances compete directly with the Exchange (including for order flow); those firms are able to determine for themselves whether NYSE MKT Order Imbalances or any other similar products are attractively priced or not.
The decision of the United States Court of Appeals for the District of Columbia Circuit in
In fact, the legislative history indicates that the Congress intended that the market system `evolve through the interplay of competitive forces as unnecessary regulatory restrictions are removed' and that the SEC wield its regulatory power `in those situations where competition may not be sufficient,' such as in the creation of a `consolidated transactional reporting system.'
As explained below in the Exchange's Statement on Burden on Competition, the Exchange believes that there is substantial evidence of competition in the marketplace for proprietary market data and that the Commission can rely upon such evidence in concluding that the fees established in this filing are the product of competition and therefore satisfy the relevant statutory standards. In addition, the existence of alternatives to the legacy format, such as converting to XDP as soon as possible, further ensures that the Exchange cannot set unreasonable fees, or fees that are unreasonably discriminatory, when vendors and subscribers can select such alternatives.
As the
For these reasons, the Exchange believes that the proposed fees are reasonable, equitable, and not unfairly discriminatory.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance
The market for proprietary data products is currently competitive and inherently contestable because there is fierce competition for the inputs necessary for the creation of proprietary data and strict pricing discipline for the proprietary products themselves. Numerous exchanges compete with one another for listings and order flow and sales of market data itself, providing ample opportunities for entrepreneurs who wish to compete in any or all of those areas, including producing and distributing their own market data. Proprietary data products are produced and distributed by each individual exchange, as well as other entities, in a vigorously competitive market. Indeed, the U.S. Department of Justice (“DOJ”) (the primary antitrust regulator) has expressly acknowledged the aggressive actual competition among exchanges, including for the sale of proprietary market data. In 2011, the DOJ stated that exchanges “compete head to head to offer real-time equity data products. These data products include the best bid and offer of every exchange and information on each equity trade, including the last sale.”
Moreover, competitive markets for listings, order flow, executions, and transaction reports provide pricing discipline for the inputs of proprietary data products and therefore constrain markets from overpricing proprietary market data. Broker-dealers send their order flow and transaction reports to multiple venues, rather than providing them all to a single venue, which in turn reinforces this competitive constraint. As a 2010 Commission Concept Release noted, the “current market structure can be described as dispersed and complex” with “trading volume . . . dispersed among many highly automated trading centers that compete for order flow in the same stocks” and “trading centers offer[ing] a wide range of services that are designed to attract different types of market participants with varying trading needs.”
If an exchange succeeds in competing for quotations, order flow, and trade executions, then it earns trading revenues and increases the value of its proprietary market data products because they will contain greater quote and trade information. Conversely, if an exchange is less successful in attracting quotes, order flow, and trade executions, then its market data products may be less desirable to customers in light of the diminished content and data products offered by competing venues may become more attractive. Thus, competition for quotations, order flow, and trade executions puts significant pressure on an exchange to maintain both execution and data fees at reasonable levels.
In addition, in the case of products that are also redistributed through market data vendors, such as Bloomberg and Thompson Reuters, the vendors themselves provide additional price discipline for proprietary data products because they control the primary means of access to certain end users. These vendors impose price discipline based upon their business models. For example, vendors that assess a surcharge on data they sell are able to refuse to offer proprietary products that their end users do not or will not purchase in sufficient numbers. Vendors will not elect to make available NYSE MKT Order Imbalances in the legacy format unless their customers request it, and customers will not elect to pay the proposed fees unless NYSE MKT Order Imbalances can provide value in the legacy formats by sufficiently increasing revenues or reducing costs in the customer's business in a manner that will offset the fees. The Exchange has provided customers with adequate notice that it intends to discontinue dissemination of the data feed in the legacy format. Therefore, the proposed Decommission Extension Fee would only be applicable to those customers who have a need or desire to continue to take the data feed in the legacy format beyond the period provided for migration to the XDP format. Customers who timely migrate to the XDP format to receive the data feed would not need to receive the data feed in the legacy format and therefore would not be subject to the Decommission Extension Fee at all. All of these factors operate as constraints on pricing proprietary data products.
No written comments were solicited or received with respect to the proposed rule change.
The foregoing rule change has become effective pursuant to Section 19(b)(3)(A) of the Act
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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 4702 (Order Types) and Rule 4703 (Order Attributes) to add a “Trade Now” instruction to certain order types.
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.
Nasdaq proposes to amend Rules [sic] 4702 (Order Types) and Rule 4703 (Order Attributes) to add a “Trade Now” instruction to certain order types. Nasdaq will offer this functionality through its OUCH, RASH, FLITE, and FIX protocols. This instruction will provide resting orders with a greater ability to receive an execution when that resting order is locked,
When a Trade Now instruction is applied to a resting buy (sell) order, the order will execute against the available size of the locking sell (buy) order at the locked price. The following example illustrates this scenario:
• Participant A enters a Non-Display buy order for 200 shares at $10, and specifies the Trade Now instruction;
• Participant B enters a Post Only sell order for 100 shares at $10;
• The Post Only order is posted at $10 and locks the Non-Display order;
• The buy order will execute for 100 shares at $10 as the remover of liquidity.
If a buy (sell) order with the Trade Now instruction is only partially executed, the unexecuted portion of that order remains on the Nasdaq book and maintains its priority. When a Trade Now instruction is entered through the OUCH or FLITE protocol for a resting buy (sell) order and there is no locking
As noted above, Nasdaq is proposing to offer the Trade Now instruction for all orders that may be sent to the continuous Nasdaq book (as opposed to the opening and closing book), and will not offer the instruction for orders that do not execute on the continuous book. Accordingly, the Trade Now instruction shall not be available for Supplemental Orders (Rule 4702(b)(6)), Market On Open Orders (Rule 4702(b)(8)), Limit On Open Orders (Rule 4702(b)(9)), Opening Imbalance Only Orders (Rule 4702(b)(10)), Market On Close Orders (Rule 4702(b)(11)), Limit on Close Orders (Rule 4702(b)(12)), and Imbalance Only Orders (Rule 4702(b)(13)). These order types are subject to other Nasdaq rules regarding the display and execution of those orders, and the use of the Trade Now instruction would be inconsistent with those other Nasdaq rules.
Depending on the interface being used by the participant, the Trade Now attribute may either allow the order to execute against locking interest automatically (“Reactive Trade Now”), or the participant may be required to send a Trade Now instruction to the Exchange once the order has become locked (“Non-Reactive Trade Now”). All orders that are entered through the RASH and FIX protocols with a Trade Now order attribute will be Reactive Trade Now, and those orders shall execute against locking interest automatically.
The Reactive Trade Now instruction will be available on an order-by-order basis, and will also be available as an optional port level setting. If the Reactive Trade Now setting is enabled on a specific port, all orders entered via the specific port will, by default, be designated with the Reactive Trade Now instruction. If the Reactive Trade Now setting is enabled on a specific port, participants will have the ability to designate on an order-by-order basis that a particular order entered via the specific port will not be designated with the Reactive Trade Now instruction, thereby overriding the port level setting for the order. If the Reactive Trade Now instruction is specified for an order for which the Trade Now instruction does not apply,
In contrast, orders entered through the OUCH and FLITE protocols will use the Non-Reactive Trade Now functionality, and participants must send the Trade Now instruction after the order becomes locked. If a participant enters a Non-Reactive Trade Now instruction when there is no locking interest, the instruction will be ignored by the system and the order will remain on the Nasdaq Book with the same priority.
The Non-Reactive Trade Now instruction will be available to participants on order-by-order basis. If the Non-Reactive Trade Now instruction is entered for an order for which the Trade Now instruction does not apply, the system will not invoke the Trade Now instruction for that order.
Nasdaq is offering two different variations of the Trade Now instruction to reflect the differences in behavior among participants who use the different Nasdaq protocols. For example, Nasdaq typically assumes a more active role in managing the order flow submitted by users of the RASH and FIX protocols. Allowing these participants to use the Reactive Trade Now instruction at the time of order entry will allow for the automatic execution of orders, and reflects the order flow management practices of these participants. In contrast, users of the OUCH and FLITE protocols generally assume a more active role in managing their order flow. Offering the Non-Reactive Trade Now instruction for these protocols, and its requirement that the instruction must be sent after the order becomes locked, reflects the order flow management practices of these participants.
Nasdaq notes that a similar functionality currently exists on NYSE Arca, Inc. (“NYSE Arca”), which NYSE Arca refers to as a “Non-Display Remove Modifier.” As set forth in NYSE Arca Rule 7.31, a Limit Non-Displayed Order may be designated with a Non-Display Remove Modifier. If so designated, a Limit Non-Displayed Order to buy (sell) will trade as the liquidity-taking order with an incoming Adding Liquidity Only Order (“ALO Order”) to sell (buy) that has a working price equal to the working price of the Limit Non-Displayed Order.
The Exchange believes that its proposal is consistent with Section 6(b) of the Act,
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. This is an optional functionality that is being
As noted above, Nasdaq will offer the Trade Now functionality through the OUCH, RASH, FLITE, and FIX protocols. Nasdaq will not offer the Trade Now functionality through the QIX protocol.
No written comments were either solicited or received.
Because the foregoing proposed rule change does not: (i) Significantly affect the protection of investors or the public interest; (ii) impose any significant burden on competition; and (iii) become operative for 30 days from the date on which it was filed, or such shorter time as the Commission may designate, it has become effective pursuant to Section 19(b)(3)(A) of the Act and Rule 19b-4(f)(6) thereunder.
A proposed rule change filed pursuant to Rule 19b-4(f)(6) under the Act
At any time within 60 days of the filing of the proposed rule change, the Commission summarily may temporarily suspend such rule change if it appears to the Commission that such action is necessary or appropriate in the public interest, for the protection of investors, or otherwise in furtherance of the purposes of the Act. If the Commission takes such action, the Commission shall institute proceedings to determine whether the proposed rule change should be approved or disapproved.
Interested persons are invited to submit written data, views, and arguments concerning the foregoing, including whether the proposed rule change is consistent with the Act. Comments may be submitted by any of the following methods:
• Use the Commission's Internet comment form (
• Send an email to
• Send paper comments in triplicate to 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 Rule 104 to delete subsection (g)(i)(A)(III) prohibiting Designated Market Makers (“DMM”) from establishing a new high (low) price on the Exchange in a security the DMM has a long (short) position during the last ten minutes prior to the close of trading. 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.
The Exchange proposes to amend Rule 104 to delete subsection (g)(i)(A)(III), which prohibits DMMs with a long (short) position in a security from making a purchase (sale) in such security during the last ten minutes prior to the close of trading that results in a new high (low) price on the Exchange in that security for that day.
Rule 104 sets forth the obligations of Exchange DMMs. Under Rule 104(a), DMMs registered in one or more securities traded on the Exchange are required to engage in a course of dealings for their own account to assist in the maintenance of a fair and orderly market insofar as reasonably practicable. Rule 104(a) also enumerates the specific responsibilities and duties of a DMM, including: (1) Maintenance of a continuous two-sided quote, which mandates that each DMM maintain a bid or an offer at the National Best Bid (“NBB”) and National Best Offer (“NBO,” together the “NBBO”) for a certain percentage of the trading day,
Rule 104(g) governs transactions by DMMs. NYSE Rule 104(g) provides that transactions on the Exchange by a DMM for the DMM's account must be effected in a reasonable and orderly manner in relation to the condition of the general market and the market in the particular stock. Rule 104(g) describes certain permitted transactions, including neutral transactions and Non-Conditional Transactions, as defined therein. Rule 104(g)(i)(A)(III) provides that, except as otherwise permitted by Rule 104, during the last ten minutes prior to the close of trading, a DMM with a long or short position in a security is prohibited from making a purchase or sale in such security that results in a new high or low price, respectively, on the Exchange for the day at the time of the DMM's transaction (“Prohibited Transactions”). Finally, Rule 104(h) addresses DMM transactions in securities that establish or increase the DMM's position. Rule 104(h)(ii) permits certain “Conditional Transactions”
The Exchange proposes to delete subsection (g)(i)(A)(III) of Rule 104. As discussed below, in today's electronic marketplace where specialists have become DMMs and control of pricing decisions has moved away from market participants on the Exchange trading Floor,
In 2006, the Commission approved the Exchange's “hybrid market” under which Exchange systems assumed the function of matching and executing electronically-entered orders, but specialists remained the responsible broker-dealer for orders on the Exchange's limit order book.
With the increasing automation of trading and the accompanying decentralization of pricing decisions away from specialists, in 2008, the Exchange proposed and the Commission approved its New Market Model, which transformed specialists into DMMs, who are no longer agents for the Exchange's limit order book and whose trading activity on the Exchange is limited to proprietary trading.
In light of these developments, Rule 104(g)(i)(A)(III) has lost its original purpose and utility. The rationale behind preventing specialists from setting the price of a security on the Exchange in the final ten minutes of trading was to prevent specialists from inappropriately influencing the price of a security at the close to advantage a specialist's proprietary position.
Moreover, although Prohibited Transactions would be eliminated, DMMs would still have the obligation under Rule 104 to ensure that they do not destabilize the market when they are buying or selling to increase a position or reaching across the market during the final ten minutes of trading.
As noted, DMMs have affirmative obligations under Rule 104(a) to engage in a course of dealings for their own account to assist in the maintenance of a fair and orderly market insofar as reasonably practicable. Specifically, Rule 104(f)(ii) sets forth the DMM's obligation to act as reasonably necessary to ensure appropriate depth and maintain reasonable price variations between transactions (also known as price continuity) and prevent unexpected variations in trading. Further, under Rule 123D(a), openings and reopenings must be fair and orderly, reflecting the DMM's professional assessment of market conditions at the time, and appropriate consideration of the balance of supply and demand as reflected by orders represented in the market. The Exchange supplies DMMs with suggested Depth Guidelines for each security in which a DMM is registered, and DMMs are expected to quote and trade with reference to the Depth Guidelines.
Further, the DMM's affirmative obligation includes obligations to re-enter the market when reaching across to execute against available interest. Under Rule 104(h), DMMs that engage in Conditional Transactions must follow up with appropriate re-entry on the opposite side of the market commensurate with the size of the DMM's transaction.
Finally, DMM pricing decisions at the close would remain subject to specific DMM obligations with respect to the quality of the markets in securities to which they are assigned. In general, as noted above, transactions on the Exchange by a DMM for the DMM's account must be effected in a reasonable and orderly manner in relation to the condition of the general market and the market in the particular stock, and DMMs must refrain from causing or exacerbating excessive price movements.
DMM trading activity on the Exchange is actively surveiled for compliance with each of these obligations. The Exchange currently employs a suite of surveillances for trading by DMMs and other market participants in and around the close of trading. The Exchange believes that the existing DMM obligations and the Exchange's regulatory program for
For all of the foregoing reasons, the Exchange believes that retaining Prohibited Transactions is no longer necessary.
The Exchange believes that the proposed rule change is consistent with Section 6(b) of the Act,
In particular, the Exchange believes that eliminating Rule 104(g)(III) would remove impediments to and perfect the mechanism of a free and open market and a national market system by permitting DMMs to enter trades in the last ten minutes of trading that establish a new high or low in a security even though the DMM has a position in that security. As proprietary traders without the ability to direct or influence trading or control the quote, restricting DMM trading in the final ten minutes of trading is no longer necessary.
The Exchange believes that eliminating Prohibited Transactions would not be inconsistent with the public interest and the protection of investors because DMM trading decisions going into the closing trade would continue to be evaluated from the perspective of their obligations to the marketplace, including the obligation to arrange a fair and orderly close, as set forth in Exchange rules. Further, the Exchange believes that eliminating Rule 104(g)(i)(A)(III) would not be inconsistent with the public interest and the protection of investors because existing safeguards would remain in place to ensure that DMMs do not inappropriately influence or manipulate the close, thereby establishing substantially the same result without an outright prohibition. As noted above, DMM trading would remain subject to Exchange rules, including the obligation to maintain a fair and orderly market under Rule 104. More specifically, in lieu of the obligations associated with Rule 104(g)(i)(A)(III), in the last ten minutes of trading the DMMs would be subject to the reentry obligations associated with Conditional Transactions. Accordingly, during that period, DMMs would have an obligation to reenter the market if their trading both reaches across the market and increases or establishes a position.
For the foregoing reasons, the Exchange believes that the proposal is consistent with the Act.
The Exchange does not believe that the proposed rule change will impose any burden on competition that is not necessary or appropriate in furtherance of the purposes of the Act. The proposed rule change is not intended to address competitive issues but rather to eliminate redundant approvals of manual trades on its trading Floor.
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.
You should submit only information that you wish to make available publicly. All submissions should refer to File Number SR-NYSE-2016-71 and should be submitted on or before December 8, 2016.
For the Commission, by the Division of Trading and Markets, pursuant to delegated authority.
The Social Security Administration (SSA) publishes a list of information collection packages requiring clearance by the Office of Management and Budget (OMB) in compliance with Public Law 104-13, the Paperwork Reduction Act of 1995, effective October 1, 1995. This notice includes revisions
SSA is soliciting comments on the accuracy of the agency's burden estimate; the need for the information; its practical utility; ways to enhance its quality, utility, and clarity; and ways to minimize burden on respondents, including the use of automated collection techniques or other forms of information technology. Mail, email, or fax your comments and recommendations on the information collection(s) to the OMB Desk Officer and SSA Reports Clearance Officer at the following addresses or fax numbers.
Or you may submit your comments online through
I. The information collection below is pending at SSA. SSA will submit it to OMB within 60 days from the date of this notice. To be sure we consider your comments, we must receive them no later than January 17, 2017. Individuals can obtain copies of the collection instrument by writing to the above email address.
II. SSA submitted the information collections below to OMB for clearance. Your comments regarding the information collections would be most useful if OMB and SSA receive them 30 days from the date of this publication. To be sure we consider your comments, we must receive them no later than December 19, 2016. Individuals can obtain copies of the OMB clearance packages by writing to
2.
4. Employer Reports of Special Wage Payments—20 CFR 404.428-404.429—0960-0565. SSA collects information on the SSA-131 to prevent earnings-related overpayments, and to avoid erroneous withholding of benefits. SSA field offices and program service centers also use Form SSA-131 for awards and post-entitlement events requiring special wage payment verification from employers. While we need this information to ensure the correct payment of benefits, we do not require employers to respond. The respondents are large and small businesses that make special wage payments to retirees.
The U.S. Advisory Commission on Public Diplomacy will hold a public meeting from 10:00a.m. until 11:30a.m., Thursday, December 8, 2016 in the Russell Senate Office Building, Room 385 in Washington, DC 20515.
The meeting will be a discussion on the use of public diplomacy tools to combat violent extremism and will feature a panel of experts.
This meeting is open to the public, Members and staff of Congress, the State Department, Defense Department, the media, and other governmental and non-governmental organizations. To attend and make any requests for reasonable accommodation, email
The United States Advisory Commission on Public Diplomacy appraises U.S. Government activities intended to understand, inform, and influence foreign publics. The Advisory Commission may conduct studies, inquiries, and meetings, as it deems necessary. It may assemble and disseminate information and issue reports and other publications, subject to the approval of the Chairperson, in consultation with the Executive Director. The Advisory Commission may undertake foreign travel in pursuit of its studies and coordinate, sponsor, or oversee projects, studies, events, or other activities that it deems desirable and necessary in fulfilling its functions.
The Commission consists of seven members appointed by the President, by and with the advice and consent of the Senate. The members of the Commission shall represent the public interest and shall be selected from a cross section of educational, communications, cultural, scientific, technical, public service, labor, business, and professional backgrounds. Not more than four members shall be from any one political party. The President designates a member to chair the Commission.
The current members of the Commission are: Mr. Sim Farar of California, Chairman; Mr. William Hybl of Colorado, Vice Chairman; Ambassador Lyndon Olson of Texas, Vice Chairman; Ambassador Penne Korth-Peacock of Texas; Anne Terman Wedner of Illinois; and Ms. Georgette Mosbacher of New York. One seat on the Commission is currently vacant.
The following individuals have been nominated to the Commission but await Senate confirmation as of this writing: Douglas Wilson of Delaware and Markos Kounalakis of California.
To request further information about the meeting or the U.S. Advisory Commission on Public Diplomacy, you may contact its Senior Advisor, Chris Hensman, at
Notice is hereby given of the following determinations: Pursuant to the authority vested in me by the Act of October 19, 1965 (79 Stat. 985; 22 U.S.C. 2459), E.O. 12047 of March 27, 1978, the Foreign Affairs Reform and Restructuring Act of 1998 (112 Stat. 2681,
For further information, including a list of the imported objects, contact the Office of Public Diplomacy and Public Affairs in the Office of the Legal Adviser, U.S. Department of State (telephone: 202-632-6471; email:
Tennessee Valley Authority.
30-Day Notice of submission of information collection approval and request for comments.
This is a renewal request for approval of Employment Application (OMB No. 3316-0063). The information collection described below will be submitted to the Office of Management and Budget (OMB) at
Requests for information, including copies of the information collection proposed and supporting documentation, should be directed to the Senior Privacy Program Manager: Christopher A. Marsalis, Tennessee Valley Authority, 400 W. Summit Hill Dr. (WT 5D), Knoxville, Tennessee 37902-1401; telephone (865) 632-2467 or by email at
Comments should be sent to the Agency Clearance Officer and the OMB Office of Information & Regulatory Affairs, Attention: Desk Officer for Tennessee Valley Authority, Washington, DC 20503, or email:
Federal Aviation Administration (FAA), DOT.
Notice of petition for exemption received.
This notice contains a summary of a petition seeking relief from specified requirements of Title 14, Code of Federal Regulations (14 CFR). The purpose of this notice is to improve the public's awareness of, and participation in, this aspect of the FAA's regulatory activities. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.
Comments on this petition must identify the petition docket number involved and must be received on or before December 7, 2016.
You may send comments identified by docket number FAA-2016-9132 using any of the following methods:
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Alphonso Pendergrass, ARM-207, Federal Aviation Administration, 800 Independence Avenue SW., Washington DC, 20591, email
This notice is published pursuant to 14 CFR 11.85.
Federal Aviation Administration (FAA), DOT.
Notice of petition for exemption received.
This notice contains a summary of a petition seeking relief from specified requirements of Title 14, Code of Federal Regulations (14 CFR). The purpose of this notice is to improve the public's awareness of, and participation in, this aspect of the FAA's regulatory activities. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.
Comments on this petition must identify the petition docket number involved and must be received on or before December 7, 2016.
You may send comments identified by docket number FAA-2016-9122 using any of the following methods:
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Lynette Mitterer, ANM-113, Federal Aviation Administration, 1601 Lind Avenue SW., Renton, WA 98057-3356, email
This notice is published pursuant to 14 CFR 11.85.
Federal Aviation Administration (FAA), DOT.
Notice.
This notice contains a summary of a petition seeking relief from specified requirements of Title 14 of the Code of Federal Regulations. The purpose of this notice is to improve the public's awareness of, and participation in, the FAA's exemption process. Neither publication of this notice nor the inclusion or omission of information in the summary is intended to affect the legal status of the petition or its final disposition.
Comments on this petition must identify the petition docket number and must be received on or before December 7, 2016.
Send comments identified by docket number FAA-2016-8912 using any of the following methods:
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Docket: Background documents or comments received may be read at
For technical questions concerning this action, contact Nia Daniels, (202) 267-7626, 800 Independence Avenue SW., Washington, DC 20591.
This notice is published pursuant to 14 CFR 11.85.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of renewal of exemptions; request for comments.
FMCSA announces its decision to renew the exemptions from the vision requirement in the Federal Motor Carrier Safety Regulations for 79 individuals. FMCSA has statutory authority to exempt individuals from the vision requirement if the exemptions granted will not compromise safety. The Agency has concluded that granting these exemption renewals will provide a level of safety that is equivalent to or greater than the level of safety maintained without the exemptions for these commercial motor vehicle (CMV) drivers.
Each group of renewed exemptions are effective from the dates stated in the discussions below. Comments must be received on or before December 19, 2016.
You may submit comments bearing the Federal Docket Management System (FDMS) numbers: [Docket No. FMCSA-1999-6480; FMCSA-2000-7006; FMCSA-2000-7165; FMCSA-
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Ms. Christine A. Hydock, Chief, Medical Programs Division, Medical Programs Division, 202-366-4001,
Under 49 U.S.C. 31136(e) and 31315, FMCSA may renew an exemption from the vision requirements in 49 CFR 391.41(b)(10), which applies to drivers of CMVs in interstate commerce, for a two-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to or greater than the level that would be achieved absent such exemption.” The procedures for requesting an exemption (including renewals) are set out in 49 CFR part 381.
This notice addresses 79 individuals who have requested renewal of their exemptions in accordance with FMCSA procedures. FMCSA has evaluated these 79 applications for renewal on their merits and decided to extend each exemption for a renewable two-year period. Each individual is identified according to the renewal date.
The exemptions are extended subject to the following conditions: (1) That each individual has a physical examination every year (a) by an ophthalmologist or optometrist who attests that the vision in the better eye continues to meet the requirements in 49 CFR 391.41(b)(10), and (b) by a medical examiner who attests that the individual is otherwise physically qualified under 49 CFR 391.41; (2) that each individual provides a copy of the ophthalmologist's or optometrist's report to the medical examiner at the time of the annual medical examination; and (3) that each individual provide a copy of the annual medical certification to the employer for retention in the driver's qualification file and retains a copy of the certification on his/her person while driving for presentation to a duly authorized Federal, State, or local enforcement official. Each exemption will be valid for two years unless rescinded earlier by FMCSA. The exemption will be rescinded if: (1) The person fails to comply with the terms and conditions of the exemption; (2) the exemption has resulted in a lower level of safety than was maintained before it was granted; or (3) continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315.
Under 49 U.S.C. 31315(b)(1), an exemption may be granted for no longer than two years from its approval date and may be renewed upon application for additional two year periods. The following group(s) of drivers will receive renewed exemptions effective in the month of September and are discussed below.
As of September 9, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 41 individuals have satisfied the conditions for obtaining a renewed exemption from the vision requirements (64 FR 68195; 65 FR 20251; 67 FR 38311; 67 FR 46016; 67 FR 57267; 67 FR 76439; 68 FR 10298; 69 FR 17263; 69 FR 26921; 69 FR 31447; 69 FR 51346; 70 FR 44946; 71 FR 14566; 71 FR 16410; 71 FR 27033; 71 FR 30227; 71 FR 32184; 71 FR 41311; 71 FR 50970; 72 FR 67340; 73 FR 1395; 73 FR 15567; 73 FR 15568; 73 FR 27014; 73 FR 27015; 73 FR 27017; 73 FR 28186; 73 FR 35197; 73 FR 35199; 73 FR 36955; 73 FR 38499; 73 FR 42403; 73 FR 48270; 73 FR 48273; 73 FR 48275; 74 FR 43217; 74 FR 57551; 75 FR 19674; 75 FR 25917; 75 FR 25919; 75 FR 27623; 75 FR 27624; 75 FR 34212; 75 FR 36779; 75 FR 38602; 75 FR 39729; 75 FR 44051; 75 FR 47888; 75 FR 50799; 76 FR 49528; 76 FR 61143; 76 FR 66123; 76 FR 67248; 76 FR 73769; 76 FR 79761; 77 FR 3547; 77 FR 23797; 77 FR 27847; 77 FR 36338; 77 FR 38384; 77 FR 38386; 77 FR 40945; 77 FR 40946; 77 FR 41879; 77 FR 46153; 77 FR 48590; 77 FR 52391; 78 FR 24798; 78 FR 46407; 78 FR 62935; 78 FR 63302; 78 FR 67454; 78 FR 67460; 78 FR 76395; 78 FR 76705; 78 FR 77780; 78 FR 77782; 79 FR 4803; 79 FR 10606; 79 FR 14331; 79 FR 14571; 79 FR 22003; 79 FR 23797; 79 FR 79 27681; 79 FR 28588; 79 FR 29495; 79 FR 35212; 79 FR 35218; 79 FR 35220; 79 FR 37842; 79 FR 38649; 79 FR 38659; 79 FR 41735; 79 FR 41737; 79 FR 45868; 79 FR 46153; 79 FR 47175; 79 FR 53514; 79 FR 56102):
Don R. Alexander (OR), Paul J. Bannon (DE), Frank R. Berritto (NY), Timothy W. Bickford (ME), Christopher D. Bolomey (ME), Thomas J. Bommer (ND), Tracy L. Bowers (IA), Tracy L. Butcher (VA), Clare H. Buxton (MI), Thomas L. Corey (IN), Layne C. Coscorrosa (WA), James H. Facemyre (WV), Anton Filic (TX), Raleigh K. Franklin (UT), Michael Giagnacova
The drivers were included in one of the following dockets: Docket Nos. FMCSA-1999-6480; FMCSA-2002-12294; FMCSA-2002-13411; FMCSA-2004-17195; FMCSA-2006-24015; FMCSA-2006-24783; FMCSA-2007-0017; FMCSA-2008-0021; FMCSA-2008-0106; FMCSA-2008-0174; FMCSA-2009-0206; FMCSA-2010-0082; FMCSA-2010-0114; FMCSA-2011-0142; FMCSA-2011-0276; FMCSA-2011-0299; FMCSA-2012-0104; FMCSA-2012-0161; FMCSA-2013-0027; FMCSA-2013-0166; FMCSA-2013-0168; FMCSA-2013-0170; FMCSA-2014-0002; FMCSA-2014-0003; FMCSA-2014-0005; FMCSA-2014-0006; FMCSA-2014-0007; FMCSA-2014-0008. Their exemptions are effective as of September 9, 2016 and will expire on September 9, 2018.
As of September 21, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 17 individuals have satisfied the conditions for obtaining a renewed exemption from the vision requirements (65 FR 20245; 65 FR 33406; 65 FR 57230; 65 FR 57234; 67 FR 46016; 67 FR 57266; 67 FR 57267; 69 FR 51346; 69 FR 52741; 71 FR 32185; 71 FR 41311; 71 FR 50970; 71 FR 53489; 73 FR 42403; 73 FR 48270; 73 FR 51336; 75 FR 34210; 75 FR 47888; 75 FR 50799; 75 FR 52062; 77 FR 40945; 77 FR 52389; 79 FR 46300):
Jack D. Clodfelter (NC), Tommy J. Cross, Jr. (TN), Daniel K. Davis, III (MA), Richard L. Derick (NH), Joseph A. Dunlap (OH), James F. Gereau (WI), Esteban G. Gonzalez (TX), Reginald I. Hall (TX), George R. House (MO), Alfred C. Jewell, Jr. (WY), John C. Lewis (SC), Lewis V. McNeice (TX), Kevin J. O'Donnell (IL), Gregory M. Preves (GA), Daniel Salinas (OR), Lee R. Sidwell (OH), Jeffrey D. Wilson (CO).
The drivers were included in one of the following dockets: Docket No. FMCSA-2000-7006; FMCSA-2000-7165; FMCSA-2002-12294; FMCSA-2006-24783; FMCSA-2010-0114. Their exemptions are effective as of September 21, 2016 and will expire on September 21, 2018.
As of September 23, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 5 individuals have satisfied the conditions for obtaining a renewed exemption from the vision requirements (73 FR 46973; 73 FR 54888; 75 FR 52063; 77 FR 52388; 79 FR 52388):
Terrence L. Benning (WI), Larry D. Curry (GA), Kelly M. Greene (FL), Garry R. Lomen (WA), Thomas P. Shank (NY).
The drivers were included on the following docket: Docket No. FMCSA-2008-0231. Their exemptions are effective as of September 23, 2016 and will expire on September 23, 2018.
As of September 26, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 6 individuals have satisfied the conditions for obtaining a renewed exemption from the vision requirements (77 FR 46793; 77 FR 59245):
Bryan Brockus (ID), Michael T. Dekorte (MI), Erric L. Gomersall (WI), Larry Johnsonbaugh, Jr. (PA), John Middleton (OH), John C. Steedley (GA).
The drivers were included on the following docket: Docket No. FMCSA-2012-0214. Their exemptions are effective as of September 26, 2016 and will expire on September 26, 2018.
As of September 30, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 10 individuals have satisfied the conditions for obtaining a renewed exemption from the vision requirements (63 FR 66227; 64 FR 16520; 71 FR 14567; 71 FR 30228; 73 FR 28187; 73 FR 35195; 73 FR 35196; 73 FR 35197; 73 FR 35198; 73 FR 35199; 73 FR 35200; 73 FR 35201; 73 FR 38497; 38498; 73 FR 38499; 73 FR 48273; 73 FR 48275; 74 FR 37299; 74 FR 48344; 75 FR 25919; 75 FR 39729; 75 FR 44051; 77 FR 40946; 77 FR 46153; 79 FR 46153):
Ronald A. Bolyard (WV), David A. Coburn, Sr. (VT), Ronald Holshouser (MO), Kelly R. Knopf, Sr. (SC), Edward J. Kosior (NY), Frazier A. Luckerson (GA), Ross A. Miceli II (PA), Donald L. Minney (OH), Philip L. Neff (PA), Loran J. Weiler (IA).
The drivers were included on the following docket: Docket No. FMCSA-2014-0010. Their exemptions are effective as of September 30, 2016 and will expire on September 30, 2018.
Each of the 79 applicants listed in the groups above has requested renewal of the exemption and has submitted evidence showing that the vision in the better eye continues to meet the requirement specified at 49 CFR 391.41(b)(10) and that the vision impairment is stable. In addition, a review of each record of safety while driving with the respective vision deficiencies over the past two years indicates each applicant continues to meet the vision exemption requirements.
These factors provide an adequate basis for predicting each driver's ability to continue to drive safely in interstate commerce. Therefore, FMCSA concludes that extending the exemption for each renewal applicant for a period of two years is likely to achieve a level of safety equal to that existing without the exemption.
FMCSA will review comments received at any time concerning a particular driver's safety record and determine if the continuation of the exemption is consistent with the requirements at 49 U.S.C. 31136(e) and 31315. However, FMCSA requests that interested parties with specific data concerning the safety records of these drivers submit comments by December 19, 2016.
FMCSA believes that the requirements for a renewal of an exemption under 49 U.S.C. 31136(e) and 31315 can be satisfied by initially granting the renewal and then requesting and evaluating, if needed, subsequent comments submitted by interested parties. As indicated above, the Agency previously published notices of final disposition announcing its decision to exempt these 79 individuals from the vision requirement in 49 CFR 391.41(b)(10). The final decision to grant an exemption to each of these individuals was made on the merits of each case and made only after careful consideration of the comments received to its notices of applications. The notices of applications stated in detail the qualifications, experience, and medical condition of each applicant for an exemption from the vision requirements. That information is available by consulting the above cited
Interested parties or organizations possessing information that would otherwise show that any, or all, of these drivers are not currently achieving the statutory level of safety should immediately notify FMCSA. The Agency will evaluate any adverse evidence submitted and, if safety is being compromised or if continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136(e) and 31315, FMCSA will take immediate steps to revoke the exemption of a driver.
You may submit your comments and material online or by fax, mail, or hand delivery, but please use only one of these means. FMCSA recommends that you include your name and a mailing address, an email address, or a phone number in the body of your document so that FMCSA can contact you if there are questions regarding your submission.
To submit your comment online, go to
We will consider all comments and material received during the comment period. FMCSA may issue a final rule at any time after the close of the comment period.
To view comments, as well as any documents mentioned in this preamble, go to
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of Unified Carrier Registration Plan Board of Directors Meeting.
The meeting will be held on December 15, 2016, from 12:00 Noon to 3:00 p.m., Eastern Standard Time.
This meeting will be open to the public via conference call. Any interested person may call 1-877-422-1931, passcode 2855443940, to listen and participate in this meeting.
Mr. Avelino Gutierrez, Chair, Unified Carrier Registration Board of Directors at (505) 827-4565.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of applications for exemption; request for comments.
FMCSA announces receipt of applications from nine individuals for an exemption from the prohibition in the Federal Motor Carrier Safety Regulations (FMCSRs) against persons with a clinical diagnosis of epilepsy or any other condition that is likely to cause a loss of consciousness or any loss of ability to control a commercial motor vehicle (CMV) to drive in interstate commerce. If granted, the exemptions would enable these individuals who have had one or more seizures and are taking anti-seizure medication to operate CMVs in interstate commerce.
Comments must be received on or before December 19, 2016.
You may submit comments bearing the Federal Docket Management System (FDMS) Docket No. FMCSA-2016-0008 using any of the following methods:
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Ms. Christine A. Hydock, Chief, Medical Programs Division, (202) 366-4001,
Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption from the FMCSRs for a two-year period if it finds “such exemption would likely achieve a level of safety that is equivalent to or greater than the level that would be achieved absent such exemption.” The statute also allows the Agency to renew exemptions at the end of the two-year period.
The nine individuals listed in this notice have requested an exemption from the epilepsy prohibition in 49 CFR 391.41(b)(8). Accordingly, the Agency will evaluate the qualifications of each applicant to determine whether granting the exemption will achieve the required level of safety mandated by statute.
The physical qualification standard for drivers regarding epilepsy found in 49 CFR 391.41(b)(8) states that a person is physically qualified to drive a CMV if that person:
Has no established medical history or clinical diagnosis of epilepsy or any other condition which is likely to cause the loss of consciousness or any loss of ability to control a CMV.
In addition to the regulations, FMCSA has published advisory criteria
The advisory criteria state the following:
If an individual has had a sudden episode of a non-epileptic seizure or loss of consciousness of unknown cause that did not require anti-seizure medication, the decision whether that person's condition is likely to cause the loss of consciousness or loss of ability to control a CMV should be made on an individual basis by the Medical Examiner in consultation with the treating physician. Prior to considering certification, it is suggested there be a six-month waiting period from the time of the episode. Following the waiting period, it is suggested that the individual undergo a complete neurological examination. If the results of the examination are negative and anti-seizure medication is not required, the driver may be qualified.
In those individual cases where a driver had a seizure or an episode of loss of consciousness that resulted from a known medical condition (
Drivers who have a history of epilepsy/seizures, off anti-seizure medication and seizure-free for 10 years, may be qualified to operate a CMV in interstate commerce. Interstate drivers who have had a single unprovoked seizure may be qualified to drive a CMV in interstate commerce if seizure-free and off anti-seizure medication for five years or more.
As a result of Medical Examiners misinterpreting advisory criteria as regulation, numerous drivers have been prohibited from operating a CMV in interstate commerce based on the fact that they have had one or more seizures and are taking anti-seizure medication, rather than an individual analysis of their circumstances by a qualified Medical Examiner based on the physical qualification standards and medical best practices.
On January 15, 2013, in a Notice of Final Disposition entitled, “Qualification of Drivers; Exemption Applications; Epilepsy and Seizure Disorders,” (78 FR 3069), FMCSA announced its decision to grant requests from 22 individuals for exemptions from the regulatory requirement that interstate CMV drivers have “no established medical history or clinical diagnosis of epilepsy or any other condition which is likely to cause loss of consciousness or any loss of ability to control a CMV.” Since the January 15, 2013 notice, the Agency has published additional notices granting requests from individuals for exemptions from the regulatory requirement regarding epilepsy found in 49 CFR 391.41(b)(8).
To be considered for an exemption from the epilepsy prohibition in 49 CFR 391.41(b)(8), applicants must meet the criteria in the 2007 recommendations of the Agency's Medical Expert Panel (MEP) (78 FR 3069).
Mr. Beery is a 64 year-old class A CDL holder in Pennsylvania. He has a history of a seizure disorder and his last seizure was in 2000. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. Beery receiving an exemption.
Mr. Cantwell is a 54 year-old class B CDL holder in Tennessee. He has a history of epilepsy and his last seizure was in 1986. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. Cantwell receiving an exemption.
Mr. McDaniel is a 44 year-old driver in Illinois. He has a history of a seizure disorder and his last seizure was in 1996. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. McDaniel receiving an exemption.
Mr. Moody is a 57 year-old class A CDL holder in North Carolina. He has a history of a seizure disorder and his last seizure was in 2006. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is
Mr. Moore is a 50 year-old driver in Indiana. He has a history of a seizure disorder and his last seizure was in 1984. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. Moore receiving an exemption.
Mr. Porcellini is a 26 year-old driver in Pennsylvania. He has a history of a seizure disorder and his last seizure was in 2003. He discontinued anti-seizure medication in 2008. His physician states that he is supportive of Mr. Porcellini receiving an exemption.
Mr. Rathman is a 47 year-old driver in Colorado. He has a history of a seizure disorder and his last seizure was in 1999. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. Rathman receiving an exemption.
Mr. Simms is a 48 year-old class B CDL holder in North Carolina. He has a history of a single seizure in 1990. He takes anti-seizure medication with the dosage and frequency remaining the same since that time. His physician states that he is supportive of Mr. Simms receiving an exemption.
Ms. Van Horne is a 38 year-old driver in Pennsylvania. She has a history of a seizure disorder and her last seizure was in 1998. She takes anti-seizure medication with the dosage and frequency remaining the same since that time. Her physician states that he is supportive of Ms. Van Horne receiving an exemption.
In accordance with 49 U.S.C. 31136(e) and 31315, FMCSA requests public comment from all interested persons on the exemption petitions described in this notice. We will consider all comments received before the close of business on the closing date indicated in the dates section of the notice.
You may submit your comments and material online or by fax, mail, or hand delivery, but please use only one of these means. FMCSA recommends that you include your name and a mailing address, an email address, or a phone number in the body of your document so that FMCSA can contact you if there are questions regarding your submission.
To submit your comment online, go to
We will consider all comments and materials received during the comment period. FMCSA may issue a final determination any time after the close of the comment period.
To view comments, as well as any documents mentioned in this preamble, go to
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of final disposition.
FMCSA announces its decision to renew exemptions of 36 individuals from its prohibition in the Federal Motor Carrier Safety Regulations (FMCSRs) against persons with insulin-treated diabetes mellitus (ITDM) from operating commercial motor vehicles (CMVs) in interstate commerce. The exemptions enable these individuals with ITDM to continue to operate CMVs in interstate commerce.
Each group of renewed exemptions were effective on the dates stated in the discussions below and will expire on the dates stated in the discussions below.
Ms. Christine A. Hydock, Chief, Medical Programs Division, 202-366-4001,
You may see all the comments online through the Federal Document Management System (FDMS) at:
On January 11, 2016, FMCSA published a notice announcing its decision to renew exemptions for 36 individuals from the insulin-treated diabetes mellitus prohibition in 49 CFR 391.41(b)(3) to operate a CMV in interstate commerce and requested comments from the public (80 FR 74196). The public comment period ended on February 10, 2016 and no comments were received.
As stated in the previous notice, FMCSA has evaluated the eligibility of these applicants and determined that renewing these exemptions would
The physical qualification standard for drivers regarding diabetes found in 49 CFR 391.41(b)(3) states that a person is physically qualified to drive a CMV if that person has no established medical history or clinical diagnosis of diabetes mellitus currently requiring insulin for control.
FMCSA received no comments in this preceding.
Based upon its evaluation of the 36 renewal exemption applications and that no comments were received, FMCSA confirms its decision to exempt the following drivers from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce in 49 CFR 391.64(3):
As of February 6, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 6 individuals have satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (76 FR 79756; 77 FR 5873; 81 FR 1281):
The drivers were included in Docket No. FMCSA-2011-0326. Their exemptions are effective as of February 6, 2016, and will expire on February 6, 2018.
As of February 10, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 6 individuals, have satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (76 FR 78720; 77 FR 7232; 81 FR 1281):
The drivers were included in Docket No. FMCSA-2011-0327. Their exemptions are effective as of February 10, 2016, and will expire on February 10, 2018.
As of February 12, 2015, and in accordance with 49 U.S.C. 31136(e) and 31315, the following individual, Guy B. Mayes (WA) has satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (78 FR 78479; 79 FR 13086; 81 FR 1281).
The driver was included in Docket No. FMCSA-2013-0192. The exemption is effective as of February 12, 2016, and will expire on February 12, 2018.
As of February 22, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 11 individuals have satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (77 FR 533; 77 FR 10607; 81 FR 1281):
The drivers were included in Docket No. FMCSA-2011-0367. Their exemptions are effective as of February 22, 2016, and will expire on February 22, 2018.
As of February 24, 2016, and in accordance with 49 U.S.C. 31136(e) and 31315, the following 11 individuals have satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (78 FR 68092; 79 FR 8182; 81 FR 1281):
The drivers were included in Docket No. FMCSA-2009-0294. Their exemptions are effective as of February 24, 2016, and will expire on February 24, 2018.
As of February 27, 2015, and in accordance with 49 U.S.C. 31136(e) and 31315, the following individual, Charles R. Clayton (NJ) has satisfied the renewal conditions for obtaining an exemption from the rule prohibiting drivers with ITDM from driving CMVs in interstate commerce (78 FR 78479; 79 FR 13086; 81 FR 1281).
The driver was included in Docket No. FMCSA-2013-0192. The exemption is effective as of February 27, 2016, and will expire on February 27, 2018.
In accordance with 49 U.S.C. 31315, each exemption will be valid for two years from the effective date unless revoked earlier by FMCSA. The exemption will be revoked if the following occurs: (1) The person fails to comply with the terms and conditions of the exemption; (2) the exemption has resulted in a lower level of safety than was maintained prior to being granted; or (3) continuation of the exemption would not be consistent with the goals and objectives of 49 U.S.C. 31136 and 31315.
Federal Motor Carrier Safety Administration (FMCSA), DOT.
Notice of denials.
FMCSA announces its denial of 84 applications from individuals who requested an exemption from the Federal vision standard applicable to interstate truck and bus drivers and the reasons for the denials. FMCSA has statutory authority to exempt individuals from the vision requirement if the exemptions granted will not compromise safety. The Agency has concluded that granting these exemptions does not provide a level of safety that will be equivalent to, or greater than, the level of safety maintained without the exemptions for these commercial motor vehicle (CMV) drivers.
Ms. Christine A. Hydock, Chief, Medical Programs Division, (202) 366-4001,
Under 49 U.S.C. 31136(e) and 31315, FMCSA may grant an exemption from
Accordingly, FMCSA evaluated 84 individual exemption requests on their merit and made a determination that these applicants do not satisfy the criteria eligibility or meet the terms and conditions of the Federal exemption program. Each applicant has, prior to this notice, received a letter of final disposition on the exemption request. Those decision letters fully outlined the basis for the denial and constitute final Agency action. The list published in this notice summarizes the Agency's recent denials as required under 49 U.S.C. 31315(b)(4) by periodically publishing names and reasons for denial.
The following 3 applicants did not have sufficient driving experience over the past 3 years under normal highway operating conditions:
The following 19 applicants had no experience operating a CMV:
The following 15 applicants did not have 3 years of experience driving a CMV on public highways with their vision deficiencies:
The following 7 applicants did not have 3 years of recent experience driving a CMV with the vision deficiency:
The following 5 applicants did not have sufficient driving experience during the past 3 years under normal highway operating conditions:
The following 14 applicants were denied for multiple reasons:
The following applicant, Kelly L. Ewing (PA), held 2 commercial driver's licenses simultaneously.
The following 7 applicants met the current federal vision standards. Exemptions are not required for applicants who meet the current regulations for vision:
The following applicant, Edward A. Iverson (ND), drove interstate while restricted to intrastate driving.
The following 8 applicants will not be driving interstate, in interstate commerce, or are not required to carry a DOT medical card:
Finally, the following 4 applicants perform transportation for the Federal government, State, or any political subdivision of the state.
Federal Transit Administration, DOT.
Notice of request for comments.
In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments must be submitted on or before December 19, 2016.
All written comments must refer to the docket number that appears at the top of this document and be submitted to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725—17th Street NW., Washington, DC 20503, Attention: FTA Desk Officer. Alternatively, comments may be sent via email to the Office of Information and Regulatory Affairs (OIRA), Office of Management and Budget, at the following address:
Tia Swain, Office of Administration, Management Planning Division, 1200 New Jersey Avenue SE., Mail Stop
The Paperwork Reduction Act of 1995 (PRA), Public Law 104-13, Section 2, 109 Stat. 163 (1995) (codified as revised at 44 U.S.C. 3501-3520), and its implementing regulations, 5 CFR part 1320, require Federal agencies to issue two notices seeking public comment on information collection activities before OMB may approve paperwork packages. 44 U.S.C. 3506, 3507; 5 CFR 1320.5, 1320.8(d)(1), 1320.12. On August 16, 2016, FTA published a 60-day notice (81 FR 54658) in the
Before OMB decides whether to approve these proposed collections of information, it must provide 30 days for public comment. 44 U.S.C. 3507(b); 5 CFR 1320.12(d). Federal law requires OMB to approve or disapprove paperwork packages between 30 and 60 days after the 30 day notice is published. 44 U.S.C. 3507(b)-(c); 5 CFR 1320.12(d);
The summaries below describe the nature of the information collection requirements (ICRs) and the expected burden. The requirements are being submitted for clearance by OMB as required by the PRA.
Federal Transit Administration (FTA), DOT.
Notice.
This notice announces final environmental actions taken by the Federal Transit Administration (FTA) for projects in the City of Alexandria, VA and the City of Jersey City, NJ. The purpose of this notice is to announce publicly the environmental decisions by FTA on the subject projects and to activate the limitation on any claims
By this notice, FTA is advising the public of final agency actions subject to Section 139(l) of Title 23, United States Code (U.S.C.). A claim seeking judicial review of FTA actions announced herein for the listed public transportation projects will be barred unless the claim is filed on or before April 17, 2017.
Nancy-Ellen Zusman, Assistant Chief Counsel, Office of Chief Counsel, (312) 353-2577 or Meghan Kelley, Environmental Protection Specialist, Office of Environmental Programs, (202) 366-6098. FTA is located at 1200 New Jersey Avenue SE., Washington, DC 20590. Office hours are from 9:00 a.m. to 5:00 p.m., Monday through Friday, except Federal holidays.
Notice is hereby given that FTA has taken final agency actions by issuing certain approvals for the public transportation projects listed below. The actions on the projects, as well as the laws under which such actions were taken, are described in the documentation issued in connection with the projects to comply with the National Environmental Policy Act (NEPA) and in other documents in the FTA administrative record for the projects. Interested parties may contact either the project sponsor or the relevant FTA Regional Office for more information. Contact information for FTA's Regional Offices may be found at
This notice applies to all FTA decisions on the listed projects as of the issuance date of this notice and all laws under which such actions were taken, including, but not limited to, NEPA [42 U.S.C. 4321-4375], Section 4(f) of the Department of Transportation Act of 1966 [49 U.S.C. 303], Section 106 of the National Historic Preservation Act [16 U.S.C. 470f], and the Clean Air Act [42 U.S.C. 7401-7671q]. This notice does not, however, alter or extend the limitation period for challenges of project decisions subject to previous notices published in the
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Federal Transit Administration, DOT.
Notice of request for comments.
In compliance with the Paperwork Reduction Act of 1995 (44 U.S.C. 3501
Comments must be submitted on or before December 19, 2016.
All written comments must refer to the docket number that appears at the top of this document and be submitted to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW., Washington, DC 20503, Attention: FTA Desk Officer. Alternatively, comments may be sent via email to the Office of Information and Regulatory Affairs (OIRA), Office of Management and Budget, at the following address:
Tia Swain, Office of Administration, Management Planning Division, 1200 New Jersey Avenue SE., Mail Stop TAD-10, Washington, DC 20590 (202) 366-0354 or
The Paperwork Reduction Act of 1995 (PRA), Public Law 104-13, Section 2, 109 Stat. 163 (1995) (codified as revised at 44 U.S.C. 3501-3520), and its implementing regulations, 5 CFR part 1320, require Federal agencies to issue two notices seeking public comment on information collection activities before OMB may approve paperwork packages. 44 U.S.C. 3506, 3507; 5 CFR 1320.5, 1320.8(d)(1), 1320.12. On August 16, 2016, FTA published a 60-day notice (81 FR 54660) in the
Before OMB decides whether to approve these proposed collections of information, it must provide 30 days for public comment. 44 U.S.C. 3507(b); 5 CFR 1320.12(d). Federal law requires OMB to approve or disapprove paperwork packages between 30 and 60 days after the 30 day notice is published. 44 U.S.C. 3507 (b)-(c); 5 CFR 1320.12(d);
The summaries below describe the nature of the information collection requirements (ICRs) and the expected burden. The requirements are being submitted for clearance by OMB as required by the PRA.
Office of Foreign Assets Control, Treasury.
Notice.
The Department of the Treasury's Office of Foreign Assets Control (OFAC) is publishing the names of four individuals whose property and interests in property are blocked pursuant to Executive Order 13224 of September 23, 2001, “Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten To Commit, or Support Terrorism.”
OFAC's action described in this notice was effective on November 10, 2016.
Associate Director for Global Targeting, tel.: 202-622-2420, Assistant Director for Sanctions Compliance & Evaluation, tel.: 202-622-2490, Assistant Director for Licensing, tel.: 202-622-2480, Office of Foreign Assets Control, or Chief Counsel (Foreign Assets Control), tel.: 202-622-2410, Office of the General Counsel, Department of the Treasury (not toll free numbers).
The SDN List and additional information concerning OFAC sanctions programs are available from OFAC's Web site (
On November 10, 2016, OFAC blocked the property and interests in property of the following four individuals pursuant to E.O. 13224, “Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten To Commit, or Support Terrorism”:
1. AL-MUHAYSINI, 'Abdallah Muhammad Bin-Sulayman (a.k.a. ALMUHAYSINI, Abdullah); DOB 30 Oct 1987; POB Al Qasim, Saudi Arabia; nationality Saudi Arabia; Passport K163255 (Saudi Arabia) issued 11 Jun 2011 expires 16 Apr 2016 (individual) [SDGT] (Linked To: AL-NUSRAH FRONT).
2. JASHARI, Abdul (a.k.a. AL-ALBANI, Abu Qatada; a.k.a. AL-ALBANI, Abu-Qatadah; a.k.a. JASHARI, Abdulj; a.k.a. JASHARI, Abdyl; a.k.a. “IRAKI, Commander”), Syria; DOB 25 Sep 1976; POB Skopje, Macedonia; nationality Macedonia, The Former Yugoslav Republic of (individual) [SDGT] (Linked To: AL-NUSRAH FRONT).
3. ZAYNIYAH, Jamal Husayn (a.k.a. AL-ANSARI, Abu-Malik; a.k.a. AL-SHAMI, Abu-Malik; a.k.a. AL-TALLI, Abu-Malik), Al-Qalamun, Syria; DOB 17 Aug 1972; alt. DOB 01 Jan 1972; POB Al-Tal, Syria; alt. POB Tell Mnin, Syria; nationality Syria; Passport 3987189 (individual) [SDGT] (Linked To: AL-NUSRAH FRONT).
4. AL-'ALLAK, Ashraf Ahmad Fari' (a.k.a. AL-ALLAL, Ashraf Ahmad Fari; a.k.a. AL-URDUNI, Abu Raghad; a.k.a. BASHQ, Abu Raghad; a.k.a. FARI', Ashraf Ahmad; a.k.a. “BASHIQ”), Dar'a, Syria; DOB 15 Dec 1978; POB Amman, Jordan; nationality Jordan (individual) [SDGT] (Linked To: AL-NUSRAH FRONT).
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning, Requirements to Ensure Collection of Section 2056A Estate Tax.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 8855, Election To Treat a Qualified Revocable Trust as Party of an Estate.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Arbitrage Restrictions on Tax-Exempt Bonds.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of regulations should be directed to Sara Covington at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
Under section 148(f), interest on a state or local bond is not tax exempt unless the issuer of the bond rebates to the United States arbitrage profits earned from investing proceeds of the bond in higher yielding nonpurpose investments. Form 8038-T is used to pay the arbitrage rebate to the United States and to pay penalty in lieu of rebates. Burden for the form is being reported under 1545-1219.
Issuers are also required to keep records of certain interest rate hedges so that the hedges are taken into account in determining arbitrage profits. Under
The collection of information in the proposed regulation (REG-138526-14) is in § 1.148-1(f)(2)(ii) which contains a requirement that the issuer obtain certifications and supporting documentation regarding the underwriter's sales of the issuer's bonds.
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning, Special Lien for Estate Taxes Deferred Under Section 6166 or 6166A.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Kerry Dennis at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Sara Covington at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)).
Currently, the IRS is soliciting comments concerning T.D. 8124, Certain Elections Under the Tax Reform Act of 1986.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulation should be directed to Martha R. Brinson, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Comments are invited on: (a) whether the collection of information is necessary for the proper performance of the functions of the agency, including whether the information shall have practical utility; (b) the accuracy of the agency's estimate of the burden of the collection of information; (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 respondents, including through the use of automated collection techniques or
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 8453-EO, Exempt Organization Declaration and Signature for Electronic Filing.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of notice should be directed to Allan Hopkins at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning, INTL-952-86 (Final-TD 8410), Allocation and Apportionment of Interest Expense and Certain Other Expenses.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Sara Covington at Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number.
Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning consolidated groups and controlled groups-intercompany transactions and related rules, and consolidated groups-intercompany transactions and related rules.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number.
Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning requirements for investments to qualify under section 936(d)(4) as investments in qualified Caribbean Basin countries.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the regulations should be directed to Allan Hopkins, at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number.
Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Form 4952, Investment Interest Expense Deduction.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of notice should be directed to Allan Hopkins at Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet, at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently the IRS is soliciting comments concerning Form 926, Return by a U.S. Transferor of Property to a Foreign Corporation.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the form and instructions should be directed to Martha R. Brinson, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number. Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Internal Revenue Service (IRS), Treasury.
Notice and request for comments.
The Department of the Treasury, as part of its continuing effort to reduce paperwork and respondent burden, invites the general public and other Federal agencies to take this opportunity to comment on proposed and/or continuing information collections, as required by the Paperwork Reduction Act of 1995, Public Law 104-13 (44 U.S.C. 3506(c)(2)(A)). Currently, the IRS is soliciting comments concerning Revenue Procedure 2004-19, Probable or Prospective Reserves Safe Harbor.
Written comments should be received on or before January 17, 2017 to be assured of consideration.
Direct all written comments to Tuawana Pinkston, Internal Revenue Service, Room 6526, 1111 Constitution Avenue NW., Washington, DC 20224.
Requests for additional information or copies of the revenue procedure should be directed to Martha R. Brinson, Internal Revenue Service, Room 6129, 1111 Constitution Avenue NW., Washington, DC 20224, or through the Internet at
The following paragraph applies to all of the collections of information covered by this notice:
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid OMB control number.
Books or records relating to a collection of information must be retained as long as their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by 26 U.S.C. 6103.
Environmental Protection Agency (EPA).
Direct final rule.
EPA is promulgating significant new use rules (SNURs) under the Toxic Substances Control Act (TSCA) for 57 chemical substances which were the subject of premanufacture notices (PMNs). The applicable review periods for the PMNs submitted for these 57 chemical substances all ended prior to June 22, 2016 (
This rule is effective on January 17, 2017. For purposes of judicial review, this rule shall be promulgated at 1 p.m. (e.s.t.) on December 1, 2016.
Written adverse or critical comments, or notice of intent to submit adverse or critical comments, on one or more of these SNURs must be received on or before December 19, 2016 (see Unit VI. of the
For additional information on related reporting requirement dates, see Units I.A., VI., and VII. of the
Submit your comments, identified by docket identification (ID) number EPA-HQ-OPPT-2016-0207, by one of the following methods:
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Additional instructions on commenting or visiting the docket, along with more information about dockets generally, is available at
You may be potentially affected by this action if you manufacture, process, or use the chemical substances contained in this rule. The following list of North American Industrial Classification System (NAICS) codes is not intended to be exhaustive, but rather provides a guide to help readers determine whether this document applies to them. Potentially affected entities may include:
• Manufacturers or processors of one or more subject chemical substances (NAICS codes 325 and 324110),
This action may also affect certain entities through pre-existing import certification and export notification rules under TSCA. Chemical importers are subject to the TSCA section 13 (15 U.S.C. 2612) import certification requirements promulgated at 19 CFR 12.118 through 12.127 and 19 CFR 127.28. Chemical importers must certify that the shipment of the chemical substance complies with all applicable rules and orders under TSCA. Importers of chemicals subject to these SNURs must certify their compliance with the SNUR requirements. The EPA policy in support of import certification appears at 40 CFR part 707, subpart B. In addition, any persons who export or intend to export a chemical substance that is the subject of this rule on or after December 19, 2016 are subject to the export notification provisions of TSCA section 12(b) (15 U.S.C. 2611(b)) (see § 721.20), and must comply with the export notification requirements in 40 CFR part 707, subpart D.
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EPA is promulgating these SNURs using direct final procedures. These SNURs will require persons to notify EPA at least 90 days before commencing the manufacture or processing of a chemical substance for any activity designated by these SNURs as a significant new use. Receipt of such notices allows EPA to assess risks that may be presented by the intended uses and, if appropriate, to regulate the proposed use before it occurs. Additional rationale and background to these rules are more fully set out in the preamble to EPA's first direct final SNUR published in the
Section 5(a)(2) of TSCA (15 U.S.C. 2604(a)(2)) authorizes EPA to determine that a use of a chemical substance is a “significant new use.” EPA must make this determination by rule after considering all relevant factors, including the four bulleted TSCA section 5(a)(2) factors listed in Unit III. Once EPA determines that a use of a chemical substance is a significant new use, TSCA section 5(a)(1)(B) requires persons to submit a significant new use notice (SNUN) to EPA at least 90 days before they manufacture or process the chemical substance for that use (15 U.S.C. 2604(a)(1)(B)(i)). TSCA furthermore prohibits such manufacturing or processing from commencing until EPA has conducted a review of the notice, made an appropriate determination on the notice, and taken such actions as are required in association with that determination (15 U.S.C. 2604(a)(1)(B)(ii)). As described in Unit V., the general SNUR provisions are found at 40 CFR part 721, subpart A.
General provisions for SNURs appear in 40 CFR part 721, subpart A. These provisions describe persons subject to the rule, recordkeeping requirements, exemptions to reporting requirements, and applicability of the rule to uses occurring before the effective date of the rule. Provisions relating to user fees appear at 40 CFR part 700. According to § 721.1(c), persons subject to these SNURs must comply with the same SNUN requirements and EPA regulatory procedures as submitters of PMNs under TSCA section 5(a)(1)(A). In particular, these requirements include the information submission requirements of TSCA section 5(b) and 5(d)(1), the exemptions authorized by TSCA sections 5(h)(1), (h)(2), (h)(3), and (h)(5), and the regulations at 40 CFR part 720. Once EPA receives a SNUN, EPA must either determine that the significant new use is not likely to present an unreasonable risk of injury or take such regulatory action as is associated with an alternative determination before the manufacture or processing for the significant new use can commence. If EPA determines that the significant new use is not likely to present an unreasonable risk, EPA is required under TSCA section 5(g) to make public, and submit for publication in the
Section 5(a)(2) of TSCA states that EPA's determination that a use of a chemical substance is a significant new use must be made after consideration of all relevant factors, including:
• The projected volume of manufacturing and processing of a chemical substance.
• The extent to which a use changes the type or form of exposure of human beings or the environment to a chemical substance.
• The extent to which a use increases the magnitude and duration of exposure of human beings or the environment to a chemical substance.
• The reasonably anticipated manner and methods of manufacturing, processing, distribution in commerce, and disposal of a chemical substance.
In addition to these factors enumerated in TSCA section 5(a)(2), the statute authorized EPA to consider any other relevant factors.
To determine what would constitute a significant new use for the 57 chemical substances that are the subject of these SNURs, EPA considered relevant information about the toxicity of the chemical substances, likely human exposures and environmental releases associated with possible uses, and the four bulleted TSCA section 5(a)(2) factors listed in this unit.
EPA is establishing significant new use and recordkeeping requirements for 57 chemical substances in 40 CFR part 721, subpart E. In this unit, EPA provides the following information for each chemical substance:
• PMN number.
• Chemical name (generic name, if the specific name is claimed as CBI).
• Chemical Abstracts Service (CAS) Registry number (if assigned for non-confidential chemical identities).
• Basis for the TSCA section 5(e) consent order or, for non-section 5(e) SNURs, the basis for the SNUR (
• Tests recommended by EPA to provide sufficient information to evaluate the chemical substance (see Unit VIII. for more information).
• CFR citation assigned in the regulatory text section of this rule.
The regulatory text section of this rule specifies the activities designated as significant new uses. Certain new uses, including production volume limits (
This rule includes 34 PMN substances that are subject to “risk-based” consent orders under TSCA section 5(e)(1)(A)(ii)(I) where EPA determined that activities associated with the PMN substances may present unreasonable risk to human health or the environment. Those consent orders require protective measures to limit exposures or otherwise mitigate the potential unreasonable risk. The so-called “TSCA section 5(e) SNURs” on these PMN substances are promulgated pursuant to § 721.160, and are based on and consistent with the provisions in the underlying consent orders. The TSCA section 5(e) SNURs designate as a “significant new use” the absence of the protective measures required in the corresponding consent orders.
Where EPA determined that the PMN substance may present an unreasonable risk of injury to human health via inhalation exposure, the underlying TSCA section 5(e) consent order usually requires, among other things, that potentially exposed employees wear specified respirators unless actual measurements of the workplace air show that air-borne concentrations of the PMN substance are below a New Chemical Exposure Limit (NCEL) that is established by EPA to provide adequate protection to human health. In addition to the actual NCEL concentration, the comprehensive NCELs provisions in TSCA section 5(e) consent orders, which are modeled after Occupational Safety and Health Administration (OSHA) Permissible Exposure Limits (PELs) provisions, include requirements addressing performance criteria for sampling and analytical methods, periodic monitoring, respiratory protection, and recordkeeping. However, no comparable NCEL provisions currently exist in 40 CFR part 721, subpart B, for SNURs. Therefore, for these cases, the individual SNURs in 40 CFR part 721, subpart E, will state that persons subject to the SNUR who wish to pursue NCELs as an alternative to the § 721.63 respirator requirements may request to do so under § 721.30. EPA expects that persons whose § 721.30 requests to use the NCELs approach for SNURs are approved by EPA will be required to comply with NCELs provisions that are comparable to those contained in the corresponding TSCA section 5(e) consent order for the same chemical substance.
This rule also includes SNURs on 23 PMN substances that are not subject to consent orders under TSCA section 5(e). These cases completed Agency review prior to June 22, 2016. Under TSCA, prior to the enactment of the Frank R. Lautenberg Chemical Safety for the 21st Century Act on June 22, 2016, EPA did not find that the use scenario described in the PMN triggered the determinations set forth under TSCA section 5(e). However, EPA does believe that certain changes from the use scenario described in the PMN could result in increased exposures, thereby constituting a “significant new use.” These so-called “non-TSCA section 5(e) SNURs” are consistent with the determination made at the time and are promulgated pursuant to § 721.170. EPA has determined that every activity designated as a “significant new use” in all non-TSCA section 5(e) SNURs issued under § 721.170 satisfies the two requirements stipulated in § 721.170(c)(2),
The PMN states that the generic use of the PMN substance will be as a specialty additive. Based on test data on analogous respirable, poorly soluble particulates and nanocarbon materials, EPA identified concerns for pulmonary toxicity and oncogenicity. Based on test data for other nanocarbon materials EPA identified concerns for environmental toxicity. The Order was issued under TSCA sections 5(e)(1)(A)(i) and 5(e)(1)(A)(ii)(I), based on a finding that the substance may present an unreasonable risk of injury to human health and the environment. To protect against these risks, the consent order requires:
1. Use of personal protective equipment involving impervious gloves and protective clothing (where there is a potential for dermal exposures) and a National Institute for Occupational Safety and Health (NIOSH)-certified air purifying, tight-fitting full-face respirator equipped with N-100, P-100, or R-100 cartridges, or power air purifying particulate respirator with an Assigned Protection Factor (APF) of at least 50 (where there is a potential for inhalation exposures).
2. Submission of a dustiness test within six months of notice of commencement of manufacture (NOC).
3. Submission of certain physical-chemical properties data within the time limits specified in the consent order.
4. Processing and use of the PMN substance only for the use specified in the consent order, including no application method that generates a vapor, mist or aerosol unless the application method occurs in an enclosed process.
5. No use of the PMN substance resulting in releases to surface waters and disposal of the PMN substance only by landfill or incineration.
The SNUR would designate as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 50 or compliance with a NCEL of 0.0025 mg/m
2. Hazard communication. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the Material Safety Data Sheet (MSDS).
3. No domestic manufacture of the PMN substance.
4. Use of the PMN substances only for the confidential uses specified in the consent order.
5. Submission of certain toxicity testing on the PMN substance prior to exceeding the confidential production volume limit as specified in the consent order of the PMN substance.
The SNUR designates as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment involving impervious gloves and protective clothing (where there is a potential for dermal exposures) and a National Institute for Occupational Safety and Health (NIOSH)-certified air purifying, tight-fitting full-face respirator equipped with N-100, P-100, or R-100 cartridges, or power air purifying particulate respirator with an Assigned Protection Factor (APF) of at least 50 (where there is a potential for inhalation exposures).
2. Submission of certain physical-chemical data for the PMN substances within the time triggers specified in the consent order.
3. Submission of certain human health testing prior to exceeding the confidential production volume limit specified in the consent order.
4. Establishment of a medical surveillance program as specified in the consent order.
5. Processing and use of the PMN substances only for the uses specified in the consent order, including no application method that generates a vapor, mist or aerosol unless the application method occurs in an enclosed process.
6. No use of the PMN substances resulting in releases to surface waters and disposal of the PMN substances only by landfill or incineration.
The SNUR would designate as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 1,000 or compliance with a NCEL of 0.1 mg/m
2. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
3. Submission of a 90-day inhalation study on the PMN substance prior to exceeding the confidential production volume limit as specified in the consent order of the PMN substance.
The SNUR designates as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment including a NIOSH-certified respirator when there is a potential for inhalation exposures.
2. Risk notification. If as a result of the test data required, the company becomes aware that the PMN substances may present a risk of injury to human health or the environment, the company must incorporate this new information, and any information on methods for protecting against such risk into an MSDS, within 90 days.
3. Manufacture of the PMN substances: (a) According to the chemical composition section of the consent order, including analyzing and reporting certain starting raw material impurities to EPA; and (b) within the maximum established limits of certain fluorinated impurities of the PMN substance as stated in the consent order.
4. Submission of certain toxicity, physical-chemical property, and environmental fate testing on the PMN substance prior to exceeding the confidential production volume limits as specified in the consent order.
5. Use of the PMN substances only for water and oil repellent use on military protective clothing.
6. No distribution of the PMN substances for consumer use.
7. No manufacture of the PMN substances in the United States.
8. No water releases of the PMN substances exceeding 17 ppb.
1. Use of a NIOSH-certified respirator when there is a potential for inhalation exposures.
2. Use of impervious gloves where there is a potential for dermal exposures.
3. Risk notification. If as a result of the test data required, the company becomes aware that the PMN substances may present a risk of injury to human health or the environment, the company must incorporate this new information, and any information on methods for protecting against such risk into an MSDS, within 90 days.
4. Manufacture of the PMN substance: (a) According to the chemical composition section of the consent order, including analyzing and reporting certain starting raw material impurities to EPA; and (b) within the maximum established limits of certain fluorinated impurities of the PMN substance as stated in the consent order.
5. Submission of certain toxicity, physical-chemical property, and environmental fate testing on the PMN substance prior to exceeding the confidential production volume limits as specified in the consent order.
6. Use of the PMN substance only for the confidential uses specified in the consent order.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 10 or compliance with a NCEL of 2.4 mg/m
2. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
3. Submission of a 90-day inhalation study on the PMN substance prior to exceeding the production volume limit specified in the consent order of the PMN substance.
The SNUR designates as a “significant new use” the absence of these protective measures.
1. Use of a NIOSH-certified respirator with an APF of at least 10 (where there is a potential for inhalation exposures) or, as an alternative, maintaining workplace airborne concentrations of the chemical substances identified in the consent order at a level below the specified Exposure Limit (EL) of 0.1 ppm and 10 ppm respectively for an8-hour time weighted average.
2. Use of the PMN substances only for the uses specified in the consent order.
3. Manufacture P-14-712 only as described in the PMN.
4. Provide personal protective equipment to workers to prevent dermal exposure, where there is a potential for dermal exposures.
5. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
6. Record and report on a quarterly basis polychlorinated dibenzo-p-dioxin and dibenzofuran levels for P-14-712.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 10 or compliance with a NCEL of 6 mg/m
2. Hazard communication. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
3. Manufacture of the PMN substance only as described in the Consent Order.
4. Submission of certain toxicity testing on the PMN substance within two years of submission of the NOC, as specified in the consent order of the PMN substance.
1. Use of personal protective equipment involving impervious gloves and protective clothing (where there is
2. Submission of certain physical chemical properties according to the time limits described in the order.
3. Submission of a 90-day inhalation study within one year of notice of commencement.
4. Use of the PMN substance only as a chemical intermediate.
5. No use of the PMN substance resulting in releases to surface waters and disposal of the PMN substance only by landfill or incineration.
The SNUR would designate as a “significant new use” the absence of these protective measures.
1. Hazard communication. Establishment and use of a hazard communication program, including environmental and human health precautionary statements on each label and in the MSDS.
2. Submission of certain toxicity testing on the PMN substance prior to exceeding the confidential production volume limit as specified in the consent order of the PMN substance.
3. Use of the PMN substance only for the confidential use specified in the consent order.
4. Comply with the release to water provisions specified in the consent order.
The SNUR designates as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 10 or compliance with a NCEL of 2.4 mg/m
2. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
3. Submission of certain toxicity testing on the PMN substance prior to exceeding the production volume limit as specified in the consent order.
The SNUR designates as a “significant new use” the absence of these protective measures.
1. Use of personal protective equipment including a NIOSH-certified respirator with an APF of at least 10 or compliance with a NCEL of 0.07 mg/m
2. Establishment and use of a hazard communication program, including human health precautionary statements on each label and in the MSDS.
3. Submission of certain toxicity testing on the PMN substances prior to exceeding the production volume limit as specified in the consent order.
The SNUR designates as a “significant new use” the absence of these protective measures.
During review of the PMNs submitted for the chemical substances that are subject to these SNURs, EPA concluded that for 34 of the 57 chemical substances, regulation was warranted under TSCA section 5(e), pending the development of information sufficient to make reasoned evaluations of the health or environmental effects of the chemical substances. The basis for such findings is outlined in Unit IV. Based on these findings, TSCA section 5(e) consent orders requiring the use of appropriate exposure controls were negotiated with the PMN submitters. The SNUR provisions for these chemical substances are consistent with the provisions of the TSCA section 5(e) consent orders. These SNURs are promulgated pursuant to § 721.160 (see Unit VI.).
In the other 23 cases, where the uses are not regulated under a TSCA section 5(e) consent order, EPA determined that one or more of the criteria of concern established at § 721.170 were met, as discussed in Unit IV.
EPA is issuing these SNURs for specific chemical substances which have undergone premanufacture review because the Agency wants to achieve the following objectives with regard to the significant new uses designated in this rule:
• EPA will receive notice of any person's intent to manufacture or process a listed chemical substance for the described significant new use before that activity begins.
• EPA will have an opportunity to review and evaluate data submitted in a SNUN before the notice submitter begins manufacturing or processing a listed chemical substance for the described significant new use.
• EPA will be able to either determine that the prospective manufacture or processing is not likely to present an unreasonable risk, or to take necessary regulatory action associated with any other determination, before the described significant new use of the chemical substance occurs.
• EPA will ensure that all manufacturers and processors of the same chemical substance that is subject to a TSCA section 5(e) consent order are subject to similar requirements.
Issuance of a SNUR for a chemical substance does not signify that the chemical substance is listed on the TSCA Chemical Substance Inventory (TSCA Inventory). Guidance on how to determine if a chemical substance is on the TSCA Inventory is available on the Internet at
EPA is issuing these SNURs as a direct final rule, as described in § 721.160(c)(3) and § 721.170(d)(4). In accordance with § 721.160(c)(3)(ii) and § 721.170(d)(4)(i)(B), the effective date of this rule is January 17, 2017 without further notice, unless EPA receives written adverse or critical comments, or notice of intent to submit adverse or critical comments before December 19, 2016.
If EPA receives written adverse or critical comments, or notice of intent to submit adverse or critical comments, on one or more of these SNURs before December 19, 2016, EPA will withdraw the relevant sections of this direct final rule before its effective date. EPA will then issue a proposed SNUR for the chemical substance(s) on which adverse or critical comments were received, providing a 30-day period for public comment.
This rule establishes SNURs for a number of chemical substances. Any person who submits adverse or critical comments, or notice of intent to submit adverse or critical comments, must identify the chemical substance and the new use to which it applies. EPA will not withdraw a SNUR for a chemical substance not identified in the comment.
To establish a significant new use, EPA must determine that the use is not ongoing. The chemical substances subject to this rule have undergone premanufacture review. In cases where EPA has not received a notice of commencement (NOC) and the chemical
When chemical substances identified in this rule are added to the TSCA Inventory, EPA recognizes that, before the rule is effective, other persons might engage in a use that has been identified as a significant new use. However, TSCA section 5(e) consent orders have been issued for 34 of the 57 chemical substances, and the PMN submitters are prohibited by the TSCA section 5(e) consent orders from undertaking activities which would be designated as significant new uses. The identities of 46 of the 57 chemical substances subject to this rule have been claimed as confidential and EPA has received no post-PMN
Therefore, EPA designates November 9, 2016 (the date of public release/web posting of this rule) as the cutoff date for determining whether the new use is ongoing. This designation varies slightly from EPA's past practice of designating the date of
Persons who begin commercial manufacture or processing of the chemical substances for a significant new use identified as of that date would have to cease any such activity upon the effective date of the final rule. To resume their activities, these persons would have to first comply with all applicable SNUR notification requirements and wait until the notice review period, including any extensions, expires. If such a person met the conditions of advance compliance under § 721.45(h), the person would be considered exempt from the requirements of the SNUR. Consult the
EPA recognizes that TSCA section 5 does not require developing any particular new information (
In the absence of a TSCA section 4 test rule covering the chemical substance, persons are required only to submit information in their possession or control and to describe any other information known to or reasonably ascertainable by them (see 40 CFR 720.50). However, upon review of PMNs and SNUNs, the Agency has the authority to require appropriate testing. In cases where EPA issued a TSCA section 5(e) consent order that requires or recommends certain testing, Unit IV. lists those tests. Unit IV. also lists recommended testing for non-5(e) SNURs. Descriptions of tests are provided for informational purposes. EPA strongly encourages persons, before performing any testing, to consult with the Agency pertaining to protocol selection. To access the OCSPP test guidelines referenced in this document electronically, please go to
In the TSCA section 5(e) consent orders for several of the chemical substances regulated under this rule, EPA has established production volume limits in view of the lack of data on the potential health and environmental risks that may be posed by the significant new uses or increased exposure to the chemical substances. These limits cannot be exceeded unless the PMN submitter first submits the results of toxicity tests that would permit a reasoned evaluation of the potential risks posed by these chemical substances. Under recent TSCA section 5(e) consent orders, each PMN submitter is required to submit each study at least 14 weeks (earlier TSCA section 5(e) consent orders required submissions at least 12 weeks) before reaching the specified production limit. Listings of the tests specified in the TSCA section 5(e) consent orders are included in Unit IV. The SNURs contain the same production volume limits as the TSCA section 5(e) consent orders. Exceeding these production limits is defined as a significant new use. Persons who intend to exceed the production limit must notify the Agency by submitting a SNUN at least 90 days in advance of commencement of non-exempt commercial manufacture or processing.
The recommended tests specified in Unit IV. may not be the only means of addressing the potential risks of the chemical substance. However, submitting a SNUN without any test data may increase the likelihood that EPA will take action under TSCA section 5(e), particularly if satisfactory test results have not been obtained from a prior PMN or SNUN submitter. EPA recommends that potential SNUN submitters contact EPA early enough so that they will be able to conduct the appropriate tests.
SNUN submitters should be aware that EPA will be better able to evaluate SNUNs which provide detailed information on the following:
• Human exposure and environmental release that may result from the significant new use of the chemical substances.
• Potential benefits of the chemical substances.
• Information on risks posed by the chemical substances compared to risks posed by potential substitutes.
By this rule, EPA is establishing certain significant new uses which have been claimed as CBI subject to Agency confidentiality regulations at 40 CFR part 2 and 40 CFR part 720, subpart E. Absent a final determination or other disposition of the confidentiality claim under 40 CFR part 2 procedures, EPA is required to keep this information confidential. EPA promulgated a procedure to deal with the situation where a specific significant new use is CBI, at 40 CFR 721.1725(b)(1).
Under these procedures a manufacturer or processor may request EPA to determine whether a proposed use would be a significant new use under the rule. The manufacturer or processor must show that it has a
If EPA determines that the use identified in the
According to § 721.1(c), persons submitting a SNUN must comply with the same notification requirements and EPA regulatory procedures as persons submitting a PMN, including submission of test data on health and environmental effects as described in 40 CFR 720.50. SNUNs must be submitted on EPA Form No. 7710-25, generated using e-PMN software, and submitted to the Agency in accordance with the procedures set forth in 40 CFR 720.40 and § 721.25. E-PMN software is available electronically at
EPA has evaluated the potential costs of establishing SNUN requirements for potential manufacturers and processors of the chemical substances subject to this rule. EPA's complete economic analysis is available in the docket under docket ID number EPA-HQ-OPPT-2016-0207.
EPA has used scientific information, technical procedures, measures, methods, protocols, methodologies, and models consistent with the risk assessment documents included in the public docket. These information sources supply information relevant to whether a particular use would be a significant new use, based on relevant factors including those listed under TSCA section 5(a)(2).
The clarity and completeness of the data, assumptions, methods, quality assurance, and analyses employed in EPA's decision are documented, as applicable and to the extent necessary for purposes of this significant new use rule, in Unit II and in the documents noted above. EPA recognizes, based on the available information, that there is variability and uncertainty in whether any particular significant new use would actually present an unreasonable risk. For precisely this reason, it is appropriate to secure a future notice and review process for these uses, at such time as they are known more definitely. The extent to which the various information, procedures, measures, methods, protocols, methodologies or models used in EPA's decision have been subject to independent verification or peer review is adequate to justify their use, collectively, in the record for a significant new use rule.
This action establishes SNURs for several new chemical substances that were the subject of PMNs, or TSCA section 5(e) consent orders. The Office of Management and Budget (OMB) has exempted these types of actions from review under Executive Order 12866, entitled
According to PRA (44 U.S.C. 3501
The information collection requirements related to this action have already been approved by OMB pursuant to PRA under OMB control number 2070-0012 (EPA ICR No. 574). This action does not impose any burden requiring additional OMB approval. If an entity were to submit a SNUN to the Agency, the annual burden is estimated to average between 30 and 170 hours per response. This burden estimate includes the time needed to review instructions, search existing data sources, gather and maintain the data needed, and complete, review, and submit the required SNUN.
Send any comments about the accuracy of the burden estimate, and any suggested methods for minimizing respondent burden, including through the use of automated collection techniques, to the Director, Collection Strategies Division, Office of Environmental Information (2822T), Environmental Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460-0001. Please remember to include the OMB control number in any correspondence, but do not submit any completed forms to this address.
On February 18, 2012, EPA certified pursuant to RFA section 605(b) (5 U.S.C. 601
1. A significant number of SNUNs would not be submitted by small entities in response to the SNUR.
2. The SNUR submitted by any small entity would not cost significantly more than $8,300.
A copy of that certification is available in the docket for this action.
This action is within the scope of the February 18, 2012 certification. Based on the Economic Analysis discussed in Unit XI. and EPA's experience promulgating SNURs (discussed in the certification), EPA believes that the following are true:
• A significant number of SNUNs would not be submitted by small entities in response to the SNUR.
• Submission of the SNUN would not cost any small entity significantly more than $8,300.
Therefore, the promulgation of the SNUR would not have a significant economic impact on a substantial number of small entities.
Based on EPA's experience with proposing and finalizing SNURs, State, local, and Tribal governments have not been impacted by these rulemakings, and EPA does not have any reasons to believe that any State, local, or Tribal government will be impacted by this action. As such, EPA has determined that this action does not impose any enforceable duty, contain any unfunded mandate, or otherwise have any effect on small governments subject to the requirements of UMRA sections 202, 203, 204, or 205 (2 U.S.C. 1501
This action will not have a substantial direct effect on States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999).
This action does not have Tribal implications because it is not expected to have substantial direct effects on Indian Tribes. This action does not significantly nor uniquely affect the communities of Indian Tribal governments, nor does it involve or impose any requirements that affect Indian Tribes. Accordingly, the requirements of Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 9, 2000), do not apply to this action.
This action is not subject to Executive Order 13045, entitled “Protection of Children from Environmental Health Risks and Safety Risks” (62 FR 19885, April 23, 1997), because this is not an economically significant regulatory action as defined by Executive Order 12866, and this action does not address environmental health or safety risks disproportionately affecting children.
This action is not subject to Executive Order 13211, entitled “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355, May 22, 2001), because this action is not expected to affect energy supply, distribution, or use and because this action is not a significant regulatory action under Executive Order 12866.
In addition, since this action does not involve any technical standards, NTTAA section 12(d) (15 U.S.C. 272 note), does not apply to this action.
This action does not entail special considerations of environmental justice related issues as delineated by Executive Order 12898, entitled “Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations” (59 FR 7629, February 16, 1994).
Pursuant to the Congressional Review Act (5 U.S.C. 801
Environmental protection, Reporting and recordkeeping requirements.
Environmental protection, Chemicals, Hazardous substances, Reporting and recordkeeping requirements.
Therefore, 40 CFR parts 9 and 721 are amended as follows:
7 U.S.C. 135
15 U.S.C. 2604, 2607, and 2625(c).
(a)
(2) The significant new uses are:
(i)
(ii)
(iii)
(iv)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.0025 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii)
(iii)
(iv)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(3) The significant new uses for any use other than as chemical intermediates, additives for flotation products, or adhesion promoters for use in asphalt applications are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.1 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(3) The significant new uses for any use other than as emulsifier intermediates or adhesion promoters for use in asphalt applications are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 2.4 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(3) The significant new uses for any use other than as surfactants for use in asphalt applications are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the exposure limit (EL) provision listed in the TSCA section 5(e) consent order for this substance. The EL is both 0.1 ppm for benzene and 10 ppm for naphthalene as an 8-hour time weighted average.
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the exposure limit (EL) provision listed in the TSCA section 5(e) consent order for this substance. The EL is both 0.1 ppm for benzene and 10 ppm for naphthalene as an 8-hour time weighted average.
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the exposure limit (EL) provision listed in the TSCA section 5(e) consent order for this substance. The EL is both 0.1 ppm for benzene and 10 ppm for naphthalene as an 8-hour time weighted average.
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the exposure limit (EL) provision listed in the TSCA section 5(e) consent order for this substance. The EL is both 0.1 ppm for benzene and 10 ppm for naphthalene as an 8-hour time weighted average.
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 6 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii)
(iii)
(iv)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii)
(iii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii)
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(3)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 2.4 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07 mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(A) As an alternative to the respirator requirements in paragraph (a)(2)(i) of this section, a manufacturer or processor may choose to follow the new chemical exposure limit (NCEL) provision listed in the TSCA section 5(e) consent order for this substance. The NCEL is 0.07mg/m
(B) [Reserved]
(ii)
(iii)
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
(a)
(2) The significant new uses are:
(i)
(ii) [Reserved]
(b)
(1)
(2)
Environmental Protection Agency (EPA).
Proposed rule.
The Environmental Protection Agency (EPA) is proposing nonattainment area classification thresholds and implementation requirements for the strengthened 2015 ozone national ambient air quality standards (NAAQS) (2015 ozone NAAQS) that were promulgated on October 1, 2015. This proposal is largely an update to the implementing regulations previously promulgated for the 2008 ozone NAAQS, and we propose to retain without significant revision the majority of those provisions to implement the 2015 ozone NAAQS. This proposal addresses the timing of attainment dates for each nonattainment area classification and a range of nonattainment area state implementation plan (SIP) requirements for the 2015 ozone NAAQS. The proposed SIP requirements pertain to attainment demonstrations, reasonable further progress (RFP) and associated milestone demonstrations, reasonably available control technology (RACT), reasonably available control measures (RACM), major nonattainment new source review (NNSR), emission inventories, the timing of required SIP submissions, and compliance with emission control measures in the SIP. Other issues addressed in this proposed rule are the revocation of the 2008 ozone NAAQS, anti-backsliding requirements that would apply when the 2008 ozone NAAQS are revoked, and reconsideration of the ozone NAAQS interprecursor trading (IPT) provisions (in response to a petition for reconsideration).
For further general information on this proposed rule, contact Mr. Robert Lingard, Office of Air Quality Planning and Standards (OAQPS), U.S. EPA, at (919) 541-5272 or
The following are abbreviations of terms used in the preamble.
Entities potentially affected directly by this proposed rule include state, local and tribal governments and air pollution control agencies (“air agencies”) responsible for attainment and maintenance of the NAAQS. Entities potentially affected indirectly by this proposed rule as regulated sources include owners and operators of sources of emissions of volatile organic compounds (VOCs) and nitrogen oxides
When submitting comments, remember to:
• Identify the rulemaking docket by docket number and other identifying information (subject heading,
• Follow directions. The proposed rule 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 to support your comment.
• 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 wherever possible, 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.
To request a public hearing or information pertaining to a public hearing regarding this document, contact Ms. Pamela Long, OAQPS, U.S. EPA, at (919) 541-0641 or
In addition to being available in the docket, an electronic copy of this
The information and proposals presented in this notice are organized as follows:
On October 1, 2015,
The revisions to the ozone NAAQS trigger a process under which states recommend area designations (
The Clean Air Act (CAA or Act) does not require that the EPA promulgate new or revised implementing regulations or guidance every time that a NAAQS is revised. State, local and tribal air agencies (hereinafter, referred to simply as air agencies) are required to submit SIPs as provided in the CAA and in EPA regulations. Where the nature of revisions to a NAAQS indicate that additional regulations or guidance (or revisions to existing regulations or guidance) may be helpful, the EPA endeavors to provide such regulations or guidance to facilitate the designations process and preparation of timely SIP submittals. It is important to note, however, that the existing EPA regulations in 40 CFR part 51 applicable to SIPs generally and to particular pollutants (
The EPA believes that the overall framework and policy approach of the implementation provisions associated with the 2008 ozone NAAQS provide an effective and appropriate template for the general approach air agencies should follow in planning for attainment of the revised ozone standards. However, to assist with the implementation of the revised ozone standards, the EPA is proposing this additional ozone NAAQS implementation rule.
We are proposing multiple actions in this rule pertaining to nonattainment area classification thresholds and associated attainment dates, as well as submittal deadlines and specific CAA requirements for the content of nonattainment area and Ozone Transport Region (OTR) SIPs for the 2015 ozone NAAQS. As a general matter, this proposed rule follows the same basic principles and approach that the EPA applied to interpret the CAA's part D, subpart 2 ozone nonattainment area requirements in developing the classification and implementation rules for the 2008 ozone NAAQS.
Regarding the format of this preamble, we organize our discussion of implementation requirements for the 2015 ozone NAAQS around the implementing regulations for the 2008 ozone NAAQS. As stated previously, we propose to retain without significant revision the majority of those existing regulations to implement the 2015 ozone NAAQS, as discussed in Section III of this preamble. We discuss the existing implementing regulations that we propose to retain with specific revisions for implementing the 2015 ozone NAAQS in Section IV of this preamble. For topics where we do not propose any action, we provide guidance on that topic in the preamble. Section V of this preamble addresses several requirements and policies not covered by this proposed rulemaking (with one exception), but for which the EPA is soliciting public comment (
For purposes of the 2015 ozone NAAQS, we are proposing to retain the majority of existing implementation provisions for the 2008 ozone NAAQS without significant revision. The existing classification and SIP requirement provisions for the 2008 standards are codified at subpart AA of 40 CFR part 51, and the corresponding provisions for the 2015 standards would be codified at the new subpart CC of part 51. As discussed earlier, the EPA believes that the implementing regulations for the 2008 standards generally provide an appropriate approach to follow in attainment planning for the 2015 standards, and we welcome comment on the following proposed provisions.
The EPA is proposing to retain the existing approach to calculating deadlines for submitting nonattainment SIP elements. Section 182 of the CAA requires states with ozone nonattainment areas to submit various SIP elements within specified time periods after enactment of the CAA Amendments of 1990. For the 2008 ozone NAAQS, the EPA adopted the approach that the SIP elements listed in the proposal are due based on the timeframes provided in CAA section 182 as measured from the effective date of designation, instead of the 1990 date. For reference, the final 2008 Ozone NAAQS SIP Requirements Rule (2008 ozone SRR) provides an extensive discussion of the EPA's current approach and rationale for SIP element submittal deadlines (80 FR 12265; March 6, 2015). The EPA is proposing to retain the same approach for calculating deadlines for submitting nonattainment area SIP elements under CAA section 182 for the 2015 ozone NAAQS, based on the current approach and rationale articulated in the final 2008 Ozone NAAQS SIP Requirements Rule.
Accordingly, states with areas designated nonattainment have 2 years from the effective date of nonattainment designation to submit SIP revisions addressing emission inventories (required by CAA section 182(a)(1)), RACT (CAA section 182(b)(2)) and emissions statement regulations
We note also that the EPA's implementing regulations for revised ozone NAAQS have required OTR states
The EPA is restating the existing requirement that states must submit all nonattainment SIP elements applicable for an area's classification upon revision of the NAAQS, and is providing the following guidance on the form and content of such submissions. As discussed in the preceding section, a SIP submission is due from air agencies for every nonattainment area for each of the SIP elements listed in this proposal, including (but not limited to) emissions statement regulations, nonattainment NSR, and vehicle I/M programs, upon revision of the NAAQS, and they are due based on the timeframes provided in CAA section 182 as measured from the effective date of designation.
The EPA interprets the CAA to require an air agency to provide a SIP submission to meet each nonattainment area planning requirement for the 2015 ozone NAAQS. Many air agencies may already have regulations to address certain requirements in place due to nonattainment designations for a prior ozone NAAQS. Air agencies should review any existing regulation that was previously approved by the EPA to determine whether it is sufficient to fulfill obligations triggered by any revised ozone NAAQS. In cases where a previously-approved provision is modified for any reason, or where no provision exists, air agencies must provide the new or modified provision as a SIP submission. This would include new or modified RACT provisions for states with nonattainment areas and states in an OTR, which must be reviewed to ensure that emissions from affected stationary sources are appropriately controlled. However, where an air agency believes that an existing regulation is adequate to meet the nonattainment requirements of CAA section 182 (or OTR RACT requirements of CAA section 184) for a revised ozone NAAQS, that air agency's SIP submission may provide a written statement of the rationale for that determination in lieu of submitting new revised regulations. For example, a state may have an emissions statement regulation (per CAA section 182(a)(3)(B)) that has been previously approved by the EPA for a prior ozone NAAQS that covers all of the state's nonattainment areas and relevant classes and categories of sources for the 2015 ozone NAAQS, and is likely to be sufficient for purposes of the emissions statement requirement for the 2015 ozone NAAQS. The EPA has taken action on similar written statements.
An air agency choosing to provide a written statement to meet the submission requirement of the CAA must provide the statement to the EPA as a SIP submission in accordance with CAA section 110 and 40 CFR 51.102, 103 and Appendix V. An air agency should identify the related applicable requirements and how each is met for the revised ozone NAAQS by the regulation previously approved for a prior ozone NAAQS. The purpose of the statement is to demonstrate compliance with the nonattainment plan requirements for the new NAAQS. These written statements must be treated in the same manner as any SIP submission and must be provided to the EPA in accordance with applicable SIP submission requirements and deadlines.
The EPA is proposing to retain its existing general requirement that establishes the applicability of 40 CFR part 51 to the current and prior ozone NAAQS. The general applicability of 40 CFR part 51 to the 2008 ozone NAAQS is codified in 40 CFR 51.1101, and requires that the provisions in subparts A through X of part 51 apply to areas to the extent they are not inconsistent with the specific implementation provisions for the 2008 standards (
The EPA is proposing to retain its existing general classification and nonattainment area planning provisions, which are codified for the 2008 ozone NAAQS in 40 CFR 51.1102. These provisions require that designated areas be classified in accordance with CAA section 181 (classifications and attainment dates), as interpreted in 40 CFR 51.1103(a), and that designated areas will be subject to the applicable planning requirements of subpart 2 of part D of title I of the CAA (additional provisions for ozone nonattainment areas). The EPA is proposing to retain the same general requirements for the 2015 ozone NAAQS, without revision, and codify them at 40 CFR 51.1302 and 51.1303(a).
The EPA is proposing to retain its existing requirements for areas initially designated attainment for the current ozone NAAQS and subsequently redesignated to nonattainment for the same standards, which are codified for the 2008 ozone NAAQS in 40 CFR 51.1106. These provisions generally allow an extension of any absolute, fixed date for SIP requirements under part 51—excluding attainment dates—equal to the length of time between the effective date of the initial designation for the NAAQS and the effective date of redesignation, unless otherwise provided in the implementation provisions for those standards. The maximum attainment date for a redesignated area would be based on the area's classification (
The EPA is proposing to retain its existing eligibility criteria for 1-year attainment date extensions under CAA section 181(a)(5), which are codified for the 2008 ozone NAAQS in 40 CFR 51.1107. An area that fails to attain a specific ozone NAAQS by its attainment date would be eligible for the first 1-year extension if, for the attainment year, the area's fourth highest daily maximum 8-hour average is at or below the level of the standards. The area would be eligible for the second 1-year extension if the area's fourth highest daily maximum 8-hour value, averaged over both the original attainment year and the first extension year, is at or below the level of the standards. For the second 1-year extension, the area's fourth highest daily maximum 8-hour average for each year (the attainment year and the first extension year) must be determined using the monitor which, for that year, has the fourth highest daily maximum 8-hour average of all the monitors that represent that area (
We are also restating in this preamble that, in addition to demonstrating that an area meets these general eligibility criteria, an air agency must demonstrate that it has complied with all requirements and commitments pertaining to the area in the applicable SIP, per CAA section 181(a)(5)(A). Given the state and federal partnership in implementing the CAA, it is reasonable for the EPA to interpret CAA section 181(a)(5)(A) as permitting the agency to rely upon the certified statements of its state counterparts, and the EPA has long interpreted the provision to be satisfied by such statements.
The EPA is proposing to retain its existing modeling and attainment demonstration requirements, which are codified for the 2008 ozone NAAQS in 40 CFR 51.1108, and to establish criteria and due dates for attainment demonstrations and implementation of control measures. Due dates for attainment demonstrations are established relative to the effective date of area designations, and all control measures in the attainment demonstration must be implemented no later than the beginning of the attainment year ozone season, notwithstanding specific RACT and/or RACM implementation deadline requirements. For reference, the final 2008 Ozone NAAQS SIP Requirements Rule provides an extensive discussion of attainment demonstration elements and related modeling protocols (80 FR 12268; March 6, 2015). The EPA's current procedures for modeling are well developed and described in the EPA's “Draft Modeling Guidance for Demonstrating Attainment of Air Quality Goals for Ozone, PM
The EPA is proposing to retain its existing RFP requirements and to add new regulatory provisions codifying statutory requirements for RFP milestone compliance demonstrations (MCDs) (
The RFP requirements for the 2008 ozone NAAQS are codified in 40 CFR 51.1110 and require that nonattainment SIPs provide for the annual incremental emission reductions needed to ensure attainment of the NAAQS. The provisions in 40 CFR 51.1110 are organized by the following major subjects: Submission deadline for SIP revisions; RFP requirements for affected areas;
The EPA is proposing to retain the same RFP approach and requirements for the 2015 ozone NAAQS, except that they would also apply to areas with approved RFP plans for the 2008 ozone NAAQS, in addition to the 1-hour and 1997 standards. This proposed approach includes continuing to state that the baseline year for RFP should be the calendar year for the most recently available triennial emission inventory at the time ROP/RFP plans are developed (
The EPA is proposing to codify our existing interpretation of statutory requirements for RFP MCD, which would be codified into specific provisions of the RFP requirements discussed here (
The EPA is proposing to retain its existing general RACT requirements, and to add new deadline requirements for certain RACT SIP revisions (
The EPA is proposing to retain its existing RACM requirements, and to clarify the requirement under CAA section 172(c)(6) that air agencies also consider the impacts of emissions from sources outside an ozone nonattainment area but within a state's boundaries, and to require such other measures for emissions reductions from these intrastate sources if needed to attain the ozone NAAQS by the applicable attainment date (
The final 2008 Ozone NAAQS SIP Requirements Rule also recommended that if wildfire impacts are significant in an area and contribute to exceedances of the standard, then air agencies should consider RACM for wildfires (which could include the use of prescribed fires). As discussed in Section V.A of this preamble, the EPA is revising its recommendation, such that prescribed fire and related wildland management practices instead be addressed outside of the regulatory framework of nonattainment planning.
The EPA is proposing to retain its existing CAA section 182(f) NO
With one significant exception, the EPA is proposing to retain its NNSR requirements contained at 40 CFR 51.165 and part 51 Appendix S, which contain provisions for the preconstruction review and issuance of permits to proposed new major stationary sources and major modifications locating in ozone nonattainment areas. The one exception pertains to a proposal to address IPT for ozone. As explained in Section IV.F of this preamble, the EPA is proposing to confirm its policy on ozone IPT, which is currently codified at 40 CFR 51.165(a)(11) and part 51 Appendix S, section IV.G.5, in response to a petition for reconsideration. A basic understanding about how the NNSR requirements would otherwise apply to the 2015 ozone NAAQS can be obtained from the preamble discussion at Section VIII.C in the final rule for the setting of
The EPA proposes to codify NNSR requirements for the ozone NAAQS at 40 CFR 51.1314. These provisions would require that for each nonattainment area an air agency must submit an NNSR plan or plan revision for the 2015 ozone NAAQS no later than 36 months after the effective date of the area's nonattainment designation for the 2015 ozone NAAQS. As discussed in Section IV.B of this preamble, we are proposing two options for revoking the 2008 ozone NAAQS. The first approach to revoking the 2008 ozone NAAQS (option 1) would parallel the approach used in revoking the 1-hour and 1997 ozone NAAQS, and would require that a set of protective anti-backsliding requirements be promulgated for all areas that are designated nonattainment for both the 2008 NAAQS and the 2015 NAAQS. Under the second approach (option 2), the 2008 ozone NAAQS would not be revoked in any area designated nonattainment for the 2008 ozone NAAQS until that area is redesignated to attainment with an approved CAA section 175A 10-year maintenance plan; but in no case earlier than 1 year after the effective date of designation for the 2015 ozone NAAQS. If the EPA were to revoke the 2008 ozone NAAQS according to proposed option 1, the EPA is also proposing conforming changes to the existing anti-backsliding provisions at 40 CFR 51.165(a)(12) and part 51 Appendix S section VII.
The EPA is not proposing any changes to the existing ozone ambient monitoring requirements are codified in 40 CFR part 58. Monitoring rule amendments published on October 17, 2006, (71 FR 61236) established minimum ozone monitoring requirements based on population and levels of ozone in an area to better prioritize monitoring resources. The minimum monitoring requirements are contained in Table D-2 of appendix D to part 58. The Photochemical Assessment Monitoring Station (PAMS) program, required by CAA section 182(c)(1), collects enhanced ambient air measurements. The rulemaking for the final 2015 ozone NAAQS included revisions to the PAMS requirements (80 FR 65416; October 26, 2015). The revisions were intended to provide a more spatially dispersed network, reduce potential redundancy, and improve data value while providing monitoring agencies flexibility in collecting additional information needed to understand their specific ozone issues.
The EPA is proposing to retain its existing OTR requirements, and to add new deadline requirements for certain RACT SIP revisions (
The EPA is proposing to retain its existing fee program SIP submission requirements, which are codified for the 2008 ozone NAAQS in 40 CFR 51.1117, and apply to each area classified Severe or Extreme for that standard. Affected areas must submit a SIP revision that meets the requirements of CAA section 185 (Enforcement for Severe and Extreme ozone nonattainment areas for failure to attain) within 10 years of the effective date of designation and classification as a Severe or Extreme area. The EPA is proposing to retain the same SIP submission requirements for the 2015 ozone NAAQS, without revision.
The EPA is proposing to retain the provision that establishes applicability of the current ozone NAAQS implementation provisions, which is codified for the 2008 ozone NAAQS in 40 CFR 51.1119. The provision states that the current provisions (subpart AA of part 51) shall replace those for the previous 1997 standards (subpart X of part 51) after revocation of the 1997 NAAQS, except for anti-backsliding purposes. The EPA is proposing to retain the same requirements for the 2015 ozone NAAQS, except that the proposed new implementation provisions (to be codified in the new subpart CC of part 51) would replace those for the 2008 ozone NAAQS (subpart AA) if the 2008 standards are revoked for all purposes, except for anti-backsliding purposes. The proposed revocation of, and anti-backsliding requirements for, the 2008 ozone NAAQS are discussed in Section IV.B of this preamble.
For purposes of the 2015 ozone NAAQS, we are proposing to promulgate some provisions that are similar to those for the 2008 ozone NAAQS, but with minor modifications to reflect application to the 2015 ozone NAAQS, as explained later. The existing classification and SIP requirement provisions for the 2008 standards, and revocation of the 1997 standards are codified at subpart AA of 40 CFR part 51, and the corresponding provisions for the 2015 standards would be codified at the new subpart CC of part 51. These proposed revisions reflect classification thresholds and attainment deadlines relevant to the 2015 ozone standards; MCD for RFP; submission and implementation deadlines for RACT SIP revisions; the consideration of intrastate pollution sources outside of a nonattainment area for attainment planning; NNSR IPT for ozone; emissions inventories and emissions statements; and revoking the 2008 standards. The EPA welcomes comment on the following proposed provisions.
The EPA is proposing thresholds for classifying nonattainment areas for the 2015 ozone NAAQS, and is proposing the timing of attainment dates for each classification. We are also proposing to grant voluntary reclassification to six California areas designated as nonattainment for the 1997 ozone NAAQS that were voluntarily reclassified under that NAAQS and the subsequent 2008 ozone standards. Each area designated as nonattainment for the 2015 ozone NAAQS will be classified at the same time as the area is designated by the EPA. Accordingly, the EPA intends to finalize classification thresholds on or before the date that it issues area designations.
After promulgating a new or revised NAAQS, the EPA considers air agencies' recommendations for initial area designations (
In accordance with CAA section 181(a)(1), each area designated as nonattainment for the 2015 ozone NAAQS will be classified at the time of designation. The planning and emission reduction requirements as well as the maximum attainment date for each area are based on that area's classification.
Under Subpart 2 of part D of title I of the CAA, state planning and emissions control requirements for ozone are determined, in part, by a nonattainment area's classification. These requirements apply in addition to the general SIP planning requirements applicable to all nonattainment areas under subpart 1 of part D. Under CAA subpart 2, ozone nonattainment areas are classified based on the severity of their ozone levels (as determined based on the area's “design value,” (DV)).
Air agencies with areas in the lower classification levels have fewer mandatory air quality planning and control requirements than those in higher classifications. For instance, air agencies with a Marginal area are only required to adopt an emissions statement rule for major stationary sources, submit a base year emissions inventory, follow the general and transportation conformity requirements in CAA section 176(c), and implement a nonattainment area preconstruction permit program (NNSR). Air agencies with a Moderate area are subject to the Marginal area requirements; in addition air agencies must submit a SIP revision that provides for a 15 percent emissions reduction from the RFP baseline year within 6 years after the baseline year, and a demonstration that the area will attain as expeditiously as practicable, but not later than 6 years after designation. Air agencies with a Moderate area must also adopt (and submit for EPA approval) certain emissions control requirements, such as RACT, a basic vehicle I/M program if the area meets the applicable population thresholds, and provisions for increased offsets for new or modified sources under the state's NNSR program. The higher classifications similarly require additional emissions control programs and stricter NNSR requirements beyond those required for a Moderate area. In addition, the major source threshold for permitting, RACT and emissions reporting decreases progressively from 100 tons per year (tpy) for Marginal areas to 10 tpy for Extreme areas.
• Areas are grouped by the severity of their air quality problem as characterized by the degree of nonattainment based on their DV.
• Classification would occur “by operation of law” without relying on the EPA exercising discretion for individual situations.
• Classification thresholds are derived from the structure or logic of the CAA's nonattainment area planning and control requirements, including the subpart 2 classification table, and consistent with the overall goal of subpart 2 of attaining the standards as expeditiously as practicable. At the same time, the CAA provides mechanisms for voluntary and mandatory reclassification to a higher classification, in the event that the initial maximum attainment date for an area is determined to be insufficient to achieve the standards.
In developing its proposed Classifications Rule for the 2008 ozone standards, the EPA evaluated other options for classifying ozone nonattainment areas but did not find them to be a more reasonable interpretation of the Act's classification provisions, and did not propose or solicit comment on them in the rule.
Under the proposed percent-above-the-standard method, the classification thresholds in the subpart 2 classification table would be translated into a corresponding set of 8-hour DVs that are the same percentages above the 2015 ozone NAAQS as the DV levels in the subpart 2 classification table are above the 1-hour ozone NAAQS. For example, the threshold separating the Marginal and Moderate classifications in the subpart 2 classification table (0.138 ppm) is 15 percent above the 1-hour ozone NAAQS (0.12 ppm). Thus, under this approach, the threshold separating the Marginal and Moderate classifications for the 2015 ozone NAAQS would be 0.070 ppm plus 15 percent, or 0.081 ppm. Table 1 depicts this proposed translation for classifications as it would apply for the 2015 ozone NAAQS.
Based on our analysis of air quality information from 2013-2015, we estimate that approximately 57 “hypothetical nonattainment areas” had ambient ozone concentrations exceeding the 2015 ozone NAAQS. We use these 57 “hypothetical nonattainment areas” for purposes of the following discussion. These hypothetical areas are intended to illustrate the potential distribution of areas into the proposed classifications. The actual number of total nonattainment areas, boundaries of those areas, and the classification of each area will depend on decisions made in the separate designations process under CAA section 107(d) and we anticipate that these decisions will be based on air quality information from 2014-2016. Applying the proposed thresholds in Table 1, the 57 hypothetical nonattainment areas based on 2013-2015 air quality data would yield the distribution in each classification as shown in Table 2.
The proposed classification method results in the vast majority of nonattainment areas being classified Marginal. It is possible that a few areas would have a later maximum statutory attainment date for their existing classification under the 2008 ozone NAAQS than they would have for their new classification under the 2015 NAAQS. For example, an area that would be classified Moderate if designated in 2017 for the more stringent 2015 ozone NAAQS (with a potential maximum statutory attainment date in 2023), may currently be classified Severe for the less-stringent 2008 ozone NAAQS (which has a later maximum statutory attainment date in 2027).
For areas likely to be classified Marginal with a 3-year attainment date
The CAA provides three mechanisms for addressing nonattainment areas that may not be able to attain by the attainment date appropriate to their classification. First, CAA section 181(a)(4) provides that within 90 days of designation and classification, the Administrator may exercise discretion to reclassify an area to a higher (or lower) classification if its DV is within 5 percent of the DV range of the higher (or lower) classification.
The second mechanism, provided in CAA section 181(b)(2), requires that an area be reclassified to a higher classification (
The third mechanism, provided in CAA section 181(b)(3), allows an air agency to voluntarily request that the EPA reclassify the area to a higher classification. The EPA must approve any such requests. Once an area is reclassified to a higher classification, it becomes subject to the associated additional planning and control requirements for that higher classification, and must attain the standard no later than the maximum attainment date for that classification. Six nonattainment areas in California were granted voluntary reclassifications for both the 1997 and 2008 ozone standards (77 FR 30165; May 21, 2012).
The EPA is again proposing to apply a previous voluntary reclassification for areas in California to the more stringent 2015 ozone standards unless the state of California explicitly requests otherwise in their comments to this proposed action.
It is important to note that an air agency may request a voluntary reclassification for an area under CAA section 181(b)(3) at any time. If the air agency wants a specific higher classification to apply to an area at the time of initial designation, the EPA encourages the air agency to make such a request prior to or contemporaneous with the designation process.
The EPA is proposing to retain its current approach in establishing attainment dates for each nonattainment area classification, which run from the effective date of designation. This approach is codified at 40 CFR 51.1103 for the 2008 ozone NAAQS, and we are proposing to retain the same approach for the 2015 ozone NAAQS without revision.
In the implementing regulations for the 1997 ozone NAAQS, the EPA interpreted these timeframes to run from the date that area designations and nonattainment classifications (by operation of law) became effective (64 FR 23954; April 30, 2004). We adopted an alternative approach in the classification regulations for the 2008 ozone standards, where the attainment dates would be December 31 of the year that is the specified number of years in the subpart 2 classification table after designation (77 FR 30166; May 21, 2012). The end of calendar year attainment date was challenged in
Consistent with the regulatory approach for both the 1997 and 2008 ozone NAAQS, we are proposing that the maximum attainment dates for nonattainment areas in each classification under the 2015 NAAQS are as follows: Marginal—3 years from effective date of designation; Moderate—6 years from effective date of designation; Serious—9 years from effective date of designation; Severe—15 years (or 17 years) from effective date of designation; and Extreme—20 years from effective date of designation.
The EPA is proposing and seeking comment on two alternative approaches for revoking the 2008 ozone NAAQS and is also seeking comment on whether to revoke the NAAQS at the current time. The first approach to revoking the 2008 ozone NAAQS would parallel the approach used in revoking the 1-hour and 1997 ozone NAAQS. Under this first approach, the 2008 ozone NAAQS would be revoked at essentially the same time for all areas of the U.S., and a set of protective anti-backsliding requirements would be promulgated for all areas that are designated nonattainment for the 2008 and 2015 NAAQS as of one year after the effective date of designation for the 2015 ozone NAAQS. Under the second approach, the 2008 ozone NAAQS would continue to apply in any area designated nonattainment for the 2008 ozone NAAQS until that area is redesignated to attainment with an approved CAA section 175A 10-year maintenance plan; but in no case earlier than 1 year after the effective date of designation for the 2015 ozone NAAQS. The 2008 ozone NAAQS would be revoked in all other areas 1 year after the effective date of designation for the 2015 ozone NAAQS.
The EPA believes that both of the proposed options to revoke the 2008 ozone NAAQS are consistent with the CAA and previous precedent in transitioning from a previous NAAQS to a new, more stringent NAAQS, and would help ensure that areas designated attainment for the revoked NAAQS continue to attain the revoked NAAQS into the future.
After revocation of the 2008 ozone NAAQS, the designations (and the classifications associated with those designations) for that NAAQS would no longer be in effect. However, the EPA would retain the listing of the designated nonattainment areas and their associated classifications for the revoked 2008 ozone NAAQS in 40 CFR part 81, for the sole purpose of identifying the anti-backsliding requirements that may apply to the areas at the time of revocation. Accordingly, such references to historical designations for the revoked NAAQS should not be viewed as current designations under CAA section 107(d).
The EPA believes it would be appropriate to revoke, rather than retain, the 2008 ozone NAAQS for all purposes because it would ensure that only one ozone NAAQS—in this case the more protective 2015 ozone NAAQS—would directly apply in an area, rather than having a situation in which two standards would apply concurrently. The EPA believes that the permanent retention of two standards, differing only in the ozone concentrations they allow, could result in unnecessarily complex implementation procedures
The D.C. Circuit held that the EPA had authority to revoke the one-hour NAAQS so long as it introduced adequate anti-backsliding measures.
Under this proposed approach, areas that are designated nonattainment for the 2008 ozone NAAQS at the time initial area designations are completed for the 2015 NAAQS would be required to continue to meet all applicable implementation requirements for the 2008 NAAQS in those areas, and would continue to seek redesignation to attainment for the 2008 ozone NAAQS when the areas meet the conditions necessary for redesignation. While such an area remains designated nonattainment for the 2008 ozone NAAQS, transportation and general conformity would continue to apply and the EPA would continue to reclassify areas as provided in CAA section 181(b)(2). Further, the designations for the 2008 ozone NAAQS would no longer be in effect in areas where the NAAQS has been revoked, and the sole designations that would remain in effect would be those for the 2015 ozone NAAQS. Transportation and general conformity requirements for the 2008 ozone NAAQS would no longer apply in the areas where that NAAQS has been revoked.
The EPA notes that under proposed option 2, it is unnecessary to propose a specific set of additional anti-backsliding requirements for the 2008 ozone NAAQS, since option 2 would only revoke this NAAQS in areas initially designated or redesignated attainment for the 2008 NAAQS. Special additional anti-backsliding requirements are not necessary for areas that have attained the 2008 NAAQS. In areas that have been redesignated to attainment for the 2008 ozone NAAQS while that NAAQS is in effect, states have fulfilled all applicable attainment and maintenance plan requirements for that NAAQS, including applicable anti-backsliding requirements for the prior revoked 1997 and 1-hour ozone NAAQS. The area, therefore, is not subject to any specific additional anti-backsliding requirements for the revoked 2008 ozone NAAQS. These areas are required instead to implement their approved CAA section 175A maintenance plan for the 2008 ozone NAAQS and, if designated attainment for the 2008 ozone NAAQS implement a Prevention of Significant Deterioration (PSD) program for this NAAQS. Revisions to the approved maintenance plan for such an area can only be made subject to the CAA's provisions in sections 110(l) and 193, which prevent changes to SIPs if such changes would interfere with attainment and maintenance of the more current 2015 ozone NAAQS.
Under either option 1 or 2 outlined earlier, the EPA is proposing to revoke the 2008 ozone NAAQS no sooner than one year after the effective date of an area's final designation for the 2015 ozone standards.
If the 2008 ozone NAAQS are revoked in an area in a manner consistent with the EPA's first proposed option, the anti-backsliding requirements for those NAAQS would become applicable. The extent of continued implementation efforts for revoked standards derives from administration of anti-backsliding requirements (if any) for the revoked standards. After the 2008 ozone NAAQS is revoked for an area, the EPA will no longer take action to reclassify or to redesignate that area for that NAAQS. Further, the designations for the 2008 ozone NAAQS would be no longer be in effect in such areas, and the sole designations that would remain in effect would be those for the 2015 ozone NAAQS. However, under option 1, the EPA would retain the listing of the designated areas and the associated nonattainment classifications for the revoked 2008 ozone NAAQS in 40 CFR part 81, for the sole purpose of identifying the anti-backsliding requirements that may apply to the areas as of the effective date of the revocation. Such references to historical designations for the revoked standards would not be current designations under CAA section 107(d) and should not be viewed as such. If the EPA finalizes the option 2 approach to revocation of the 2008 ozone NAAQS, the EPA would continue to redesignate areas for the 2008 ozone NAAQS after the initial revocation occurs 1 year after the effective date of designations for the 2015 ozone NAAQS. For any area
“Anti-backsliding” provisions are designed to ensure that for existing ozone nonattainment areas that are designated nonattainment for the revised and more stringent ozone NAAQS, there is protection against degradation of air quality (
Where a NAAQS is relaxed, CAA section 172(e) requires EPA to promulgate regulations that impose on areas, which have not attained a NAAQS prior to a relaxation, controls that are at least as stringent as the controls applicable in nonattainment areas prior to any such relaxation. Such controls are often referred to as “anti-backsliding requirements.” Because the CAA does not speak to what to do where a NAAQS is strengthened, the EPA has historically concluded, and proposes to do so again here, that it is reasonable to look to the principles set forth in CAA section 172 to impose anti-backsliding requirements for purposes of transitioning to a more stringent NAAQS.
Under option 1, the EPA is proposing to retain, for purposes of the transition from the 2008 to the 2015 ozone NAAQS, the existing approach to establishing anti-backsliding requirements. The proposed subpart CC, 40 CFR 51.1300
The following sections discuss the applicable anti-backsliding requirements and how they apply to areas with various designations and classifications for the 2015 standards, the 2008 standards that we are proposing to revoke, and the already revoked 1997 and 1-hour ozone NAAQS. Our proposed approach for revoking the 2008 ozone NAAQS is discussed in Section IV.B of this preamble.
For the revoked 2008 ozone NAAQS, the potentially applicable requirements for an area for anti-backsliding purposes would be identical to the requirements currently codified at 40 CFR 51.1100(o). These requirements include: (1) RACT; (2) Vehicle I/M programs; (3) Major source applicability cut-offs for purposes of RACT; (4) ROP and/or RFP reductions and associated MCDs; (5) the Clean Fuel Fleet program under section 183(c)(4) of the CAA; (6) Clean fuels for boilers under section 182(e)(3) of the CAA; (7) Transportation control measures during heavy traffic hours as provided under section 182(e)(4) of the CAA; (8) Enhanced (ambient) monitoring under section 182(c)(1) of the CAA; (9) Transportation controls under section 182(c)(5) of the CAA; (10) Vehicle miles traveled provisions under section 182(d)(1)(A) of the CAA; (11) NO
Table 4 provides a summary of the four transition categories, and the proposed requirements that would apply for each of those categories. The
Areas designated attainment for the 2015 ozone NAAQS and nonattainment for the 2008 ozone NAAQS have already attained the most stringent existing standard, notwithstanding their existing designation as nonattainment for the 2008 NAAQS. Because it is mathematically impossible to attain the 2015 NAAQS without having first attained the 2008 NAAQS (
Given the succession of NAAQS of increasing stringency that has occurred, the EPA believes that the burden of developing a separate approvable 110(a)(1) maintenance plan for the 2015 ozone NAAQS would outweigh any compensating benefit for an area that is already attaining that NAAQS and implementing, where applicable, any prior nonattainment requirements that are already incorporated into the SIP and have been sufficient to bring the area into attainment of both the prior and 2015 standards. Ongoing compliance with the 2015 ozone NAAQS in such areas will be governed by the provisions of the area's approved SIP and the CAA's general air quality management requirements in sections 107, 110 and 182. Should the area subsequently violate the 2015 ozone NAAQS, it may become subject to a SIP call (under CAA section 110(k)(5)) or redesignation to nonattainment (under CAA section 107(d)(3)).
Areas in this category would also be designated nonattainment for the more stringent 2015 ozone NAAQS and, therefore, would be subject to NNSR and other nonattainment requirements for their classification under the more stringent 2015 ozone NAAQS. Thus, the EPA believes that there is no useful purpose or justification for a second CAA section 175A maintenance plan that would apply only to the revoked 2008 ozone NAAQS, in light of the nonattainment and eventual maintenance requirements that apply for the more protective 2015 ozone NAAQS.
The EPA is proposing to retain its current approach through which an air agency may demonstrate that it is no longer required to adopt any additional applicable requirements for an area that have not already been approved into the SIP for a revoked ozone NAAQS. The final 2008 Ozone NAAQS SIP Requirements Rule adopted two acceptable procedures that, if followed and approved by the EPA, address anti-backsliding requirements associated with one or more revoked standards. These two procedures—formal redesignation to attainment and redesignation substitute—are described later. We are proposing to retain these two procedures for purposes of revocation of the 2008 ozone NAAQS. After one of these procedures has resulted in an approval by the EPA, an air agency seeking to revise its SIP to remove anti-backsliding measures, such as NNSR provisions, from the active portion of the SIP must demonstrate consistency with CAA sections 110(l) and 193 (if applicable). Requirements could then be shifted from the active portion of the SIP to the contingency
The first of the proposed procedures is formal redesignation of the area to attainment for the 2015 ozone NAAQS. For areas subject to anti-backsliding requirements for the revoked 1997 or 2008 standards, approval of a request for redesignation to attainment for the 2015 ozone NAAQS would signify that the air agency has satisfied its obligations to adopt anti-backsliding requirements for the revoked 1997 or 2008 standards. Once the area is redesignated, the requirement(s) for NNSR for the 2015 ozone NAAQS and for any prior ozone NAAQS cease to apply, and the air agency may begin implementing the PSD program requirements. Nonattainment NSR requirements may be removed from the SIP, or may be retained as a maintenance plan contingency measure.
Redesignation to attainment would also terminate any obligations to implement CAA section 185 fee programs in a Severe or Extreme area for the 2015 or revoked 1997 or 2008 ozone NAAQS pursuant to the express terms of CAA section 185. All of the remaining anti-backsliding measures that have been approved into the SIP must continue to be implemented unless or until the air agency can show that such implementation is not necessary for maintenance, consistent with CAA sections 110(l) and 193 if applicable.
The second of the proposed procedures for satisfying the anti-backsliding requirements associated with a specific revoked standard is referred to as a “redesignation substitute.” This redesignation substitute showing would serve as a successor to redesignation to attainment, for which the area would have been eligible were it not for revocation. The showing is based on the CAA's criteria for redesignation to attainment (CAA section 107(d)(3)(E)), but differs in some important respects. This procedure does not require air agencies to go through formal SIP submission procedures to submit a request for approval of a redesignation substitute because the action is not a redesignation under CAA section 107(d)(3)(E). States would have to demonstrate that the area has attained the relevant revoked standard and met all of the requirements for redesignation for that standard. An area would then no longer be subject to any remaining applicable anti-backsliding requirements associated with the specific revoked NAAQS, including the major source thresholds and offset ratios associated with the area's classification under those standards.
The EPA is proposing to retain its current approach to implementing the Clean Data Policy, under which a determination of attainment suspends the obligation to submit certain attainment-related planning requirements for the associated NAAQS for an area as long as the area continues to attain those standards.
The planning elements that would be suspended under 40 CFR 51.1318 are the same as those suspended under existing 40 CFR 51.1118: RFP requirements, attainment demonstrations, RACM, contingency measures and other state planning requirements related to attainment of the relevant standards. For a Severe or Extreme area, a CAA section 185 fee program is expressly linked by the statute itself to an attainment plan. Therefore, suspension of the obligation to submit the attainment plan also necessarily suspends the obligation to submit the fee program which is part of the attainment plan (provided that the EPA has not already determined that the area failed to attain by its attainment deadline and, thus, triggered the obligation to implement a fee program). The EPA notes that a determination of attainment would not, however, suspend obligations to submit non-planning requirements such as NNSR, subpart 2 RACT or emission inventories under CAA section 182(a)(1).
Under this proposed approach, the EPA's long-standing Clean Data Policy, which has been upheld by the D.C. Circuit and all other courts that have considered it, would remain embodied in a regulation applicable for the purpose of all existing and prior ozone NAAQS. We believe that this approach makes the most sense for implementing the 2015 ozone NAAQS.
The EPA is proposing to retain its current approach for implementing the title V permit program for sources in areas designated nonattainment for the current ozone NAAQS and subject to anti-backsliding requirements for a prior ozone NAAQS. The final 2008 Ozone NAAQS SIP Requirements Rule adopted an approach under which, following revocation of the prior (1997) ozone NAAQS, major source thresholds for title V would be the same as the major source thresholds applicable for purposes of other requirements such as RACT and NNSR (80 FR 12307; March 6, 2015). We are proposing to retain this approach for purposes of implementing the 2015 ozone NAAQS, without revision.
Under this proposed approach, following revocation of the 2008 ozone NAAQS, major source thresholds for title V would be the same as the major
As background, the EPA notes that, under CAA section 502, sources are required to operate in accordance with the terms of a title V permit if, among other things, the source is a major source
The EPA is proposing to revise its existing RFP provisions for purposes of the 2015 ozone NAAQS to address MCDs required under CAA section 182(g) for ozone nonattainment areas classified Serious or higher. The existing regulatory provisions characterize the emissions reductions and time intervals that constitute RFP milestones, but do not explicitly address the requirements for demonstrating compliance with these milestones. The following sections discuss the challenges of MCD implementation for ozone, and a proposed approach that would satisfy CAA requirements consistent with milestone demonstrations for other regulated pollutants.
CAA section 182(g)(1) requires that states demonstrate whether nonattainment areas classified Serious, Severe, or Extreme have achieved incremental emission reductions needed to ensure attainment of the NAAQS (
As noted previously, the existing ozone implementation regulations do not explicitly address the MCDs required under the CAA. Specifically, CAA section 182(g)(2) requires that states submit to the Administrator a demonstration that an RFP milestone has been met, not later than 90 days after the date on which the applicable milestone occurs. For purposes of CAA section 182(g), the statute refers to the required emissions reduction for the time interval as the applicable milestone. Section 182(g)(2) of the CAA states that the form, manner of submittal, and contents of the required compliance demonstration shall be set by the Administrator, by rule.
CAA sections 182(g)(3) and (g)(5) establish measures a state shall elect to implement if the state fails to submit an MCD by the due date or the EPA determines that a milestone was not met. For Serious and Severe areas, an air agency shall elect within 90 days of the failure or determination to: (1) Have the area reclassified to the next higher classification; (2) implement additional measures to meet the next milestone per the applicable contingency plan; or (3) adopt an economic incentive program as described in CAA section 182(g)(4). For an Extreme area, an air agency shall within 9 months of the failure or determination submit a SIP revision to implement a CAA section 182(g)(4) economic incentive program.
The EPA is proposing that an air agency will have the option to demonstrate milestone compliance in terms of either: (1) Compliance with control measures requirements in an RFP plan that complies with the requirements of the CAA (
The final implementing regulations for the PM
We are proposing a similar approach for MCDs for the 2015 ozone NAAQS. We believe it would be sufficient for purposes of CAA section 182(g)(2) for an air agency to demonstrate milestone compliance in terms of compliance with control measures requirements in the approved RFP plan (
This proposed measure provides a reasonable and feasible means to implement the demonstration requirement in CAA section 182(g)(2) because it is grounded in SIP provisions that correlate control measures and resulting emissions reductions. Conversely, the EPA believes it would not typically be feasible for air agencies to demonstrate compliance with milestones based on an assessment of actual emissions data because such data are not typically expected to be timely available. Compiling and analyzing area-wide emissions data can be a resource intensive and time consuming process that the EPA expects takes many months after the end of an emissions reporting year. In fact, the EPA's triennial emissions reporting rules provide no less than 12 months for states to report annual emissions after the end of the calendar year.
We invite comment on this proposed approach for MCDs, including potential alternatives to reporting actual emissions data as measures for demonstrating RFP that air agencies can reasonably assess and report within 90 days of each milestone.
The EPA is proposing to retain its existing general RACT provisions (
CAA section 182(b)(2) establishes that a state shall submit a revision to a SIP to provide for implementation of RACT by 2 years after November 15, 1990, and provide for RACT implementation as expeditiously as practicable, but no later than May 31, 1995 (approximately 54 months total). For purposes of the 2008 ozone NAAQS, the EPA interpreted this CAA timeframe to require submittal of RACT SIP revision no later than 24 months after the effective date of initial area designations, and implementation of the RACT SIP revisions no later than January 1 of the fifth year after the effective date of initial designations. We did not, however, establish regulatory schedules for submission and implementation of RACT SIP revisions for areas reclassified after initial area designations under an ozone NAAQS.
To address these reclassification scenarios, we are proposing default submission and implementation deadlines for resulting SIP revisions. The EPA is proposing that, following a reclassification action, RACT SIP revisions be submitted no later than 24 months after the effective date of reclassification, or the deadline established by the Administrator in the action reclassifying an area. We are proposing that the RACT SIP revisions be implemented as expeditiously as practicable, but no later than the start of the ozone season attainment year associated with the area's new attainment deadline, or January 1 of the third year after the associated SIP revision submittal deadline, whichever is earlier. We are also proposing that the Administrator would retain existing
For the timeline for implementing RACT SIP revisions triggered by area reclassifications that occur after initial area designations, we propose to establish a deadline relative to the submittal due date for associated RACT SIP revisions. The CAA authorizes the Administrator to adjust applicable SIP submission deadlines as necessary or appropriate to assure consistency among required submissions. Regarding mandatory reclassifications pursuant to CAA section 181(b)(2), CAA section 182(i) allows the Administrator to adjust applicable deadlines (excluding attainment dates), including those for SIP submittals. For voluntary reclassifications, CAA section 181(b)(3) does not establish a precise timeframe for submitting an attainment plan. Current practice is that we establish SIP revision submittal deadlines through the action granting an air agency's request for voluntary area reclassification. Depending on the timing of the reclassification action, the resulting SIP revision submittal deadline might allow adequate lead time for RACT implementation, or impinge on the applicable attainment year (
We are proposing a generic RACT SIP implementation deadline of no later than January 1 of the third year after the associated SIP revision submittal deadline. This generic implementation deadline would apply where the Administrator elects to not establish a specific alternate implementation deadline in an area reclassification action. The proposed interval between the RACT SIP revision submittal deadline and the implementation deadline was developed by drawing a parallel to the construct of the overall RACT SIP revision submittal and implementation timeframe articulated in section 182(b)(2) of the CAA. In the statute, SIP revisions for sources of VOCs were required by 2 years after November 15, 1990, and were required to provide for RACT implementation as expeditiously as practicable, but no later than the start of the ozone season that is the third year after the SIP revision deadline (
We invite comment on the proposed submission and implementation deadlines for SIP revisions resulting from reclassification actions.
The CAA is silent regarding the schedule for implementation of RACT SIP revisions triggered by new CTGs. When new CTGs are issued, these RACT SIP revisions would be applicable to areas classified Moderate or higher, and any portion of a state located in an OTR. For CTGs in effect at the time of initial designations for a revised NAAQS, the EPA has interpreted the CAA provisions to require implementation of related RACT SIP revisions as expeditiously as practicable, but no later than January 1 of the fifth year after the effective date of initial designations for the revised NAAQS (80 FR 12279; March 6, 2015). For new CTGs issued after initial area designations, we considered several approaches for establishing deadlines for submitting and implementing RACT SIP revisions.
Under the first approach, we are proposing a RACT SIP submission deadline of no later than 24 months after the effective date of the action issuing the CTG, or the deadline established by the Administrator in the action issuing the CTG. We are proposing that the RACT SIP revisions be implemented no later than January 1 of the third year after the associated SIP revision submittal deadline. This deadline is based on the same rationale and approach used for our proposed generic implementation deadline for RACT SIP revisions triggered by reclassification actions, discussed in the preceding section. We are requesting comment on the appropriate implementation deadline, and propose that it should in no case exceed January 1 of the third year after the SIP revision submittal deadline.
Under the second approach, we would also articulate in the general RACT provisions the Administrator's authority to establish an alternate to the generic deadline for implementing RACT SIP revisions in the action issuing a new CTG. Under this option, setting a RACT SIP revision implementation deadline in a CTG action would allow the Administrator to tailor the implementation timeframe to the particular technical considerations and attainment objectives associated with the sources subject to the CTG.
We are proposing this second combined approach that would establish a generic RACT implementation deadline for SIP revisions resulting from new CTGs, while also articulating the Administrator's authority to set a different implementation deadline in the action issuing a new CTG. This proposed approach would apply to covered sources nonattainment areas and portions of a state located in an OTR subject to new RACT SIP obligations. Under this proposed approach, RACT SIP revisions must be submitted no later than 24 months after the effective date of reclassification, or the deadline established by the Administrator in the action issuing a new CTG. We are proposing that RACT SIP revisions be implemented as expeditiously as practicable, but no later than January 1 of the third year after the associated SIP revision submittal deadline. This generic implementation deadline would apply where the Administrator elects to not establish a specific RACT implementation deadline for an individual new CTG. Note that the CAA already requires that RACT SIP revisions triggered by a new CTG must be submitted within the period specified by the Administrator in the action issuing the new CTG. We invite comment on the proposed submission and implementation deadlines for SIP revisions resulting from new CTGs.
As discussed in Section III.H of this preamble, the EPA is proposing to otherwise adopt all existing RACT requirements for purposes of the 2015 ozone NAAQS, based on the current rationale and approach articulated in the final 2008 Ozone NAAQS SIP Requirements Rule.
The EPA is proposing to retain its existing general RACM provisions (
CAA section 172(c)(6) requires that SIP provisions include enforceable emission limitations and other control measures, means or techniques as may be necessary to attain a standard by the applicable attainment date. The EPA interprets this provision to include “additional reasonable measures,” which are those measures and technologies that can be applied to any emission source within an air agency's jurisdiction, including those outside of a nonattainment area. Upwind sources within a state may have a significant impact on air quality in a nonattainment area, and failure to consider and require, as appropriate, reasonable control measures for these sources may preclude the expeditious attainment of a NAAQS in the area. Though not directly a part of RACM, the EPA has addressed this “other control measures” provision in the preamble discussions for previous NAAQS implementation rulemakings,
The EPA is proposing that, for each nonattainment area required to submit an attainment demonstration (
We invite comment on the proposed inclusion of this SIP revision requirement for RACM and other control measures in the ozone implementation rule provisions. As discussed in Section III.H of this preamble, the EPA is proposing to otherwise adopt all existing RACM requirements for purposes of the 2015 ozone NAAQS, based on the current rationale and approach articulated in the final 2008 Ozone NAAQS SIP Requirements Rule.
In 2015, the EPA took final action in the 2008 ozone SRR to amend the regulatory text in 40 CFR 51.165 and part 51 Appendix S to allow air agencies to permit IPT for ozone as part of their NNSR programs.
On May 5, 2015, a coalition of environmental and health advocate groups
This action, in response to the petition for reconsideration, proposes and requests comment on ozone IPT provisions for the NNSR offset requirement, as described in Sections IV.F.2 and 4 of this preamble. Under these provisions, IPT cannot be used to meet the NNSR offset requirement unless the precursor substitution is technically supported. For air agencies implementing an EPA-approved NNSR program, these provisions must be approved in the air agency's plan addressing NNSR requirements for ozone. In addition, as explained in Section IV.F.5 of this preamble, the EPA is including a Technical Guidance Document (TGD) (in the Docket to this rulemaking) to assist air agencies and major stationary sources of ozone in the development of ozone IPT ratios tailored to particular ozone nonattainment areas. The EPA also requests comment on the process and framework described in this TGD to establish IPT ratios.
The EPA proposes to reaffirm its longstanding policy that air agencies may allow major stationary sources to use ozone IPT to satisfy the NNSR offset requirements in ozone nonattainment areas. In addition, the EPA is proposing criteria for developing and implementing ozone IPT programs that will be applicable in particular ozone nonattainment areas. The proposed ozone IPT provisions would replace the existing provisions contained in the NNSR regulations at 40 CFR 51.165 and Appendix S. In addition, the EPA proposes that these ozone IPT provisions would supersede any previous ozone IPT policy articulated in EPA guidance.
In proposing new ozone IPT provisions, it is important to note that the EPA is not proposing to change or seek comment on any existing or traditional NNSR emissions offsets requirements contained in the NNSR regulations at 40 CFR 51.165 and part 51 Appendix S. Existing NNSR emissions
A key component of an ozone IPT program for any ozone nonattainment area is an IPT ratio.
The EPA proposes to provide flexibility for air agencies to incorporate IPT ratios into their IPT programs for ozone nonattainment areas.
When the EPA published its NNSR implementation rules for PM
Use of ozone IPT is not permissible where an air agency chooses to include emissions offsets from NNSR air permitting in their initial 15 percent RFP (ROP) plan for those Moderate or higher ozone nonattainment areas that are satisfying this ROP requirement for the first time under CAA section 182(b)(1)(A)(i). The EPA believes that this restriction on the use of IPT is necessitated by the CAA, which provides that this initial RFP (ROP) plan requirement must be satisfied exclusively by reductions in VOC emissions.
The EPA previously authorized IPT to satisfy the NNSR offset requirement for PM
The EPA's NNSR regulations identify both NO
Emissions of NO
The EPA recognizes that ozone IPT can be implemented in several ways, with the primary variable being the way in which the IPT ratio is established and applied. The EPA proposes that air agencies be allowed to choose any of the options presented later, including a combination if so desired, as a feature of their EPA-approved NNSR programs. However, as explained in Section IV.F.4.c of this preamble, we believe that for implementing ozone IPT in NNSR permits issued pursuant to Appendix S, an air agency will be limited to the use of case-by-case IPT ratios. Accordingly, with the goal of providing flexibility to air agencies/
As explained earlier, the EPA believes that it is reasonable for air agencies to have the option of implementing either a case-by-case ozone IPT ratio or an area-specific default IPT ratio, depending on the needs and capabilities of the individual air agencies. The EPA also believes that air agencies having EPA-approved NNSR programs should have the option of implementing a combination of the two proposed options. This would enable an air agency to develop an area-specific default IPT ratio, but, at the same time, allow an individual permit applicant to propose an alternative case-specific IPT ratio (if it can demonstrate to the satisfaction of both the reviewing authority and the EPA that such alternative ratio is appropriate for the proposed offsetting transaction for a specific permit application).
Finally, IPT programs are discretionary on the part of air agencies and are not required SIP revisions. Therefore, air agencies would not be required to submit a regulatory provision consistent with the proposed IPT provision at 40 CFR 51.165(a)(11)(i) within the 36-month timeframe set forth in 40 CFR 51.1314 for NSR requirements for the revised ozone NAAQS. Air agencies would be permitted to submit an IPT plan revision to the EPA for approval within the 36-month timeframe or at any later date that the air agencies deems to be appropriate.
As mentioned earlier in the preamble, the EPA is including a TGD in the docket for this rulemaking. The purpose of the proposed TGD is to provide air agencies with guidance on a technical approach to estimate ozone impacts from precursor emissions for a specific nonattainment area or for case-by-case determinations. The TGD provides a framework and associated general methodology to apply existing or new empirical relationships between ozone and precursors to develop IPT ratios. The data sets and analyses included in the TGD may be used by air agencies as appropriate to develop IPT ratios; alternatively, air agencies may use existing modeling or generate their own modeling to provide the basis for the development of IPT ratios. The EPA believes the methodology presented in the TGD may be used by air agencies for developing default IPT ratios for specific nonattainment areas, and by air agencies and major stationary sources for developing appropriate case-by-case IPT ratios.
In addition, in light of proposed changes to EPA's Guideline for Air Quality Models, published as Appendix W to 40 CFR part 51, which provide greater clarity regarding the use of
The EPA is proposing to clarify its emissions inventory and emissions statement requirements in the context of this action by adding 40 CFR 51.1315. CAA sections 182(a)(1) and 182(a)(3)(A) require states to submit emissions inventories to the EPA. To clarify these statutory requirements within the context of implementing the 2008 ozone NAAQS, the EPA added 40 CFR 51.1115 (80 FR 12264, 12314; March 6, 2015). These statutory and regulatory authorities do not address the associated emissions statement requirements under CAA section 182(a)(3)(B). For purposes of the 2015 ozone NAAQS we are proposing to add 40 CFR 51.1315, which will clarify requirements for the emissions inventories and emissions statements required by CAA sections 182(a)(1), 182(a)(3)(A), and 182(a)(3)(B), respectively. While the proposed 40 CFR 51.1315 is similar to the existing 40 CFR 51.1115, these provisions are not identical, as discussed later. Moreover, we are also clarifying in this preamble how air agencies demonstrate compliance with CAA section 182(a)(3)(B) in the context of the 2015 ozone NAAQS.
The emission inventory requirements for the 2008 ozone NAAQS, found at 40 CFR 51.1115, describe the criteria and timing for base year and periodic inventories required under CAA sections 182(a)(1) and 182(a)(3)(A), respectively. For reference, the preamble to the final 2008 Ozone NAAQS SIP Requirements Rule provides an extensive discussion of the EPA's rationale and approach for emission inventories (80 FR 12289; March 6, 2015). In general, we provided that air agencies may rely, when appropriate, on their 3-year cycle inventory as described by the Air Emissions Reporting Requirements rule (AERR, codified in 40 CFR 51, subpart A) to meet the 182(a)(3)(A) periodic inventory obligations, with additional requirements for the reporting of ozone season day emissions and treatment of partial-county inventories.
To support the periodic emissions inventory requirement, the EPA is proposing revisions to the AERR point source reporting thresholds in AERR Table 1 (40 CFR 51, subpart A, appendix A) to be consistent with the major source thresholds for ozone nonattainment areas. These reporting thresholds are in tons of potential emissions per year. The existing AERR Table 1 includes Moderate area thresholds of 100 tpy for NO
Air agencies are advised to check the EPA Web site for the currently approved mobile source models and to consult with the EPA Office of Transportation and Air Quality and their Regional office to determine the versions of models to use for their SIPs for the 2015 ozone NAAQS. MOVES2014a, which incorporates both onroad and nonroad emissions estimates, is the most recently approved model for states other than California. The model and additional information are available at:
The EPA is proposing to otherwise adopt the same emission inventory requirements for the 2015 ozone NAAQS, based on the current approach articulated in the final 2008 Ozone NAAQS SIP Requirements Rule.
For nonattainment areas, air agencies must develop, and include in their SIP, emission reporting programs for certain VOC and NO
This section addresses several important requirements and policies, with one exception, the EPA is not proposing specific regulatory text due to lingering legal issues, scientific unknowns and uncertainties associated with developing and implementing new requirements and/or policies. The one exception concerns proposed new regulatory provisions that require air agencies to demonstrate RACM for Marginal areas for treatment under CAA section 179B (
The final 2008 Ozone NAAQS SIP Requirements Rule discussed the large contribution that wildfire can make to air pollution (including ozone), and wildfire's threat to public safety. The rule also recognized that this effect can be mitigated through management of wildland vegetation, including through prescribed fire. Such mitigation can help manage the contribution of fires to ozone levels in nonattainment areas. Therefore, the EPA recommended as guidance but not as a requirement of the final rule, if wildfire impacts are significant and contribute to exceedances of the standard, then air agencies should consider RACM for wildfires (which RACM could include a required program of prescribed fires). The EPA also recommended that air agencies should consider RACM for managing emissions from prescribed fires (including those prescribed fires conducted to reduce future wildfire emissions). The rule noted that information is available from the U.S. Department of the Interior (DOI) and the U.S. Department of Agriculture (USDA) Forest Service on smoke management programs and basic smoke management practices (BSMP).
More recently, in its proposed implementation rule for the PM
Before explaining this recommendation further, the EPA wishes to clarify that the recommendation is focused on wildland fire management. There are other uses of prescribed fire and other types of burning that occur in nonattainment areas, or that affect downwind nonattainment areas, such as burning of land clearing debris, agricultural burning, and burning of logging slash on land where the primary purpose of the logging is for commercial timber sale.
The EPA also wants to clarify that it is not the intention to in any way discourage federal, state, local or tribal agencies or private land owners from taking situation-appropriate steps to minimize impacts from prescribed fire emissions on wildland. The EPA encourages all land owners and managers to apply appropriate BSMP to reduce emissions from prescribed fires, especially where an air agency has determined that prescribed fires are a significant source affecting air quality. The EPA understands that the federal land managers (FLMs) apply these measures routinely and will be available to consult with other agencies and private parties interested in doing the same.
However, for several reasons, the EPA does not believe it would be effective policy or technically appropriate to recommend that control measures for wildland fire be adopted into the SIP as enforceable measures and credited for emissions reductions (of ozone and precursors) that would help the area attain the standard.
The EPA acknowledges that some temporal and spatial patterns of fire emissions must still be assumed in the attainment demonstration in order to ensure that the required air quality modeling results in a realistic physical and chemical environment and a correspondingly realistic model response against which to analyze the changes from categories where express accounting of changes is still being done. This rule is not intended to constrain the options for states regarding the appropriate assumptions to make for fire emissions. Rather, it simply recommends that once this base level is established, ozone plans should not attempt to expressly project changes over the planning period in emissions from wildfires or prescribed fires on wildland within the nonattainment area, or in upwind areas included in the modeling domain, that are due to variability in wildfire occurrence or changes in the use of prescribed fire or other wildland fire management practices. Moreover, the EPA anticipates that changes in spatial and temporal patterns of wildfire will likewise be too uncertain for them to be allowed to have the effect of reducing or increasing the control requirement on conventional anthropogenic sources. The EPA therefore recommends that baseline wildland fire emissions should generally be held constant over the planning period, regardless of whether wildland fire management practices by land managers are expected, and possibly encouraged, to change.
Air agencies still have flexibility in determining how best to represent baseline wildland fire emissions. As noted earlier, base year emission inventories for the nonattainment areas should represent the conditions leading to nonattainment and be consistent with inventories used for modeling. For fires, the EPA additionally encourages air agencies to use a representative mix of prescribed fire and wildfire in their inventories. Using PM
A consequence of the recommendation of not expressly accounting for changes in wildland fires in attainment demonstrations is that measures to reduce emissions from wildland fires, such as prescribed fire to prevent catastrophic wildfires and for mitigation purposes or smoke management programs and BSMP for prescribed fires in wildland, need not be included as RACM for the respective fire types. This is because the changes in emissions due to such measures would not be accounted for in determining what is necessary for attainment and/or what would advance the attainment date, which is how the EPA is recommending that RACM be determined. So, for example, in an area that can attain in 6 years with measures that do not address wildland fire, the EPA does not recommend that states attempt to quantify whether increased prescribed fire could advance the attainment date by 1 year, due to aforementioned difficulties associated with such quantification.
To be clear, nothing about this policy regarding RACM is intended to suggest that fires should be ignited in wildland (or elsewhere) without regard to the air quality or public health consequences. As noted earlier, the EPA believes these consequences are important to address, and intends to engage in dialogue with the FLMs, air agencies, tribes, state and private land owners and other stakeholders at appropriate times, such as during the process for the development of land management plans, about how land managers determine when and where prescribed fire is appropriate for particular wildlands and how to identify and implement appropriate mitigation measures. The policy simply makes clear the EPA's view regarding its recommendation for RACM for wildland fires.
Finally, the EPA notes that, because a significant element of the rationale for this policy is the uncertainty in the timing of wildfires, we may reconsider this recommendation in the future, if adequate tools emerge that allow for predicting fire emissions with sufficient specificity. However, even if such tools emerge, due to inherent uncertainties it may be impossible to satisfactorily incorporate the use of such information into an attainment demonstration framework.
Conformity is required under CAA section 176(c) to ensure that federal actions are consistent with (“conform to”) the purpose of the SIP. Conformity to the purpose of the SIP means that federal activities will not cause new air quality violations, worsen existing violations, or delay timely attainment of the relevant NAAQS or interim reductions and milestones. Conformity applies to areas that are designated nonattainment, and those nonattainment areas redesignated to attainment with a CAA section 175A maintenance plan after 1990 (“maintenance areas”).
The EPA's Transportation Conformity Rule (40 CFR 51.390 and part 93, subpart A) establishes the criteria and procedures for determining whether transportation activities conform to the SIP. These activities include adopting, funding or approving transportation plans, transportation improvement programs (TIPs) and federally supported highway and transit projects. The EPA first promulgated the Transportation Conformity Rule on November 24, 1993 (58 FR 62188), and subsequently published several amendments. We subsequently restructured the Transportation Conformity Rule in such a manner that existing conformity requirements will apply for any new or revised NAAQS (77 FR 14979; March 14, 2012); the conformity rule, therefore, applies directly and does not need to be updated to reflect the 2015 ozone NAAQS. However, the EPA intends to issue an update to existing transportation guidance related to the implementation of the revised ozone standards. The updates to the existing guidance will address topics that include when conformity applies for the 2015 ozone NAAQS, when conformity may stop applying for the 2008 ozone NAAQS and the baseline year to be used by metropolitan planning organizations (MPOs) in nonattainment areas for the 2015 ozone NAAQS that are required to use one or both of the interim emissions tests to demonstrate conformity before such areas have adequate or approved motor vehicle emissions budgets for the 2015 ozone NAAQS (or adequate or approved budgets for a previous ozone NAAQS). For further information on transportation conformity rulemakings, policy guidance and outreach materials,
With regard to general conformity, the EPA first promulgated general
The EPA is discussing transportation and general conformity in this proposed rulemaking in order to provide affected parties with information on when conformity must be implemented after nonattainment areas are designated for the 2015 ozone NAAQS. The information presented here is consistent with existing conformity regulations and statutory provisions that are not addressed by this ozone implementation rulemaking. Affected parties include state and local transportation and air quality agencies, MPOs, and federal agencies including the U.S. Department of Transportation (DOT), the U.S. Department of Defense, the DOI and the USDA.
Transportation and general conformity will apply 1 year after the effective date of nonattainment designations for a new or revised ozone NAAQS including the 2015 ozone NAAQS. This is because CAA section 176(c)(6) provides a 1-year grace period from the effective date of initial designations for any new or revised NAAQS before transportation and general conformity apply in areas newly designated nonattainment for a specific pollutant and NAAQS. The grace period applies to newly designated nonattainment for a new or revised ozone NAAQS including the 2015 ozone NAAQS even if the area had been designated nonattainment for a prior ozone NAAQS. With regard to general conformity, the EPA's April 2010 revisions to its general conformity regulations (
With regard to transportation conformity, the conformity grace period will apply to all areas designated nonattainment for a new or revised ozone NAAQS including the 2015 ozone NAAQS. The requirements differ depending on whether the nonattainment area includes any part of an MPO designated under 23 United States Code (U.S.C.) section 134. Within 1 year after the effective date of the initial nonattainment designation for a given pollutant and NAAQS, the MPOs and DOT must make a conformity determination with regard to that pollutant and standard for all of the metropolitan transportation plans and TIPs in the nonattainment area. The conformity requirements for surrounding “donut areas,” including the application of the 1-year conformity grace period, are generally the same as those for metropolitan areas.
1. Projects that are exempt from transportation conformity such as elimination of at-grade railroad crossings, repaving roadways, widening narrow pavements and reconstructing bridges as long as new travel lanes are not added because they are exempt from conformity; and
2. Transportation control measures included in approved SIPs because these projects provide emissions reductions toward attaining or maintaining the NAAQS.
Additionally, any project or project phase that was funded or approved prior to a lapse may proceed but no additional funding or approval decisions may be made until the lapse is ended.
Isolated rural nonattainment areas are areas that do not contain or are not part of an MPO (40 CFR 93.101).
The CAA only requires transportation and general conformity determinations in areas that are designated nonattainment or maintenance for a given pollutant and standard.
Under our current Transportation Conformity Rule, the latest approved or adequate emission budgets for a prior ozone NAAQS (
As long as the EPA does not make specific changes to its transportation or general conformity regulations, air agencies should not need to revise their transportation and/or general conformity SIPs. The EPA is not proposing any changes to its transportation conformity or general conformity regulations. Air agencies with new nonattainment areas may need to revise conformity SIPs in order to ensure the state regulations apply in any newly designated areas.
However, if this is the first time that transportation conformity will apply in a state, the air agency is required by the statute and EPA regulations to submit a SIP revision that addresses three specific transportation conformity requirements that address consultation procedures and written commitments to control or mitigation measures associated with conformity determinations for transportation plans, TIPs or projects (40 CFR 51.390). Additional information and guidance can be found in the EPA's “Guidance for Developing Transportation Conformity State Implementation Plans (SIPs)” (
As air agencies develop SIP revisions for the 2015 and future ozone NAAQS, the agency recommends that state and local air quality agencies work with federal agencies with large facilities (
In a few cases, tracts of land under federal management may also be included in nonattainment and maintenance area boundaries. The role of fire in these areas should be assessed and emissions budgets developed in concert with those federal land management agencies. In such areas the EPA encourages air agencies to consider in any baseline, modeling and SIP attainment inventory used and/or submitted to include emissions expected from projects subject to general conformity, including emissions from wildland fire that may be reasonably expected in the area. Where appropriate, air agencies may consider developing plans for addressing wildland fuels in collaboration with land managers and owners. Information is available from DOI and USDA Forest Service on the ecological role of fire and on smoke management programs and BSMP.
For purposes of the 2015 ozone NAAQS, the EPA is proposing no changes to the requirements for contingency measures articulated in the final 2008 Ozone NAAQS SIP Requirements Rule (80 FR 12285; March 6, 2015).
Regarding content of the 1 year's worth of reductions covered by the contingency measures, the EPA is proposing to continue to allow these reductions of the contingency measures to be based entirely or in part on NO
With respect to Extreme ozone nonattainment areas, CAA section 182(e)(5) allows the agency to exercise discretion in approving Extreme area attainment plans that rely, in part, on the future development of new control technologies or improvements of existing control technologies, where certain conditions are met. This discretion can be applied as long as an air agency has demonstrated that: All RACM, including RACT, have been included in the plan; the area's RFP demonstration during the first 10 years after designation does not rely on anticipated future technologies; and the air agency has submitted enforceable commitments to timely develop and adopt contingency measures to be implemented if the anticipated future technologies do not achieve planned reductions. The EPA is proposing to continue to allow air agencies to submit, for Extreme nonattainment areas, enforceable commitments to develop and adopt contingency measures meeting the requirements of 182(e)(5) to satisfy the requirements for both attainment contingency measures in CAA sections 172(c)(9) and 182(c)(9). These enforceable commitments must obligate the air agency to submit the required contingency measures to the EPA no later than 3 years before any applicable implementation date, in accordance with CAA section 182(e)(5).
Most modeled ozone air quality values that exceed the NAAQS in the United States (U.S.) are due primarily to emission sources within the U.S. However, domestic ozone air quality can also be affected by sources of emissions located outside of the U.S. These contributions to U.S. ozone concentrations from sources outside of the U.S., which can be from nearby sources in a bordering country or from sources many thousands of miles away,
Congress recognized that some nonattainment areas may be impacted not only by local sources of ozone or ozone precursor emissions, but also sources of emissions from outside of the U.S. Through CAA section 179B, Congress provided the EPA with the authority to approve attainment plans for areas that could attain the relevant NAAQS by the statutory attainment date “but for” emissions emanating from outside the U.S. When applicable, this CAA provision relieves states from imposing control measures on emissions sources in the state's jurisdiction beyond those necessary to address reasonably controllable emissions from within the U.S. Specifically, CAA section 179B(a) provides that the EPA shall approve an attainment plan for such an area if: (i) The attainment plan meets all other applicable requirements of the CAA, and (ii) the submitting state can satisfactorily demonstrate that “but for emissions emanating from outside the United States,” the area would attain and maintain the relevant NAAQS. In addition, CAA section 179B(b) applies specifically to the ozone NAAQS and provides that if a state demonstrates that an ozone nonattainment area would have timely attained the NAAQS by the applicable attainment date “but for emissions emanating from outside of the United States,” then the area can avoid extension of the ozone attainment dates pursuant to CAA section 181(a)(5), the application of fee provisions of CAA section 185, and the mandatory reclassification provisions under CAA section 181(b)(2)
In the 2008 ozone SIP Requirements Rule, the EPA stated that a section 179B demonstration could include consideration of any emissions from North American or intercontinental sources. (80 FR 12293). The EPA also stated at that time that it did not believe use of section 179B was limited to nonattainment areas adjoining international borders.
Even if an area is impacted by emissions from outside the U.S., CAA section 179B does not affect the designations process.
CAA section 179B does not alter the CAA's general construct expressed in subpart 1 of part D that states with nonattainment areas are expected to adopt reasonable emissions controls to lessen emissions of criteria pollutants to promote citizen health protection. The construct ensures that states will take reasonable actions to mitigate the public health impacts of exposure to ambient levels of pollution that violate the NAAQS by imposing reasonable control measures on the sources that are within the jurisdiction of the state regardless of impacts from interstate or international emissions. The primary purpose of part D of Title I of the CAA is to achieve emission reductions so that people living in a nonattainment area receive the public health protection intended by the NAAQS.
Marginal ozone nonattainment areas are not generally required to implement reasonably available control technology requirements under subpart 2 of part D of Title 1 of the CAA. If an air agency were to apply for treatment under CAA section 179B(b) to avoid mandatory reclassification of a Marginal area after its failure to attain by the applicable attainment date, an area could continue to remain Marginal and, therefore, never implement reasonable emissions controls.
The EPA believes that adopting an interpretation of CAA section 179B that would allow people to continue to be subjected to levels of ozone above the NAAQS that a state could reasonably reduce—in this case not to attainment level, but to a level below the current level—would be antithetical to the objectives of the CAA. The EPA believes it is appropriate for the Administrator to take this general construct of the CAA into account in determining during the application of CAA section 179B whether, “to the satisfaction of the Administrator,” an area would have attained the ozone NAAQS by the applicable attainment date but for emissions emanating from outside of the U.S. Accordingly, the EPA is proposing and seeking comment on a requirement that all demonstrations under CAA section 179B(b), regardless of an area's classification (including nonattainment areas classified as Marginal), must include a showing that the air agency adopted all RACM, including RACT, for the area in accordance with CAA section 172(c)(1), 42 U.S.C. 7502(c)(1). Under this interpretation, if the air agency did not adopt reasonable control measures before making a section 179B(b) demonstration, it will be missing a critical component of the demonstration that the area would have attained the ozone NAAQS by the attainment date “but for” international impacts, namely a showing that the area could otherwise attain by application of reasonable controls on sources of emissions that are within the state's jurisdiction.
The EPA encourages air agencies to coordinate with their EPA regional office to identify approaches to evaluate the potential impacts of international transport and to determine the most appropriate information and analytical methods for each area's unique situation. The EPA will also work with air agencies that are developing attainment plans for which CAA section 179B is relevant, and ensure the air agencies have the benefit of the EPA's understanding of international transport of ozone and ozone precursors. Air agencies are encouraged to consult with their EPA Regional office to establish appropriate technical requirements for these analyses. The EPA invites comment as to whether the EPA should develop technical guidance for the “but for” analysis in a section 179B demonstration, and invites comment about which methodologies and tools would be most effective to help states develop section 179B demonstrations.
With respect to the larger issue of background ozone (or U.S. background, (USB)), the EPA has solicited input from air agencies, tribes, and interested stakeholders on aspects of USB that are relevant to attaining the 2015 ozone NAAQS in a manner consistent with the provisions of the CAA.
Workshop attendees included representatives of state, local and tribal air agencies, and other interested stakeholders. A general theme among attendee comments was a concern that the EPA is underestimating the magnitude and effects of USB, and that available policy solutions do not provide meaningful relief from nonattainment designations in affected areas.
The EPA also recently finalized revisions to the Exceptional Events Rule to further facilitate review and approval of exceptional events that contribute to USB, such as stratospheric intrusions and wildfires (81 FR 68216; October 3, 2016).
Increasingly, state air agencies are considering multi-pollutant emission reduction strategies such as energy efficiency and renewable energy (EE/RE) requirements as compliance options for CAA plans and EPA encourages this multi-pollutant approach when assessing compliance options for ozone RFP and attainment demonstration SIPs. Many states are already implementing cost-effective EE/RE requirements that reduce all types of power generation related emissions (including carbon dioxide, NO
The EPA discussed this approach more completely in the final Clean Power Plan (CPP)
The EPA has available several resources to help air agencies incorporate these multi-pollutant strategies in NAAQS SIPs/TIPs. Resources include the “Roadmap for Incorporating EE/RE Programs and Policies in NAAQS SIPs/TIPs”
The EPA's tool, AVERT, can help planners in quantifying the emissions reductions that result from EE/RE policies and programs. AVERT outputs are readily available for SMOKE formatting to incorporate the emission impacts into air quality models.
Also, state-level RE requirements have been implemented in 29 states plus Washington, DC, representing all regions of the country.
In an effort to examine the effects of these programs, EPA developed a counterfactual EE/RE scenario for a couple of areas that were nonattainment for EPA's 2008 ozone NAAQS, including the New York-New Jersey-Connecticut area.
Air agencies may also wish to consider strategies that foster more efficient urban and regional development patterns as a long-term air pollution control measure. Resources include the U.S. Department of Housing and Development—DOT-EPA Partnership for Sustainable Communities, as well as the policy and technical guidance documents on land use and related travel efficiency available on the EPA's Office of Transportation and Air Quality Web site.
If wildfire impacts are significant in a particular area, air agencies and communities may be able to lessen the impacts of wildfires by working collaboratively with land managers and land owners to employ various mitigation measures including taking steps to minimize fuel loading in areas vulnerable to fire.
Areas may also consider incorporating travel efficiency strategies, such as new or expanded mass transit options, commuter strategies, system operations (
CAA section 172(c)(6) requires nonattainment SIPs to “include enforceable emission limitations, and such other control measures, means or techniques . . . as well as schedules and timetables for compliance, as may be necessary or appropriate to provide for attainment . . .” The EPA's current guidance, “Guidance on Preparing Enforceable Regulations and Compliance Programs for the 15 Percent Rate-of-Progress Plans (EPA-452/R-93-005, June 1993)”
Section 301(d) of the CAA authorizes the EPA to approve eligible Indian tribes to implement provisions of the CAA on Indian reservations and other areas within the tribes' jurisdiction.
It is important for state and local air agencies and tribes to work together to coordinate planning efforts where nonattainment areas include both Indian country and state land. Coordinated planning in these areas will help ensure that the planning decisions made by the state and local air agencies and tribes complement each other and that the nonattainment area makes reasonable progress toward attainment and ultimately attains the 2015 ozone NAAQS. In reviewing and approving individual TIPs and SIPs, we will determine if together they are consistent with the overall air quality needs of an area.
States have an obligation to notify other states in advance of any public hearing(s) on their state plans if such plans will significantly impact such other states. 40 CFR 51.102(d)(5). Under CAA section 301(d) of the CAA and the TAR, tribes may become eligible to be treated in a manner similar to states (TAS) for this purpose (40 CFR 49.6-49.9). Affected tribes with this status must also be informed of the contents of such state plans and given access to the documentation supporting these plans. In addition to this mandated process, we encourage states to extend the same notice to all affected tribes, regardless of their TAS status.
Executive Orders and the EPA's Indian policies generally call for the EPA to coordinate and consult with tribes on matters that affect tribes. Executive Order 13175, titled, “Consultation and Coordination with Indian Tribal Governments” requires the EPA to develop a process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have Tribal implications.” In addition, the EPA's policies include the agency's 1984 Indian Policy relating to Indian tribes and implementation of federal environmental programs, the April 10, 2009, OAQPS guidance “Consulting with Indian Tribal Governments,” and the “EPA Policy on Consultation and Coordination With Indian Tribes.”
Consistent with these policies, the EPA intends to coordinate and consult with tribes on activities potentially affecting the attainment and maintenance of the 2015 ozone NAAQS in Indian country, including our actions on SIPs. We encourage state air agencies to work with tribes with land that is part of the same general air quality planning area during the SIP development process and to coordinate with tribes as they develop their SIPs regardless of whether the tribe's area of Indian country is separately designated.
The EPA believes this action will not have disproportionately high and adverse human health or environmental effects on minority, low-income, or indigenous populations because it would not negatively affect the level of protection provided to human health or the environment under the 2015 ozone NAAQS, which are at levels to protect sensitive populations with an adequate margin of safety.
This action is a significant regulatory action that was submitted to OMB for review. Any changes made in response to OMB recommendations have been documented in the docket.
The information collection activities in this proposed rule have been submitted for approval to OMB under the PRA. The ICR document that the EPA prepared has been assigned the EPA ICR No. 2347.03 and OMB Reference No. 2060-0695. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.
The EPA is proposing these implementing regulations for 2015 ozone NAAQS so that air agencies will know what CAA requirements apply to their nonattainment areas when the air agencies develop their SIPs for attaining and maintaining the NAAQS. The intended effect of these implementing regulations is to provide certainty to air agencies regarding their planning obligations. For purposes of analysis of the estimated paperwork burden, the EPA assumed 57 nonattainment areas,
Air agencies should already have information from many emission sources, as facilities should have provided this information to meet 1-hour, 1997, and 2008 ozone NAAQS SIP requirements, operating permits and/or emissions reporting requirements. Such information does not generally reveal the details of production processes. But, to the extent it may, CBI for the affected facilities is protected. Specifically, submissions of emissions and control efficiency information that is confidential, proprietary and trade secret is protected from disclosure under the requirements of subsections 503(e) and 114(c) of the CAA.
The annual burden for this information collection averaged over the first 3 years of this ICR is estimated to be a total of 41,800 labor hours per year at an annual labor cost of $2.5 million (present value) over the 3-year period or approximately $107,000 per state for the 23 state air agency respondents. The ICR Supporting Statement for the 2015 8-hour Ozone NAAQS Implementation Rule EPA ICR No. 2347.03 in the docket provides the details for the 23 state air agencies that are required to provide the 66 SIP revisions for the 57 hypothetical areas designated nonattainment for the 2015 ozone standard. The average annual reporting burden is 633 hours per response, with approximately 2.87 responses per state for 66 state responses from the state air agencies. There are no capital or operating and maintenance costs associated with the proposed rule requirements. Burden is defined at 5 CFR 1320.3(b).
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 OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
To comment on the agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden, the EPA has established a public docket for this rule, which includes this ICR, under Docket ID No. EPA-HQ-OAR-2016-0202. Commenters should submit any comments related to the ICR to both the EPA and OMB.
I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This action will not impose any requirements on small entities. Entities potentially affected directly by this rule include state, local and tribal governments and none of these governments are small governments. Other types of small entities are not directly subject to the requirements of this rule because this
This action does not contain any unfunded mandate as described in UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect small governments. The action implements mandates specifically and explicitly set forth in the CAA without the exercise of any policy discretion by the EPA.
This action does not have federalism implications. It will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.
This action does not have tribal implications as specified in Executive Order 13175. It would not have a substantial direct effect on one or more Indian tribes, since no tribe has to develop a TIP under these regulatory revisions. Furthermore, these regulation revisions do not affect the relationship or distribution of power and responsibilities between the federal government and Indian tribes. The CAA and the Tribal Air Rule establish the relationship of the federal government and tribes in developing plans to attain the NAAQS, and these revisions to the regulations do nothing to modify that relationship. Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, the EPA briefed tribal officials in developing this proposal.
The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive Order. This action is not subject to Executive Order 13045 because it does not concern an environmental health risk or safety risk.
This action is not a “significant energy action” because it is not likely to have a significant adverse effect on the supply, distribution or use of energy.
This rulemaking does not involve technical standards.
The EPA believes that this action does not have disproportionately high and adverse human health or environmental effects on minority populations, low-income populations and/or indigenous populations as specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The documentation for this decision is contained in Section VI of this preamble.
The statutory authority for this action is provided by sections 109; 110; 172; 181 through 185B; 301(a)(1) and 501(2)(B) of the CAA, as amended (42 U.S.C. 7409; 42 U.S.C. 7410; 42 U.S.C. 7502; 42 U.S.C. 7511-7511f; 42 U.S.C. 7601(a)(1); 42 U.S.C. 7661(2)(B)).
Environmental protection, Air pollution control, Carbon monoxide, Lead, Nitrogen dioxide, Ozone, Particulate matter, Sulfur oxides.
Environmental protection, Air pollution control, Intergovernmental relations, Ozone, Particulate matter, Transportation, Volatile organic compounds.
For the reasons stated in the preamble, Title 40, Chapter I of the Code of Federal Regulations is proposed to be amended as follows:
42 U.S.C. 7401,
(c) The 2008 ozone NAAQS set forth in this section will remain applicable to all areas of the country notwithstanding the promulgation of 2015 ozone NAAQS under § 50.19. The 2008 ozone NAAQS set forth in this section will no longer apply to an area 1 year after the effective date of the initial area designation of that area for the 2015 ozone NAAQS pursuant to section 107 of the CAA. For purposes of the anti-backsliding requirements of § 51.1305, § 51.165 and Appendix S to part 51, the area designations and classifications with respect to the revoked 1-hour, 1997 and 2008 ozone NAAQS are codified in 40 CFR part 81.
(c) Notwithstanding the promulgation of 2015 ozone NAAQS under § 50.19, the 2008 ozone NAAQS set forth in this section will remain applicable to any area of the country designated nonattainment for the 2008 ozone NAAQS as of the date of that area's initial designation for the 2015 ozone NAAQS pursuant to section 107 of the CAA. For any other area of the country, the 2008 ozone NAAQS set forth in this section will no longer apply to such area 1 year after the effective date of the initial designation of that area for the 2015 ozone NAAQS pursuant to section 107 of the CAA.
23 U.S.C. 101; 42 U.S.C. 7401-7671q.
As of revocation of the 2008 ozone NAAQS in an area, as set forth in § 50.15(c), the provisions of §§ 51.1100 to 51.1118 of subpart AA cease to apply, [Proposed Regulatory Text for Option 1: except for § 51.1107 for the anti-backsliding purposes of § 51.1305(c)(2).]
The following definitions apply for purposes of this subpart. Any term not defined herein shall have the meaning as defined in 40 CFR 51.100.
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
(1) Reasonably available control technology (RACT) under CAA sections 172(c)(1) and 182(b)(2).
(2) Vehicle inspection and maintenance programs (I/M) under CAA sections 182(b)(4) and 182(c)(3).
(3) Major source applicability thresholds for purposes of RACT under CAA sections 172(c)(2), 182(b), 182(c), 182(d), and 182(e).
(4) Reductions to achieve Reasonable Further Progress (RFP) under CAA sections 172(c)(2), 182(b)(1)(A), and 182(c)(2)(B) and EPA's implementing regulations at § 51.1310.
(5) Clean fuels fleet program under CAA section 183(c)(4).
(6) Clean fuels for boilers under CAA section 182(e)(3).
(7) Transportation Control Measures (TCMs) during heavy traffic hours as specified under CAA section 182(e)(4).
(8) Enhanced (ambient) monitoring under CAA section 182(c)(1).
(9) Transportation controls under CAA section 182(c)(5).
(10) Vehicle miles traveled provisions of CAA section 182(d)(1).
(11) NO
(12) Attainment demonstration requirements under CAA sections 172(c)(4), 182(b)(1)(A), and 182(c)(2).
(13) Nonattainment contingency measures required under CAA sections 172(c)(9) and 182(c)(9) for failure to attain an ozone NAAQS by the applicable attainment date for that NAAQS or failure to make reasonable further progress toward attainment of that ozone NAAQS.
(14) Nonattainment NSR major source thresholds and offset ratios under CAA sections 172(a)(5) and 182(a)(2).
(15) Penalty fee program requirements for Severe and Extreme Areas under CAA section 185.
(16) Contingency measures associated with areas utilizing CAA section 182(e)(5).
(17) Reasonably available control measures (RACM) requirements under CAA section 172(c)(1).]
(q)
(r)
(s)
(t)
(u)
(v)
(w)
(x)
(y)
(z)
(aa)
(bb)
(cc) An area “
(dd) An area “
(ee) An area “
(ff)
(gg)
(hh)
The provisions in subparts A-Y and AA of part 51 apply to areas for purposes of the 2015 ozone NAAQS to the extent they are not inconsistent with the provisions of this subpart.
An area designated nonattainment for the 2015 ozone NAAQS will be classified in accordance with CAA section 181, as interpreted in § 51.1303(a), and will be subject to the requirements of subpart 2 of part D of title I of the CAA that apply for that classification.
(a) In accordance with CAA section 181(a)(1), each area designated nonattainment for the 2015 ozone NAAQS shall be classified by operation of law at the time of designation. The classification shall be based on the 8-hour design value for the area at the time of designation, in accordance with Table 1 of paragraph (a) of this section. A state may request a higher or lower classification as provided in paragraphs (b) and (c) of this section. For each area classified under this section, the attainment date for the 2015 NAAQS shall be as expeditious as practicable, but not later than the date provided in Table 1 as follows:
(b) A state may request, and the Administrator must approve, a higher classification for an area for any reason in accordance with CAA section 181(b)(3).
(c) A state may request, and the Administrator may in the Administrator's discretion approve, a higher or lower classification for an area in accordance with CAA section 181(a)(4).
(d) The following nonattainment areas are reclassified for the 2015 ozone NAAQS as follows: Serious—Ventura County, CA; Severe—Los Angeles-San Bernardino Counties (West Mojave Desert), Riverside County (Coachella Valley), and Sacramento Metro, CA; Extreme—Los Angeles-South Coast Air Basin, and San Joaquin Valley, CA.
(a)
(2)
(3)
(4)
For an area that is initially designated attainment for the 2015 ozone NAAQS and which has been redesignated to attainment for a prior revoked ozone NAAQS with an approved CAA section 175A maintenance plan and an approved PSD SIP, the area's approved maintenance plan and the state's approved PSD SIP for the area are considered to satisfy the state's obligations with respect to the area's maintenance of the 2015 ozone NAAQS pursuant to CAA section 110(a)(1).
(b)
(2) If EPA, after notice-and-comment rulemaking, approves a redesignation to attainment, the state may request approval from the EPA to either remove provisions for nonattainment NSR from the SIP for the 1997 and 2008 ozone standards, subject to the requirements of CAA sections 110(l) and 193, or shift them to the SIP's list of maintenance plan contingency measures for the area.
(3) If the EPA, after notice-and-comment rulemaking, approves a redesignation to attainment, the state may request approval from the EPA to shift other anti-backsliding obligations for the 1997 and 2008 ozone standards to contingency measures, provided that such action is consistent with CAA sections 110(l) and 193.
(4) If EPA, after notice and comment rulemaking, approves a redesignation substitute for a revoked NAAQS, the state may request approval from the EPA to either remove provisions for nonattainment NSR for that revoked NAAQS from the SIP, or shift them to the SIP's list of maintenance plan contingency measures for the area.
(5) If EPA, after notice and comment rulemaking, approves a redesignation substitute for a revoked NAAQS, the state may request approval from the EPA to shift other anti-backsliding obligations for that revoked NAAQS to
(6) Areas that are designated nonattainment for the 2008 ozone NAAQS at the time of designation for the 2015 ozone NAAQS may be redesignated to attainment prior to the effective date of revocation of the 2008 ozone NAAQS.
(c)
(d)
(2)
(ii) As of the effective date of the revocation of a prior ozone NAAQS, the EPA is no longer obligated to reclassify an area to a higher classification for the respective prior ozone NAAQS based upon a determination that the area failed to attain that prior ozone NAAQS by the area's attainment date for that prior ozone NAAQS.
(iii) For a prior revoked ozone NAAQS, the EPA is required to determine whether an area attained the prior ozone NAAQS by the area's attainment date solely for anti-backsliding purposes to address an applicable requirement for nonattainment contingency measures and CAA section 185 fee programs. In making such a determination, the EPA may consider and apply the provisions of CAA section 181(a)(5) and former 40 CFR 51.907 and 51.1107 in interpreting whether a 1-year extension of the attainment date is applicable.
(e)
(f)
For any area that is initially designated attainment for the 2015 ozone NAAQS and that is subsequently redesignated to nonattainment for the 2015 ozone NAAQS, any absolute, fixed date applicable in connection with the requirements of this part other than an attainment date is extended by a period of time equal to the length of time between the effective date of the initial designation for the 2015 ozone NAAQS and the effective date of redesignation, except as otherwise provided in this subpart. The maximum attainment date for a redesignated area would be based on the area's classification, consistent with Table 1 in § 51.1303.
(a) A nonattainment area will meet the requirement of CAA section 181(a)(5)(B) pertaining to 1-year extensions of the attainment date if:
(1) For the first 1-year extension, the area's 4th highest daily maximum 8-hour average in the attainment year is no greater than the level of that NAAQS.
(2) For the second 1-year extension, the area's 4th highest daily maximum 8-hour value, averaged over both the original attainment year and the first extension year, is no greater than the level of that NAAQS.
(b) For purposes of paragraph (a)(1) of this section, the area's 4th highest daily maximum 8-hour average for a year shall be from the monitor with the highest 4th highest daily maximum 8-hour average for that year of all the monitors that represent that area.
(c) For purposes of paragraph (a)(2) of this section, the area's 4th highest daily maximum 8-hour value, averaged over both the original attainment year and the first extension year, shall be from the monitor in each year with the highest 4th highest daily maximum 8-hour average of all monitors that represent that area.
(a) An area classified Moderate under § 51.1303(a) shall submit an attainment demonstration that provides for such specific reductions in emissions of VOCs and NO
(b) An area classified Serious or higher under § 51.1303(a) shall be
(c) Attainment demonstration criteria. An attainment demonstration due pursuant to paragraph (a) or (b) of this section must meet the requirements of Appendix W of this part and shall include inventory data, modeling results, and emission reduction analyses on which the state has based its projected attainment date; the adequacy of an attainment demonstration shall be demonstrated by means of a photochemical grid model or any other analytical method determined by the Administrator, in the Administrator's discretion, to be at least as effective.
(d) Implementation of control measures. For each nonattainment area, the state must provide for implementation of all control measures needed for attainment as expeditiously as practicable. All control measures in the attainment plan and demonstration must be implemented no later than the beginning of the attainment year ozone season, notwithstanding any alternate RACT and/or RACM implementation deadline requirements in § 51.1312.
For purposes of CAA section 179B(b), 42 U.S.C. 7509a(b), in order to establish to the satisfaction of the Administrator that, with respect to an ozone nonattainment area classified as Marginal in such State, such State would have attained the national ambient air quality standard for ozone by the applicable attainment date, but for emissions emanating from outside the United States, a State must demonstrate that all reasonably available control measures have been implemented in the nonattainment area in accordance with CAA section 172(c)(1), 42 U.S.C. 7502(c)(1).
(a)
(1)
(2)
(i) If classified Moderate or higher, the area is subject to the RFP requirements under CAA section 172(c)(2) and shall submit a SIP revision that:
(A) Provides for a 15 percent emission reduction from the baseline year within 6 years after the baseline year;
(B) Provides for an additional emissions reduction of 3 percent per year from the end of the first 6-year period after the baseline year up to the beginning of the attainment year if a baseline year earlier than 2017 is used; and
(C) Relies on either NO
(ii) If classified Serious or higher, the area is also subject to RFP under CAA section 182(c)(2)(B) and shall submit a SIP revision no later than 48 months after the effective date of designation providing for an average emissions reduction of 3 percent per year:
(A) For all remaining 3-year periods after the first 6-year period after the baseline year until the year of the area's attainment date; and
(B) That relies on either NO
(3)
(i) The state shall not distinguish between the portion of the area with a previously approved 15 percent ROP plan and the portion of the area without such a plan, and shall meet the requirements of paragraph (a)(4) of this section for the entire nonattainment area.
(ii) The state shall treat the area as two parts, each with a separate RFP target as follows:
(A) For the portion of the area without an approved 15 percent VOC ROP plan for a prior ozone NAAQS, the state shall submit a SIP revision as required under paragraph (a)(4) of this section.
(B) For the portion of the area with an approved 15 percent VOC ROP plan for a prior ozone NAAQS, the state shall submit a SIP as required under paragraph (a)(2) of this section.
(4)
(i) For each area, the state shall submit a SIP revision consistent with CAA section 182(b)(1). The 6-year period referenced in CAA section 182(b)(1) shall begin January 1 of the year following the year used for the baseline emissions inventory.
(ii) For Moderate areas, the plan must provide for an additional 3 percent per year reduction from the end of the first 6-year period after the baseline year up to the beginning of the attainment year if a baseline year other than the most recent triennial inventory year is selected under paragraph (b) of this section.
(iii) For each area classified Serious or higher, the state shall submit a SIP revision consistent with CAA section 182(c)(2)(B). The final increment of progress must be achieved no later than the attainment date for the area.
(5)
(6)
(7)
(b)
(c)
(2)
(i) Such information and analysis as needed to quantify the actual reduction in emissions achieved in the time interval preceding the applicable milestone; or
(ii) Such information and analysis as needed to demonstrate progress achieved in implementing the approved SIP control measures, including RACM and RACT, corresponding with the reduction in emissions achieved in the time interval preceding the applicable milestone.
(a)
(2)
(ii) For a RACT SIP required pursuant to reclassification, the SIP revision deadline is either 24 months from the effective date of reclassification, or the deadline established by the Administrator in the reclassification action.
(iii) For a RACT SIP required pursuant to the issuance of a new Control Techniques Guideline (CTG) under CAA section 183, the SIP revision deadline is either 24 months from the date of CTG issuance, or the deadline established by the Administrator in the action issuing the CTG.
(3)
(ii) For RACT required pursuant to reclassification, the state shall provide for implementation of such RACT as expeditiously as practicable, but either no later than January 1 of the 3rd year after the associated SIP revision submission deadline or the deadline established by the Administrator in the final action issuing the area reclassification.
(iii) For RACT required pursuant to issuance of a new CTG under CAA section 183, the state shall provide for implementation of such RACT as expeditiously as practicable, but either no later than January 1 of the 3rd year after the associated SIP submission deadline or the deadline established by the Administrator in the final action issuing the CTG.
(b)
(c)
(a) A person or a state may petition the Administrator for an exemption from NO
(b) The petition must contain adequate documentation that the criteria in CAA section 182(f) are met.
(c) A CAA section 182(f) NO
The requirements for nonattainment NSR for the ozone NAAQS are located in § 51.165. For each nonattainment area, the state shall submit a nonattainment NSR plan or plan revision for a specific ozone NAAQS no later than 36 months after the effective date of the area's designation of nonattainment or redesignation to nonattainment for that ozone NAAQS.
(a) For each nonattainment area, the state shall submit a base year inventory
(b) For each nonattainment area, the state shall submit a periodic emission inventory of emissions sources in the area to meet the requirement in CAA section 182(a)(3)(A). With the exception of the inventory year and timing of submittal, this inventory shall be consistent with the requirements of paragraph (a) of this section. Each periodic inventory shall be submitted no later than the end of each 3-year period after the required submission of the base year inventory for the nonattainment area. This requirement shall apply until the area is redesignated to attainment.
(c) The emissions values included in the inventories required by paragraphs (a) and (b) of this section shall be actual ozone season day emissions as defined by § 51.1300(ee).
(d) In the inventories required by paragraphs (a) and (b) of this section, state shall report emissions from point sources according to the point source emissions thresholds of the Air Emissions Reporting Requirements (AERR), 40 CFR part 51, subpart A.
(e) The data elements in the emissions inventories required by paragraphs (a) and (b) of this section shall be consistent with the detail required by 40 CFR part 51, subpart A. Since only emissions within the boundaries of the nonattainment area shall be included as defined by § 51.1300(ee), this requirement shall apply to the emissions inventories required in this section instead of any total county requirements contained in 40 CFR part 51, subpart A.
(a)
(b)
(2)
(ii) For a RACT SIP required pursuant to reclassification, the SIP revision deadline is 24 months from the effective date of reclassification, or the Administrator will establish the SIP revision submission deadline in the reclassification action.
(iii) For a RACT SIP required pursuant to the issuance of a new control techniques guideline (CTG) under CAA section 183, the SIP revision deadline is 24 months from the date of CTG issuance, or the Administrator will establish the SIP revision submission deadline in the action issuing the CTG.
(3)
(ii) For RACT required pursuant to reclassification, the state shall provide for implementation of such RACT as expeditiously as practicable, but either no later than January 1 of the 3rd year after the associated SIP revision submission deadline or no later than a superseding deadline established by the Administrator in the final action issuing the area reclassification.
(iii) For RACT required pursuant to issuance of a new CTG under CAA section 183, the state shall provide for implementation of such RACT as expeditiously as practicable, but either no later than January 1 of the 3rd year after the associated SIP submission deadline or no later than a superseding deadline established by the Administrator in the final action issuing the CTG.
For each area classified Severe or Extreme for a specific ozone NAAQS, the state shall submit a SIP revision within 10 years of the effective date of designation for that ozone NAAQS that meets the requirements of CAA section 185.
Upon a determination by EPA that an area designated nonattainment for a specific ozone NAAQS has attained that NAAQS, the requirements for such area to submit attainment demonstrations and associated reasonably available control measures, reasonable further progress plans, contingency measures for failure to attain or make reasonable progress and other planning SIPs related to attainment of the ozone NAAQS for which the determination has been made, shall be suspended until such time as: The area is redesignated to attainment for that NAAQS or a redesignation substitute is approved as appropriate, at which time the requirements no longer apply; or EPA determines that the area has violated that NAAQS, at which time the area is again required to submit such plans.
As of revocation of the 2008 ozone NAAQS, as set forth in § 50.15(c), the provisions of Subpart CC shall replace the provisions of subpart AA, §§ 51.1100 to 51.1118, which cease to apply except for § 51.1107 for the anti-backsliding purposes of § 51.1305(d)(2).
5.
(i) The offset requirements of paragraph IV.A, Condition 3 of this Ruling for emissions of the ozone precursors NO
(
(
(
(ii) * * *
Nonattainment area new source review obligations for prior ozone NAAQS.
A. Except as provided in paragraph VII.B of this Ruling, an area designated nonattainment for the 2015 ozone NAAQS and designated nonattainment for a prior ozone NAAQS, as of the effective date of the revocation of the respective prior ozone NAAQS, remains subject to the obligation to adopt and implement the major source threshold and offset ratio requirements for nonattainment NSR that apply or applied to the area pursuant to sections 172(c)(5), 173 and 182 of the CAA based on the highest of: (i) The area's classification under section 181(a)(1) of the CAA for the 1-hour ozone NAAQS as of the effective date of revocation of that NAAQS; (ii) the area's classification under § 51.903 for the 1997 ozone NAAQS as of the effective date of revocation of the 1997 ozone NAAQS; (iii) the area's classification under § 51.1103 for the 2008 ozone NAAQS as of the date a permit is issued or as of the effective date of revocation of the 2008 ozone NAAQS, whichever is earlier; and (iv) the area's classification under § 51.1303 for the 2015 ozone NAAQS.
B.1. An area remains subject to the obligations for a revoked NAAQS under paragraph VII.A of this Ruling until either: (i) The area is redesignated to attainment for the 2015 ozone NAAQS, in which case regulatory anti-backsliding requirements related to the 1997 and 2008 ozone standards are satisfied; or (ii) the EPA approves a demonstration for the area in a redesignation substitute procedure for a revoked NAAQS per the provisions of § 51.1305(b). Under this redesignation substitute procedure for a revoked NAAQS, and for this limited anti-backsliding purpose, the demonstration must show that the area has attained that revoked NAAQS due to permanent and enforceable emission reductions and that the area will maintain that revoked NAAQS for 10 years from the date of EPA's approval of this showing.
2. Effect of redesignation to attainment for 2015 ozone NAAQS or approval of a redesignation substitute for a revoked ozone NAAQS. After redesignation to attainment for the 2015 ozone NAAQS, the state may request that provisions for nonattainment NSR for the 1997 and 2008 ozone standards, if applicable, be removed from the SIP, subject to the requirements of CAA sections 110(l) and 193. After EPA approval of a redesignation substitute for a revoked NAAQS under the provisions of § 51.1305(b), the state may request that provisions for nonattainment NSR for that revoked NAAQS be removed from the SIP, subject to the requirements of CAA sections 110(l) and 193. Upon removal of nonattainment NSR provisions for a revoked NAAQS, the state remains subject to the obligation to adopt and implement the major source threshold and offset ratio requirements for nonattainment NSR that apply or applied to the area for the remaining applicable NAAQS consistent with paragraph VII.A of this Ruling.
(a) * * *
(11) * * *
(i) The plan may allow the offset requirement in paragraph (a)(3) of this section for emissions of the ozone precursors NO
(A) The plan shall indicate whether such precursor substitutions for ozone precursors are to be based on a default ratio for the applicable ozone nonattainment area, case-by-case ratios established for individual permits, or a combination of these approaches whereupon a permit applicant may propose a case-by-case permit-specific ratio in lieu of the default ratio for a particular ozone nonattainment area.
(B) The plan shall include any default ratio for precursor substitutions for ozone and shall be accompanied by a description of the air quality model(s) used and the technical demonstration substantiating the equivalent or greater air quality benefit for ozone in the nonattainment area. Any default ratio for precursor substitutions for ozone shall be subject to the approval of the Administrator.
(C) The plan shall provide that for any case-by-case ratios used for individual permit, the ratio shall be approved by the reviewing authority and the Administrator, and should require that the permit applicant submit information to the reviewing authority, including the proposed ratio for the precursor substitution for ozone, a description of the air quality model(s) used, and the technical demonstration substantiating the equivalent or greater air quality benefit for ozone in the nonattainment area.
(ii) The plan may allow the offset requirements in paragraph (a)(3) of this section for direct PM
(12) The plan shall require that in any area designated nonattainment for the 2015 ozone NAAQS and designated nonattainment for the 2008 ozone NAAQS as of the effective date of revocation of the 2008 ozone NAAQS, the requirements of this section applicable to major stationary sources and major modifications of ozone shall include the anti-backsliding requirements contained at § 51.1305.
Nuclear Regulatory Commission.
Republication of systems of records notices; request for comment.
The U.S. Nuclear Regulatory Commission (NRC) has conducted a comprehensive review of all its Privacy Act of 1974 (PA) systems of records notices. The NRC is revising and republishing all its systems of records (systems) notices as a result of this review. Four of the system notices NRC 2, “Biographical Information Records-NRC,” NRC 19, “Official Personnel Training Records—NRC,” NRC 36, “Employee Locator Records,” and NRC 39, “Personnel Security Files and Associated Records—NRC” include proposed revisions that require an advance period for public comment. The remaining systems revisions are minor corrective and administrative changes that do not meet the threshold criteria established by the U.S. Office of Management and Budget (OMB) for either a new or an altered system of records. The proposed revisions to NRC 2, NRC 19, and NRC 36 will add a routine use for records that indicate a violation of civil or criminal law, regulation or order. The revisions to NRC 39 will include modifications and administrative updates. One system of records, NRC 24, Property and Supply Records, is being revoked with this publication. These notices were last published in the
Submit comments on changes made to NRC Systems of Records NRC-2, “Biographical Information Records-NRC,” NRC-19, “Official Personnel Training Records—NRC,” NRC-36, “Employee Locator Records,” and NRC-39, “Personnel Security Files and Associated Records—NRC” by December 19, 2016. Comments received after this date will be considered if it is practical to do so, but the Commission is able to ensure consideration only for comments received before this date.
You may
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•
For additional direction on obtaining information and submitting comments, see “Obtaining Information and Submitting Comments” in the
Sally Hardy, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; telephone: 301-415-5607, email:
Please refer to Docket ID NRC-2016-0235 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-2016-0235 in the subject line of your comment submission, in order to ensure that the NRC is able to make your comment submission available to the public in this docket.
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. The NRC will post all comment submissions at
If you are requesting or aggregating comments from other persons for submission to the NRC, then you should inform those persons not to include identifying or contact information that they do not want to be publicly disclosed in their comment submission. Your request should state that the NRC does not routinely edit comment submissions to remove such information before making the comment submissions available to the public or entering the comment into ADAMS.
The NRC is proposing revisions to NRC 2, “Biographical Information Records-NRC,” NRC 19, “Official Personnel Training Records-NRC,” NRC 36, “Employee Locator Records-NRC,” and NRC 39, “Personnel Security Files and Associated Records-NRC.” The proposed revisions to these systems include revisions that require an advance period for public comment. The proposed revisions to NRC 2, NRC 19, and NRC 36 will add a routine use for records that indicate a violation of civil or criminal law, regulation or order. Under this routine use, such records may be referred to a Federal, State, local or foreign agency that has authority to investigate, enforce, implement or prosecute such laws and may be disclosed for civil or criminal law or regulatory enforcement purposes to another agency in response to a written request from that agency's head or an official who has been delegated such authority. The revisions to NRC 39 will include modifications and administrative updates to the following sections: Categories of Records in the System; Authority for Maintenance of the System; and Routine Uses. The proposed revisions reflect that records in this system may be used by the Office of the Director of National Intelligence, and that this system will be available to maintain any inquiry records associated with the Insider Threat Program mandated by Executive Order 13587, “Structural Reforms To Improve the Security of Classified Networks and the Responsible Sharing and Safeguarding of Classified Information,” dated
A report on these revisions is being sent to the OMB, the Committee on Homeland Security and Governmental Affairs of U.S. Senate, and the Committee on Oversight and Government Reform of the U.S. House of Representatives as required by the Privacy Act.
If changes are made based on the NRC's review of comments received, then the NRC will publish a subsequent notice.
The text of the report, in its entirety, is attached.
For the Nuclear Regulatory Commission.
1. Parking Permit Records—NRC.
2. Biographical Information Records—NRC.
3. Enforcement Actions Against Individuals—NRC.
4. Conflict of Interest Records—NRC.
5. Contracts Records—NRC.
6. Department of Labor (DOL) Discrimination Cases—NRC.
7. (Revoked.)
8. Employee Disciplinary Actions, Appeals, Grievances, and Complaints Records—NRC.
9. Office of Small Business and Civil Rights Discrimination Complaint Records—NRC.
10. Freedom of Information Act (FOIA) and Privacy Act (PA) Request Records—NRC.
11. General Personnel Records (Official Personnel Folder and Related Records)—NRC.
12. Child Care Subsidy Program Records—NRC.
13. (Revoked.)
14. Employee Assistance Program Records—NRC.
15. (Revoked.)
16. Facility Operator Licensees Records (10 CFR part 55)—NRC.
17. Occupational Injury and Illness Records—NRC.
18. Office of the Inspector General (OIG) Investigative Records—NRC and Defense Nuclear Facilities Safety Board (DNFSB).
19. Official Personnel Training Records—NRC.
20. Official Travel Records—NRC.
21. Payroll Accounting Records—NRC.
22. Personnel Performance Appraisals—NRC.
23. Office of Investigations Indices, Files, and Associated Records—NRC.
24. (Revoked.)
25. Oral History Program—NRC.
26. Transit Subsidy Benefits Program Records—NRC.
27. Radiation Exposure Information and Reporting System (REIRS) Records—NRC.
28. Merit Selection Records—NRC.
29. (Revoked.)
30. (Revoked.)
31. (Revoked.)
32. Office of the Chief Financial Officer Financial Transactions and Debt Collection Management Records—NRC.
33. Special Inquiry Records—NRC.
34. (Revoked.)
35. Drug Testing Program Records—NRC.
36. Employee Locator Records—NRC.
37. Information Security Files and Associated Records—NRC.
38. Mailing Lists—NRC.
39. Personnel Security Files and Associated Records—NRC.
40. Facility Security Access Control Records—NRC.
41. Tort Claims and Personal Property Claims Records—NRC.
42. Strategic Workforce Planning Records—NRC.
43. Employee Health Center Records—NRC.
44. Employee Fitness Center Records—NRC.
45. Electronic Credentials for Personal Identity Verification—NRC.
These systems of records are those systems maintained by the NRC that contain personal information about individuals from which information is retrieved by an individual's name or identifier.
The notice for each system of records states the name and location of the record system, the authority for and manner of its operation, the categories of individuals that it covers, the types of records that it contains, the sources of information in those records, and the routine uses of each system of records. Each notice also includes the business address of the NRC official who will inform interested persons of the procedures whereby they may gain access to and request amendment of records pertaining to them.
The Privacy Act provides certain safeguards for an individual against an invasion of personal privacy by requiring Federal agencies to protect records contained in an agency system of records from unauthorized disclosure, ensure that information is current and accurate for its intended use, and that adequate safeguards are provided to prevent misuse of such information.
The following routine uses apply to each system of records notice set forth below which specifically references this Prefatory Statement of General Routine Uses.
1. A record from this system of records which indicates a violation of civil or criminal law, regulation or order may be referred as a routine use to a Federal, State, local or foreign agency that has authority to investigate, enforce, implement or prosecute such laws. Further, a record from this system of records may be disclosed for civil or criminal law or regulatory enforcement purposes to another agency in response to a written request from that agency's head or an official who has been delegated such authority.
2. A record from this system of records may be disclosed as a routine use to a Federal, State, local, or foreign agency to obtain information relevant to an NRC decision concerning hiring or retaining an employee, letting a contract, or issuing a security clearance, license, grant or other benefit.
3. A record from this system of records may be disclosed as a routine use to a Federal, State, local, or foreign agency requesting a record that is relevant and necessary to its decision on a matter of hiring or retaining an employee, issuing a security clearance, reporting an investigation of an employee, letting a contract, or issuing a license, grant, or other benefit.
4. A record from this system of records may be disclosed as a routine use in the course of discovery; in presenting evidence to a court, magistrate, administrative tribunal, or grand jury or pursuant to a qualifying order from any of those; in alternative dispute resolution proceedings, such as arbitration or mediation; or in the course of settlement negotiations.
5. A record from this system of records may be disclosed as a routine use to a Congressional office from the record of an individual in response to an inquiry from the Congressional office made at the request of that individual.
6. A record from this system of records may be disclosed as a routine use to NRC-paid experts or consultants, and those under contract with the NRC on a “need-to-know” basis for a purpose within the scope of the pertinent NRC task. This access will be granted to an NRC contractor or employee of such contractor by a system manager only after satisfactory justification has been provided to the system manager.
7. A record from this system of records may be disclosed as a routine use to appropriate agencies, entities, and persons when: (1) The NRC suspects or has confirmed that the security or confidentiality of information in the system of records has been compromised; (2) the NRC has determined that as a result of the suspected or confirmed compromise there is a risk of harm to economic or property interests, identity theft or fraud, or harm to the security or integrity of this system or other systems or programs (whether maintained by the NRC or another agency or entity) that rely upon the compromised information; and (3) the disclosure to be made to such agencies, entities, and persons is reasonably necessary to assist in connection with the NRC's efforts to respond to the suspected or confirmed compromise and prevent, minimize, or remedy such harm.
8. To respond to the National Archives and Records Administration, Office of Government Information Services (OGIS), to the extent necessary to allow OGIS to fulfill its responsibilities under 5 U.S.C. § 552(h), to review administrative agency policies, procedures and compliance with the Freedom of Information Act (FOIA) and offer mediation services to resolve disputes between persons making FOIA requests and administrative agencies.
Parking Permit Records—NRC.
Administrative and Multimedia Services Branch, Office of Administration, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland, and current contractor facility.
NRC employees and contractors who apply for parking permits for NRC-controlled parking spaces.
These records consist of the applications and the revenue collected for the Headquarters' parking facilities. The applications include, but are not limited to, the applicant's name, address, telephone number, length of service, vehicle, rideshare, and handicap information.
31 U.S.C. 3511; 41 CFR 102-74.265
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To record amount paid and revenue collected for parking;
b. To contact permit holder;
c. To determine priority for issuance of permits;
d. To provide statistical reports to city, county, State, and Federal Government agencies; and
e. For the routine uses specified in paragraph numbers 1, 4, 5, 6, and 7 in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media.
Accessed by name, tag number, and/or permit number.
Paper records are maintained in locked file cabinets under visual control of the Administrative Services Center staff. Computer files are maintained on a hard drive, access to which is password protected. Access to and use of these records is limited to those persons whose official duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. NRC records disposition schedules are accessible through the NRC's Web site at
Chief, Administrative and Multimedia Services Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification Procedure.”
Same as “Notification procedure.”
Applications submitted by NRC employees and contractors.
None.
Biographical Information Records—NRC.
Office of Public Affairs, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Current and former Commissioners and senior NRC staff members.
These records contain information relating to education and training, employment history, and other general biographical data about the Commissioners and senior NRC staff members, including photographs of Commissioners.
42 U.S.C. 5841, 5843(a), 5844(a), 5845(a), and 5849.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide information to the press;
b. To provide information to other persons and agencies requesting this information; and
c. For the routine uses specified in paragraph numbers 1, 5, 6, and 7 of the Prefatory Statement of General Routine Uses. Biographies of current Commissioners are available on the NRC's Web site.
Records are maintained on electronic media.
Records are accessed by name.
Access to and use of this information is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Senior Advisor, Office of Public Affairs, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification Procedure.”
Same as “Notification procedure.”
Information is provided by each individual and approved for use by the individual involved.
None.
Enforcement Actions Against Individuals—NRC.
Primary system—Office of Enforcement, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems may exist, in whole or in part, at the NRC Regional Offices at the locations listed in Addendum I, Part 2, and in the Office of the General Counsel, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Individuals involved in NRC-licensed activities who have been subject to NRC enforcement actions or who have been the subject of correspondence indicating that they are being, or have been, considered for enforcement action.
The system includes, but is not limited to, individual enforcement actions, including Orders, Notices of Violations with and without Civil Penalties, Orders Imposing Civil Penalties, Letters of Reprimand, Demands for Information, and letters to individuals who are being or have been considered for enforcement action. Also included are responses to these actions and letters. In addition, the files may contain other relevant documents directly related to those actions and letters that have been issued. Files are arranged numerically by Individual Action (IA) numbers, which are assigned when individual enforcement actions are considered. In instances where only letters are issued, these letters also receive IA numbers. The system includes a computerized database from which information is retrieved by names of the individuals subject to the action and IA numbers.
42 U.S.C. 2073(e), 2113, 2114, 2167, 2168, 2201(i), 2231, 2282; 10 CFR 30.10, 40.10, 50.5, 50.110, 50.111, 50.120, 60.11, 61.9b, 70.10, 72.12, 110.7b, 110.50, and 110.53; 10 CFR part 2, subpart B; Atomic Energy Act of 1954, as amended (42 U.S.C. 2011
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To respond to general information requests from the Congress;
b. To deter future violations, certain information in this system of records may be routinely disseminated to the public by means such as publishing in the
c. When considered appropriate for disciplinary purposes, information in this system of records, such as enforcement actions and hearing proceedings, may be disclosed to a bar association, or other professional organization performing similar functions, including certification of individuals licensed by NRC or Agreement States to perform specified licensing activities;
d. Where appropriate to ensure the public health and safety, information in this system of records, such as enforcement actions and hearing proceedings, may be disclosed to a Federal or State agency with licensing jurisdiction;
e. To respond to the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906; and
f. For all of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on computer media.
Records are accessed by individual action file number or by the name of the individual.
Paper records are maintained in lockable file cabinets and are under visual control during duty hours. Access to computer records requires use of proper password and user identification codes. Access to and use of these records is limited to those NRC employees whose official duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in the records is primarily obtained from NRC inspectors and investigators and other NRC employees, individuals to whom a record pertains, authorized representatives for these individuals, and NRC licensees, vendors, other individuals regulated by the NRC, and persons making allegations to the NRC.
None.
Conflict of Interest Records—NRC.
Office of the General Counsel, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
NRC current and former employees, consultants, special Government employees, and advisory committee members.
These records contain information relating to:
a. General biographical data (
b. Financial status (
c. Certifications by employees that they and members of their families are in compliance with the Commission's stock ownership regulations;
d. Requests for approval of outside employment by NRC employees and NRC responses thereto;
e. Advice and determinations (
f. Information pertaining to appointment (
5 CFR 2634-2641, 5801; 5 U.S.C. 7351, 7353; Ethics in Government Act of 1978, as amended (5 U.S.C. app., section 101
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide the Department of Justice, Office of Personnel Management, Office of Government Ethics, Office of Special Counsel, Office of the Inspector General, and/or Merit Systems Protection Board with information concerning an employee in instances where the NRC has reason to believe a Federal law may have been violated or where the NRC desires the advice concerning potential violations of Federal law; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and electronic files.
Records are accessed by name.
Paper records are maintained in locked file cabinets and computer records are password protected. Access to these records is limited to individuals with a need to know.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Assistant General Counsel for Legal Counsel, Legislation, and Special Projects, Office of the General Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records either comes from the individual to whom it applies, or is derived from information he or she supplied, or comes from the office to which the individual is to be assigned, other NRC offices, or other persons such as attorneys.
None.
Contracts Records—NRC.
Primary system—Acquisition Management Division, Office of Administration, NRC, Two White Flint North, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in part, at the locations listed in Addendum I, Parts 1 and 2, in working files maintained by the assigned contracting office representative and in the NRC's Agencywide Documents
Persons who are employed as NRC contractors. NRC employees substantially involved with contracting, such as contracting office representatives and other acquisition officials.
These records contain personal information (such as technical qualifications, education, rates of pay, employment history) of contractors and their employees, and other contracting records. They also contain evaluations, recommendations, and reports of NRC acquisition officials, assessment of contractor performance, invoice payment records, and related information.
15 U.S.C. 631, 644; 31 U.S.C. 3511; 13 CFR 124.501-520; 44 U.S.C. 3301; 48 CFR subpart 4.8; 48 CFR part 19.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide information to the U.S. Federal Procurement Data Center, U.S. Department of Health and Human Services, U.S. Defense Contract Audit Agency, U.S. Government Accountability Office, and other Federal agencies for audits and reviews; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on computer media.
Paper records are accessed by contract number or purchase order number; and are cross-referenced to the automated system that contains the name of the contractor, vendor, contracting office representative, procurement official, and taxpayer identification number (TIN).
File folders are maintained in unlocked conserver files in a key code locked room. Access to and use of these records is limited to those persons whose official duties require such access. Access to automated systems is protected by passwords and roles and responsibilities.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Acquisition Management Division, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification Procedure.” Some information was received in confidence and will not be disclosed to the extent that disclosure would reveal confidential business (proprietary) information.
Same as “Notification procedure.”
Information in this system of records comes from the contractor or potential contractor or NRC employee.
Pursuant to 5 U.S.C. 552a(k)(1) and (k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Department of Labor (DOL) Discrimination Cases—NRC.
Primary system—Office of Enforcement, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems may exist, in whole or in part, in enforcement or allegation coordinators' offices at NRC Regional Offices at the addresses listed on Addendum I, Part 2. The duplicate systems in the Regional Offices would ordinarily be limited to the cases filed in each Region.
Individuals who have filed complaints with DOL concerning alleged acts of discrimination in violation of section 211 of the Energy Reorganization Act.
The system consists of documents related to, and provided by, the DOL including copies of complaints, correspondence filed with the Administrative Law Judge assigned to the case, and decisions by the Regional Administrators of DOL's Occupational, Safety, and Health Administration, Administrative Law Judges, and the Administrative Review Board.
42 U.S.C. 2201, as amended; 42 U.S.C. 2282, as amended; 42 U.S.C. 5851, as amended; 10 CFR 30.7, 40.7, 50.7, 60.9, 61.9, 70.7, and 72.10.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
Any of the routine uses specified in the Prefatory Statement of General Routine Uses.
These documents are maintained in a locked filed cabinet. There is no index relating to these documents.
These documents are not kept in alphabetical or date order and are not retrievable by the name of an individual.
Paper documents are maintained in locking file cabinets. Access to and use of these documents is limited to those NRC employees whose official duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification Procedure.” Information received from the DOL is treated by DOL as public information and subject to disclosure under applicable laws.
Same as “Notification procedure.”
The sources of the records include the individuals to whom a record pertains, attorneys for these individuals, defendants, attorneys for the defendants, and DOL.
None.
Employee Disciplinary Actions, Appeals, Grievances, and Complaints Records—NRC.
Primary system—Office of the Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland.
The Office of the Inspector General (OIG) employee files are located with the NRC's OIG, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—A duplicate system may be maintained, in whole or in part, in the Office of the General Counsel, NRC, One White Flint North, 1555 Rockville Pike, Rockville, Maryland, and at NRC's Regional Offices at locations listed in Addendum I, Part 2.
Current and former NRC employees, and annuitants who have filed written complaints brought to the Office of the Chief Human Capital Officer's attention or initiated grievances or appeal proceedings as a result of a determination made by the NRC, Office of Personnel Management, and/or Merit Systems Protection Board, or a Board or other entity established to adjudicate such grievances and appeals.
Includes all documents related to: Disciplinary actions; adverse actions; appeals; complaints, including but not limited to those raised under the agency's prevention of harassment program; grievances; arbitrations; and negative determinations regarding within-grade salary increases. It contains information relating to determinations affecting individuals made by the NRC, Office of Personnel Management, Merit Systems Protection Board, arbitrators or courts of law. The records may include the initial appeal or complaint, letters or notices to the individual, records of hearings when conducted, materials placed into the record to support the decision or determination, affidavits or statements, testimony of witnesses, investigative reports, instructions to an NRC office or division concerning action to be taken to comply with decisions, and related correspondence, opinions, and recommendations.
5 U.S.C. 3132(a); 5 U.S.C. 3521-3525; 5 U.S.C. 4303, as amended; 5 U.S.C. 7503; 29 U.S.C. 633a; 29 U.S.C. 791; 42 U.S.C. 2000e-16; 42 U.S.C. 2201(d), as amended.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To furnish information to the Office of Personnel Management and/or Merit Systems Protection Board under applicable requirements related to grievances and appeals;
b. To provide appropriate data to union representatives and third parties (that may include the Federal Services Impasses Panel and Federal Labor Relations Authority) in connection with grievances, arbitration actions, and appeals; and
c. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and computer media.
Records are retrieved by individual's name.
Records are maintained in locked file cabinets and in a password-protected automated system. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Policy, Labor and Employee Relations Branch, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For OIG employee records: Director, Resource Management and Operations Support, Office of the Inspector General, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Some information was received in confidence and will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
Individuals to whom the record pertains, NRC, Office of Personnel Management and/or Merit Systems Protection Board officials; affidavits or statements from employees, union representatives, or other persons; testimony of witnesses; official documents relating to the appeal, grievance, or complaint, including but not limited to those raised under the agency's prevention of harassment program; Official Personnel Folder; and other Federal agencies.
None.
Office of Small Business and Civil Rights Discrimination Complaint Records—NRC.
Primary system—Office of Small Business and Civil Rights, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—A duplicate system exists, in part, in the Office of the General Counsel, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Applicants for NRC employment and current and former NRC employees who have initiated Equal Employment Opportunity (EEO) counseling and/or filed a formal complaint of employment discrimination under Title VII of the Civil Rights Act, the Age Discrimination in Employment Act of 1967, the Equal Pay Act, Rehabilitation Act and the Genetic Information Nondiscrimination Act (GINA) or Agency Policy for Prohibiting Discrimination Based on Sexual Orientation and Procedures for Filing a Sexual Orientation Discrimination Complaint. Individuals in the United States in education programs or activities receiving Federal financial assistance from the NRC who initiated an informal complaint and/or filed a formal complaint of sex discrimination under Title IX of the Education Amendments Act. Individuals in the United States in programs or activities receiving Federal financial assistance from the NRC who initiated an informal complaint and/or filed a formal complaint of discrimination under Title VI of the Civil Rights Act, the Age Discrimination Act of 1975, Section 504 of the Rehabilitation Act of 1973, and Title IV of the Energy Reorganization Act of 1974, as amended.
This system of records may contain copies of written reports by counselors; investigative files; administrative files, including documentation of withdrawn and/or dismissed complaints; complainant's name, title, and grade; types and theories of discrimination alleged; description of action and conditions giving rise to complaints, settlement agreements, and compliance documents; description of corrective and/or remedial actions; description of disciplinary actions, if any; request for hearings, procedural information, and hearing transcripts; procedural information and forms regarding Alternative Dispute Resolution (ADR); Equal Employment Opportunity Commission (EEOC), GINA or Policy for Prohibiting Discrimination Based on Sexual Orientation and Procedures for Filing a Sexual Orientation Discrimination Complaint, Merit System Protection Board (MSPB), Department of Education (ED), and Department of Justice (DOJ) findings, analyses, decisions and orders; final agency decisions and final actions; and notices of intent to file in Federal district court, notices of cases filed in Federal district court, and Federal court decisions.
5 U.S.C. 2301, 2302; 29 U.S.C. 206(d), as amended; 29 U.S.C. 633a, as amended; 29 U.S.C. 791; 42 U.S.C. 1981; 42 U.S.C. 2000e-16, as amended; 42 U.S.C. 5891; Executive Order (E.O.) 11246 as amended; E.O. 11478 as amended; E.O. 12086, as amended by E.O. 12608; E.O. 12106; E.O. 13166; 10 CFR parts 4 and 5; 29 CFR part 1614.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To furnish information related to discrimination complaints to the EEOC, Office of Personnel Management (OPM), MSPB, DOJ, ED, Health and Human Services, Office of Management and Budget, and Congress, under applicable requirements; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media.
Records are accessed by name and docket number.
Paper records are maintained in locked file cabinets. Automated system is password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Associate Director, Civil Rights and Diversity Directorate and Associate Director, Small Business, Outreach and Compliance Directorate, Office of Small Business and Civil Rights, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Some information was received in confidence and will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
Individual to whom the record pertains, counselors, mediators, investigators, NRC staff, Office of the Chief Human Capital Officer, the EEOC, OPM, MSPB, DOJ and/or ED officials, affidavits or statements from complainants, testimony of witnesses, and official documents relating to the complaints.
Pursuant to 5 U.S.C. 552a(k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552(c)(3), (d), (e)(4)(G), (H), and (I), and (f).
Freedom of Information Act (FOIA) and Privacy Act (PA) Request Records—NRC.
Primary system—FOIA, Privacy, Info Collections Branch, Customer Service Division, Office of the Chief Information Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems may exist, in part, at the locations listed in Addendum I, Parts 1 and 2.
Persons who have made a FOIA or PA request for NRC records.
This system contains copies of the written requests from individuals or organizations made under the FOIA or PA, the NRC response letters, and related records.
5 U.S.C. 552 and 552a; 42 U.S.C. 2201, as amended; 10 CFR part 9.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. If an appeal or court suit is filed with respect to any records denied;
b. For preparation of reports required by 5 U.S.C. 552 and 5 U.S.C. 552a;
c. To another Federal agency when consultation or referral is required to process a request; and
d. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
e. FOIA records, which are publicly available in the Public Documents Room, are accessible through the NRC Web site,
Records are maintained on paper, audio and video tapes, and electronic media.
Records are accessed by unique assigned number for each request and by requester's name.
Records are maintained in locked file cabinets that are kept in locked rooms. Electronic records are password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC' Web site at
FOIA/PA Specialist, FOIA, Privacy, Info Collections Branch, Customer Service Division, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Requests are made by individuals. The response to the request is based upon information contained in NRC records.
None.
General Personnel Records (Official Personnel Folder and Related Records)—NRC.
Primary system—For Headquarters and all Senior Executive Service (SES) personnel, Office of the Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland. For Regional personnel, at Regional Offices I-IV listed in Addendum I, Part 2. The NRC has an interagency agreement with the U.S. Department of the Interior (DOI), International Business Center (IBC),
Duplicate system—Duplicate systems exist, in part, within the organization where an employee actually works for administrative purposes, at the locations listed in Addendum I, Parts 1 and 2.
Current and former NRC employees.
This system contains personnel records that document an individual's Federal career and includes notification of personnel action (SF-50) and documents supporting the action taken; life insurance, thrift savings plan, health benefits and related beneficiary forms; letters of disciplinary action; notices of reductions-in-force; and other records retained in accordance with the Office of Personnel Management's Guide to Personnel Recordkeeping. These records include employment information such as personal qualification statements, resumes, and related documents including information about an individual's birth date, social security number, veterans preference status, tenure, minority group designator, physical handicaps, past and present salaries, grades, position titles; employee locator information identifying home and work address, phone numbers and emergency contacts; and certain medical records related to initial appointment and employment.
5 U.S.C., part III; 5 U.S.C. 4103; 42 U.S.C. 290dd; 42 U.S.C. 2201(d); and Executive Order (E.O.) 9397, as amended by E.O. 13478.
In accordance with an interagency agreement the NRC may disclose records to the DOI/IBC in order to affect the maintenance of electronic personnel records on behalf of the NRC related to its employees.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses; or, where determined to be appropriate and necessary, the NRC may authorize DOI/IBC to make the disclosure:
a. To the Office of Personnel Management (OPM) and/or Merit Systems Protection Board (MSPB) for making a decision when an NRC employee or former NRC employee questions the validity of a specific document in an individual's record;
b. To a prospective employer of a Government employee. Upon transfer of the employee to another Federal agency, the information is transferred to such agency;
c. To store all personnel actions and related documentation resulting from, OPM investigations, Office of the Inspector General investigations, and security investigations, and determination of eligibility for Federal benefits, employment verification, and to update monthly Enterprise Human Resources Integration data repository;
d. To provide statistical reports to Congress, agencies, and the public on characteristics of the Federal work force;
e. To provide information to the OPM and/or MSPB for review, audit, or reporting purposes;
f. To provide members of the public with the names, position titles, grades, salaries, appointments (temporary or permanent), and duty stations of employees;
g. For medical records, to provide information to the Public Health Service in connection with Health Maintenance Examinations and to other Federal agencies responsible for Federal benefit programs administered by the Department of Labor (Office of Workers' Compensation Programs) and the OPM;
h. To disclose information to officials of labor organizations recognized under 5 U.S.C. chapter 71 when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting working conditions; and
i. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media. Effective November 2009, the Official Personnel Folders (OPFs) are maintained electronically in OPM's Enterprise Human Resources Interface.
Records are retrieved by name and/or social security number.
The OPFs are stored electronically in a secure OPM central repository, with role-based security for access to the records and audit trail for all user activity. Paper documents are maintained in lockable file cabinets. Automated systems are password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
For Headquarters and all NRC SES employees—Associate Director for Human Resources Operations and Policy, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
For Region I-IV non-SES employees—The appropriate Regional Personnel Officer at the locations listed in Addendum I, Part 2.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records comes from the individual to whom it applies; is derived from information supplied by that individual; or is provided by agency officials, other Federal agencies, universities, other academic institutions, or persons, including references, private and
Pursuant to 5 U.S.C. 552a(k)(5) and (k)(6), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Child Care Subsidy Program Records—NRC.
FEEA Child Care Service Inc., 3333 S. Wadsworth Boulevard, Suite 300, Lakewood, Colorado (or current contractor facility).
NRC employees who voluntarily apply for child care subsidy.
These records include application forms for child care subsidy containing personal information about the employee (parent), their spouse (if applicable), their child/children, and their child care provider, including name, social security number, employer, grade, home and work telephone numbers, home and work addresses, total family income, name of child on whose behalf the parent is applying for subsidy, child's date of birth; information on child care providers used, including name, address, provider license number and State where issued, child care cost, and provider tax identification number; and copies of IRS Form 1040 or 1040A for verification purposes.
40 U.S.C. 590(g); 5 CFR 792.201-206; Executive Order (E.O.) 9397, as amended by E.O. 13478.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To the Office of Personnel Management to provide statistical reports; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media at the current contractor site.
Information may be retrieved by employee name or social security number.
When not in use by an authorized person, paper records are stored in lockable file cabinets and computer records are protected by the use of passwords.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Associate Director for Human Resources Operations and Policy, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information is obtained from NRC employees who apply for child care subsidy and their child care provider.
None.
Employee Assistance Program Records—NRC.
Office of the Chief Human Capital Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland, and current contractor facility.
NRC employees or family members who have been counseled by or referred to the Employee Assistance Program (EAP) for problems relating to alcoholism, drug abuse, job stress, chronic illness, family or relationship concerns, and emotional and other similar issues.
This system contains records of NRC employees or their families who have participated in the EAP and the results of any counseling or referrals which may have taken place. The records may contain information as to the nature of each individual's problem, subsequent treatment, and progress.
5 U.S.C. 7901; 21 U.S.C. 1101-1181; 42 U.S.C. chapter 6A, Subchapter III-A; 44 U.S.C. 3101; 44 U.S.C. 3301; 5 CFR 792.101-105.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. For statistical reporting purposes; and
b. Any disclosure of information pertaining to an individual will be made in compliance with the Confidentiality of Alcohol and Drug Abuse Patient Records regulations, 42 CFR part 2, as authorized by 42 U.S.C. 290dd-2, as amended.
c. For the routine uses specified in paragraph number 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media.
Information accessed by the EAP identification number and name of the individual.
Files are maintained in a safe under the immediate control of the Employee Assistance Program Manager and the current EAP contractor. Case files are maintained in accordance with the confidentiality requirements of Public Law 93-282, any NRC-specific confidentiality regulations, and the Privacy Act of 1974.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Employee Assistance Program Manager, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information compiled by the Employee Assistance Program Manager, and the Employee Assistance Program contractor during the course of counseling with an NRC employee or members of the employee's family.
None.
Facility Operator Licensees Records (10 CFR part 55)—NRC.
For power reactors, at the appropriate Regional Office at the address listed in Addendum I, Part 2; for non-power (test and research) reactor facilities, at the Operator Licensing and Training Branch, Division of Inspection and Regional Support, Office of Nuclear Reactor Regulation, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland. The Reactor Program System—Operator Licensing (RPS-OL) is located at NRC Headquarters and is accessible by the four Regional Offices.
Individuals licensed under 10 CFR part 55, new applicants whose applications are being processed, and individuals whose licenses have expired.
These records contain information pertaining to 10 CFR part 55 applicants for a license, licensed operators, and individuals who previously held licenses. This includes applications for a license, license and denial letters, and related correspondence; correspondence relating to actions taken against a licensee; 10 CFR 50.74 notifications; certification of medical examination and related medical information; fitness for duty information; examination results and other docket information.
42 U.S.C. 2131-2141; 10 CFR part 55.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To determine if the individual meets the requirements of 10 CFR part 55 to take an examination or to be issued an operator's license;
b. To provide researchers with information for reports and statistical evaluations related to selection, training, and examination of facility operators;
c. To provide examination, testing material, and results to facility management; and
d. For any of the routine uses specified in paragraph numbers 1, 2, 4, 5, 6, and 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and logs, and on electronic media.
Records are accessed by name and docket number and ADAMS accession number.
Maintained in locked file cabinets or an area that is locked. Computer files are password protected. Access to and use of these records is limited to those persons whose official duties require such access based on roles and responsibilities.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Operator Licensing and Training Branch, Division of Inspection and Regional Support, Office of Nuclear Reactor Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system comes from the individual applying for a license, the 10 CFR part 50 licensee, a licensed physician, and NRC and contractor staff.
None.
Occupational Injury and Illness Records—NRC.
Primary system—For Headquarters personnel: Part 1 (Workers' Compensation Program)—Office of the Chief Human Capital Officer, NRC, Three White Flint North, North Bethesda, Maryland. Part 2 (Occupational Safety and Health Program)—Office of Administration, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
For Regional personnel, at each of the Regional Offices listed in Addendum I, Part 2.
Current and former NRC employees with a reported occupational injury or illness.
These records contain information regarding the location and description of the injury or illness, treatment, and disposition as well as copies of Office of Workers' Compensation Program claim forms.
5 U.S.C. 7902, as amended; 29 U.S.C. 657(c), as amended; Executive Order (E.O.) 12196 as amended; 29 CFR parts 1904, 1960.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To prepare periodic statistical reports on employees' health and injury status for transmission to and review by the Department of Labor;
b. For transmittal to the Secretary of Labor or an authorized representative under duly promulgated regulations;
c. For transmittal to the Office of Personnel Management, Merit Systems Protection Board, and/or Equal Employment Opportunity Commission as required to support individual claims; and
d. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media.
Records retrieved by employee name or assigned claim number.
Paper records are locked file cabinets under the visual control of the responsible staff. Electronic records are password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules that can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
For Headquarters Part 1—Benefits Officer, Human Resources Operations and Policy, Office of the Chief Human Capital Officer, and Part 2—Safety and Occupational Health Manager, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For Region I-IV—The appropriate Human Resources Team Leader at the locations listed in Addendum I, Part 2.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
The NRC Health Center; the NRC Headquarters and Regional Office reports; and forms with original information largely supplied by the employees or their representative, supervisors, witnesses, medical personnel, etc.
None.
Office of the Inspector General (OIG) Investigative Records—NRC and Defense Nuclear Facilities Safety Board (DNFSB).
Office of the Inspector General, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Individuals and entities referred to in complaints or actual investigative cases, reports, accompanying documents, and correspondence prepared by, compiled by, or referred to the OIG.
The system comprises five parts: (1) An automated Investigative Database Program containing reports of investigations, inquiries, and other reports closed since 1989; (2) paper files of all OIG and predecessor Office of Inspector and Auditor (OIA) reports,
Inspector General Act of 1978, as amended, 5 U.S.C. app. 3; and the Consolidated Appropriations Act, 2014.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, OIG may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To any Federal, State, local, tribal, or foreign agency, or other public authority responsible for enforcing, investigating, or prosecuting violations of administrative, civil, or criminal law or regulation if that information is relevant to any enforcement, regulatory, investigative, or prosecutorial responsibility of the receiving entity when records from this system of records, either by themselves or in combination with any other information, indicate a violation or potential violation of law, whether administrative, civil, criminal, or regulatory in nature.
b. To public or private sources to the extent necessary to obtain information from those sources relevant to an OIG investigation, audit, inspection, or other inquiry.
c. To a court, adjudicative body before which NRC or DNFSB is authorized to appear, Federal agency, individual or entity designated by NRC or DNFSB or otherwise empowered to resolve disputes, counsel or other representative, or witness or potential witness when it is relevant and necessary to the litigation if any of the parties listed below is involved in the litigation or has an interest in the litigation:
1. NRC or DNFSB, or any component of NRC or DNFSB;
2. Any employee of NRC or DNFSB where the NRC or DNFSB or the Department of Justice has agreed to represent the employee; or
3. The United States, where NRC or DNFSB determines that the litigation is likely to affect the NRC or DNFSB or any of their components.
d. To a private firm or other entity with which OIG or NRC or DNFSB contemplates it will contract or has contracted for the purpose of performing any functions or analyses that facilitate or are relevant to an investigation, audit, inspection, inquiry, or other activity related to this system of records, to include to contractors or entities who have a need for such information or records to resolve or support payment to the agency. The contractor, private firm, or entity needing access to the records to perform the activity shall maintain Privacy Act safeguards with respect to information. A contractor, private firm, or entity operating a system of records under 5 U.S.C. 552a(m) shall comply with the Privacy Act.
e. To another agency to the extent necessary for obtaining its advice on any matter relevant to an OIG investigation, audit, inspection, or other inquiry related to the responsibilities of the OIG.
f. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906.
g. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosure of information to a consumer reporting agency is not considered a routine use of records. Disclosures may be made from this system to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Information is maintained on index cards, in paper files, and on electronic media.
Information is retrieved from the Investigative Database Program by the name of an individual, by case number, or by subject matter. Information in the paper files backing up the Investigative Database Program and older cases closed by 1989 is retrieved by subject matter and/or case number, not by individual identifier. Information is retrieved from index card files for cases closed before 1989 by the name or numerical identifier of the individual or entity under investigation or by subject matter. Information in both the Allegations Tracking System and the Investigative Management System is retrieved by allegation number, case number, or name.
Access to the automated Investigative Database Program is password protected. Index card files for older cases (1970-1989) are maintained in secure office facilities. Both the Allegations Tracking System and the Investigative Management System are accessible from terminals that are double-password-protected. Paper files backing up the automated systems and older case reports and work papers are maintained in approved security containers and locked filing cabinets in a locked room; associated indices, records, diskettes, tapes, etc., are stored in locked metal filing cabinets, safes, storage rooms, or similar secure facilities. All records in this system are available only to authorized personnel who have a need to know and whose duties require access to the information.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Assistant Inspector General for Investigations, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Information classified under Executive Order 12958 will not be disclosed. Information received in confidence will be maintained under the Inspector General Act, 5 U.S.C. app. 3, and the Commission's Policy Statement on Confidentiality, Management Directive 8.8, “Management of Allegations.”
Same as “Notification procedure.”
The information is obtained from sources including, but not limited to, the individual record subject; NRC officials and employees; employees of Federal, State, local, and foreign agencies; and other persons.
Under 5 U.S.C. 552a(j)(2), the Commission has exempted this system of records from subsections (c)(3) and (4), (d)(1)-(4), (e)(1)-(3), (5), and (8), and (g) of the Act. This exemption applies to information in the system that relates to criminal law enforcement and meets the criteria of the (j)(2) exemption. Under 5 U.S.C. 552a(k)(1), (k)(2), (k)(5), and (k)(6), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Official Personnel Training Records—NRC.
Primary system located at the NRC's current contractor facility on behalf of the Office of the Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland.
The Office of the Inspector General (OIG) employee files are located with the OIG at NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in part, at the Technical Training Center, Regional Offices, and within the organization where the NRC employee works, at the locations listed in Addendum I, Parts 1 and 2.
Individuals who applied or were selected for NRC, other Government, or non-Government training courses or programs.
These records contain information relating to an individual's educational background and training courses including training requests and authorizations, evaluations, supporting documentation, and other related personnel information, including but not limited to, an individual's name, address, telephone number, position title, organization, and grade.
5 U.S.C. 3396; 5 U.S.C. 4103; Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 11348, as amended by E.O. 12107; 5 CFR parts 410 and 412.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. Extracted from the records and made available to the Office of Personnel Management; other Federal, State, and local government agencies; educational institutions and training facilities for purposes of enrollment and verification of employee attendance and performance; and
b. Disclosed for the routine uses specified in paragraph numbers 1, 5, 6, and 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media.
Information is accessed by name, user identification number, course number, or course session number.
Electronic records are maintained in a password protected computer system. Paper is maintained in lockable file cabinets and file rooms. Access to and use of these records is limited to those persons whose official duties require such access, with the level of access controlled by roles and responsibilities.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Associate Director for Training and Development, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For OIG employee records: Director, Resource Management and Operations Support, Office of the Inspector General, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information is provided by the subject individual, the employee's supervisor, and training groups, agencies, or educational institutions and learning activities.
None.
Official Travel Records—NRC.
Primary system—Division of the Controller, Office of the Chief Financial Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland. NRC has an interagency agreement with DEVA Consulting Group, Rockville, Maryland, to review and approve vouchers as of June 2013. The Office of International Programs, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland, maintains the passport and visa records.
Duplicate system—Duplicate systems may exist, in part, within the organization where an employee actually works for administrative purposes, at the locations listed in Addendum I, Parts 1 and 2.
Prospective, current, and former NRC employees; consultants; and invitational travelers.
These records contain requests and authorizations for official travel, travel vouchers, passports, visas, and related documentation; charge card applications, terms and conditions for use of charge cards, charge card training documentation, monthly reports regarding accounts, credit data, and related documentation; all of which may include, but are not limited to, an individual's name, address, social security number, and telephone numbers.
5 U.S.C. part III, subpart D, chapter 57; 31 U.S.C. 716; 41 U.S.C. subtitle II, chapter 61; 41 CFR part 102-118; Executive Order (E.O.) 9397, as amended by E.O. 13478.
In accordance with the interagency agreement, NRC may disclose records to DEVA Consulting Group to cross-service travel voucher reimbursements on behalf of the NRC. Specifically, DEVA Consulting Group will examine and pay travel vouchers and maintain the official agency record.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses; or, where determined to be appropriate and necessary, the NRC may authorize DEVA Consulting Group to make the disclosure:
a. To the U.S. Treasury for payment;
b. To the Department of State or an embassy for passports or visas;
c. To the General Services Administration and the Office of Management and Budget for required periodic reporting;
d. To the charge card issuing bank;
e. To the Department of Interior, National Business Center, for collecting severe travel card delinquencies by employee salary offset;
f. To a consumer reporting agency to obtain credit reports; and
g. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosure Pursuant to 5 U.S.C. 552a(b)(12):
Disclosures of information to a consumer reporting agency, other than to obtain credit reports, are not considered a routine use of records. Disclosures may be made from this system to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Records are maintained on paper in file folders, on electronic media.
Records are accessed by name, social security number, authorization number, and voucher payment schedule number.
Maintained in key locked file cabinets and in conserver files in a passcode locked room. Passports and visas are maintained in a locked file cabinet. For electronic records, an identification number, a password, and assigned access to specific programs are required in order to retrieve information.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Travel Operations Branch, Division of the Controller, Office of the Chief Financial Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For passport and visa records: Chief, International Operations Branch, Office of International Programs, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information is provided by the individual, NRC staff, NRC contractors, charge card issuing bank, the consumer reporting agency, outside transportation agents, Department of State, and embassies.
None.
Payroll Accounting Records—NRC.
Primary system—Division of the Controller, Office of the Chief Financial Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland. NRC has an interagency agreement with the Department of the Interior's Interior Business Center (DOI/IBC), Federal Personnel/Payroll System (FPPS), in Denver, Colorado, to maintain electronic personnel information and perform payroll processing activities for its employees as of November 2, 2003.
Duplicate system—Duplicate systems exist, in part, within the organization
Current and former NRC employees, including special Government employees (
Pay, leave, benefit enrollment and voluntary allowance deductions, and labor activities, which includes, but is not limited to, an individual's name and social security number.
26 CFR 31.6011(b)-2, 31.6109-1; 5 U.S.C. 6334; 5 U.S.C. part III, subpart D; 31 U.S.C. 716; 31 U.S.C., subtitle III, chapters 35 and 37; Executive Order (E.O.) 9397, as amended by E.O. 13478.
In accordance with an interagency agreement the NRC may disclose records to the DOI/IBC FPPS in order to effect all financial transactions on behalf of the NRC related to employee pay. Specifically, the DOI/IBC's FPPS may affect employee pay or deposit funds on behalf of NRC employees, and/or it may withhold, collect or offset funds from employee salaries as required by law or as necessary to correct overpayment or amounts due.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses; or, where determined to be appropriate and necessary, the NRC may authorize DOI/IBC to make the disclosure:
a. For transmittal of data to U.S. Treasury to effect issuance of paychecks to employees and consultants and distribution of pay according to employee directions for savings bonds, allotments, financial institutions, and other authorized purposes including the withholding and reporting of Thrift Savings Plan deductions to the Department of Agriculture's National Finance Center;
b. For reporting tax withholding to Internal Revenue Service and appropriate State and local taxing authorities;
c. For FICA and Medicare deductions to the Social Security Administration;
d. For dues deductions to labor unions;
e. For withholding for health insurance to the insurance carriers by the Office of Personnel Management;
f. For charity contribution deductions to agents of charitable institutions;
g. For annual W-2 statements to taxing authorities and the individual;
h. For transmittal to the Office of Management and Budget for financial reporting;
i. For withholding and reporting of retirement, tax levies, bankruptcies, garnishments, court orders, re-employed annuitants, and life insurance information to the Office of Personnel Management;
j. For transmittal of information to State agencies for unemployment purposes;
k. For transmittal to the Office of Child Support Enforcement, Administration for Children and Families, Department of Health and Human Services Federal Parent Locator System and Federal Tax Offset System for use in locating individuals and identifying their income sources to establish paternity, establish and modify orders of support, and for enforcement action;
l. For transmittal to the Office of Child Support Enforcement for release to the Social Security Administration for verifying social security numbers in connection with the operation of the Federal Parent Locator System by the Office of Child Support Enforcement;
m. For transmittal to the Office of Child Support Enforcement for release to the Department of Treasury for the purpose of administering the Earned Income Tax Credit Program (Section 32, Internal Revenue Code of 1986) and verifying a claim with respect to employment in a tax return;
n. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906;
o. Time and labor data are used by the NRC as a project management tool in various management records and reports (
p. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosures of information to a consumer reporting agency are not considered a routine use of records. Disclosures may be made from this system to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Information is maintained on electronic media (stored in memory, on disk, and magnetic tape), on microfiche, and in paper copy.
Electronic payroll, time, and labor records prior to November 2, 2003, are maintained in the Human Resources Management System (HRMS), the PAY PERS Historical database reporting system, and on microfiche at NRC. Electronic payroll records from November 2, 2003, forward are maintained in the DOI/IBC's FPPS in Denver, Colorado. Time and labor records are maintained in the HRMS at NRC.
Information is accessed by employee identification number, name and social security number.
Records are maintained in buildings where access is controlled by a security guard force. File folders, microfiche, tapes, and disks, including backup data, are maintained in secured locked rooms and file cabinets after working hours. All records are in areas where access is controlled by keycard and is limited to NRC and contractor personnel who need the information to perform their official duties. Access to computerized records requires use of proper passwords and user identification codes.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Payroll and Payments Branch, Division of the Controller, Office of the Chief Financial Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records is obtained from sources, including but not limited to, the individual to whom it pertains, the Office of the Chief Human Capital Officer and other NRC officials, and other agencies and entities.
None.
Personnel Performance Appraisals—NRC.
Primary system—Part A: For Headquarters personnel, Office of the Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland. For Regional personnel, at Regional Offices I-IV listed in Addendum I, Part 2.
Part B: Office of the Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland.
NRC has an interagency agreement with the DOI, international Business Center (IBC), in Denver, Colorado, to maintain electronic personnel and payroll information for its employees as of November 2, 2003.
The Office of the Inspector General (OIG) employee files located with the OIG at NRC, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems may exist in part, within the organization where the employee actually works, at the locations listed in Addendum I, Parts 1 and 2.
NRC employees other than the Commissioners, the Inspector General, and temporary personnel employed for less than 1 year.
Part A: Senior Level System employees, GG-1 through GG-15 employees, hourly wage employees, and administratively determined rate employees.
Part B: Senior Executive Service and equivalent employees.
This system contains performance appraisals, which includes performance plans, summary ratings, and other related records.
5 U.S.C. chapter 43; 42 U.S.C. 2201(d), 5841; and 5 CFR part 293.
In accordance with an interagency agreement the NRC may disclose records to DOI/IBC in order to affect the maintenance of electronic personnel records on behalf of the NRC related to its employees.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. For agency personnel functions;
b. To disclose information to officials of labor organizations recognized under 5 U.S.C. chapter 71 when relevant and necessary to their duties of exclusive representation concerning personnel policies, practices, and matters affecting working conditions; and
c. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in folders and on electronic media. Summary ratings from November 2, 2003, forward are stored in the DOI/IBC Federal Personnel/Payroll System. Prior to November 2, 2003 they are maintained at the NRC in the Human Resources Management System (HRMS).
Records are accessed by name and/or social security number.
Records are maintained in locking cabinets in a locked room and related documents may be maintained in unlocked file cabinets or an electromechanical file organizer. Automated systems are password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Associate Director for Human Resources Operations and Policy, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For OIG employees: Director, Resource Management and Operations Support, Office of the Inspector General, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For Regional personnel: Regional Personnel Officers at the appropriate Regional Office I-IV listed in Addendum I, Part 2.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Part A: Subject employee and employee's supervisors.
Part B: Subject employee, employee's supervisors, and any documents and sources used to develop critical elements and performance standards for that Senior Executive Service position.
Pursuant to 5 U.S.C. 552a(k)(1) and (k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Office of Investigations Indices, Files, and Associated Records—NRC.
Primary system—Office of Investigations, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Records exist within the NRC Regional Office locations, listed in Addendum I, Part 2, during an active investigation.
Individuals and entities referred to in potential or actual investigations and matters of concern to the Office of Investigations and correspondence on matters directed or referred to the Office of Investigations.
Office of Investigations correspondence, cases, memoranda, materials including, but not limited to, investigative reports, confidential source information, correspondence to and from the Office of Investigations, memoranda, fiscal data, legal papers, evidence, exhibits, technical data, investigative data, work papers, and management information data.
42 U.S.C. 2035(c); 42 U.S.C. 2201(c); and 42 U.S.C. 5841; 10 CFR 1.36.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the persons or entities mentioned therein if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To a Federal, State, local, or foreign agency or to an individual or organization if the disclosure is reasonably necessary to elicit information or to obtain the cooperation of a witness or an informant;
b. A record relating to an investigation or matter falling within the purview of the Office of Investigations may be disclosed as a routine use to the referring agency, group, organization, or individual;
c. A record relating to an individual held in custody pending arraignment, trial, or sentence, or after conviction, may be disclosed as a routine use to a Federal, State, local, or foreign prison, probation, parole, or pardon authority, to any agency or individual concerned with the maintenance, transportation, or release of such an individual;
d. A record in the system of records relating to an investigation or matter may be disclosed as a routine use to a foreign country under an international treaty or agreement;
e. To a Federal, State, local, or foreign law enforcement agency to assist in the general crime prevention and detection efforts of the recipient agency or to provide investigative leads to the agency; and
f. A record may be disclosed for any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Information maintained on paper, photographs, audio/video tapes, and electronic media.
Information retrieved by document text and/or case number.
Hard copy files maintained in approved security containers and locking filing cabinets. All records are under visual control during duty hours and are available only to authorized personnel who have a need to know and whose duties require access to the information. The electronic management information system is operated within the NRC's secure LAN/WAN system. Access rights to the system only available to authorized personnel.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Office of Investigations, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Information classified under Executive Order 12958 will not be disclosed. Information received in confidence will be maintained under the Commission's Policy Statement on Confidentiality, Management Directive 8.8, “Management of Allegations,” and the procedures covering confidentiality in Chapter 7 of the Office of Investigations Procedures Manual and will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
Information is obtained from sources including, but not limited to, NRC officials, employees, and licensees; Federal, State, local, and foreign agencies; and other persons.
Pursuant to 5 U.S.C. 552a(k)(1), (k)(2), and (k)(6), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Oral History Program—NRC.
Office of the Secretary, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Individuals who volunteer to be interviewed for the purpose of providing information for a history of the nuclear regulatory program.
Records consist of recorded interviews and transcribed scripts of the interviews.
42 U.S.C. 2161(b) and 44 U.S.C. 3301.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. For incorporation in publications on the history of the nuclear regulatory program;
b. To provide information to historians and other researchers; and
c. For the routine uses specified in paragraph number 7 of the Prefatory Statement of General Routine Uses.
Maintained on electronic media.
Information is accessed by the name of the interviewee.
Maintained on an access restricted drive. Access to and use of these records is limited to those authorized by the Historian or a designee.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
NRC Historian, Office of the Secretary, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records is obtained from interviews granted on a voluntary basis to the Historian.
None.
Transit Subsidy Benefits Program Records—NRC.
Administrative and Multimedia Services Branch, Office of Administration, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
NRC employees who apply for subsidized mass transit costs.
The records consist of an individual's application to participate in the program which includes, but is not limited to, the applicant's name, home address, office telephone number, and information regarding the employee's commuting schedule and mass transit system(s) used.
5 U.S.C. 7905; 26 U.S.C. 132; 31 U.S.C. 3511; 41 CFR 102-74.210; 41 CFR subtitle F; 41 CFR 102-71.20; Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 13150.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide statistical reports to the city, county, State, and Federal government agencies;
b. To provide the basis for program approval and issue monthly subsides; and
c. For the routine uses specified in paragraph numbers 1, 4, 5, 6, and 7 in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media.
Accessed by name and smart trip card.
Paper records are maintained in locked file cabinets under visual control of the Administrative Services Center. Computer files are maintained on a hard drive and accessible by user login. Access to and use of these records is limited to those persons whose official duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Administrative and Multimedia Services Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
NRC employees.
None.
Radiation Exposure Information and Reporting System (REIRS) Records—NRC.
Primary system—Oak Ridge Associated Universities (ORAU), Oak Ridge, Tennessee (or current contractor facility).
Duplicate system—Duplicate systems exist, in part, regarding employee exposure records, with the NRC's Radiation Safety Officers at Regional office locations listed in Addendum 1, Part 2, in the Office of Nuclear Reactor Regulations (NRR), the Office of Nuclear Material Safety and Safeguards (NMSS). The Office of Administration (ADM), NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland, maintains the employee dosimeter tracking system.
Individuals monitored for radiation exposure while employed by or visiting or temporarily assigned to certain NRC-licensed facilities; individuals who are exposed to radiation or radioactive materials in incidents required to be reported under 10 CFR 20.2201-20.2204 and 20.2206 by all NRC licensees; individuals who may have been exposed to radiation or radioactive materials offsite from a facility, plant installation, or other place of use of licensed materials, or in unrestricted areas, as a result of an incident involving byproduct, source, or special nuclear material.
These records contain information relating to an individual's name, sex, social security number, birth date, place and period date of exposure; name and license number of individual's employer; name and number of licensee reporting the information; radiation doses or estimates of exposure received during this period, type of radiation, part(s) or organ(s) exposed, and radionuclide(s) involved.
5 U.S.C. 7902; 29 U.S.C. 668; 42 U.S.C. 2051, 2073, 2093, 2095, 2111, 2133, 2134, and 2201(o); 10 CFR parts 20 and 34; Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 12196, as amended; E.O.13708.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide data to other Federal and State agencies involved in monitoring and/or evaluating radiation exposure received by individuals as enumerated in the paragraph “Categories of individuals covered by the system;”
b. To return data provided by licensee upon request; and
c. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media. The electronic records maintained in Oak Ridge, TN, are in a centralized database management system that is password protected. Backup tapes of the database are generated and maintained at a secure, off site location for disaster recovery purposes. During the processing and data entry, paper records are temporarily stored in designated business offices that are locked when not in use and are accessible only to authorized personnel. Upon completion of data entry and processing, the paper records are stored in an offsite security storage facility accessible only to authorized personnel.
Records are accessed by individual name, social security number, date of birth, and/or by licensee name or number.
Information maintained at ORAU is accessible by the Office of Nuclear Regulatory Research (RES) and individuals that have been authorized access by NRC, including all NRC Radiation Safety Officers and ORAU employees that are directly involved in the REIRS project. Reports received and reviewed by the NRC's RES, NRR, NMSS, and Regional offices are in lockable file cabinets and bookcases in secured buildings. A log is maintained of both telephone and written requests for information.
The data maintained in the REIRS database are protected from unauthorized access by several means. The database server resides in a protected environment with physical security barriers under key-card access control. Accounts authorizing access to the server and databases are maintained by the ORAU REIRS system administrator. In addition, ORAU maintains a computer security “firewall” that further restricts access to the ORAU computer network. Authorization for access must be approved by NRC, ORAU project management, and ORAU computer security. Transmittal of data via the Internet is protected by data encryption.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
REIRS Project Manager, Radiation Protection Branch, Division of Systems Analysis, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records comes from licensees; the subject individual; the individual's employer; the person in charge of the facility where the individual has been assigned; NRC Form 5, “Occupational Exposure Record for a Monitoring Period,” or equivalent, contractor reports, and Radiation Safety Officers.
None.
Merit Selection Records—NRC.
Primary system—Electronic records: NRC has an interagency agreement with the DOI, International Business Center (IBC), in Denver, Colorado, to host the NRC's job application system. Paper records: Headquarters personnel*, Office of Human Resources, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland. Regional personnel, at each of the Regional Offices listed in Addendum I, Part 2. *The Office of the Inspector General (OIG) maintains the paper files for OIG personnel.
Duplicate system—Duplicate systems exist, in part, within the organization with the position vacancy, at the locations listed in Addendum I, Parts 1 and 2.
Individuals covered by the system include those who have submitted resumes to the NRC, registered in the NRC application system, or applied for Federal employment with the NRC.
This system contains application information of persons applying to NRC for Federal employment or merit promotion within the NRC, including application for Federal employment (resumes or similar documents); vacancy announcements; job descriptions; examination results; supervisory evaluation or performance appraisal forms; reference forms; and related correspondence. These records include, but are not limited to, applicant information relating to education, training, employment history, earnings, past performance, awards and commendations, citizenship, veteran's preference, birth date, social security number, and home address and telephone numbers.
5 U.S.C. 3301, 5101, 7201; 42 U.S.C. chapter 21, subchapter VI; 42 U.S.C. 2201(d); Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 11478, as amended; E.O. 12106, as amended.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To prepare reports for a variety of internal and external sources including the Office of Personnel Management, Merit Systems Protection Board; EEOC and EEO Investigators; Union representatives and EEO Committee representatives; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained in electronic and paper form.
Records are retrieved by vacancy announcement number, applicant name, or social security number.
Maintained in a password protected automated system and in lockable file cabinets. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Associate Director for Human Resources Operations and Policy, Office of Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For Regional personnel: Regional Personnel Officer at the appropriate Regional Office I-IV listed in Addendum I, Part 2. For applicants to the Honor Law Graduate Program—Honor Law Graduate Program Coordinator, Office of the General Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001. For OIG personnel: Personnel Officer, Office of the Inspector General, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Some information was received in confidence and will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
The source of this information is the subject individual, or is derived from information supplied by that individual; individual's current and previous supervisors within and outside NRC; pre-employment evaluation data furnished by references and educational institutions whose names were supplied by applicant; and information from other Federal agencies.
Pursuant to 5 U.S.C. 552a(k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Office of the Chief Financial Officer Financial Transactions and Debt Collection Management Records—NRC.
Office of the Chief Financial Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland. NRC has a commercial contract with the Deva & Associates, Rockville, MD, as the service provider for the NRC core financial system since April 2013.
Other NRC systems of records contain information that may duplicate some of the records in this system. These other systems include, but are not limited to:
NRC-5, Contracts Records—NRC;
NRC-10, Freedom of Information Act (FOIA) and Privacy Act (PA) Request Records—NRC;
NRC-18, Office of the Inspector General (OIG) Investigative Records—NRC;
NRC-19, Official Personnel Training Records—NRC;
NRC-20, Official Travel Records—NRC;
NRC-21, Payroll Accounting Records—NRC; and
NRC-41, Tort Claims and Personal Property Claims Records—NRC.
Individuals covered are those to who the NRC owes/owed money, those who receive/received a payment from NRC, and those who owe/owed money to the United States. Individuals receiving payments include, but are not limited to, current and former employees, contractors, consultants, vendors, and others who travel or perform certain services for NRC. Individuals owing money include, but are not limited to, those who have received goods or services from NRC for which there is a charge or fee (NRC licensees, applicants for NRC licenses, Freedom of Information Act requesters, etc.) and those who have been overpaid and owe NRC a refund (current and former employees, contractors, consultants, vendors, etc.).
Information in the system includes, but is not limited to, names, addresses, telephone numbers, Social Security Numbers (SSN), employee identification number (EIN), Taxpayer Identification Numbers (TIN), Individual Taxpayer Identification Numbers (ITIN), Data Universal Numbering System (DUNS) number, fee categories, application and license numbers, contract numbers, vendor numbers, amounts owed, background and supporting documentation, correspondence concerning claims and debts, credit reports, and billing and payment histories. The overall agency accounting system contains data and information integrating accounting functions such as general ledger, funds control, travel, accounts receivable, accounts payable, property, and appropriation of funds. Although this system of records contains information on corporations and other business entities, only those records that contain information about individuals that is retrieved by the individual's name or other personal identifier are subject to the Privacy Act.
5 U.S.C. 552a; 5 U.S.C. 5514; 15 U.S.C. 1681; 26 U.S.C. 6103; 31 U.S.C. chapter 37; 31 U.S.C. 6501-6508; 42 U.S.C. 2201; 42 U.S.C. 5841; 31 CFR 900-904; 10 CFR parts 15, 16, 170, 171; Executive Order (E.O.) 9397, as amended by E.O. 13478; and E.O. 12731.
In accordance with an interagency agreement, the NRC may disclose records to the Deva & Associates as the service provider for the NRC core financial system. In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses or, where determined to be appropriate and necessary, the NRC may authorize Deva & Associates to make the disclosure:
a. To debt collection contractors (31 U.S.C. 3718) or to other Federal agencies such as the Department of the Treasury (Treasury) and DOI for the purpose of collecting and reporting on delinquent debts as authorized by the Debt Collection Act of 1982 or the Debt Collection Improvement Act (DCIA) of 1996;
b. To Treasury; the Defense Manpower Data Center, Department of Defense; the United States Postal Service; government corporations; or any other Federal, State, or local agency to conduct an authorized computer matching program in compliance with the Privacy Act of 1974, as amended, to identify and locate individuals, including Federal employees, who are delinquent in their repayment of certain debts owed to the U.S. Government, including those incurred under certain programs or services administered by the NRC, in order to collect debts under common law or under the provisions of the Debt Collection Act of 1982 or the Debt Collection Improvement Act of 1996 which include by voluntary repayment, administrative or salary offset, and referral to debt collection contractors;
c. To the Department of Justice, United States Attorney, Treasury, Deva & Associates, or other Federal agencies for further collection action on any delinquent account when circumstances warrant;
d. To credit reporting agencies/credit bureaus for the purpose of either adding to a credit history file or obtaining a credit history file or comparable credit information for use in the administration of debt collection. As authorized by the DCIA, NRC may report current (not delinquent) as well as delinquent consumer and commercial debt to these entities in order to aid in the collection of debts, typically by providing an incentive to the person to repay the debt timely;
e. To any Federal agency where the debtor is employed or receiving some form of remuneration for the purpose of enabling that agency to collect a debt owed the Federal Government on NRC's behalf by counseling the debtor for voluntary repayment or by initiating administrative or salary offset procedures, or other authorized debt collection methods under the provisions of the Debt Collection Act of 1982 or the DCIA of 1996. Under the DCIA, NRC may garnish non-Federal wages of certain delinquent debtors so long as required due process procedures are followed. In these instances, NRC's notice to the employer will disclose only the information that may be necessary for the employer to comply with the withholding order;
f. To the Internal Revenue Service (IRS) by computer matching to obtain the mailing address of a taxpayer for the purpose of locating such taxpayer to collect or to compromise a Federal claim by NRC against the taxpayer under 26 U.S.C. 6103(m)(2) and under 31 U.S.C. 3711, 3717, and 3718 or
g. To refer legally enforceable debts to the IRS or to Treasury's Debt Management Services to be offset against the debtor's tax refunds under the Federal Tax Refund Offset Program;
h. To prepare W-2, 1099, or other forms or electronic submittals, to forward to the IRS and applicable State and local governments for tax reporting purposes. Under the provisions of the DCIA, NRC is permitted to provide Treasury with Form 1099-C information on discharged debts so that Treasury may file the form on NRC's behalf with the IRS. W-2 and 1099 Forms contain information on items to be considered as income to an individual, including certain travel related payments to employees, payments made to persons not treated as employees (
i. To banks enrolled in the Treasury Credit Card Network to collect a payment or debt when the individual has given his or her credit card number for this purpose;
j. To another Federal agency that has asked the NRC to effect an administrative offset under common law or under 31 U.S.C. 3716 to help collect a debt owed the United States. Disclosure under this routine use is limited to name, address, SSN, EIN, TIN, ITIN, and other information necessary to identify the individual; information about the money payable to or held for the individual; and other information concerning the administrative offset;
k. To Treasury or other Federal agencies with whom NRC has entered into an agreement establishing the terms and conditions for debt collection cross servicing operations on behalf of the NRC to satisfy, in whole or in part, debts owed to the U.S. Government. Cross servicing includes the possible use of all debt collection tools such as administrative offset, tax refund offset, referral to debt collection contractors, salary offset, administrative wage garnishment, and referral to the Department of Justice. The DCIA requires agencies to transfer to Treasury or Treasury-designated Debt Collection Centers for cross servicing certain nontax debt over 180 days delinquent. Treasury has the authority to act in the Federal Government's best interest to service, collect, compromise, suspend, or terminate collection action under existing laws under which the debts arise;
l. Information on past due, legally enforceable nontax debts more than 180 days delinquent will be referred to Treasury for the purpose of locating the debtor and/or effecting administrative offset against monies payable by the Government to the debtor, or held by the Government for the debtor under the DCIA's mandatory, Government-wide Treasury Offset Program (TOP). Under TOP, Treasury maintains a database of all qualified delinquent nontax debts, and works with agencies to match by computer their payments against the delinquent debtor database in order to divert payments to pay the delinquent debt. Treasury has the authority to waive the computer matching requirement for NRC and other agencies upon written certification that administrative due process notice requirements have been complied with;
m. For debt collection purposes, NRC may publish or otherwise publicly disseminate information regarding the identity of delinquent nontax debtors and the existence of the nontax debts under the provisions of the DCIA of 1996;
n. To the Department of Labor (DOL) and the Department of Health and Human Services (HHS) to conduct an authorized computer matching program in compliance with the Privacy Act of 1974, as amended, to match NRC's debtor records with records of DOL and HHS to obtain names, name controls, names of employers, addresses, dates of birth, and TINs. The DCIA requires all Federal agencies to obtain taxpayer identification numbers from each individual or entity doing business with the agency, including applicants and recipients of licenses, grants, or benefit payments; contractors; and entities and individuals owing fines, fees, or penalties to the agency. NRC will use TINs in collecting and reporting any delinquent amounts resulting from the activity and in making payments;
o. If NRC decides or is required to sell a delinquent nontax debt under 31 U.S.C. 3711(I), information in this system of records may be disclosed to purchasers, potential purchasers, and contractors engaged to assist in the sale or to obtain information necessary for potential purchasers to formulate bids and information necessary for purchasers to pursue collection remedies;
p. If NRC has current and delinquent collateralized nontax debts under 31 U.S.C. 3711(i)(4)(A), certain information in this system of records on its portfolio of loans, notes and guarantees, and other collateralized debts will be reported to Congress based on standards developed by the Office of Management and Budget, in consultation with Treasury;
q. To Treasury in order to request a payment to individuals owed money by the NRC;
r. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906; and
s. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosures of information to a consumer reporting agency are not considered a routine use of records. Disclosures may be made from this system to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Information in this system is stored on paper, microfiche, and electronic media.
Automated information can be retrieved by name, SSN, TIN, DUNS number, license or application number, contract or purchase order number, invoice number, voucher number, and/or vendor code. Paper records are retrieved by invoice number.
Records in the primary system are maintained in a building where access is controlled by a security guard force. Records are kept in lockable file rooms or at user's workstations in an area where access is controlled by keycard and is limited to NRC and contractor
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Controller, Division of the Controller, Office of the Chief Financial Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Record source categories include, but are not limited to, individuals covered by the system, their attorneys, or other representatives; NRC; collection agencies or contractors; employing agencies of debtors; and Federal, State and local agencies.
None.
Special Inquiry Records—NRC.
Primary system—Special Inquiry Group, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in whole or in part, at the locations listed in Addendum I, Parts 1 and 2.
Individuals possessing information regarding or having knowledge of matters of potential or actual concern to the Commission in connection with the investigation of an accident or incident at a nuclear power plant or other nuclear facility, or an incident involving nuclear materials or an allegation regarding the public health and safety related to the NRC's mission responsibilities.
The system consists of an alphabetical index file bearing individual names. The index provides access to associated records which are arranged by subject matter, title, or identifying number(s) and/or letter(s). The system incorporates the records of all Commission correspondence, memoranda, audit reports and data, interviews, questionnaires, legal papers, exhibits, investigative reports and data, and other material relating to or developed as a result of the inquiry, study, or investigation of an accident or incident.
42 U.S.C. 2051, 2052, 2201(c), (i) and (o).
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To provide information relating to an item which has been referred to the Commission or Special Inquiry Group for investigation by an agency, group, organization, or individual and may be disclosed as a routine use to notify the referring agency, group, organization, or individual of the status of the matter or of any decision or determination that has been made;
b. To disclose a record as a routine use to a foreign country under an international treaty or convention entered into and ratified by the United States;
c. To provide records relating to the integrity and efficiency of the Commission's operations and management and may be disseminated outside the Commission as part of the Commission's responsibility to inform the Congress and the public about Commission operations; and
d. For any of the routine uses specified in paragraph numbers 1, 2, 4, 5, 6, and 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and electronic media. Documents are maintained in secured vault facilities.
Accessed by name (author or recipient), corporate source, title of document, subject matter, or other identifying document or control number.
These records are located in locking filing cabinets or safes in a secured facility and are available only to authorized personnel whose duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Records Manager, Special Inquiry Group, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or
Same as “Notification procedure.” Information classified under Executive Order 12958 will not be disclosed. Information received in confidence will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
The information in this system of records is obtained from sources including, but not limited to, NRC officials and employees; Federal, State, local, and foreign agencies; NRC licensees; nuclear reactor vendors and architectural engineering firms; other organizations or persons knowledgeable about the incident or activity under investigation; and relevant NRC records.
Pursuant to 5 U.S.C. 552a(k)(1), (k)(2), and (k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Drug Testing Program Records—NRC.
Primary system—Division of Facilities and Security, Office of Administration, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist in part at the NRC Regional office locations listed in Addendum I, Part 2 (for a temporary period of time); and at the current contractor testing laboratories, collection/evaluation facilities.
NRC employees, applicants, consultants, licensees, and contractors.
These records contain information regarding the drug testing program; requests for and results of initial, confirmatory and follow-up testing, if appropriate; additional information supplied by NRC employees, employment applicants, consultants, licensees, or contractors in challenge to positive test results; and written statements or medical evaluations of attending physicians and/or information regarding prescription or nonprescription drugs.
5 U.S.C. 7301; 5 U.S.C. 7361-7363; 42 U.S.C. 2165; 42 U.S.C. 290dd; Executive Order (E.O.) 12564; 9397, as amended by E.O. 13478.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To identify substance abusers within the agency;
b. To initiate counseling and/or rehabilitation programs;
c. To take personnel actions;
d. To take personnel security actions;
e. For statistical reporting purposes. Statistical reporting will not include personally identifiable information; and
f. For the routine uses specified in paragraphs number 6 and 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media. Specimens are maintained in appropriate environments.
Records are indexed and accessed by name, social security number, testing position number, specimen number, drug testing laboratory accession number, or a combination thereof.
Records in use are protected to ensure that access is limited to those persons whose official duties require such access. Unattended records are maintained in NRC-controlled space in locked offices, locked desk drawers, or locked file cabinets. Stand-alone and network processing systems are password protected and removable media is stored in locked offices, locked desk drawers, or locked file cabinets when unattended. Network processing systems have roles and responsibilities protection and system security plans. Records at laboratory, collection, and evaluation facilities are stored with appropriate security measures to control and limit access to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Division of Facilities and Security, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
NRC employees, employment applicants, consultants, licensees, and contractors who have been identified for drug testing who have been tested; physicians making statements regarding medical evaluations and/or authorized prescriptions for drugs; NRC contractors for processing including, but not limited to, specimen collection, laboratories for analysis, and medical evaluations; and NRC staff administering the drug testing program to ensure the achievement of a drug-free workplace.
Pursuant to 5 U.S.C. 552a(k)(5), the Commission has exempted portions of this system of records from 5 U.S.C.
Employee Locator Records—NRC.
Primary system—Part 1: For Headquarters personnel: Office of Chief Human Capital Officer, NRC, Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland. For Regional personnel: Regional Offices I-IV at the locations listed in Addendum 1, Part 2.
Part 2: Operations Division, Office of the Chief Information Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
Part 3: Division of Administrative Services, Office of Administration, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in part, for Incident Response Operations within the Office of Nuclear Security and Incident Response, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland, and at the NRC's Regional Offices, at the locations listed in Addendum I, Part 2.
Duplicate system—Duplicate systems may exist, in part, within the organization where an individual actually works, at the locations listed in Addendum I, Parts 1 and 2.
NRC employees and contractors.
These records include, but are not limited to, an individual's name, home address, office organization and location (building, room number, mail stop), telephone number (home, business, and cell), person to be notified in case of emergency (name, address, telephone number), and other related records.
44 U.S.C. 3101, 3301; Executive Order (E.O.) 9397, as amended by E.O. 13478; and E.O. 12656.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To contact the subject individual's designated emergency contact in the case of an emergency;
b. To contact the subject individual regarding matters of official business;
c. To maintain the agency telephone directory (accessible from
d. For internal agency mail services; and
e. The routine uses specified in paragraph numbers 1, 6 and 7 of the Prefatory Statement of General Routine Uses.
Electronic media.
Information is accessed by name.
Electronic records are password protected. Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Part 1: For Headquarters personnel: Associate Director for Human Resources Operations and Policy, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission (NRC), Washington, DC 20555-0001; and for Regional personnel: Regional Personnel Officer at the Regional Offices listed in Addendum I, Part 2; Part 2: IT Specialist, Infrastructure Operations Branch, Operations Division, Office of the Chief Information Officer, NRC, Washington, DC 20555-0001; Part 3: Mail Services Team Leader, Administrative Services Center, Division of Administrative Services, Office of Administration, NRC, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Individual on whom the record is maintained; Employee Express; NRC Form 15, “Employee Locator Notification” and other related records.
None.
Information Security Files and Associated Records—NRC.
Division of Security Operations, Office of Nuclear Security and Incident Response, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Individuals include present and former NRC employees, contractors, consultants, licensees, and other cleared persons.
These records include information regarding:
a. Personnel who are authorized access to specified levels, categories and types of information, the approving authority, and related documents; and
b. Names of individuals who classify and/or declassify documents (
42 U.S.C. 2161-2169 and 2201(i); Executive Order 13526; 10 CFR part 95.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose
a. To prepare statistical reports for the Information Security Oversight Office; and
b. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper in file folders and on electronic media.
Accessed by name and/or assigned number.
Information maintained in locked buildings, containers, or security areas under guard and/or alarm protection, as appropriate. Records are processed only on systems approved for processing classified information or accessible through password protected systems for unclassified information. The classified systems are stand-alone systems located within secure facilities or with removable hard drives that are either stored in locked security containers or in alarmed vaults cleared for open storage of TOP SECRET information.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Division of Security Operations, Office of Nuclear Security and Incident Response, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Some information is classified under Executive Order 13526, and will not be disclosed. Other information has been received in confidence and will not be disclosed to the extent that disclosure would reveal a confidential source.
Same as “Notification procedure.”
NRC employees, contractors, consultants, and licensees, as well as information furnished by other Government agencies or their contractors.
Pursuant to 5 U.S.C. 552a(k)(1) and (k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4), (G), (H), and (I), and (f).
Mailing Lists—NRC.
Primary system—Publications Branch, Division of Administrative Services, Office of Administration, NRC, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist in whole or in part at the locations listed in Addendum I, Parts 1 and 2.
Individuals, including NRC staff, with an interest in receiving information from the NRC.
Mailing lists include an individual's name and address; and title, occupation, and institutional affiliation, when applicable.
44 U.S.C. 3101, 3301.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. For distribution of documents to persons and organizations listed on the mailing list; and
b. For the routine use specified in paragraph numbers 6 and 7 of the Prefatory Statement of General Routine Uses.
Records are maintained on electronic media.
Records are accessed by company name, individual name, or file code identification number.
Access to and use of these records is limited to those persons whose official duties require such access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Printing Services Specialist, Publications Branch, Division of Administrative Services, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the
Same as “Notification procedure.”
Same as “Notification procedure.”
NRC staff, NRC licensees, and individuals expressing an interest in NRC activities and publications.
None.
Personnel Security Files and Associated Records—NRC.
Division of Facilities and Security, Office of Administration, NRC, Two White Flint North, Rockville, Maryland.
Persons including NRC employees, employment applicants, consultants, contractors, and licensees; other Government agency personnel, other persons who have been considered for an access authorization, special nuclear material access authorization, unescorted access to NRC buildings or nuclear power plants, NRC building access, access to Federal automated information systems or data, or participants in the criminal history program; aliens who visit NRC's facilities; and actual or suspected violators of laws administered by NRC.
These records contain information about individuals, which includes, but is not limited to, their name(s), address, date and place of birth, social security number, identifying information, citizenship, residence history, employment history, military history, financial history, foreign travel, foreign contacts, education, spouse/cohabitant and relatives, personal references, organizational membership, medical, fingerprints, criminal record, and security clearance history. These records also contain copies of personnel security investigative reports from other Federal agencies, summaries of investigative reports, results of Federal agency indices and database checks, records necessary for participation in the criminal history program, reports of personnel security interviews, clearance actions information (
42 U.S.C. 2011
Information in these records may be used by the Division of Facilities and Security and on a need-to-know basis by appropriate NRC officials, Hearing Examiners, Personnel Security Review Panel members, Office of Personnel Management, Central Intelligence Agency, Office of the Director of National intelligence, and other Federal agencies:
a. To determine clearance or access authorization eligibility;
b. To determine eligibility for access to NRC buildings or access to Federal automated information systems or data;
c. To certify clearance or access authorization;
d. To maintain the NRC personnel security program, including the Insider Threat Program;
e. To provide licensees information needed for unescorted access or access to safeguard information determinations; and
f. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records maintained on paper, tapes, and electronic media.
Indexed and accessed by name, social security number, docket number, or a combination thereof.
Records in use are protected to ensure that access is limited to those persons whose official duties require such access. Unattended records are maintained in NRC-controlled space in locked offices, locked desk drawers, or locked file cabinets. Mass storage of records is protected when unattended by a combination lock and alarm system. Unattended classified records are protected in appropriate security containers in accordance with Management Directive 12.1.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Division of Facilities and Security, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.” Some information is classified under Executive Order 12958 and will not be disclosed. Other information has been received in confidence and will not be disclosed to the extent the disclosure would reveal a confidential source.
Same as “Notification procedure.”
NRC applicants, employees, contractors, consultants, licensees, visitors and others, as well as information furnished by other Government agencies or their contractors.
Pursuant to 5 U.S.C. 552a(k)(1), (k)(2), and (k)(5), the Commission has exempted portions of this system of records from 5 U.S.C. 552a(c)(3), (d), (e)(1), (e)(4)(G), (H), and (I), and (f).
Facility Security Access Control Records—NRC.
Primary system—Division of Facilities and Security, Office of Administration, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist in part at NRC Regional Offices and the NRC Technical Training Center at the locations listed in Addendum I, Part 2.
Current and former NRC employees, consultants, contractors, other Government agency personnel, and approved visitors.
The system includes information regarding: (1) NRC personal identification badges issued for continued access to NRC-controlled space; and (2) records regarding visitors to NRC. The records include, but are not limited to, an individual's name, social security number, electronic image, badge number, citizenship, employer, purpose of visit, person visited, date and time of visit, and other information contained on Government issued credentials.
42 U.S.C. 2165-2169 and 2201; Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 13462, as amended by E.O. 13516.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To control access to NRC classified information and to NRC spaces by human or electronic means;
b. Information (identification badge) may also be used for tracking applications within the NRC for other than security access purposes;
c. The electronic image used for the NRC employee personal identification badge may be used for other than security purposes only with the written consent of the subject individual; and
d. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on paper and electronic media.
Information is indexed and accessed by individual's name, social security number, identification badge number, employer's name, date of visit, or sponsor's name.
All records are maintained in NRC-controlled space that is secured after normal duty hours or a security area under guard presence in a locked security container/vault. There is an approved security plan which identifies the physical protective measures and access controls (
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Division of Facilities and Security, Office of Administration, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Sources of information include NRC employees, contractors, consultants, employees of other Government agencies, and visitors.
None.
Tort Claims and Personal Property Claims Records—NRC.
Primary system—Office of the General Counsel, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in whole or in part, in the Office of the Chief Financial Officer, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland, and at the locations listed in Addendum I, Parts 1 and 2. Other NRC systems of records, including but not limited to, NRC-18, “Office of the Inspector General (OIG) Investigative Records—NRC and Defense Nuclear Facilities Safety Board (DNFSB),” and NRC-32, “Office of the Chief Financial Officer Financial Transactions and Debt Collection Management Records—NRC,” may contain some of the information in this system of records.
Individuals who have filed claims with NRC under the Federal Tort Claims Act or the Military Personnel and Civilian Employees' Claims Act and individuals who have matters pending before the NRC that may result in a claim being filed.
This system contains information relating to loss or damage to property and/or personal injury or death in which the U.S. Government may be liable. This information includes, but is not limited to, the individual's name, home address and phone number, work address and phone number, driver's license number, claim forms and supporting documentation, police
Federal Tort Claims Act, 28 U.S.C. 2671
In addition to the disclosures permitted under subsection (b) of the Privacy Act, NRC may disclose information contained in a record in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To third parties, including claimants' attorneys, insurance companies, witnesses, potential witnesses, local police authorities where an accident occurs, and others who may have knowledge of the matter to the extent necessary to obtain information that will be used to evaluate, settle, refer, pay, and/or adjudicate claims;
b. To the Department of Justice (DOJ) when the matter comes within their jurisdiction, such as to coordinate litigation or when NRC's authority is limited and DOJ advice or approval is required before NRC can award, adjust, compromise, or settle certain claims;
c. To the appropriate Federal agency or agencies when a claim has been incorrectly filed with NRC or when more than one agency is involved and NRC makes agreements with the other agencies as to which one will investigate the claim;
d. The Department of the Treasury to request payment of an award, compromise, or settlement of a claim;
e. Information contained in litigation records is public to the extent that the documents have been filed in a court or public administrative proceeding, unless the court or other adjudicative body has ordered otherwise. This public information, including information concerning the nature, status, and disposition of the proceeding, may be disclosed to any person, unless it is determined that release of specific information in the context of a particular case would constitute an unwarranted invasion of personal privacy;
f. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906; and
g. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosure of information to a consumer reporting agency is not considered a routine use of records. Disclosures may be made from this system of records to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Information in this system of records is stored on paper and computer media.
Information is indexed and accessed by the claimant's name and/or claim number.
The paper records and log books are stored in locked file cabinets or locked file rooms and access is restricted to those agency personnel whose official duties and responsibilities require access. Automated records are protected by password.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Assistant General Counsel for Administration, Office of the General Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information is obtained from a number of sources, including but not limited to, claimants, NRC employees involved in the incident, witnesses or others having knowledge of the matter, police reports, medical reports, investigative reports, insurance companies, and attorneys.
None.
Strategic Workforce Planning Records—NRC.
Primary system—Technical Training Center, NRC, 5746 Marlin Road, Suite 200, Chattanooga, Tennessee.
Duplicate system—Duplicate systems may exist, in part, at the locations listed in Addendum I, Parts 1 and 2.
Current, prospective, and former NRC employees, experts, and consultants.
Specific information maintained on individuals includes individual skills assessments that identify the knowledge and skills possessed by the individual and the levels of skill possessed, and may include a skills profile containing, but not limited to, their name; service computation date; series and grade; work and skills experience; special qualifications; licenses and certificates held; and availability for geographic relocation.
5 U.S.C. 3396; 5 U.S.C. 4103; 42 U.S.C. 2201; 44 U.S.C. 3506; Executive Order (E.O.) 9397, as amended by E.O. 13478; E.O. 11348, as amended by E.O. 12107.
The primary use of the records will be to assess the knowledge and skills needed to perform the functions assigned to individuals and their organizations.
Information in the system may be used by the NRC to assess the skills of the staff to develop an organizational training plan/program; to prepare individual training plans; to develop recruitment plans; and to assign personnel. Other offices may maintain similar kinds of records relative to their specific duties, functions, and responsibilities.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, which includes disclosure to other NRC employees who have a need for the information in the performance of their duties, NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the information was collected under the following routine uses:
a. To employees and contractors of other Federal, State, local, and foreign agencies or to private entities in connection with joint projects, working groups, or other cooperative efforts in which the NRC is participating;
b. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906; and
c. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are maintained on electronic media.
Information may be retrieved by, but not limited to, the individual's name; office; skill level; various skills; or work experience.
Records are maintained in areas where access is controlled by keycard and is limited to NRC and contractor personnel. Access to computerized records requires use of password and user identification codes. Level of access is determined by roles and responsibilities.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Chief, Program Management, Human Capital Analysis Branch, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information is obtained from a number of sources, including but not limited to, the individual to whom it pertains, system of records NRC-11, supervisors and other NRC officials, contractors, and other agencies or entities.
None.
Employee Health Center Records—NRC.
Primary system—Employee Health Center, NRC, One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
Duplicate system—Duplicate systems exist, in part, at health care facilities operating under a contract or agreement with NRC for health-related services in the vicinity of each of NRC's Regional offices listed in Addendum I, Part 2. NRC's Regional offices may also maintain copies of occupational health records for their employees.
This system may contain some of the information maintained in other systems of records, including NRC-11, “General Personnel Records (Official Personnel Folder and Related Records)—NRC,” NRC-17, “Occupational Injury and Illness Records—NRC,” and NRC-44, “Employee Fitness Center Records—NRC.”
Current and former NRC employees, consultants, contractors, other Government personnel, and anyone on NRC premises who requires emergency or first-aid treatment.
This system is comprised of records developed as a result of voluntary employee use of health services provided by the Health Center, and of emergency health services rendered by Health Center staff to individuals for injuries and illnesses suffered while on NRC premises. Specific information maintained on individuals may include, but is not limited to, their name, date of birth, and social security number; medical history and other biographical data; test reports and medical diagnoses based on employee health maintenance physical examinations or health screening programs (tests for single medical conditions or diseases); history of complaint, diagnosis, and treatment of injuries and illness rendered by the Health Center staff; immunization records; records of administration by Health Center staff of medications prescribed by personal physicians; medical consultation records; statistical records; daily log of patients; and medical documentation such as personal physician correspondence, test results submitted to the Health Center staff by the employee; and occupational health records.
5 U.S.C. 7901; Executive Order 9397, as amended by E.O. 13478.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the
a. To refer information required by applicable law to be disclosed to a Federal, State, or local public health service agency concerning individuals who have contracted certain communicable diseases or conditions in an effort to prevent further outbreak of the disease or condition;
b. To disclose information to the appropriate Federal, State, or local agency responsible for investigation of an accident, disease, medical condition, or injury as required by pertinent legal authority;
c. To disclose information to the Office of Workers' Compensation Programs in connection with a claim for benefits filed by an employee;
d. To Health Center staff and medical personnel under a contract or agreement with NRC who need the information in order to schedule, conduct, evaluate, or follow up on physical examinations, tests, emergency treatments, or other medical and health care services;
e. To refer information to private physicians designated by the individual when requested in writing;
f. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 and 2906; and
g. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Records are stored in file folders, on electronic media, and on file cards, logs, x-rays, and other medical reports and forms.
Records are retrieved by the individual's name, date of birth, and social security number, or any combination of those identifiers.
Records in the primary system are maintained in a building where access is controlled by a security guard force and entry to each floor is controlled by keycard. Records in the system are maintained in lockable file cabinets with access limited to agency or contractor personnel whose duties require access. The records are under visual control during duty hours. Access to automated data requires use of proper password and user identification codes by authorized personnel.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Technical Assistance Project Manager, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9; and provide their full name, any former name(s), date of birth, and Social Security number.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records is obtained from a number of sources including, but not limited to, the individual to whom it pertains; laboratory reports and test results; NRC Health Center physicians, nurses, and other medical technicians or personnel who have examined, tested, or treated the individual; the individual's coworkers or supervisors; other systems of records; the individual's personal physician(s); NRC Fitness Center staff; other Federal agencies; and other Federal employee health units.
None.
Employee Fitness Center Records—NRC.
Primary system—Fitness Center, NRC, Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
Duplicate system—Regional offices, listed in Addendum I, Part 2, only maintain lists of their employees who receive subsidy from NRC for off-site fitness center memberships.
NRC employees who apply for membership at the Fitness Center, including current and former members.
The system includes applications to participate in NRC's Fitness Center, information on an individual's degree of physical fitness and their fitness activities and goals; and various forms, memoranda, and correspondence related to Fitness Facilities membership and financial/payment matters. Specific information contained in the application for membership includes the employee applicant's name, gender, age, badge id, height, weight, and medical information, including a history of certain medical conditions; the name of the individual's personal physician and any prescription or over-the-counter drugs taken on a regular basis; and the name and address of a person to be notified in case of emergency.
5 U.S.C. 7901; Executive Order (E.O.) 9397, as amended by E.O. 13478.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To the individual listed as an emergency contact, in the event of an emergency;
b. To the National Archives and Records Administration or to the General Services Administration for records management inspections conducted under 44 U.S.C. 2904 or 2906; and
c. For any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosures of information to a consumer reporting agency are not considered a routine use of records. Disclosures may be made from this system to “consumer reporting agencies” as defined in the Fair Credit Reporting Act (15 U.S.C. 1681a(f) (1970)) or the Federal Claims Collection Act of 1966, as amended (31 U.S.C. 3701(a)(3) (1996)).
Records are maintained on paper and electronic media.
Information is indexed and accessed by an individual's name and/or NRC Badge ID number.
Records are maintained in a building where access is controlled by a security guard force. Access to the Fitness Center is controlled by keycard and bar code verification. Records in paper form are stored alphabetically by individuals' names in lockable file cabinets maintained in the NRC where access to the records is limited to agency and Fitness Center personnel whose duties require access. The records are under visual control during duty hours. Automated records are protected by screen saver. Access to automated data requires use of proper password and user identification codes. Only authorized personnel have access to areas in which information is stored.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Employee Assistance Program Manager, Office of the Chief Human Capital Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
Information in this system of records is principally obtained from the subject individual. Other sources of information include, but are not limited to, the NRC Fitness Center Director, staff physicians retained by the NRC, and the individual's personal physicians.
None.
Electronic Credentials for Personal Identity Verification—NRC.
Primary system—Office of the Chief Information Officer, NRC, White Flint North Complex, 11555 Rockville Pike, Rockville, Maryland, and current contractor facility.
Duplicate system—Duplicate systems may exist, in whole or in part, at the locations listed in Addendum I, Part 2.
Individuals covered are persons who have applied for the issuance of electronic credentials for signature, encryption, and/or authentication purposes; have had their credentials renewed, replaced, suspended, revoked, or denied; have used their credentials to electronically make contact with, retrieve information from, or submit information to an automated information system; or have corresponded with NRC or its contractor concerning digital services.
The system contains information needed to establish and verify the identity of users, to maintain the system, and to establish accountability and audit controls. System records may include: (a) Applications for the issuance, amendment, renewal, replacement, or revocation of electronic credentials, including evidence provided by applicants or proof of identity and authority, and sources used to verify an applicant's identity and authority; (b) credentials issued; (c) credentials denied, suspended, or revoked, including reasons for denial, suspension, or revocation; (d) a list of currently valid credentials; (e) a list of currently invalid credentials; (f) a record of validation transactions attempted with electronic credentials; and (g) a record of validation transactions completed with electronic credentials.
5 U.S.C. 301; 42 U.S.C. 2165 and 2201(i); 44 U.S.C. 3501, 3504; Electronic Government Act of 2002, 44 U.S.C. chapter 36; Homeland Security Presidential Directive 12 (HSPD-12), Policy for a Common Identification Standard for Federal Employees and Contractors, August 27, 2004; Executive Order (E.O.) 9397, as amended by E.O. 13478.
In addition to the disclosures permitted under subsection (b) of the Privacy Act, the NRC may disclose information contained in this system of records without the consent of the subject individual if the disclosure is compatible with the purpose for which the record was collected under the following routine uses:
a. To agency electronic credential program contractors to compile and maintain documentation on applicants for verifying applicants' identity and authority to access information system applications; to establish and maintain documentation on information sources for verifying applicants' identities; to ensure proper management, data accuracy, and evaluation of the system;
b. To Federal authorities to determine the validity of subscriber digital certificates and other identity attributes;
c. To the National Archives and Records Administration (NARA) for records management purposes;
d. To a public data repository (
e. Any of the routine uses specified in the Prefatory Statement of General Routine Uses.
Disclosure of system records to consumer reporting systems is not permitted.
Records are stored electronically or on paper.
Records are retrievable by an individual's name, email address, certificate status, certificate number or credential number, certificate issuance date, or approval role.
Technical, administrative, and personnel security measures are implemented to ensure confidentiality, integrity, and availability of the system data stored, processed, and transmitted. Hard copy documents are maintained in locking file cabinets. Electronic records are, at a minimum, password protected. Access to and use of these records is limited to those individuals whose official duties require access.
Records are retained and disposed of in accordance with the National Archives and Records Administration (NARA) approved disposition schedules which can be found in the NRC Comprehensive Records Disposition Schedule, NUREG-0910, the NARA General Records Schedules, as well as in recently approved Requests for Records Disposition Authorities. The NRC's records disposition schedules are accessible through the NRC's Web site at
Director, Operations Division, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
Individuals seeking to determine whether this system of records contains information about them should write to the Freedom of Information Act or Privacy Act Officer, Office of the Chief Information Officer, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and comply with the procedures contained in NRC's Privacy Act regulations, 10 CFR part 9.
Same as “Notification procedure.”
Same as “Notification procedure.”
The sources for information are the individuals who apply for electronic credentials, the NRC and contractors using multiple sources to verify identities, and internal system transactions designed to gather and maintain data needed to manage and evaluate the electronic credentials program.
None.
Part 1—NRC Headquarters Offices
1. One White Flint North, 11555 Rockville Pike, Rockville, Maryland.
2. Two White Flint North, 11545 Rockville Pike, Rockville, Maryland.
3. Three White Flint North, 11601 Landsdown Street, North Bethesda, Maryland.
Part 2—NRC Regional Offices
1. NRC Region I, 2100 Renaissance Boulevard, Suite 100, King of Prussia, Pennsylvania.
2. NRC Region II, Marquis One Tower, 245 Peachtree Center Avenue NE., Suite 1200, Atlanta, Georgia.
3. NRC Region III, 2443 Warrenville Road, Suite 210, Lisle, Illinois.
4. NRC Region IV, 1600 East Lamar Boulevard, Arlington, Texas.
5. NRC Technical Training Center, Osborne Office Center, 5746 Marlin Road, Suite 200, Chattanooga, Tennessee.
Bureau of Land Management, Interior.
Final rule.
This final rule replaces Onshore Oil and Gas Order No. 3, Site Security (Order 3), with new regulations codified in the Code of Federal Regulations (CFR). The final rule establishes minimum standards for oil and gas facility site security, and includes provisions to ensure that oil and gas produced from Federal and Indian (except Osage Tribe) oil and gas leases are properly and securely handled, so as to ensure accurate measurement, production accountability, and royalty payments, and to prevent theft and loss.
The BLM developed this rule based on the proposed rule that was published in the
Like the proposed rule, the final rule addresses Facility Measurement Points (FMPs), site facility diagrams, the use of seals, bypasses around meters, documentation, recordkeeping, commingling, off-lease measurement, the reporting of incidents of unauthorized removal or mishandling of oil and condensate, and immediate assessments for certain acts of noncompliance. The final rule also establishes a process for the BLM to consider variances from the requirements of the final regulation.
Some of the key changes from the proposed rule that are incorporated into the final rule include: Additional exemptions from the final rule's commingling requirements; a streamlined FMP application and approval process; simplified site facility diagram submissions; and clarifications to tank gauging procedures and frequency.
The BLM believes that this final rule, as well as the final rules to update and replace Onshore Oil and Gas Order No. 4 (Order 4), related to measurement of oil, and Onshore Oil and Gas Order No. 5 (Order 5), related to measurement of gas enhance the BLM's overall production verification and accountability program.
The final rule is effective on January 17, 2017.
Michael Wade, BLM Colorado State Office, at 303-239-3737, for information about the requirements of this final rule, or Steven Wells, Division Chief, Fluid Minerals Division, 202-912-7143, for information regarding the BLM's Fluid Minerals Program. Persons who use a telecommunications device for the deaf (TDD) may call the Federal Relay Service at 1-800-877-8339 to contact the above individuals during normal business hours. The Service 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.
Under applicable law, royalties are owed on all production removed or sold from Federal and Indian oil and gas leases, as well as on any oil or gas that is avoidably lost during production. The basis for those royalty payments is the measured production from those leases. In the fiscal year (FY) 2015 sales year, onshore Federal oil and gas leases sold 180 million barrels (bbl) of oil,
As explained in the preamble for the proposed rule (80 FR 40768), given the magnitude of this production and the BLM's statutory and management obligations, it is critically important that the BLM ensure that operators accurately measure, properly report, and account for all production. This final rule helps the BLM achieve that objective by updating and replacing Order 3's requirements with regulations codified in the CFR that reflect changes in oil and gas measurement practices and technology since Order 3 was first promulgated in 1989.
Specifically, the requirements in this rule ensure the proper and secure handling of production from Federal and Indian (except Osage Tribe) oil and gas leases. The proper handling of production is essential to accurate measurement, proper reporting, and overall production accountability, all of which are necessary to ensure that the American public, as well as Indian tribes and allottees, receive the royalties to which they are entitled on oil and gas produced from Federal and Indian leases, respectively.
Order 3 was one of seven Onshore Oil and Gas Orders that the BLM issued under its regulations at 43 CFR part 3160.
The development of this rule was driven largely by internal and external reviews of the BLM's existing production measurement and accountability program. These reviews began in 2007 when the Secretary appointed an independent panel—the Subcommittee on Royalty Management (Subcommittee)—to review the Department's procedures and processes related to the management of mineral revenues and to provide advice to the Department based on that review.
The Subcommittee report expressed concern that the applicable “BLM policy and guidance is outdated” and “some policy memoranda have expired” (Subcommittee report, p. 31). The Subcommittee also expressed concern that “BLM policy and guidance have not been consolidated in a single document or publication,” which has led to the “BLM's 31 oil and gas field offices using varying policy and guidance” (id.). For example, “some BLM State Offices have issued their own `Notices to Lessees' for oil and gas operations” (id.). While the Subcommittee recognized that such Notices to Lessees may have a positive effect on some oil and gas field operations, it also observed that they necessarily “lack a national perspective and may introduce inconsistencies among State [Offices]” (id.).
The Subcommittee made a number of recommendations relevant to site security. It recommended that the BLM re-evaluate its regulations and update its policy and guidance on production accountability, including requiring that requests to commingle production from multiple leases, unit participating areas (PAs), or areas subject to communitization agreements (CAs) identify allocation among zones (Subcommittee report, p. 32). The Subcommittee also recommended that the BLM re-evaluate its policies and guidance for royalty-free use of gas in lease operations. It also specifically recommended that the BLM establish a workgroup to evaluate Order 3. In response, the Department formed a fluid minerals team, comprising Departmental employees who are oil and gas experts. Based on its review, the team determined that Order 3 should be updated.
In addition to the Subcommittee report, the GAO and the OIG have performed multiple audits since 2009 and issued reports that included many findings and recommendations addressing similar issues: (1) Report to Congressional Requesters, Oil and Gas Management, Interior's Oil and Gas Production Verification Efforts Do Not Provide Reasonable Assurance of Accurate Measurement of Production Volumes GAO-10-313 (GAO Report 10-313); (2)
In 2010, the GAO found that Interior's measurement regulations and policies do not provide reasonable assurance that oil and gas are accurately measured. Regarding matters relevant to site security, the report found that the BLM lacks regulatory or policy requirements for operators to clearly identify points of royalty measurement, creating challenges for the BLM in verifying production (GAO Report 10-313, p. 34). It also found that the BLM does not have sufficient national policies or a consistent process for approving arrangements that allow operators to commingle production from multiple Federal, Indian, State, and private leases, which also makes it difficult for the agency to verify production (GAO Report 10-313, p. 36). In response, the GAO specifically recommended that the BLM: (1) Develop guidance clarifying when Federal oil and gas may be commingled and establish standardized measurement methods for such circumstances so that production can be adequately measured and verified; (2) Confirm that commingling agreements are consistent with Interior guidance before they are approved, and that the agreements facilitate key production verification activities; and (3) Track all onshore meters, including information about meter location, identification number, and owner, to help ensure that Interior (through the BLM) is accurately and consistently tracking where and how onshore oil and gas are measured nationwide.
The GAO reiterated some of these concerns in 2015 (GAO Report 15-39). In that report, the GAO acknowledged the improvements the BLM had made in its processes and policies (
Based in part on its concern that the BLM's production verification efforts do “not provide reasonable assurance that operators are accurately measuring and reporting” the volumes of oil and gas produced from Federal and Indian leases, the GAO included the BLM's onshore oil and gas program on its High Risk List in 2011 (Report to Congressional Committees,
The OIG made similar observations as part of its reviews of the BLM's inspection and enforcement program. For example, in 2009 the OIG observed that the BLM's “inspection efforts are hampered because of provisions in the bureau's regulations that have not kept up with modern technology. Most notably, six of the seven Onshore Oil and Gas Orders, which address activities, such as drilling operations, the measurement of oil and gas, and site security, are outdated as they were enacted in the late 1980s and early 1990s.” The OIG specifically recommended that the BLM “(e)nsure that oil and gas regulations are current by updating and issuing onshore orders.” (OIG Report 2009, p. 10-11).
The OIG also expressed concern that “(c)urrent BLM policies (with respect to penalties and assessments) do not allow for immediate assessments for chronic offenders. As a result, at times there is little incentive for companies to meet their regulatory responsibilities.” (
The OIG supplemented these recommendations in 2014 with a series of recommendations that flowed from individual OIG investigations that were consolidated into one report—
• Develop and implement procedures to ensure timely receipt of site facility diagrams and ensure that they contain adequate information related to production and sales phases (OIG Report 2014 at 10, 18);
• Take steps to address misreporting associated with off-lease measurement (
• Ensure that adequate information exists regarding on-lease beneficial use in order to identify inappropriate deductions (
• Ensure that Federal measurement points are properly documented and recorded (
In addition to the concerns from these entities, the BLM also recognized, based on its own experience, that its site security requirements needed strengthening. For example, as explained in the proposed rule, it is not uncommon for a BLM inspector, a lease operator, and field employees to all have different understandings of where the point of royalty measurement is on a given lease, because Order 3 did not require operators to formally identify and obtain BLM approval for the use of a particular royalty measurement point on a given lease, unit PA, or CA. This type of discrepancy can create needless uncertainties in production, accounting, and verification, and can increase the time spent on individual inspections and audits by both operators and the BLM, which strains the BLM's limited resources and requires additional response and resources on the part of operators. This final rule corrects this problem by requiring operators to identify and obtain BLM approval for their royalty measurement points, which are called FMPs under this rule.
Similarly, with respect to commingling approvals, the BLM recognizes that the absence of uniform national guidance means that some BLM-approved commingling agreements may not provide the production data that the BLM needs to independently verify production that is attributable to the Federal or Indian leases covered by those agreements. The absence of this data limits the BLM's ability to fulfill its obligation to ensure that all production from Federal and Indian (except Osage Tribe) oil and gas leases is properly accounted for and that royalties are properly calculated. The final rule addresses these concerns by establishing uniform requirements for both existing and future commingling approvals. With respect to existing approvals, the final rule includes provisions: (1) Specifically grandfathering existing CAAs involving downhole commingling and where production falls below certain specified thresholds; (2) Expressly exempting from compliance with the rule's commingling requirements downhole commingling in new wells in areas where the BLM has specifically recognized that downhole commingling is necessary to ensure maximum economic recovery (such as when a lower formation is necessary to produce an upper one) or when commingled production is below certain levels; and, (3) Expressly recognizing as compliant CAAs authorized by tribal law or agreement. As explained in this preamble, the provisions related to grandfathering and the additional exemptions were developed in response to comments and are consistent with the exceptions in the original proposed rule.
As explained in Section III of this preamble, the requirements in this final rule respond to the Subcommittee, GAO, and OIG recommendations by updating, enhancing, clarifying, and codifying the Order 3 requirements to reflect changes in technology, industry practice, and applicable statutory requirements. The final rule also responds to comments received during the public comment period on the proposed rule.
The Department of the Interior (Department) plays the critical role of ensuring that the country's oil and gas assets are carefully developed and that the American people, Indian tribes and individual allottees receive fair compensation when these assets are leased and developed. A key part of this role consists of providing reasonable assurance that Federal and Indian oil and gas are accurately measured and that measurement efforts undertaken by the private companies developing these resources are held to high standards.
As discussed in the background section of this preamble, the BLM's rules concerning site security and production accountability found in Order 3 have not kept pace with industry standards and practices, statutory requirements, or applicable measurement technology and practices. This final rule enhances the BLM's overall production accountability efforts by addressing these concerns and will ensure that the oil and gas produced from Federal and Indian (except Osage Tribe) leases is adequately accounted for, ultimately ensuring that all royalties due are paid. The following table provides an overview of the changes between the proposed rule and this final rule. A similar chart explaining the differences between the proposed rule and Order 3 appears in the proposed rule at 80 FR 40771.
This final rule is codified primarily in a new 43 CFR subpart 3173 within a new part 3170. The BLM is also issuing final rules that update and replace Order 4 (oil measurement) and Order 5 (gas measurement). Those final rules are codified at new 43 CFR subparts 3174 and 3175, respectively, within the new part 3170. Subpart 3170 of this final rule contains definitions of certain terms and provisions that are common to all three rules (and to any other provisions within part 3170),
In addition, this final rule makes changes to various provisions in 43CFR part 3160 and in 43 CFR 3161.1, 3162.3-2, 3162.4-1, 3162.6, 3162.7-1, 3163.2, and 3165.3. Public comments on changes to the provisions in part 3160 are discussed in connection with the new subparts 3170 or 3173 provisions to which the particular comment relates. Other comments on changes to provisions in part 3160 are discussed at the end of this Section-by-Section analysis.
Section 3170.1 of the final rule identifies the various grants of rulemaking authority in the Federal and Indian mineral leasing statutes and related statutes that give the Secretary authority to promulgate this rule. As explained in that section, the Department is authorized to lease Federal and Indian (except Osage Tribe) oil and gas under various mineral leasing statutes, including the Mineral Leasing Act, 30 U.S.C. 181
Each of these statutes expressly authorizes the Secretary of the Interior to promulgate necessary and appropriate rules and regulations governing those leases.
These statutes and regulations form the basis of and provide the authority for the issuance of this final rule. For example, § 101(a) of FOGRMA directs the Secretary to “establish a comprehensive inspection, collection and fiscal and production accounting and auditing system to provide the capability to accurately determine oil and gas royalties, interest, fines, penalties, fees, deposits, and other payments owed, and to collect and account for such amounts in a timely manner.” Ensuring that oil and gas produced from Federal and Indian leases is accurately measured and properly accounted for is a critical component of any system to ensure that all royalties due are paid. Under § 101(a) of FOGRMA, the Secretary is authorized to promulgate “such rules and regulations as [s]he deems reasonably necessary to carry out.” the purposes of the act. The FOGRMA mandate complements the policy articulated in FLPMA that the United States receive fair compensation for the use of public lands and resources. See 43 U.S.C. 1701(a)(9). This rule, by improving BLM requirements governing site security and related measures, helps ensure that all royalties due are paid, and thus that the United States receives fair compensation for the use of public minerals.
The BLM did not receive any public comments related to this provision and only made minor changes for clarity between the proposed and final versions.
Section 3170.2(a) explains that the regulations in part 3170 apply to all onshore Federal and Indian (except Osage Tribe) oil and gas leases. Paragraph (b) explains that part 3170 also applies to agreements for oil and gas development under the Indian Mineral Development Act, unless the relevant provisions of the rule are inconsistent with the specific terms of such agreement. Paragraph (c) explains that a Tribal Energy Resource Agreement entered into with the
The BLM received several comments expressing concern with proposed paragraph (d), which applies the part 3170 regulations to State or private tracts committed to a federally approved unit or CA as defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180. The same language also appeared in a new paragraph (e) that was proposed to be added to §
Many commenters thought that the new paragraph (e) language proposed for § 3161.1 would extend the BLM's jurisdiction over oil and gas to activities that are not covered by this rule. Specifically, commenters were concerned that adding the proposed language to § 3161.1 and also to proposed § 3170.2 would expand the BLM's authority over the processing and approval of Applications for Permits to Drill (APDs) within State and private tracts committed to a BLM-approved Federal or Indian unit or CA. Commenters said that such an expansion of authority would force operators to obtain Federal drilling permits for drilling on State and private tracts. From the commenters' perspective, this perceived expansion in jurisdiction would fundamentally alter the way in which operators plan for development.
The BLM disagrees with this interpretation of the new language and never intended for this rule to extend the BLM's permitting authority over State and private drilling approvals. However, to avoid confusion, the BLM in this final rule added a new paragraph (b) to its § 3161.1 revisions, which clarifies that it is the regulations in parts 3160 and 3170 relating to site security, measurement, reporting of production and operations, and assessments or penalties for non-compliance with such requirements (
This section defines terms and acronyms used across all of the various subparts of part 3170.
The BLM did not receive any comments on the majority of the definitions that appeared in the proposed rule and that are now in the final rule. Those definitions for which we received no comments were carried forward in this final rule and are not discussed further here. As explained in the proposed rule, a number of the definitions in § 3170.3 of the proposed rule were the same definitions that were found in Order 3, with only minor revisions to either simplify or clarify those definitions.
The following discussion first describes the new definitions that have been added to § 3170.3 in the final rule, and then summarizes and responds to comments that the BLM received on a handful of the proposed definitions. With respect to the former, based on comments received and its own internal reviews, the BLM added three new definitions to § 3170.3: “Averaging period,” “bias,” and “tampering.” As explained below some of these definitions were originally proposed as part of the proposed rules to replace Order 4 (80 FR 58952) and Order 5 (80 CFR 61646). The BLM determined that it was appropriate to move those definitions from those rulemakings to § 3170.3, because the terms are used in multiple subparts, and should therefore be defined once in a section that covers the entirety of part 3170. Other definitions were added in response to public comments.
The final rule defines “averaging period” to mean the previous 12 months or the life of the meter, whichever is shorter. For FMPs that measure production from a newly drilled well, the averaging period excludes production from that well that occurred in or before the first full month after production began. For example, if an oil FMP or a gas FMP were installed to measure the production from a new well that first produced on April 10, the averaging period for this FMP would not include the production that occurred in April and May of that year. The BLM added this definition to § 3170.3 because the term is used multiple times in subparts 3174 (oil measurement) and 3175 (gas measurement), relating to the applicability of uncertainty threshold requirements. The BLM determined it was important to provide a single definition of the averaging period in order to provide for consistent application of the BLM's oil and gas measurement rules.
The final rule adds a definition for the term “bias” to § 3170.3 because that term is used in both subparts 3174 and 3175. “Bias” is defined to mean a “shift in the mean value of a set of measurements away from the true value of what is being measured.” This definition was originally proposed as part of the rule to replace Order 5 in § 3175.10. The definition added to part 3170.3 is identical to the definition in proposed § 3175.10, because the BLM did not receive any comments on that definition in the context of the Order 5 rulemaking.
In response to recommendations from many commenters, the BLM added a definition of the term “tampering” to § 3170.3. The proposed and final rules prohibit operators from tampering with measurement equipment, components, or processes and appropriate valves. While the meaning of tampering is commonly understood, the BLM agrees with commenters that the term should be defined to ensure there is a common understanding of what is meant by tampering for purposes of this rule. Section 3170.3 defines tampering to include “any deliberate adjustment or alteration to a meter or measurement device, appropriate valve, or measurement process that could introduce bias into the measurement or affect the BLM's ability to independently verify volumes or qualities reported.” The BLM modified the definition of “commingling” in the final rule to clarify that combining production from multiple wells within a single lease, unit PA, or CA, or the downhole combining of production from different zones or formations that are part of the same lease, unit PA, or CA, is not considered “commingling” for the purpose of the final rule. Many commenters expressed concern that the definition for commingling in the proposed rule would have required an operator to obtain approval to combine production from multiple properties within a CA or unit PA prior to measurement, particularly when the CA or unit PA contains leases with multiple owners (
The conclusions reached by these commenters were incorrect. Neither the proposed rule nor the final rule defined “commingling” to include the combining of production from multiple properties within a CA or unit PA prior to measurement. However, in response to these comments, the BLM revised the definition of commingling to help clarify the situations that are and are not considered commingling, and to emphasize that the combining of production from multiple properties within a CA or unit PA prior to royalty measurement is not commingling.
One commenter said the proposed commingling definition could deter operators from drilling horizontal wells through several sections that contain different mineral estates and reduce the production and utilization of the State's oil and gas resources. The BLM agrees with this comment with respect to the limited situations in which there is no unit agreement or CA in place for those sections. Downhole commingling when there is multiple ownership and no unit or CA in place would adversely affect the uncertainty, bias, and verifiability of the measurement of the volumes produced from each property, and the BLM would deny such a request unless it qualified under § 3173.14(b) of the final rule. If there was a unit or CA in place, however, the BLM would not consider the combining of production between several sections within the unit or CA to be commingling and no approval would be required. The BLM did not make any changes to the rule based on this comment.
The definition of an FMP in this final rule is carried forward from the proposed rule, which defined an FMP to be a “BLM-approved point where oil or gas produced from a Federal or Indian lease, unit PA, or CA is measured and the measurement affects the calculation of the volume or quality of production on which royalty is owed.” As explained in more detail below in the discussion of comments for § 3173.12, the final rule sets forth a process for an operator of a new or existing facility to apply for approval of an FMP and issuance of an FMP number in proposed § 3173.12. Because § 3173.12 of the final rule requires operators of existing facilities to apply for an FMP in stages over a 36-month period, it will require 3 years from the effective date of the final rule for the BLM to receive, evaluate, and act on an FMP application for existing facilities. Therefore, for purposes of compliance with other provisions of this final rule, during this interim period, the definition of an FMP makes clear, as in the proposed rule, that an FMP “also includes a meter or measurement facility used in the determination of the volume or quality of royalty-bearing oil or gas produced before BLM approval of an FMP under § 3173.12 of this part.”
The BLM received many comments on the proposed definition of an FMP. A couple of commenters pointed out that there are differences between the BLM's proposed definition and the ONRR's definition at 30 CFR 1206.171. Commenters said these differences could cause confusion for industry, the BLM, and ONRR, and recommended that a single definition be established for both agencies. These commenters did not provide specific details or any examples of the confusion that could arise as a result of these definitional differences. The BLM compared both definitions and agrees that there are differences, but disagrees with commenters that these differences will cause confusion. The intent of both definitions is the same. Both agencies want to ensure that the FMP is the point at which measurement determines the royalty that is owed to the Federal Government or the Indian mineral owners. In general, the ONRR definition applies to offshore oil and gas operations, whereas the BLM definition applies only to onshore operations. So, while the two agencies' FMP definitions are not exactly the same, they capture a similar concept (
It should be noted that in 2013, the GAO specifically noted in report GAO-10-313 that Interior's onshore and offshore policies for tracking and approving where and how oil and gas are measured are inconsistent. The Bureau of Safety and Environmental Enforcement (BSEE) already assigns FMP numbers for offshore oil and gas leases, which the operator, transporter, or purchaser must then use when reporting production results to ONRR. Based on that practice, the GAO recommended that the BLM clearly identify points of measurement where oil and gas royalties due to the Federal Government are determined and reported. By including the definition of FMP in the final rule, the BLM is able to both address the GAO's concerns and bring onshore reporting in-line with the approach used offshore.
The BLM received additional comments pertaining to the FMP definition. One recommended that the definition be changed to allow operators to use gas processing plant tailgate meters located off the lease, unit, or CA as FMPs as a general matter, or to allow those meters to be used as FMPs under a variance. Another commenter asked whether an FMP is the same as a Central Delivery Point or Point of Royalty Measurement as defined in Washington Office Instruction Memorandum (IM) 2013-152, a BLM policy document created in 2013 regarding commingling approvals.
The BLM did not change the definition of an FMP to include tailgate meters because, under the Mineral Leasing Act (MLA) and FOGRMA, the Secretary's authority to regulate onshore oil and gas operations applies to lessees/operators and, during certain activities, to purchasers and transporters. While the owners of off-lease/unit/CA gas processing plants may sometimes fall into these categories of regulated entities, they will not always, and while the BLM may consider requests for off-lease measurement it is not required to approve such request. Therefore, the BLM chose not to include off-lease/unit/CA tailgate meters in the definition of an FMP in order to avoid default applications of this rule that might be inconsistent with BLM's statutory authority or the requirements of this final rule related to off-lease measurement at §§ 3173.23 through 3173.28. With respect to whether the definition of an FMP is the same as the Central Delivery Point or Point of Royalty Measurement as defined in IM 2013-152, the BLM can confirm that they are the same.
The definition of “off-lease measurement,” in both the proposed and final rules, means measurement at an FMP that is not located on the lease, unit, or communitized area from which the production came. The BLM received several comments requesting that the definition be expanded to exempt from the proposed rule's off-lease measurement approval requirement cases in which a horizontally or directionally drilled well is completed through a Federal or Indian lease, unit, or communitized area, but conducts measurement operations off-lease at the wellhead. The commenters said that, in many instances, wells are being drilled from a surface location that is sited off-lease due to environmental conditions, such as rugged terrain or sensitive wildlife habitat. The BLM did not
The final rule makes minor changes to the list of acronyms that appear in proposed § 3170.3 based on the acronyms used in part 3170. The BLM did not receive any comments on this list. The acronym Btu (British thermal unit) has been relocated from § 3173.1 to § 3170.3 because this acronym is used in both subparts 3173 and 3175. The acronym S&W (sediment and water) is new to section. The BLM decided to include it in § 3170.3 because the acronym is used in both subparts 3173 and. Although it is a commonly understood acronym in the oil and gas industry, the BLM believes it is appropriate to include the acronym here for clarity and to help inform the general public. The BLM also added the acronym LACT (lease automatic custody transfer) because it is used in both subparts 3173 and 3174.
The BLM did not make any changes to the requirements of this section between the proposed and final versions. Section 3170.4 strengthens the prohibition against meter by-passes contained within section III.D of Order 3 by adding language that prohibits tampering with any measurement device, component of a measurement device, or measurement process. As explained in § 3170.3, tampering includes any deliberate adjustment or alteration to the meter or measurement device or measurement process that could introduce bias into the measurement or affect the BLM's ability to independently verify volumes or qualities reported. Examples of tampering include deliberately installing an orifice plate in a gas meter with the bevel upstream, adjusting a transducer to read higher or lower than a certified test device, entering incorrect information into the configuration log of an electronic gas measurement system, submitting derived integral values on a volume statement in lieu of raw data, or making analogous adjustments or alterations to an oil measurement system.
The BLM received many comments on this section of the proposed rule, most of which suggested that the BLM clarify that inadvertent human error or force majeure events should not be considered “tampering” for purposes of this section. For example, one commenter said meter reports may use derived values due to tap freezes or data loss. The commenter believes that these situations should not be considered “tampering.” The commenter said the language in the proposed rule would not allow for such cases, and should be modified. The BLM agrees with this comment and in the final rule has provided a definition for the term “tampering,” as previously discussed, that clearly states that the act of tampering must be deliberate on the part of the operator. By requiring acts to be deliberate, consistent with the commenter's suggestion, the BLM is able to take into consideration whether a particular act is due to human error or is outside of the operator's control.
The BLM did not amend the definition of tampering in response to the comment about the use of derived values rather than raw data in a meter report, such as when a tap freezes or other malfunctions are experienced. These circumstances can occur in the context of either oil or gas measurement, and they are addressed in specific provisions of subparts 3174 and 3175 (the new rules replacing Orders 4 and 5) that establish procedures that an operator must follow to notify the BLM of the malfunctioning equipment, document how derived values were determined, and indicate on the quantity transaction record that derived values, rather than raw data, were used to determine volumes. As a result, the BLM did not amend the definition of tampering in response to comments about derived values.
Section 3170.5 is reserved for potential future incorporation by reference of standards that apply to more than one of the subparts of part 3170.
Section 3170.6 of the final rule clarifies and makes more uniform the BLM's existing process and regulations for granting variances from the minimum standards contained in part 3170.
Paragraph (a)(1) lists all the information that a party seeking a variance from the requirements of part 3170 must include when filing a request, including: Identification of the specific requirement from which a variance is sought, and the length of time the variance is requested; an explanation of the need for the variance; a detailed explanation of the proposed alternative means of compliance; and a showing that the proposed alternative meets or exceed the objectives of the applicable requirement. Paragraph (a)(2) requires that variance requests be submitted as separate documents from any plans or applications. The BLM will not consider variance-request documents that are submitted as part of a master development plan, APD, right-of-way application, or other applications for approval. This requirement does not preclude operators from submitting variance requests at the same time that they submit a master development plan or other application. In fact, the final rule encourages operators to submit their variance requests simultaneously with, but separately from, their development plans or applications, especially if the operators' proposals are contingent upon the BLM approving their variance requests. The BLM's primary rationale for requiring separate submittal is that, in the past, operators have put their variance requests in the cover letters that accompanied their development proposals, where they are sometimes overlooked. Having operators submit their variance requests via a separate Sundry Notice will help the BLM easily identify them when they are submitted simultaneously with other applications. Paragraph (a)(2) clarifies that approval of a plan or application that contains a request for a variance does not constitute approval of the variance. The BLM made this clarification to ensure that variances are submitted separately and brought to the attention of the BLM.
Paragraph (a)(3) tells operators how to submit their variance requests. Operators must use WIS, which is an acronym described in the final rule to mean the Well Information System or any successor electronic filing system that might be developed by the BLM, to file their request, along with any supporting documents associated with it. This paragraph also provides an option for operators to submit a hardcopy application if electronic filing is not possible or practical. In such cases, the operator must submit a variance in hardcopy as directed by the AO in the Field Office having jurisdiction over the lands described in
No substantive changes were made to proposed paragraph (a)(4). This paragraph strengthens and standardizes the criteria the BLM uses for granting variances. Under Order 3, the AO was required to make only one determination—whether or not the variance request meets or exceeds the objectives of the applicable minimum standard. Under this paragraph in the final rule, the AO will still have to make that determination before granting a variance. Additionally, the final rule requires the AO to make two more determinations before granting a variance—that issuing a variance: (1) Will not adversely affect royalty income or production accountability; and (2) Is consistent with maximum ultimate economic recovery.
Paragraphs (a)(5) and (a)(6) specify that granting or denying a variance is entirely within the BLM's discretion, and that a variance from a requirement in a regulation does not constitute a variance from any other regulations, including other Onshore Oil and Gas Orders. These paragraphs did not change from the proposed rule.
Paragraph 3170.6(b) affirms the BLM's authority to rescind a variance or modify any condition of approval of a variance due to changes in Federal law, technology, regulation, BLM policy, field operations, noncompliance, or for any other reason.
The BLM received many comments on this section of the proposed rule. A few commenters were concerned that the proposed rule would void existing variances and that operators with existing variances would have to apply for new ones. These commenters were concerned this would place an unnecessary burden on affected parties. They recommended that the provision be revised to expressly “grandfather” existing variances.
The BLM did not make a change to the rule in response to these comments. This final rule does not automatically rescind any existing variance approvals. Rather, it clarifies the BLM's authority to rescind variances and provides the means by which it may rescind an existing approval if necessary. The BLM will re-evaluate existing variance approvals on a case-by-case basis, such as during the FMP application and review process under § 3173.16. For example, if an operator has an existing variance approval from the BLM's previous commingling requirements, but during the FMP approval process the BLM determines that the existing approval is inconsistent with this final rule's new commingling standards, or the operator cannot be exempted from the new commingling standards, then the BLM will rescind the existing variance if the deficiencies are not corrected within the time specified by the BLM.
Several commenters disagreed with the provision in paragraph (b) that allows the BLM to rescind variance approvals and modify conditions of approval. These commenters stated that companies made investments and proceeded with projects based on previously approved BLM variances. These commenters said that rescinding existing authorizations and what they believe to be contractual agreements would pose a great risk to their operations.
The BLM did not make a change in the rule in response to these comments. The BLM's overriding contractual agreement with the operator is the lease agreement, which is expressly made subject to regulations and formal orders subsequently promulgated as long as such regulations are not inconsistent with the lease rights granted or the specific lease provisions (See BLM Lease Form 3100-11). The Department has long interpreted this language as “incorporat(ing) future regulations, even though inconsistent with those in effect at the time of lease execution, and even though to do so creates additional obligations or burdens for the lessee.”
The BLM recognizes that the commingling and off-lease measurement requirements in this rule may result in the termination of existing commingling and off-lease measurement variance approvals. However, the BLM has sought to minimize the adverse impacts of these requirements by providing exemptions for economically marginal properties. These additional exemptions are discussed in further detail in the sections of this preamble that address commingling and off lease measurement.
One commenter supported the standards in paragraph (a)(4) that the BLM will use to determine whether to grant a variance but went one step further to recommend that operators be required to demonstrate that compliance with the regulation is not feasible, so that the rule's relatively limited opportunities for variances are not abused. The BLM does not expect operators to abuse the variance process, which requires them to submit an application requesting a variance, and provide sufficient information and justification for the variance that the BLM will then review prior to making a determination on the variance request. In fact, this rule strengthens and standardizes the criteria that the BLM will use to determine whether to grant a variance and requires that the BLM make a determination that “the proposed alternative meets or exceeds the objectives of the applicable requirement(s) of the regulation.” As a result, the BLM does not believe the change requested by the commenter is necessary and did not make any changes the rule based on this comment.
A few commenters expressed concern with language in paragraph (b) that allows the BLM to rescind a variance for “other reasons” because, they said, it could result in the BLM acting arbitrarily. The BLM disagrees that this language would allow it to act arbitrarily because paragraph (b) requires the BLM to provide a written justification when it rescinds a variance. The BLM included the term “other reason” because the BLM cannot anticipate every possible situation in which there will be good cause for rescinding a variance. The BLM must preserve its ability to rescind a variance approval if that approval adversely affects royalty income or production accountability, or is not consistent with maximum ultimate economic recovery. If the operator does not agree with the BLM's decision to rescind a variance, the operator may file an appeal under applicable BLM regulations at 43 CFR subpart 3165—Relief, Conflicts, and Appeals.
A few commenters stated that even though the BLM will provide written justification when it rescinds a variance or modifies a COA, operators should be given a 30-day advance notice if their variance is about to be rescinded, or COA modified, in order to give them an
Section 3170.7 of the final rule updates BLM regulations to reflect the records-retention requirement for Federal oil and gas leases that Congress established in the 1996 amendments to FOGRMA.
Paragraphs (a) and (b) are the same as in the proposed rule. These paragraphs establish both the entities covered and the time period over which the records-retention requirements apply. In the final rule, purchasers and transporters are held to the same minimum standards as operators for recordkeeping, records retention, and records submission—
Although paragraph (c) did not change substantively from the proposed rule, the final rule splits it up into two paragraphs for clarity. Paragraph (c)(1) states that records pertaining to Federal leases, units, or CAs must be maintained for at least 7 years, consistent with applicable statutory requirements. Paragraph (c)(2) codifies the applicable statutory requirements for further retention beyond 7 years under the circumstances specifically identified by statute (
Similarly, although paragraph (d) did not change substantively from the proposed rule, the final rule splits it up into two paragraphs for clarity. Paragraph (d)(1) states that records pertaining to Indian leases, units, or CAs must be maintained for at least 6 years, consistent with applicable statutory requirements. Paragraph (d)(2) codifies the applicable statutory requirements for further retention beyond 6 years under the circumstances specifically identified by statute (
Paragraph (e)(1) addresses the discrepancy between the records-retention requirements for Federal (7 years) and Indian (6 years) leases, as relevant to units and CAs that contain both Federal and Indian leases. No substantive changes were made as part of the final rule. However, the phrase, “but a judicial proceeding or demand is not commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the unit or CA until the Secretary or his designee releases the record holder from the obligation to maintain the records” has been eliminated from this paragraph of the proposed rule and moved to its own paragraph (e)(2).
In paragraph (e)(2) of the proposed rule, which is now paragraph (e)(1) of the final rule, the phrase “or until the Secretary or his designee releases the record holder from the obligation to maintain the records, whichever is later,” was removed from the final rule in order to more closely track the authorizing language in FOGRMA, and also to make the record-retention obligation clearer.
Paragraph (f) requires the record holder to maintain an audit trail and is unchanged from the proposed rule.
Paragraph (g) requires operators, purchasers, and transporters to place specific identifying information on all records, including source records, used to determine quality, quantity, disposition, and verification of production attributable to a Federal or Indian lease, unit PA, or CA. The proposed rule would have required record holders to use BLM-assigned FMP numbers on such records. The final rule is revised to allow record holders, in lieu of an FMP number, to use the lease, unit PA, or CA number, as applicable, on their records, including source records. In any case, the record holder must also include a unique equipment identifier, such as a unique tank identification number or meter station number. The BLM made this change in response to many comments that it would be difficult or impossible for some record holders to modify their electronic systems to accommodate FMP numbers on their records. In these instances, the final rule allows record holders to use the lease, unit PA, or CA number instead of the FMP number.
Paragraph (h) requires operators, purchasers, and transporters to provide all records to the BLM upon request. This ensures that all records—whether they are created by lessees, operators, transporters, or purchasers—are readily available to the BLM. The BLM did not receive any comments on this paragraph and did not change it in the final rule.
Paragraph (i) requires that all records be legible. The BLM did not receive any comments on this paragraph and did not change it in the final rule.
Paragraph (j) requires that all records requiring a signature must also have the signer's printed name. The BLM did not receive any comments on this paragraph of the proposed rule and did not change it in the final rule.
The BLM received a number of comments on § 3170.7 of the proposed rule as a whole requesting various changes to be made to the proposed requirements. Each of these comments is addressed below.
One commenter stated that maintaining audit records for 7 years, as required in paragraph (c)(1), would result in unnecessary costs for purchasers and transporters, and that they should not have to account for production volumes. The BLM does not agree with this comment, nor can it make the changes suggested by the commenter. As discussed earlier, the records retention period set by FOGRMA for Federal leases is now 7 years and the change in retention period in this final rule merely conforms the regulations to that statutory authority.
A number of other commenters asserted that the BLM does not have the authority to hold purchasers and transporters to the same records-retention and recordkeeping requirements as lessees and operators, as outlined in paragraphs (a) and (f) of § 3170.7. Other commenters indicated that they did not see a need for this new requirement and that it would be too costly. Still others disagreed that FOGRMA authorizes the BLM to impose recordkeeping and records-retention requirements on purchasers and transporters in the first instance. One commenter argued that the BLM had not properly defined “any person directly involved in producing, transporting, purchasing, selling, or measuring oil
The BLM disagrees with these comments. Section 103(a) of FOGRMA, 30 U.S.C. 1713(a), requires a “lessee, operator, or other person directly involved in developing, producing, transporting, purchasing, or selling oil or gas . . . through the point of first sale or the point of royalty computation, whichever is later, [to] establish and maintain any records, make any reports, and provide any information that the Secretary may, by rule, reasonably require.” While FOGRMA does not specifically define “any person directly involved,” the intent of the provision is clear. It authorizes the Secretary to establish by rule requirements for anyone involved “. . . in developing, producing,
Based on its experience in the field, the BLM believes it is appropriate to implement this statutory authority and have purchasers and transporters adhere to the same recordkeeping and records-retention requirements as lessees and operators. This is because the BLM must occasionally rely on purchasers' and transporters' records to verify production when operators do not maintain their own records properly, or go out of business, or are acquired by other companies and their records are destroyed. For this reason, the BLM believes that it is important for everyone involved in the production and sale of oil and gas produced from Federal and Indian leases to be responsible for maintaining and providing the necessary records to account for and verify that production. The BLM did not make any changes in response to these comments.
Another commenter said the BLM did not adequately analyze the economic impact that this requirement would have on purchasers and transporters. The BLM does not agree with this comment. As part of this rulemaking process the BLM prepared an
Several commenters said that some transporters do not have space to store records and would not be capable of meeting the paragraph (a) requirements. They said that transporters would create inaccurate records, and that operators would be held responsible. They asked that the BLM not hold operators responsible for transporters' recordkeeping violations. Conversely, some commenters said operators may provide incorrect information to purchasers and transporters, such as incorrect FMP numbers, which could subject purchasers and transporters to recordkeeping penalties if they were to use the inaccurate information in their records. The BLM does not agree with the concerns raised by these commenters, as under the rules each party will be responsible for the content of their own records and must also bear some responsibility for ensuring the accuracy of the information they are tracking. The BLM does not believe that the provision should be modified to account for the possibility that operators might provide faulty information to a purchaser or transporter. Parties bear the responsibility to ensure the accuracy of their own records, and the BLM anticipates that provision of faulty information to a purchaser or transporter by an operator could be handled on a case-by-case basis in the enforcement context. The final rule was not changed as a result of these comments.
Some commenters said the BLM should make the records-retention requirements for both Federal and Indian leases the same—6 years. Paragraph (c) requires Federal-lease operators to retain their records for 7 years (consistent with Congress' 1996 amendments to FOGRMA), while paragraph (d) requires Indian-lease operators to retain theirs for 6 years. One commenter said the 6-year retention requirement for all records under Order 3 has not been a problem and questioned why Congress extended the retention period for Federal-lease operators from 6 years to 7 years. The BLM understands these concerns, but the retention period for records maintained by Federal-lease operators is 7 years by statute. 30 U.S.C. 1724(f). That statutory requirement has been in place for 20 years. This final rule simply codifies that requirement. Thus, the BLM did not change the final rule in response to these comments.
Several commenters expressed concern about the requirement in paragraph (g) of the proposed rule that lessees, operators, purchasers, and transporters place FMP numbers on all of their source records, particularly records generated by flow computers. They said that flow computers cannot handle the 11-digit FMP numbers and that it would take operators years to modify their production accounting systems to accommodate the new numbers. The BLM agrees with these commenters and changed the final rule to allow lessees, operators, purchasers and transporters, as an alternative, to use the lease, unit PA, or CA number, along with a unique equipment identifier, on their records. The BLM believes this change will simplify the final rule's record-keeping requirements because in its experience lessees, operators, purchasers and transporters are already using a lease, unit PA, or CA number, plus some unique equipment identifier in connection with existing operations, which means this information is already reflected on records being generated under existing recordkeeping systems.
In addition to the preceding comments on specific provisions of § 3170.7, the BLM received some general comments on § 3170.7 that were not directed to any specific paragraph. Several commenters said the recordkeeping requirements do not address new production reporting technology and practices that are used by regulators outside of the U.S., such as the Norwegian Petroleum Directorate. These commenters did not suggest any specific changes, and therefore the BLM did not make any changes in the final rule in response to these comments. That said, it should be noted that the BLM is currently updating its existing database system (AFMSS) that it uses to track Federal and Indian oil and gas production. As part of this comprehensive update, the BLM is following data management models and standards established by industry organizations, such as the Professional Petroleum Data Management Association. These update efforts respond to the concerns raised by commenters.
Another commenter said the new recordkeeping and records-retention requirements would cause problems for the BLM. This commenter said BLM field offices do not have room for the additional records that would be generated under the final rule. The BLM disagrees with this commenter. The
Several commenters suggested that requiring purchasers and transporters to keep and retain records would be redundant because purchasers and transporters already provide this information to the operators, who use it to fill out their own production records. The BLM agrees that operators do often base their production reporting on information that purchasers and transporters provide them, however, the BLM cannot confirm that this happens in all cases. Moreover, as noted, operators' records may sometimes be or become unavailable. Requiring each party involved in production from Federal and Indian oil and gas leases to maintain its own records allows the BLM to compare the information and make an independent determination that production is being properly accounted for and that the correct royalties are being paid.
One commenter said this section's new recordkeeping and records-retention requirements will be costly and cause delays, and will discourage oil and gas development on Federal lands, as well as on adjacent State and private lands. The commenter said this in turn will result in lost royalties and jobs. The BLM does not agree with this comment. These recordkeeping requirements are not substantially different from the requirements that operators are currently following (
Section 3170.8 provides that BLM decisions, orders, assessments, or other actions under part 3170 are administratively appealable (first to the BLM State Director and then to the Interior Board of Land Appeals) under 43 CFR 3165.3(b), 3165.4, and part 4. The BLM did not receive any comments on this section; however, in response to comments received on provisions of the proposed rules to replace Orders 4 and 5 the BLM made several changes to this section.
The language from the proposed rule was moved to a new paragraph (a) and a new paragraph (b) was added that creates a separate appeal process for decisions made by the BLM, based on a recommendation from the PMT, for approval or denial of specific measurement equipment or procedures. Under paragraph (b) a party may file a request for discretionary review by the ASLM. Paragraph (b) also provides that the ASLM may delegate this review function as he or she deems appropriate, in which case the application for discretionary review must be made to the person or persons to whom the review function has been delegated.
A specific appeals procedure for recommendations from the PMT was developed for two reasons. First, such a procedure responds directly to comments received on Orders 4 and 5 specifically requesting a procedure to review decisions made by the PMT. Second, the BLM determined that a separate appeal process is necessary because it determined that PMT reviews did not fit under the existing appeals procedure at 43 CFR 3170.8. As explained in this preamble and the preambles for the rules to replace Orders 4 and 5, the PMT will review new measurement technologies and methods and then make recommendations to the BLM as to whether they should be approved. It is the BLM's intent that those approvals be made at the national or Washington Office level, as a result those decisions would not properly be appealable to a BLM State Director as contemplated in paragraph (a). The new language under paragraph (b) reads: “For any recommendation made by the PMT, and approved by the BLM, a party affected by such decision may file a request for discretionary review by the Assistant Secretary for Land and Minerals Management. Under paragraph (b), the Assistant Secretary may delegate this review function as he or she deems appropriate, in which case the affected party's application for discretionary review must be made to the person or persons to whom the Assistant Secretary's review function has been delegated.”
Section 3170.9 provides that noncompliance with any requirements of part 3170 or any order issued thereunder may result in enforcement actions under 43 CFR subpart 3163 or any other remedy available under applicable law or regulation.
The BLM received numerous comments regarding the BLM's proposal, in proposed § 3170.9, not to include in this rule the enforcement, corrective action, and abatement period provisions that were in Order 3, and instead to develop an internal Inspection and Enforcement Handbook that would provide direction to BLM inspectors on how to classify a violation as major or minor, and what the corrective action and timeframes for correction should be. These comments and the BLM's response are discussed later in this preamble in connection with § 3173.29.
This section defines the terms used in subpart 3173 that pertain to site security and production handling. The BLM did not receive any comments on a majority of the definitions that appeared in proposed § 3173.1. Those definitions, for which we received no comment, were carried forward into this final rule and are not discussed further here. The following discussion summarizes and responds to comments that the BLM received on a handful of proposed definitions, describes modifications to some of those definitions, and describes five definitions that were added to § 3173.1 of the final rule: “Free water,” “permanent measurement facility,” “payout period,” “royalty net present value (NPVR),” and “royalty-free use of oil and gas.”
At the outset it should be noted that as explained in the preamble to the proposed rule, a number of the definitions in § 3173.1 are the same definitions that were found in Order 3, with only minor simplifications or clarifications.
As noted in the Section-by-Section discussion for § 3170.3, the acronym for “British thermal unit (Btu)” has been moved from this section to § 3170.3 of the final rule because it is used in more than one subpart of § 3170. The acronym BIA (Bureau of Indian Affairs) was added to this final rule because it is used in §§ 3173.14 and 3173.23.
Similarly, the acronym for “CAA (commingling and allocation approval)” was provided in the proposed rule, but the term was not otherwise defined. One commenter suggested that a definition for this term be provided. The BLM agrees with this comment and has provided a definition in the final rule
The BLM also replaced the term “low-volume property” with the term “economically marginal property” and modified the definition based on comments received. The term “low-volume property” was intended to identify category of leases, unit PAs, and CAs for which commingled measurement of production may be justified, even though the property would not meet the conditions of proposed § 3173.14(a)(1) regarding mineral interest ownership of commingled production. In response to comments, the BLM made a number of changes to this definition, most notably changing the term to “economically marginal property” in the final rule.
The BLM believes this new term is more reflective of the BLM's intent, which is to describe a type of property that should be allowed to be part of a CAA in order to avoid premature plugging and abandonment. The thresholds that the proposed and final rules use to identify a property as at risk of being shut-in are not exclusively volume-based. The new name recognizes that the thresholds are actually based on production volume and other economic considerations, including commodity price, fixed and variable operating costs, and taxes.
Specifically, under both the proposed and final rules, the BLM can approve commingling in two circumstances relating to economics of well operations: (1) When a prudent operator, for economic reasons, would plug a well or shut-in the lease, unit PA, or CA instead of spending the money to achieve non-commingled measurement of production; or (2) When the capital expenditure on equipment necessary to achieve non-commingled measurement of production would exceed the net present value of projected Federal or Indian royalty over the life of the new equipment. The BLM captured both of these circumstances in the definition of a “low-volume property” in the proposed rule, and carried that structure into the final rule's definition of an “economically marginal property.”
Under the final rule, a lease, unit PA, or CA qualifies as an “economically marginal property”:
(1) “If the operator demonstrates that the expected revenue generated from crude oil or nature gas production volumes on that property (above the operating costs associated with those production activities) is not sufficient to cover the nominal costs of the capital expenditures required to achieve measurement of non-commingled production of oil or gas from that property over a payout period of 18 months,” or
(2) If the operator demonstrates that “its royalty net present value, or the discounted value of the Federal or Indian royalties collected on revenue earned from crude oil or natural gas production on the lease, unit PA, or CA over the expected life of the equipment that would need to be installed to achieve non-commingled measurement volumes, is less than the capital cost of purchasing and installing this equipment.”
The final rule takes a somewhat different approach than the proposed rule to define these two circumstances. Specifically, the final rule:
• Changes the threshold for what qualifies as an economically marginal property from a 10 percent, before tax, rate of return in the proposed rule to an 18-month, after-tax, payout period in the final rule;
• States explicitly that the economic analysis considers operating costs;
• Clarifies that the analyses for oil and gas commodities are done separately, based on the income streams from the commodity and the expenses required to achieve non-commingled measurement of that commodity; and
• States explicitly that if economic circumstances change, and a Federal or Indian lease, unit PA, or CA ceases to be an economically marginal property, the lease, unit PA, or CA will no longer qualify for a CAA.
The BLM changed the first economic threshold test from a 10 percent, before tax, rate of return in the proposed rule to an 18-month, after-tax, payout in the final rule, primarily based on comments received. As explained in the preamble to the proposed rule, the initial test was developed based on the provisions of Instruction Memorandum (IM) 2013-152. The purpose of the economic analysis in IM 2013-152, the proposed rule, and the final rule is to simulate the analysis that a prudent operator would make in deciding whether or not to invest money to achieve non-commingled measurement of production. If that analysis concludes that it would be uneconomic for the operator to make the investment and they would instead opt to shut in the property, then the BLM will grant commingling approval. In these situations, the BLM believes that it is in the public interest to sustain production by allowing commingling, even if commingled measurement may be somewhat less accurate and hard to verify than non-commingled measurement.
The only question is how best to identify the point at which a prudent operator would choose to shut in rather than invest in equipment to achieve non-commingled measurement. Several commenters said the proposed 10 percent rate-of-return cutoff point (calculated before Federal, State, and local taxes) was too low, and that the BLM, should instead use a 20 percent rate of return. Other commenters recommended replacing the 10 percent rate of return threshold with a payout period. The BLM agrees with the commenters who recommended that the BLM use a payout period method rather than a rate-of-return method, because the former provides a simpler and more objective picture of whether a particular course of action is economically viable, and it is a method commonly used by industry.
Under the rate-of-return method in the proposed rule, the BLM would have had to assume a rate of return on initial investment that would be sufficient for a prudent operator to install metering equipment to achieve non-commingled measurement of a lease, unit PA, or CA. The payout method used in the final rule uses a formula to determine whether the production volumes at that lease, unit PA, or CA are sufficient to generate enough net revenue, after taxes and operating costs, to cover the nominal cost of equipment installation within the payout period. Additionally it was clear from the comments received that different companies apply different rates of return to evaluate their investments. For these reasons, the BLM felt it was appropriate to replace the rate-of-return method with the payout method.
One commenter stated that industry typically uses a payout period of 6 months to 18 months as the criterion for deciding whether or not to invest in a new project. The commenter went on to state that a 15 percent rate of return (before tax) yields approximately the same result as a 22-month payout. An 18-month payout would be approximately the same as a 20 percent (before tax) rate of return, which is a threshold suggested by several commenters. Based on these comments, the BLM believes that an 18-month payout period is reasonably representative of the threshold a prudent operator would use to determine the economic viability of achieving non-commingled measurement of production.
Additionally, there were a few comments that recommended that the
Also unlike the proposed definition of “low-volume property,” the definition of “economically marginal property” in the final rule specifically considers taxes, fixed and variable operating costs, and commodity prices. While the “low-volume property” definition in the proposed rule implicitly included operating costs and commodity prices in the rate-of-return calculation, it did not include taxes. The BLM believes that the addition of taxes and the explicit addition of operating costs and commodity price considerations help to make the payout calculation more representative of an economic analysis that a prudent operator would perform.
Finally, in the final rule definition, the BLM clarified that the economic analyses are specific to the commodity to which the commingling request applies. For example, if a lease produces a high volume of gas with small amounts of associated condensate, and the operator wishes to commingle the condensate production with similar volumes of condensate produced from private leases, the economic analysis performed under § 3173.14(b)(1) would only consider the income, costs, and payout period related to measuring the condensate. The BLM made this addition to the final rule to clarify that neither operators nor BLM field offices should include the income and costs from a commodity which the operator is not proposing to commingle. The proposed rule was silent on whether the economic analysis should be based on total oil and gas production or just on the commodity the operator requests for commingling. However, it was always the BLM's intent that this analysis occur on the basis of the commodity for which commingled measurement is proposed. This clarification in the final rule is consistent with that intent.
In support of the new definition for “economically marginal property” the BLM added two additional definitions—“payout period” and “royalty net present value (RNPV)”—each of which is discussed (in alphabetical order) below.
In addition, in the final rule the BLM added a definition for the term “free water.” That term appeared multiple times in the proposed rule but was not defined because the BLM believes it is commonly understood by the industry. While the BLM did not receive any comments on the use of this term, the BLM determined that it should nevertheless include a definition in the final rule to clarify its intent with respect to the use of the term in this regulation. The final rule therefore defines “free water” as “the measured volume of water that is present in a container and that is not in suspension in the contained liquid at observed temperature.” This definition tracks the commonly understood definition of the term used routinely by industry and the BLM.
The final rule modifies the definition of the term “land description” from the proposed rule in § 3173.1, to clarify the information needed by the BLM. The purpose of defining the term “land description” in both the proposed and final rules is to ensure that the geographic location information that operators occasionally provide to the BLM meets the applicable standards.
Under the proposed rule, the BLM defined “land description” to mean “the geographical coordinates referenced to the National Spatial Reference System, North American Datum 1983 or latest edition, in feet and direction from the nearest two adjacent section lines, or, if not within the Rectangular Survey System, the nearest two adjacent property lines, generated from the BLM's current Geographic Coordinate database (Public Land Survey System).” The final rule modifies this definition to require operators to provide information about location that is consistent with the U.S. Department of the Interior's
As noted in the discussion above, to support the implementation of the definition of “economically marginal property” the BLM added a definition for the term “payout period,” which is defined as “the time required, in months, for the cost of an investment in an oil or gas FMP at a specific lease, unit PA, or CA to equal the nominal revenue earned from crude oil production for an oil FMP, or natural gas production for a gas FMP, minus taxes, royalties, and any operating and variable costs.” This definition is consistent with the intent behind the definition of “economically marginal property” established by this final rule. The definition clarifies that payout periods are determined independently for each oil and gas FMP at a given lease, unit PA, or CA.
The BLM included a definition for the term “permanent measurement facility” to the final rule in response to a commenter's concern with § 3173.12(d) of the proposed rule, which required operators to obtain FMP approval before any production leaves a measurement facility. The commenter pointed out that during well testing, and before initiating production, operators send oil to a temporary tank or send gas down the sales line to determine the well's production rate. The test results help the operator determine the size and type of measurement facility needed. The commenter said it would be overly burdensome to require operators to obtain FMP approvals for temporary measurement equipment used during well testing as well as for permanent measurement facilities.
The BLM agrees in part with this comment and has provided a definition for the term “permanent measurement facility,” which means “all equipment constructed or installed and used on-site for 6 months or longer for the purpose of determining the quantity, quality, or storage of production that meets the definition of FMP under § 3170.3.” In addition, the final rule also
The BLM added a definition of “royalty net present value (RNPV)” to support implementation of the term “economically marginal property.” The final rule defines RNPV as the “net present value of all Federal or Indian royalties paid on revenue earned from crude oil production or natural gas production from an oil or gas FMP at a given lease, unit PA, or CA over the expected life of the metering equipment that must be installed for that lease, unit PA, or CA to achieve non-commingled measurement.” This definition is consistent with the intent behind the definition of “economically marginal property” established by this final rule.
The BLM also received comments concerning its use of the term “royalty-free use.” Specifically, a commenter expressed concern that the terms “beneficial use” and “royalty-free use” were used interchangeably multiple times in the preamble discussion of the proposed rule, without any definitions being offered for either term. The commenter also noted that only the term “royalty-free use” was used in the proposed rule itself, and no definition was provided. The commenter suggested a definition of “royalty-free uses,” which specifically included all equipment and facilities serving directionally or horizontally drilled wells that may be located off the lease.
The BLM agrees with the commenter that it should not have used the two terms interchangeably. The BLM should have used the term “royalty-free use” rather than “beneficial use,” because the former is more specific and more applicable in the context of this rule. For example, the term “beneficial use” sometimes refers to using produced water for other purposes, such as a water source for livestock or for enhancing vegetation regrowth during reclamation, both of which have nothing to do with production verification and accountability.
The BLM did not, however, feel it was necessary to provide a definition for royalty-free use at this time. First, the royalty-free use of oil or gas from onshore Federal and Indian leases, units, and CAs is governed by the longstanding Notice to Lessees and Operators 4A (NTL-4A) and the BLM believes the concept to be well understood by operators. Second, the BLM plans to update its regulations pertaining to the royalty-free use of oil and gas as part of a separate rulemaking—Waste Prevention, Production Subject to Royalties, and Resource Conservation (81 FR 6616) (Waste Prevention Rule)—that will provide additional clarity on the royalty-free use of oil and gas from onshore Federal and Indian leases. Until such time as the Waste Prevention Rule is finalized, for the purpose of this final rule, the meaning of the term “royalty-free use of oil and gas” will be consistent with the royalty-free use of oil or gas as currently defined in NTL-4A. No changes were made to proposed rule in response to this comment.
Paragraphs (a) and (b) of § 3173.2 require any lines entering or leaving any oil storage tank or storage facility to have valves capable of being effectively sealed during specific operational phases—production, sales, water draining, or hot oiling.
Paragraph (c) identifies the specific types of valves that are not considered “appropriate valves” (
Paragraph (d) prohibits tampering with an “appropriate valve,” and specifies that tampering may result in assessment of civil penalties for knowingly or willfully preparing, maintaining, or submitting false, inaccurate, or misleading information under Section 109(d)(1) of FOGRMA, 30 U.S.C. 1719(d)(1), and 43 CFR 3163.2(f)(1), or for knowingly or willfully taking, removing, transporting, using, or diverting oil or gas from a lease site without valid legal authority under Section 109(d)(2) of FOGRMA, 30 U.S.C. 1719(d)(2), and 43 CFR 3163.2(f)(2).
The BLM received many comments on proposed § 3173.2. Several commenters expressed concern with the relationship between the general prohibition against tampering under § 3170.4 of the proposed rule and the specific prohibition against tampering with any appropriate valve under proposed paragraph (d) of this section.
One commenter, in particular, was concerned that under the new requirements the commenter would not be able to perform maintenance on valves without the procedure being considered tampering or unauthorized seal removal. Two other commenters stated that the criteria for determining what qualifies as tampering were overbroad and ambiguous. They also questioned if an unintentional act or human error would be considered tampering.
The BLM believes these comments have merit and, as discussed previously, has added a definition of the term “tampering” to § 3170.3 of the final rule. As previously noted, “tampering” means any deliberate adjustment or alteration to the meter or measurement device, appropriate valve, or measurement processes that could introduce bias into the measurement or affect the BLM's ability to independently verify volumes or qualities reported. This definition should help the public understand how the BLM will determine whether a particular incident constitutes tampering.
As for operator maintenance on valves, such acts will not be considered tampering as long as the maintenance work does not alter the valve or introduce bias into the measurement. If the valve being worked on falls under the seal requirements (
Another commenter stated that valves would need to be changed out in response to the requirements under this section, making marginal wells unprofitable. The BLM does not believe that any valves will need to be changed
Another commenter was concerned that proposed § 3173.2(c)(3), which exempts valves on tanks that contain oil that the AO or authorized representative (AR) has determined to be waste or slop, would impose additional costs on operators because of the time it could take the AO or AR to make the determination. While waiting for the AO or AR determination, the commenter said, operators would have to spend money on additional tanks to store their slop or waste oil. The BLM disagrees. This requirement is very similar to the existing requirements of Order 3, and therefore will not impose any additional burdens on operators. A company will not need a new tank while waiting for a determination from the AO or AR; rather the company will have to properly seal any tanks holding such oil until it is determined to be slop oil or waste oil. The cost to obtain a seal should not present any sort of monetary hardship for the operator. Thus, the BLM did not make any changes in response to this comment.
Section 3173.3 of the final rule identifies a nonexclusive list of the components used in LACT meters or Coriolis oil measurement systems (CMS) that must be effectively sealed to indicate whether tampering may have occurred. The BLM received a few comments on this section of the proposed rule.
One commenter stated that the proposed seal requirements are much more extensive than those in Order 3 and will create additional burden and expense for the operator because seals routinely break and the seal-reporting requirements for these instances under § 3173.9 are fairly detailed. In addition, the commenter said there is a risk of delayed revenue while the operator waits for the AO to approve removal of a seal. The BLM disagrees that the seal requirements are much more extensive than those found in Order 3. This final rule adds only four items to the Order 3 list of components that are used for quantity or quality determination of oil and that must therefore be effectively sealed. Those four additional components are the right-angle drive, totalizer, prover connections, and valves on diverter lines larger than 1 inch in nominal diameter. The BLM does not believe seal requirements for these components are particularly burdensome, and, since they all are points where tampering could occur, it is important that they be subject to the same sealing requirements as other components of the measurement system.
As for the commenter's concern about revenue being delayed while an operator waits for the AO to approve removal of a seal—under normal circumstances, there is no need to wait for AO approval to remove a seal. Seals may be taken off and put back on as long as these events are recorded in the seal record. In the event a Federal seal is placed on a component, the AO must provide approval prior to any removal; however, an AO can provide verbal approval to remove a Federal seal as soon as the associated violation is corrected. These comments did not result in any changes to the final rule.
One commenter said they could not determine what effect proposed § 3173.3 would have on their operations when related requirements—contained in the rulemaking that is replacing Order 4 (oil measurement)—had not yet published or been made available for public comment. The additional requirements cross referenced in proposed § 3173.3 can be found in proposed 43 CFR 3174.8(a) (for LACT systems) and proposed 43 CFR 3174.9(e) (for Coriolis systems). The BLM recognized the need for both sets of requirements to be available for public comment at the same time, which is why the comment period for this proposed rule was extended from its original September 11, 2015, closure date until December 14, 2015, in order to ensure there was sufficient overlap between the comment periods for the proposed rules for subparts 3173, 3174, and 3175. This overlap gave operators an opportunity to review the parts of proposed subpart 3174 that were referenced in § 3173.3. This comment did not result in any changes to the final rule.
Another commenter said that the seal requirements for oil measurement systems are only appropriate at those points where theft or mishandling can realistically occur, and the requirements under this section are unnecessary. The commenter suggested that the BLM maintain the seal requirements in Order 3, which address the sealing of tanks when oil is sold through a LACT. The BLM did not make a change in response to this comment. The BLM does not believe that theft or mishandling, which affects only the quantity of the oil being measured, are the only factors that may impact the determination of royalties owed. The quality of the oil being produced will also influence royalty determination. For this reason, the BLM believes it is necessary to have a section in the rule dedicated to ensuring that all components of an oil measurement system that are used to determine the quality and quantity of oil must be effectively sealed. The BLM does agree with the commenter's suggestion that we maintain Order 3's seal requirements, which is why they were incorporated into the list of components that must be sealed under § 3173.3 of this final rule.
The BLM also received several comments stating that some components of a LACT are not capable of being sealed, such as flow computers and back pressure valves. The commenters said flow computers are not capable of accepting a seal and back-pressure valves cannot operate if they are sealed. These commenters recommended that the BLM not subject these two components to the § 3173.3 sealing requirements. A third commenter stated, without providing specifics, that some of the devices listed in this proposed section are not constructed to be sealed. The commenter suggested that sealable components would have to be purchased or a secondary device would have to be built to allow for sealing. Without more specific information, the BLM cannot address this comment. However, prior to issuing this final rule, the BLM re-assessed the components listed in this section and continues to believe, except as noted below, that all of the identified components can reasonably be sealed, as all of them are routinely sealed today.
With regards to requiring flow computers to follow this final rule's seal requirements, commenters should be aware that the intent of sealing the flow computer is to have a log of when someone accesses the software. Sealing a flow computer could be accomplished through a lead wire seal, adhesive backed paper (sticker), or plastic seal, or a password and an event log. However, in response to this comment, the BLM has changed the final rule. The BLM removed flow computers from paragraph (a)(5) of this section and added a new item to the list—LACT or CMS—in paragraph (a)(6), giving the operator the opportunity to decide how best to ensure that the flow computer is sealed. As a result of these changes, paragraphs § 3173.3(a)(6) through (12) in the proposed rule are redesignated as § 3173.3(a)(7) through (13) in the final rule.
As for concerns raised about the inability to seal back-pressure valves, the BLM has made a change in response to this comment. In 3173.3(a)(7) of the
In the final rule, paragraph (a) of § 3173.4 codifies the authority in section IV of Order 3, which calls for the BLM to place a Federal seal on any appropriate valve, sealing device, or oil meter system component that does not comply with the requirements of final §§ 3173.2 or 3173.3. Paragraph (b) clarifies that the placement of a Federal seal does not relieve the operator of the requirement to comply with §§ 3713.2 or 3173.3. Paragraph (c) prohibits the removal of a Federal seal without BLM approval.
The BLM received several comments requesting that Federal seals not be attached immediately upon discovery of a violation that warrants placement of a seal. Two commenters requested a 10-day notice prior to the BLM placing a Federal seal, and another commenter requested that a reasonable time be given to bring the component into compliance prior to the BLM attaching a Federal seal. Other commenters said the BLM should not be sealing or changing valves or any other production components without an operator's representative being present to witness the change. Commenters recommended that the BLM give notice to the operator as to why the seal was placed, and the procedure for removing the seal.
The BLM did not change the final rule in response to these comments because the only violations that would cause the BLM to place a Federal seal on valves or production equipment would be those that are considered major, as defined in 43 CFR 3160.0-5—that is, noncompliance actions that could cause or threaten immediate, substantial, and adverse impacts on health and safety, the environment, production accountability, or royalty income. Since the seal requirements in §§ 3173.2 or 3173.3 of this final rule were put in place to ensure that tampering does not occur, the BLM generally believes these incidents of noncompliance constitute major violations.
However, the BLM believes that some of the commenters' concerns have merit, and will ensure that its Inspection and Enforcement Handbook provides clear guidance to BLM inspectors that: They must not change the position of a valve or component; the Federal seal must be attached to the valve or component as found; and each Federal seal installed must have a card attached that identifies it as a Federal seal, and advises that the removal or violation of the seal without approval by the AO will result in an immediate assessment of $1,000. The name and telephone number of the AO will be shown on the card. In addition, the operator will also receive notice in the form of an INC that will address all the violations associated with the Federal seal that the operator must correct prior to removal of the seal. The BLM did not make any changes to the final rule in response to this comment.
Section 3173.5, paragraphs (a) and (b), of the final rule make clear that, at the completion of either a single or a multiple truckload sale, the driver of the load(s) must possess all the information that is required in § 3174.12. Under paragraph (c), once the seals are broken, the purchaser or transporter is responsible for the entire contents of a tank until it is resealed.
The BLM received a comment asking us to delay this final rule until we publish and make available for public comment two related rulemakings that will replace Orders 4 (subpart 3174) and 5 (subpart 3175). The commenter noted that § 3173.5(a) and (b) require truck drivers to possess certain information after oil sales, but the information will be set forth in § 3174.12, which was proposed in the separate Order 4. The BLM recognizes the commenter's concern, at least as it relates to the proposed rule to replace Order 4, which is why the comment period for this proposed rule was extended from its original September 11, 2015, closure date until December 14, 2015, to ensure there was sufficient overlap between the comment periods for the proposed rules for subparts 3173, 3174, and 3175. This overlap gave operators an opportunity to review the parts of proposed subpart 3174 that were referenced in § 3173.5. This comment did not result in any changes to the final rule.
Several commenters expressed concern with language in paragraph (c) that makes the purchaser or transporter responsible for the entire contents of the oil tank from the time that the seals are broken until it is resealed. The requirements in paragraph (c) are taken directly from Order 3 with one minor modification. Under section III.C.1.c of Order 3, only the “purchaser” is responsible for the entire contents of the unsealed tank during a sale. The commenters stated that § 3173.5(c) would be a burden on transporters because it will cost them time and money to wait on-site for tanks to be resealed by the facility's operator after an oil sale. The BLM disagrees with this comment. It is standard practice for transporters, whether or not they are the purchasers, to remove and replace seals without the operator's representative being on location. Transporters do this because it protects them from liability if, subsequently, produced oil cannot be accounted for. No changes were made to the final rule as a result of this comment.
Section 3173.6 of the final rule requires the operator, purchaser, or transporter, as appropriate, to record specific information when water is drained from tanks that hold hydrocarbons, including the total observed volume (TOV) and free water that are in the tank before, and TOV after, water is drained. Order 3 did not require operators to record these volumes, which could have led to hydrocarbons being drained with the water and removed without proper measurement and accounting, and without royalties being paid.
The BLM received many comments regarding this section. Several commenters stated that the documentation requirements were excessive and added little to no value to accounting for production. The BLM made several changes in response to these comments, to reduce documentation requirements and eliminate any confusion over when operators should document the FMP number during water-draining operations. Specifically, the BLM reduced the overall amount of information that operators must document by eliminating from this section the requirements that operators record the opening and closing gauge times, the name of the person and company draining the tank, and the FMP number associated with the tank.
Another commenter questioned whether the requirement to identify the FMP associated with a tank subject to this provision would mean that an FMP is required for each condensate tank in the field. By way of clarification, condensate tanks, just like oil storage tanks, must have FMP numbers.
Another commenter recommended that the BLM exempt “low-volume sources” from the requirements, to reduce the paperwork and record-maintenance costs for operators of such sources. The BLM does not believe that an exemption for small producers (or operators of low-volume sources) is appropriate and did not change the final rule as a result of this comment. As noted earlier, it is important for all operators to ensure that hydrocarbons are not being drained with the water and removed without proper measurement and accounting, and without the royalties due being paid. Having operators record the volume of hydrocarbons that are in the tank before and after water is drained helps ensure that the proper royalties are paid. When performing production accountability inspections, the BLM will compare these water-draining records, along with other production and sales records, with production reports that operators submit to ONRR. These records will allow the BLM to independently verify production that is attributable to Federal and Indian leases. The BLM did not make any changes in response to this comment.
One commenter said the existing Order 3 seal requirements already prevent theft of oil because they provide a tracking mechanism for the transfer of any liquids from production tanks, and therefore the provisions of the proposed rule were unnecessary. The BLM disagrees that Order 3's seal requirements already prevent theft of oil. Existing requirements related to seal records do not provide any information on how much TOV is in a tank before and after water is drained. They merely show when a tank is sealed and unsealed, and by whom, not what was drained, nor how much was removed from the tank. No changes were made to the final rule as a result of this comment.
Other commenters stated that § 3173.6 would require the gauging of tanks prior to and after a sale. They said that while such a practice is necessary during custody transfer, this requirement could be hazardous to employees because it would unnecessarily expose them to benzene or volatile organic compounds (VOC). In response to these comments, the BLM added new language to paragraphs (e) and (g) that allows either manual or automatic gauging for the opening and closing gauge, TOV, and free-water measurements, all of which must be to the nearest
Finally, one commenter said the color-cut measurement method requirement in the proposed rule is not accurate for indicating water oil contact with heavy oils that are less than 30 degrees gravity. The commenter said that an opening and closing gauge would be a sufficient indicator to determine the amount of water in the tank. The BLM agrees with the comment that color-cut measurements are not accurate in some situations and has removed this requirement from the final rule. Instead, paragraph (e) has been rewritten to require operators to simply document “free-water measurements,” which allows operators to use any reliable method for measuring free water, including electronic equipment.
Section 3173.7(a) of the final rule requires that specific information be recorded when hydrocarbons are removed from storage and used on the lease, unit PA, or CA for hot oiling, clean-up, and completion operations, including the volume of hydrocarbons removed from storage and expected to be returned to storage. Paragraph (b) requires operators to consider as sold, and to measure following the requirements of this final rule, any production used from storage for hot oiling, line flushing, or completion operations on a different lease, unit PA, or CA.
Under Order 3, the operator was required to record only the date, seal number removed, new seal number installed, and the reason for removing oil for hot-oiling, clean-up, or completion operations. The operator was not required to record the volume of hydrocarbons that was removed from storage and were expected to be returned. This omission could have led to the volume of produced hydrocarbons being counted twice—first when it was initially produced then later after it was returned to storage.
The BLM received many comments on this requirement. A few commenters said that an operator's field personnel are on hand, closely monitoring these types of operations, ensuring that the oil is returned to the tank and that it is counted just once. Commenters said there is no reason for the BLM to require operators to maintain records of these volumes because operators only pay royalties on oil that is sold, not oil that is produced, and hot-oiling, clean-up, and completion operations are unrelated to sales. The BLM agrees that having an operator's field personnel on hand, closely monitoring these operations, is ideal for ensuring that oil is not counted twice during these operations. However, the BLM's experience has shown that in many instances field personnel do not monitor these operations because they are called away for other duties. The BLM did not change the final rule in response to this comment, because the BLM believes there is a need to address inconsistent practices among operators and to ensure there is proper documentation of the volume of oil used in these operations.
In response to the comment that hot oiling, clean-up, and completion operations have nothing to do with sales volumes, the BLM notes that it is required to verify not only sales volumes but also production volumes and to report on avoidably lost gas under NTL-4A. Hot oiling, clean-up, and completion all involve production volumes, and therefore are properly within the scope of the proposed rule.
Another commenter said the BLM does not have the authority to impose the requirements under this section, requested that the BLM explain why these new requirements are necessary, and asked that we provide the legal citation for the new law that justifies this authority. The BLM's authority to impose site-security, record-keeping, and production accountability requirements for the production of Federal and Indian oil and gas is not “new.” The statutes authorizing the BLM to issue this rule have been in place for decades and were identified earlier in this preamble. These statutes include the ones that were identified as the basis for existing Order 3.
A few commenters said that the requirement that operators gauge oil level, maintain seals, track FMPs, gauge tanks, etc., during completion operations will add to the workload of field personnel performing those tasks. For example, an employee will need to be onsite 24 hours a day, 7 days a week to make sure the seal changes are recorded on the run tickets and logged properly for tracking purposes. Several commenters said the documentation requirements under this section were excessive and added little to no value to production accounting.
The BLM agrees with these commenters that the proposed documentation requirements were too expansive and in response changed the final rule to reduce the amount of information that operators must document during hot oiling, clean-up, and completion operations. In the final rule, the BLM removed requirements
With respect to the general concern that these requirements are unnecessary, the BLM does not agree. These requirements are important and represent an important part of the final rule, because in their absence, operators could drain, transfer, or sell hydrocarbons without measuring and accounting for them during hot oiling, clean-up, and completion operations, resulting in incorrect royalties being paid. The BLM will use these records when performing production accountability inspections. Specifically, it will compare records from hot oiling, clean-up and completion operations, and other production and sales records, with reports that operators submit to ONRR. This will allow the BLM to independently verify production that is attributable to Federal and Indian leases.
As for the commenter's claim that these recordkeeping requirements for well completion operations would necessitate an operator's field personnel to be present at the wellsite 24/7, the BLM does not have enough information to respond to this comment. While the BLM agrees that, in general, operators will now have to document more information than they have been documenting under Order 3, the BLM does not believe that any of these additional recordkeeping requirements will require company personnel to be onsite 24/7. The final rule was not changed as a result of this comment.
The BLM did not receive any comments on paragraph (b). However, the BLM makes a clarification in the final rule that the production reported to ONRR as sold must be “for the period covering the production in question.”
Section 3173.8 of the final rule includes security provisions that are intended to prevent theft or mishandling of oil, complementing the minimum standards for site security and production handling established in this rule. Paragraph (a) requires operators, transporters, and purchasers to report verbally all incidents of theft and mishandling of production to the BLM no later than the next business day after they or their employees discover them. Paragraph (b) specifies the information that must be included in a written incident report, which is required within 10 business days of any oral report. Such reports must be made the next business day after discovery and may be made orally or through a “written incident report.” Oral reports must be followed by written reports within 10 business days. Adding purchasers and transporters to these requirements is a change from Order 3, which required only operators to report theft or production mishandling, but is consistent with the overall approach to these requirements in the proposed and final rules.
Many commenters were concerned about the requirement in paragraph (a) that purchasers and transporters report incidents of theft and mishandling to the BLM, and questioned the BLM's authority to impose such a requirement on them. Since the wells and facilities belong to the operator, commenters said, the operator should be the one reporting all theft and production mishandling. The commenters said it would be redundant and unnecessary to have purchasers and transporters reporting theft and mishandling to the BLM, and could lead to multiple reports and confusion. A few commenters added that this change could make operators accountable for potentially arbitrary and inaccurate third-party reports of theft or production mishandling.
Finally, some commenters asked why operators could be subject to an immediate assessment when they fail to report theft or mishandling to the BLM.
The BLM believes it is necessary to require purchaser and transporters, in addition to operators, to report instances of theft or production mishandling when they discover them because, as noted in the proposed rule preamble, purchases and transporters are sometimes the first to discover such instances or to recognize suspicious activity. When transporters or purchasers report theft or production mishandling, the BLM intends to work with transporters, purchasers, and operators to verify the reports, with each party being responsible for the information it provides. The BLM's authority to require purchasers and transporters to report theft or production mishandling comes from Section 103(a) of FOGRMA, which provides that “a lessee, operator, or other person directly involved in developing, producing, transporting, purchasing, or selling oil or gas . . . shall establish and maintain any records, make any reports, and provide any information that the Secretary may, by rule, reasonably require for the purposes of implementing this Act or determining compliance with rules or orders under this Act.” Sections 102(b)(2) and 301(a) of FOGRMA allow the BLM to prescribe any rules, regulations, or appropriate measures to protect oil from theft. The final rule simply places the same expectations on purchasers, transporters, and operators, which are all parties involved in production, for reporting theft and mishandling of production.
The BLM does not agree that requiring purchasers and transporters to report theft and production mishandling creates confusion or is redundant and unnecessary. Reports by purchasers and transporters, together with information provided by operators, will improve the existing reporting system by giving the BLM more facts faster to investigate these situations. No changes were made to the final rule as a result of these comments.
Other commenters discussing the provisions of the proposed rule related to theft or mishandling did not agree with the BLM's decision to eliminate the self-inspection requirements contained in Order 3 section III.F, which are related to Order 3's requirements for reporting theft or mishandling of oil. The purpose of the self-inspection requirement, according to those commenters, was for operators to periodically measure production volumes to assure that they complied with the BLM's minimum site security requirements. These commenters said that self-inspection programs are a good practice, and that it would not be appropriate for the BLM to find an operator in violation of this section if they elect to implement a self-inspection program and report incidences of theft and mishandling. The commenters encouraged the BLM to maintain the Order 3 requirements for a self-inspection compliance program, rather than eliminate them.
It has been impractical for the BLM to enforce the Order 3 self-inspection requirements because the requirements were vague, and the BLM never supplemented them with internal guidance or enforcement policy. This final rule replaces the Order 3 self-inspection program with stronger recordkeeping and documentation requirements, such as those in § 3173.9 (Required recordkeeping for inventory and seal records). As explained in the recordkeeping section of this preamble, we believe this approach will ultimately improve overall production verification and accountability. That said, the BLM
As for the commenters' suggestion that the BLM not issue immediate assessments or take enforcement actions against those operators who are implementing a self-inspection program, the BLM does not agree with this suggestion. The BLM takes enforcement actions against operators that fail to report theft or production mishandling. The fact that an operator has a self-inspection plan in place does not and should not immunize the operator from enforcement for a failure to report. Under the final rule, consistent with the proposed rule, an operator that fails to report is subject to an immediate assessment under § 3173.29 (Immediate Assessments) of the final rule. No change was made in response to this comment.
Finally, a number of commenters suggested that the BLM should be told whether incidents of theft or production mishandling have also been reported to law enforcement and company security in addition to the BLM. The BLM agrees that it needs to know if law enforcement and company security have been notified and added a new paragraph (b)(8), which now includes this requirement. This change will help the BLM work with company security and law enforcement to investigate and prosecute alleged incidents of theft and production mishandling in order to prevent future occurrences.
Paragraph (a) of this section of the final rule requires operators to perform an end-of-month inventory consisting of the TOV in storage (measured to the nearest
The BLM received several comments on proposed § 3173.9. In the proposed rule, operators were simply required to measure and record the TOV in storage at the end of each calendar month. A few commenters said they did not have the ability to measure inventory at all sites on the actual last day of the month due to the number of tanks they operate, the volume corrections for temperature/S&W, and the accuracy needed to meet the measurement standards of this section.
The BLM agrees that operators may not be able to measure all inventory on the very last day of the month, especially those operators who have large numbers of storage tanks. In response, the final rule provides two options for an operator to perform an end-of-month inventory. The operator can either perform the measurements within +/−3 days of the end of the month, or it can interpolate the values based on daily production values and gross sales volumes, using inventory measurements taken before and after the final day of the month. To help guide operators on the interpolation of their end-of-month inventories, the BLM provides the following equation in paragraph (b)(2) of this section, as well as an example of how the equation is to be applied:
Other commenters interpreted the proposed section to mean that operators were required to gauge their storage tanks manually, since at the time the proposed rule was released the BLM's oil measurement regulations did not allow operators to use automatic tank gauging systems. As a result, these commenters asserted that requiring operators to manually gauge tanks would unnecessarily expose their employees to hazardous fumes. The BLM understands this concern and has added clarifying language to the final rule that allows operators to measure TOV either manually or with automated systems. The BLM was able to make this change because in the related rulemaking that is replacing Order 4 with a new subpart 3174, operators now have the ability to use automatic tank gauging systems for oil sales, and thus such a system will also be permissible for inventory maintenance.
Other commenters said this section was not necessary because recording the TOV in tanks is routine practice under sales contracts, and the seal requirements in paragraph (b) of this section are unnecessary because they are already covered in §§ 3173.2 and 3173.3 of the proposed rules. With respect to those comments stating that recording the tank TOV is routine operator practice under sales contracts, it should be noted that those recordkeeping activities relate to periodic tank sales. Those records do not allow the BLM or the operator to determine monthly production or to detect theft or improper handling of production like an end-of-month inventory does. Additionally, operators are already required to report end-of-month inventories to ONRR so this requirement should not create an additional burden for operators. The BLM did not change the final rule in response to this comment.
With respect to the concerns about paragraph (b), the BLM disagrees that the seal recordkeeping requirements are already covered in §§ 3173.2 and 3173.3. Those two sections only identify which valves or components must be sealed. They do not address the recordkeeping requirements associated with such seals. The BLM did not change the final rule in response to this comment.
Finally, some commenters asserted that paragraph (b) should not apply to purchasers and transporters because they are not responsible for installing or maintaining such seals. The BLM agrees that § 3173.9, particularly paragraph (b), does not apply to purchasers and transporters. However, the BLM did not change the rule in response to this comment because the text in § 3173.9 makes clear that its requirements apply solely to operators.
Section 3173.10, paragraphs (a) and (b), require all parties involved in Federal and Indian oil and gas production to submit Sundry Notices, Form 3160-5, electronically to the BLM for their site facility diagrams, requests for FMP designations, requests for CAAs, requests for off-lease measurement, and any amendments to the diagrams or requests. As noted in the preamble of the proposed rule, requiring electronic submission will, in the long run, increase efficiencies throughout BLM field offices, for both the BLM and operators, by making the diagrams easier to track and more accessible to inspectors in the field. Paragraph (b) provides an exemption from the electronic-filing requirement
Several commenters supported the proposed requirements for online filing, but were concerned with the BLM's ability to handle a significant increase in electronic submissions “at one time,” and wanted the BLM to clarify what it means when it says that this change will, in the long run, increase BLM efficiencies. Some of these same commenters said they were concerned with the ability of the BLM's existing WIS to handle this volume of submissions.
Requiring electronic submission of Sundry Notices and Reports on wells provides both operators and the BLM with an efficient chronological method for tracking items submitted for approval, rather than relying on hard copies. The BLM is aware that the Well Information System has had problems in the past, and is working on an improved version of its in-house database, known as AFMSS II. As part of its transition to AFMSS II, the BLM is evaluating industry information technology standards, such as XML, to develop a system that will make data sharing and management as seamless as possible between the BLM and the public. That said, even the existing system should not prevent the BLM from realizing the benefits of electronic filing of facility diagrams.
One of the reasons the proposed rule gave operators a phase-in period to apply for an FMP on existing leases, units, and CAs was to help the BLM avoid having to process a flood of Sundry Notices at one time. Under the proposed rule, operators would have applied for their FMP numbers over a 9- to 27-month period, starting on the effective date of the final rule, on a tiered scheduled based on production level, with the highest producing wells having the earliest required application date. As discussed later in this preamble, the final rule extends the phase-in periods for the FMP application process to 12, 24, and 36 months, based on production level thresholds that are similar to those in the proposed rule. This will give some operators up to 3 years after the effective date of this final rule to apply for an FMP for stand-alone leases, CAs, unit PAs and CAAs. If a stand-alone lease, unit PA, or CA has not produced for a year or more before the effective date of this final rule, the operator will not need to apply for an FMP until resuming production. The BLM believes that these changes will substantially reduce the number of electronic filings the BLM must process at any one time, reducing the risk that its systems lack the capacity to handle the submissions.
Similarly, and as explained below in connection with § 3173.11(d) and (e), the BLM has also modified the proposed rule's requirements for updated site facility diagrams. Instead of requiring all facilities to upgrade their diagrams with 30 days of receiving an FMP, as was suggested in the proposed rule, under the final rule site facility diagrams at existing facilities will only have to be updated when or if the existing facility is modified (
Some commenters wanted to know if the BLM will send out electronic notifications when it approves Sundry Notices that have been filed electronically. The BLM will provide such notifications, just as it does now as part of its new APD system.
One commenter suggested that the BLM use off-the-shelf software common to industry to handle its electronic data submissions, saying it would reduce reporting costs to industry since these programs are already used industry-wide. The BLM disagrees because the BLM already has an existing e-filing system up and running, and operators are already familiar with using it. This system allows operators to see the status of their submissions and provides them an electronic response of the AO's decision. The AFMSS II update builds on this existing infrastructure. The BLM did not change this final rule as a result of these comments.
As discussed in the proposed rule, the requirements in § 3171.11 update and replace Order 3's Site Facility Diagram requirements, which are currently found in section III.I. Paragraphs (a) through (c) of § 3171.11 set forth the requirements for the content and format of site facility diagrams, while Appendix A to subpart 3173 provides some basic examples of what these diagrams should look like.
Under § 3173.11(a) through (c), a site facility diagrams must include, in addition to drawings that show the relative locations of equipment, specific information, such as FMP numbers; the land description; unit PA, or CA numbers; site equipment; and royalty-free use information. Site facility diagrams are one of the BLM's primary mechanisms for ensuring that operators are complying with measurement regulations and policy, which is why it is important that accurate diagrams are submitted to the BLM in a timely manner.
As explained in the preamble to the proposed rule, under Order 3 the BLM required operators to provide generalized diagrams showing each piece of equipment being used at a facility, including connections between each piece of equipment, valve positions on production storage tanks (sales valves, drain valves, equalizers, and overflow valves), and their relative positions to each other. While these diagrams were useful to the BLM, they did not provide all of the information necessary for inspection and enforcement activities. The more detailed information required by this final rule will provide the BLM with a more useful tool to achieve improved production accountability.
For example, the requirement in paragraph (c)(9) of this final rule (paragraph (c)(10) in the proposed rule) will allow the BLM, for the first time, to verify royalty-free-use volumes that operators report on their OGORs. This paragraph requires operators to specify on their site facility diagrams which equipment on the lease is using oil or gas royalty-free and how they determine the volumes of oil or gas used by that equipment, if the volume is not measured. This requirement will provide greater consistency in how operators determine the volumes of oil and gas used royalty-free, and will enable the BLM to more easily verify those volumes, which enhances production accountability. This particular change also responds to the GAO recommendations (Report 10-313) that the BLM establish uniform systems for collecting and tracking information about royalty-free use in order to ensure that such use can be properly verified. Affirmatively requiring this information to be reported on a site facility diagram will ultimately save the BLM and operator time because it will eliminate the need for the BLM to obtain the information in connection with a production accountability review.
Paragraph (d) sets forth the timeframe within which facilities that are required to obtain an FMP under § 3173.12 must submit a site facility diagram that complies with this rule. It covers both existing and new facilities. Paragraph (d)(1) in this final rule (paragraph (c)(1) in the proposed rule) requires operators, whose facilities become operational on or after the effective date of this rule to submit their diagrams within 30 days after the BLM assigns their FMP. For operators of existing facilities that were in operation on or before the effective
Paragraph (e) sets forth the timeframe within which facilities that do not require FMP numbers under § 3173.12 (
Paragraph (f) explains that operators of facilities required to have a site facility diagram have an ongoing obligation to update those diagrams within 30 days after the operator modifies its facilities, constructs or modifies a non-Federal facility located on the Federal lease or federally approved unit or communitized area, or if there is a change in operator.
The BLM received many comments on this section of the proposed rule. One commenter suggested that the BLM develop a database that allows operators to submit the information needed for site facility diagrams using a standard form. The commenter said any changes to a site facility diagram, along with other information, could be automatically and periodically submitted by operators, thus making the process of submitting and updating diagram information to the BLM effortless. The BLM recognizes the potential efficiencies provided by the commenter, but did not make any changes at this time because the BLM's WIS—which follows the Sundry Notice format—is currently the only method for electronic submission. At this time, that system does not allow for submission along the lines suggested by the commenter. As result, the BLM will accept electronic records that contain the requested information on additional pages as long as they are submitted with the actual diagram on Form 3160-5 (Sundry Notices) and they follow the prescribed numbering format. The BLM did not change the final rule based on this comment.
Many commenters expressed concern that application of the proposed rule's site facility diagram requirements to existing facilities is unnecessary, and that the deadlines in the proposed rule for submitting the diagrams would be onerous. These commenters also said the demands in this section are so burdensome that they would cause operators to reconsider future development plans, after having invested money in complying with previous regulations.
Although the BLM believes the new site facility diagrams for existing facilities, including those that handle waste water, will allow the BLM to improve production accountability, the BLM also believes that commenters' concerns with the deadlines for submitting the new diagrams have merit. In response to these comments, and in an effort to reduce the number of diagrams that operators must initially submit to the BLM, we have revised paragraph (d)(2) (formerly paragraph (d) in the proposed rule) and added a new paragraph (e)(2) to the final rule which specifies that operators of existing facilities are not initially required to submit updated site diagrams, so long as they have a diagram on file that complies with the requirements of Order 3. As noted, these paragraphs require updates to existing diagrams only when facilities undergo changes. The BLM believes that this change addresses the identified concern, while ensuring that as these existing facilities undergo changes the agency will eventually receive site facility diagrams that meet the requirements of § 3173.11. Although the existing site-facility diagrams are not as detailed, the BLM will continue to work off the diagrams that it has on file to perform its production accountability-related inspections on existing facilities, until such time as those diagrams are updated.
Other commenters questioned why it was necessary to provide a diagram for salt-water disposal facilities because, they said, these facilities are unrelated to actual oil and gas production operations. The BLM does not agree with this commenter. These diagrams are not a new requirement. Operators are already required to have site facility diagrams on file with the BLM for their water-disposal facilities; Order 3.III.I.1. requires diagrams for “all facilities.” The BLM is responsible for accounting for all production, including water, not just oil and gas. No changes were made to the final rule as a result of these comments.
A few comments sought clarification on how to legibly depict multiple wells and headers, encompassing an area several miles in size, on a single sheet of 8
One commenter said the valve-positioning and labeling requirements in paragraph (c) and the examples in the Appendix would result in operators putting redundant information on the diagrams when multiple tanks, with similar valves that are operated similarly, are involved. The BLM did not make a change in response to this comment. The BLM cannot create a single template that addresses how all site facility diagrams, for a myriad of field configurations, should be drawn. The Appendix examples are meant to be a starting point for operators. It is up to the operator to determine how best to identify valve positioning on paper, as long as the valves and their positions are identified, legible, and comprehensible as required in § 3173.11.
The BLM received several comments on the requirement in paragraph (c)(9) of the final rule (paragraph (c)(10) of the proposed rule) that operators identify on their diagrams any equipment that uses production royalty-free, and either the calculated or measured volumes that are used. Under the final rule, operators are permitted to use any method they want to determine their royalty-free use volume, as long as they show on the diagram how they determined it.
Several commenters pointed out that royalty-free fuel use fluctuates monthly, and one commenter even provided its method for determining “on lease use fuel gas.” The commenter recommended
A few commenters questioned the BLM's rationale for creating the new site-facility-diagram requirement, while eliminating the Order 3 requirement for site security plans, which some operators had established. The BLM agrees that these two requirements are related. The site-facility diagram was part of the larger site-security plan required in Order 3. As discussed earlier in this preamble, the Order 3 site-security plan's self-inspection requirements are not in the final rule. However, elements of the old site security plan requirements have been incorporated into this final rule at §§ 3170.4 (Prohibitions against by-pass and tampering), 3173.8 (Report of theft or mishandling of production), 3173.9 (Required recordkeeping for inventory and seal records), and 3173.11 (Site facility diagrams); and into the final rule that is replacing Order 4 at 43 CFR 3174.12 (Measurement tickets).
Many commenters questioned the need for operators to provide information and documentation on their site facility diagrams, as required under proposed § 3173.11, for what they consider to be extraneous equipment and components. Commenters offered to work with the BLM to create a pragmatic approach for allowing the BLM to verify royalty-free volumes and for operators to submit their diagrams within a sensible time. However, as proposed, many commenters saw this section as unnecessary and unreasonable overreach by the BLM, and a drain on resources for both operators and the agency, especially given that operators would need to track information on multiple components on numerous pieces of equipment across several locations. For example, one commenter did not understand how putting equipment serial numbers, rated fuel use, and manufacturer information on a site facility diagram would help the BLM verify whether a reasonable determination was made on royalty-free use volumes reported to ONRR. Depending on their configuration, production facilities can have an extensive number of major components, and requiring operators to track down this information and report it on their diagrams would cause a hardship on many operators, commenters said.
Another commenter disagreed with the requirement in proposed paragraph (c)(11) that an operator or its representative include a signed certification statement on the diagram. This requirement is redundant and unnecessary, the commenter said, because existing statutes—18 U.S.C. 1001 and 43 U.S.C. 1212—already make it a crime for any person to knowingly and willfully make a false statement to the BLM.
The BLM agrees with these comments and in response has made changes to the final rule that reduce the information that must be submitted and expand the timeframe within which the submission must occur, including deleting paragraph (c)(11). The final rule will not require operators to include a signed certification statement as part of their site facility diagrams, because, as noted by a commenter, operators are responsible by law for ensuring the accuracy of the information in their diagrams. In response to comments questioning the requirement in paragraph (c)(10)(i) of the proposed rule, which directed operators to provide equipment serial numbers, rated fuel use, and manufacturer information on their site-facility diagrams, the BLM removed this requirement in paragraph (c)(10)(i) of the proposed rule from the final rule because the information, although useful in verifying whether equipment had been replaced, would not help the BLM verify that the royalty-free-use volumes reported to ONRR were accurate.
One commenter said that the requirement in paragraph (a), that operators submit a site facility diagram for each FMP, is cumbersome, particularly in cases where the FMP for oil facilities and gas facilities are on the same site. The commenter recommended that the BLM require a single FMP number for an entire facility at a single site in order make it simpler for operators, while providing the necessary information to the BLM. The BLM disagrees with this comment because the BLM's inspection verification process is based, in large part, on comparing production information that is reported to ONRR against information contained in a site facility diagram, and operators report their oil and gas production separately to ONRR. Having information on both types of facilities on one diagram could complicate and undermine the BLM's verification process. No change has been made to the rule based on this comment.
Many commenters were also very concerned with the cost to operators to comply with the proposed diagram requirement, particularly the costs of re-submitting all site facility diagrams within the proposed rule's 30-day submission deadline. However, as discussed above and in greater detail in the Economic and Threshold Analysis, the final rule greatly scales back the range of circumstances in which operators of existing operations must submit new site-facility diagrams. This reduces the number of diagrams that must be prepared and the amount of information that operators need to provide on those diagrams, which will significantly reduce compliance costs. The BLM estimated in the proposed rule that it would take operators 8 hours to prepare and submit a revised diagram. The BLM now believes that with the reduced workload, operators can perform this task in 6 hours. The BLM originally estimated in the proposed rule that operators would submit revised diagrams for 125,000 existing facilities over a 27-month phase-in period. After taking a more detailed look at our computer data, the BLM has revised downward its estimate of the number of existing facilities to 83,116. The BLM now estimates under this final rule's revised requirements that only 5 percent of existing facilities, or about 4,165 facilities, do not have accurate and up-to-date site facility diagrams on file with the BLM and will have to submit revised diagrams to the BLM over the 3-year phase-in period. The BLM now estimates that the total one-time cost to industry to submit revised site facility diagrams will be $1.6 million, spread over 3 years, down from the BLM's previous estimate in the proposed rule of $63.6 million. On an ongoing basis, the BLM estimates operators will submit about 5,000 new diagrams per year for a total annual cost to the regulated community of $1.9 million.
Other commenters said they were physically limited—by the sizes of their staff and facilities—from submitting site facility diagrams for multiple existing
The BLM agrees that operators need more time to submit diagrams for new and existing facilities, and made corresponding changes to the final rule. The commenter misstated the requirement of the proposed rule, which would have required operators to submit their diagrams much earlier—within 30 days of completing construction of their facilities. Under the final rule, operators will need to submit diagrams for new facilities (those that become operational on or after the effective date of this final rule) within 30 days after the BLM assigns an FMP to those facilities. The BLM believes these changes ensures that it will not receive a site facility diagram for a new facility prior to having assigned that facility an FMP number, which means operators will not have to go back and subsequently revise their diagrams to reflect the new FMP numbers. As discussed earlier, under the final rule, operators of existing facilities that already have site facility diagrams on file with the BLM that meet the requirements of Order 3 do not have to revise those diagrams unless they modify their facilities or there is a change in operator.
Finally, one commenter was concerned about having to submit and resubmit multiple site facility diagrams for a facility with multiple FMPs, if the FMPs were not approved within 30 days of each other. The commenter said compliance would be impossible under these circumstances. The BLM believes that this commenter was trying to describe a well pad with multiple wells that are coming in to production consecutively. In this case, the FMP numbers will not change, but a new site-facility diagram will be required within 30 days from the onset of production from each well to reflect the new facility coming online. The BLM did not change the final rule in response to this comment. With respect to the commenter's concern about facilities having multiple FMPs, for the most part, facilities will have no more than two FMPs—one for oil and one for gas. Even though the applications for each FMP number will be submitted under a separate Sundry Notices, there is no reason an operator could not submit them at the same time, nor for the BLM to assign the FMP numbers at different times, as it is unlikely that the measurement system for oil would come online later than the measurement system for gas.
Section 3173.12 of the final rule establishes a formal nationwide process for designating and approving the point at which oil or gas must be measured for the purpose of determining royalty. Prior to this final rule, the BLM did not have a formal, written process for designating measurement points on the leases it manages. While some Field Offices had their own internal policies for establishing these points, this lack of uniform guidance across Field Offices resulted in instances of confusion about the location of royalty measurement points, which interfered with the BLM's production verification process. This section now requires operators to obtain BLM approval of FMPs for all measurement points used to determine royalties.
The BLM will approve an FMP that meets the requirements of this final rule (the most important elements of which are the identification of the wells associated with the FMP and the measurement method). The BLM will assign each FMP a unique identifying number, which the operator, transporter, or purchaser will use when reporting production results to ONRR. Each FMP number will be 11 digits long. The first two digits (ranging from 52 to 99) will identify the product—oil or gas—as well as other information, such as whether the FMP is on-lease or off-lease, whether it is part of a commingling arrangement, and the measurement method used at the FMP—tank gauge, LACT, Coriolis, etc. The next 5 digits will represent the American Petroleum Institute (API) state and county code, while the last 4 digits will be a combination of letters or numbers that will make each FMP number unique.
The BSEE already assigns similar FMP numbers for the offshore oil and gas leases that it manages, which the operator, transporter, or purchaser must then use when reporting production results to ONRR. The changes in this final rule will make BLM practices consistent with existing BSEE and ONRR practices for production reporting.
Paragraph (a)(1) of this final section provides that, unless otherwise approved, the FMPs for all Federal or Indian leases, unit PAs, or CAs must be located within the boundaries of the lease, unit PA, or communitized area from which the production originated, and must measure only production from that lease, unit PA, or communitized area, unless otherwise approved. Paragraph (a)(2) provides that off-lease measurement or commingling and allocation of production requires prior approval under 43 CFR 3162.7-2 and 3162.7-3, and §§ 3173.15, 3173.16, 3173.24, and 3173.25 of this final rule.
Paragraph (b) provides that the BLM will not approve a meter at the tailgate of a gas processing plant located off the lease, unit, or communitized area as an FMP. This paragraph codifies existing BLM practice with respect to tailgate meters.
Paragraph (c) provides that the operator must submit separate applications for approval of separate FMP numbers for a measurement point that measures oil produced from a particular lease, unit PA, CA, or pursuant to an approved CAA, and a measurement point that measures gas produced from the same lease, unit PA, or CA, or pursuant to an approved CAA. The requirements for a separate FMP apply even if the measurement equipment or facilities are at the same location. As discussed earlier, the first two numbers in the FMP number specify whether the FMP measures oil or gas. The BLM will not approve the same FMP number for a facility that measures oil and a facility that measures gas.
Paragraph (d) requires the operator to apply for approval of an FMP for a new permanent measurement facility (
Paragraph (e) provides that for existing permanent production measurement facilities, an operator has 1 year, 2 years or 3 years from the effective date of the final rule within which to apply for BLM approval of its FMP, depending on the production level of the lease, unit PA, or CA that the
1. Under paragraph (e)(1), operators of stand-alone leases, unit PAs, or CAs, which produce 10,000 Mcf or more of gas per month, or 100 bbl or more of oil per month must, apply for FMP approval within 1 year after the effective date of the final rule.
2. Paragraph (e)(2) requires operators of stand-alone leases, unit PAs, or CAs, which produce 1,500 Mcf or more but less than 10,000 Mcf of gas per month, or 10 bbl or more but less than 100 bbl of oil per month, to apply for FMP approval within 2 years after the effective date of the final rule.
3. Paragraph (e)(3) requires operators of stand-alone leases, unit PAs, or CAs that produce less than 1,500 Mcf of gas per month, or less than 10 bbl of oil per month, to apply for FMP approval within 3 years after the effective date of the final rule.
To determine which category a facility is in, the final rule requires the facility to calculate average production over the 12 months preceding the effective date of the final rule, or over the period the lease, unit, CA, or CAA has been in production, whichever is shorter.
Paragraph (e)(4) explains that if a stand-alone lease, unit PA, or CA has not produced for a year or more before the effective date of this final rule, the operator is not required to apply for an FMP immediately, but rather need only apply prior to resuming production. Under paragraph (e)(6), if an operator applies for FMP approval by the date, the operator may continue to use the lease, unit PA, or CA number for reporting production to ONRR while the application is pending, until the effective date of the BLM-assigned FMP number, at which point the operator must use the FMP number for such reporting. If, however, an operator fails to apply for an FMP approval by the date required by the final rule, paragraph (e)(7) explains that the operator will be subject to an incident of noncompliance and may also be subject to an assessment of civil penalty under 43 CFR subpart 3163, together with any other remedy available under applicable law or regulation.
Paragraph (f) identifies the information that a request for FMP approval must include. Under paragraph (f)(1), FMP requests must be submitted on a Sundry Notice and include information pertaining to the equipment that will be used to measure the oil and gas. Paragraph (f)(2) requires the applicable Measurement Type Code specified in WIS. Paragraph (f)(3) requires information about the equipment used for oil and gas measurement: (i) For gas measurement, specify unique station number, primary element (meter tube) size or serial number, and type of secondary device (mechanical or electronic); (ii) For oil measurement by tank gauge, specify oil tank number or tank serial number and size in barrels or gallons for all tanks associated with measurement at an FMP; and (iii) For oil measurement by LACT or CMS, specify whether the equipment is LACT or CMS and the associated oil tank number or tank serial number and size in barrels or gallons (there may be more than one tank associated with an FMP). Paragraph (f)(4) requires operators to include a list of the API well numbers that will flow to the requested FMP if that FMP will serve more than one well, and provide a land description for the FMP location. Under paragraph (f)(5), the FMP location by land description must also be included in the FMP application.
As explained below, the BLM in the final rule has also reduced the quantity of information that operators must submit on their FMP number applications. For consistency with § 3173.10(c)(10)(i), the BLM removed requirements that operators provide component names, manufacturer, model, serial number, range limits for electronic flow computers, transducer (static, differential, and temperature), chart recorders, LACT totalizer, and Coriolis meter from § 3173.12(f)(3)(i), (ii), (iii), (iv) and combined subparagraphs (iii) and (iv) into (iii).
Paragraph (g) allows concurrent requests for FMP approval and for approval of off-lease measurement or commingling and allocation.
Section 3173.12 is a key element of the final rule as it implements one of the GAO's central recommendations: That the Interior Department consistently track where and how oil and gas are measured, including information about meter location, identification number, and owner. By requiring operators to obtain approval from the BLM for the location of the FMP at which oil or gas is measured, the final rule provides that consistent tracking. The BLM will also now tie the FMP numbers to other appropriate approvals and documentation that are part of its production verification and accountability efforts, such as site facility diagrams, off-lease measurement approvals, commingling approvals, and royalty-free use (if volumes used royalty-free are measured).
In the final rule, operators, purchasers, and transporters must include on all records the FMP number or until the BLM approves the FMP number, the lease, unit PA, or CA number, along with a unique equipment identifier and the name of the company that created the record.
The BLM estimates there are approximately 83,116 existing oil and gas facilities associated with Federal and Indian leases. Many facilities have one FMP for oil and one FMP for gas for a total of approximately 166,232 FMPs for existing facilities.
In connection with its creation of the new FMP system in § 3173.12, the BLM has also revised its existing well and facility identification provisions at 43 CFR 3162.6(b) and (c) to include a signage requirement for wells on Federal or Indian lands and facilities at which Federal or Indian oil or gas is measured or processed. Additional revisions to § 3162.6 include: (1) Making the surveyed-location language in paragraphs (b) and (c) consistent, including a new reference to longitude and latitude; and (2) Removing a sentence in paragraph (b) that provided a grace period for well signs that were in existence on the effective date of the rulemaking in which that section was first promulgated.
The BLM received a comment requesting that the definition of an FMP in § 3173.1 include more details on how to obtain an FMP, the deadlines for operators to obtain an FMP, and the economic impacts that the FMP requirement would have on industry. The BLM disagrees with this commenter. Section 3173.12 of this final rule provides all of the information requested by the commenter related to requests to apply for an FMP. It addresses the deadlines—which are based on average production volumes—for operators to submit FMP applications for facilities that are in service on or before the effective date of this rule, or that will come into service after the effective date. It also specifies
A number of commenters were concerned that they could not meet the proposed rule's deadlines in § 3173.12(e) for applying for and then receiving an FMP number before producing oil and gas. They said the resources needed to prepare FMP applications would be exorbitant, especially for large producers that have many thousands of wells, many of which will likely have associated commingling or off-lease measurement approvals that the BLM will need to review (see discussion of § 3173.16 below).
Many commenters also complained about the proposed tiered volume thresholds that figured into the timelines for filing FMP applications. Many operators said that most of their wells' production levels would require them to submit their FMP applications within 9 months of the final rule's effective date. Commenters said such timeframes would be unreasonably short for operators with large well inventories, considering that they would also be required to submit new site facility diagrams and possibly update existing commingling and off-lease measurement approvals.
Under the proposed rule, operators would have had to submit their FMP application within:
• Twenty seven months from the effective date of the final rule for leases, unit PAs, and CAs that produced less than 3,000 thousand cubic feet (Mcf) of gas or 20 bbl of oil per month;
• Eighteen months from the effective date of the final rule for leases, unit PAs, and CAs that produced between 3,000 and 6,000 Mcf of gas or 20 and 40 bbl of oil per month; and
• Nine months from the effective date of the final rule for leases, unit PAs, and CAs that produced over 6,000 Mcf of gas or 40 bbl of oil per month.
The BLM agrees with commenters that the proposed deadlines were too tight. In response, the BLM changed the final rule to give operators additional time to submit FMP applications for facilities that are in service before the effective date of the final rule. The amount of additional time is based on the facility's average reported monthly oil and gas production volumes over the previous 12 months. When establishing the new thresholds, the BLM analyzed lease production data in AFMSS to determine the impacts on all currently producing leases. In setting the FMP application deadlines, the BLM attempted to spread the impact evenly across the three timeframes and across all BLM-administered leases.
As discussed previously, the final rule also allows operators to continue to produce oil and gas while their FMP applications are pending BLM approval, provided that those applications are submitted within the deadlines specified in § 3173.12(e). While waiting for their FMP approvals, operators may continue to use the lease, unit PA, or CA numbers that they have been using for reporting their production to ONRR. These changes should make it easier for operators to meet the final rule's FMP application deadlines and give them more time to plan and budget for this new requirement, while continuing their production operations. As explained in connection with § 3173.11(d) and (e), this final rule removes the proposed rule's requirement that all existing facilities submit updated site facility diagrams within 30 days of approval of an FMP, further reducing requirements on existing facilities.
In addition, as discussed previously, the BLM changed the final rule to eliminate some of the information required in the FMP applications (
A number of commenters also expressed concern that the BLM would not have been able to handle the number of FMP applications that the agency would have received under the proposed rule's timeline and requirements. However, the BLM now anticipates having a much smaller workload, spread more evenly over time. For one thing, a review of AFMSS data suggests that there are only 83,116 active facilities affected by this rule—about 25 percent fewer than the BLM had estimated in analyzing the proposed rule. In addition, the final rule requires operators to provide less information on their FMP applications and site facility diagrams than the proposed rule would have required. We now estimate that it will take BLM staff 2 hours to process each FMP application, instead of the 4 hours we anticipated under the proposed rule's information requirements. Additionally, because of the provisions allowing continued production and reporting while an FMP application is pending, operators should no longer be concerned about potential FMP application backlogs.
Several commenters said they were concerned about delays in the FMP approval process holding them up from putting new wells online and removing production from the lease. The proposed rule at § 3173.12(d) required operators to “obtain” FMP approval for measurement facilities that came into service after the rule's effective date before they could begin removing production from a lease, unit PA, CA, or CAA. The BLM agrees that proposed paragraph (d) needed to be changed to avoid production delays on new facilities. To address these concerns, the BLM has made several changes to paragraph (d) in the final rule. First, the BLM added language to the section to clarify that operators must apply for FMP approvals for permanent measurement facilities only—not temporary test facilities—as defined in § 3173.1 of this final rule. In addition, the BLM added language to paragraph (d) that requires operators of new facilities to simply “apply for” FMP approval before any production leaves the permanent measurement facility. This change allows operators to install a new measurement facility, remove production from that facility without delay, and use the lease, unit PA, or CA number for production reporting to ONRR until the BLM assigned an FMP number, as long as they apply for their FMP approval before any production leaves that permanent facility. While the applications are pending, operators may continue using their lease, unit PA, or CA number for reporting production to ONRR.
One commenter thought the BLM should allow operators to file one application on the facility as a whole, and not be required to submit one application for oil and another for gas. The BLM did not revise the rule as a result of this comment. One of the purposes of an FMP is to be able to consistently verify where and how oil or gas is measured. The BLM does this by comparing information that operators report to the BLM against information operators report to ONRR, which does, in fact, collect the oil and gas production information separately. Using one FMP number to track oil and gas measurement operations together would compromise the BLM's ability to consistently verify production
Finally, one commenter said that BLM staff should be given a deadline for approving FMPs, since it is not fair to hold operators to multiple deadlines, making them subject to INCs for missing those deadlines, while not holding the BLM to the same standard. As discussed above, the BLM's new FMP approval process will not interfere with operators' production. Once operators file a timely request for an FMP approval on existing facilities, they may continue to operate and use their lease, unit PA, or CA number for reporting production to ONRR until the BLM assigns an FMP number.
Once an FMP number is assigned to a facility, § 3173.13(a) of this final rule gives the operator several months before it must use the FMP number when reporting production to ONRR. Specifically, for existing facilities, the operator will have to begin using the FMP number for reporting production to ONRR on its OGOR for the fourth production month after the FMP number is assigned. For facilities that come into service after the effective date of this final rule, operators are required to apply for FMP approval before any production leaves the permanent measurement facility and then use the FMP number for reporting production to ONRR on its OGOR for the first production month after the FMP number is assigned. As result of these changes, we do not believe deadlines for BLM review are necessary or appropriate.
Section 3173.13 of the final rule sets forth the requirements that are applicable to all approved FMPs. Paragraph (a) requires the operator of an existing facility to use assigned FMP numbers in reporting production to ONRR on its OGORs for the fourth production month after an FMP is assigned. For new facilities in service after the effective date of this rule, paragraph (a) requires the operator to begin using its assigned FMP numbers on its OGORs for the first production month after the FMP number is assigned.
Paragraph (b) requires an operator to file, within 30 days after any changes or modifications to an approved FMP, a Sundry Notice notifying the BLM of the change. It also describes the information that operators must provide to the BLM in the Sundry Notice, including any changes or modifications to the equipment that is used for measuring oil or gas at the FMP, or to the API well numbers associated with the FMP.
The BLM received several comments on this section of the proposed rule. Unlike the final rule, the proposed rule required operators to use their FMP numbers for both recordkeeping purposes and production reporting to ONRR beginning on the first day of the month after the FMP number was assigned. A few commenters said they needed more time to start using the number for production reporting and recordkeeping because an FMP could be issued on the last day of the month, thereby obligating the operator to use the FMP on the next day. The commenters said that this would not give them enough time to take the steps they need to comply with FMP requirements, such as stenciling the FMP number onto equipment, labeling all records with the FMP number, and making updates to their existing database systems that track oil and gas production operations.
The BLM agrees that requiring operators to begin using their FMP numbers for recordkeeping and production reporting on the first day of the month after the FMP number is assigned may not be possible for some operators. As discussed earlier, the BLM changed § 3170.7(g) from requiring operators to use FMP numbers on all records, to allowing operators to use either FMP numbers or lease, unit PA, or CA numbers, along with unique equipment identifiers, on their records. In addition, the BLM changed final § 3173.13(a) to extend the effective date that operators of existing facilities are required to begin using their FMP numbers in production reporting to ONRR. Under the final § 3173.13(a), operators must start using FMP numbers for reporting production to ONRR on their OGORs for the fourth production month after the FMP number is assigned. For example, if the BLM assigns an existing facility an FMP number on January 17, the operator must begin using that FMP number on its May production OGORs. Because ONRR requires operators to submit their electronic reports “on the 15th day of the second month following the production month being reported,” the May production report must be submitted by July 15, effectively giving the operator 5-
For new facilities, operators will be required to begin using their FMP numbers in reporting production to ONRR on their OGORs for the first production month after the FMP number is assigned. For example, if the BLM assigns the FMP number on April 30, the operator must begin using that FMP number for its May production. As noted, however, the May production report is not due to ONRR until July 15, effectively giving the operator 2-
Some commenters asked why proposed § 3173.13(d) required operators to submit a Sundry Notice detailing “any” modifications they make to an approved FMP and why the changes were made. Commenters said the BLM does not need this information. The BLM agrees that it does not need to know why a change was made and has removed this requirement from the final rule. However, the BLM does need to know when operators change out measurement equipment at an approved FMP, along with specific information about the replacement equipment, and when they add or remove wells served by an FMP, along with the associated API well numbers. The BLM needs this information so that it can keep track of these types of changes, which directly impact the BLM's efforts to verify production. In addition, the BLM has provided some additional context, by clarifying that it does not need to be notified when temporary modifications (
The BLM received several comments on the requirement in proposed § 3173.13(a) that operators stamp or stencil FMP numbers on specific pieces of equipment within 30 days after an FMP number assignment. Commenters said this requirement was too expensive and would take too much time. Several commenters recommended that the BLM, instead, cross-reference the FMP number to a unique meter station identifier supplied by the operator, such as the meter station number, LACT ID number, or tank number, all of which are already available and visible to BLM inspectors. The BLM agrees that the
The BLM changed the final rule at § 3173.12(f) to require operators, when they apply for a gas FMP number, to identify the royalty measurement point by specifying a unique station number; primary element (meter tube) size or serial number; type of secondary device (mechanical or electronic); and associated API well numbers where production from more than one well will flow to the requested FMP; along with a land description of the FMP's location. On an oil FMP number application, operators must supply the tank number or tank serial number and size in barrels or gallons; specify whether LACT or CMS, if applicable; associated API well numbers where production from more than one well will flow to the requested FMP; along with a land description of the FMP's location.
One commenter said operators should be exempt from the requirement that they file a Sundry Notice when they temporarily modify an FMP due to changing out equipment for maintenance. The commenter said the replacement equipment, using the same measurement methodology, would not impact accuracy. The BLM agrees that operators do not need to notify the BLM when they install temporary replacement equipment while performing maintenance on the permanent equipment. As noted, the final rule clarifies in paragraph (b)(1) that the BLM does not need to be notified when temporary modifications (
Finally, one commenter objected to the requirement in proposed paragraph (b)(2) that operators file a Sundry Notice whenever there is a change in the wells or facilities served by an FMP. This commenter said an operator may need to transfer product to different meters several times a day when the meters freeze during the winter months. The commenter said it would be impossible to maintain a list of the wells going to the FMPs under these conditions. The BLM is not aware of situations where operators direct their gas stream to different sales meters because of line freezing. This practice may be allowed on State and private wells, but, such a transfer is not allowed on Federal and Indian wells. We did not change the final rule as a result of this comment.
As explained in the Definitions section of this preamble, commingling, for production accounting and reporting purposes, means the “combining, before the point of royalty measurement, production from more than one lease, unit PA, or CA, or production from one or more leases, unit PAs, or CAs with production from State, local governmental, or private properties that are outside the boundaries of those leases, unit Pas, or CAs.” Operators apply for commingling approval for several reasons, including:
(1) It can simplify accounting to have the sales point be the same as the point of royalty measurement;
(2) Lower operating costs can be achieved by reducing the number of meters required (such as when well testing is an appropriate allocation method); and
(3) Lower operating costs can also be achieved by eliminating the need for separate plumbing and surface equipment (pipelines, separators, dehydrators, compressors, tanks, etc.).
Commingling can also have some advantages for the BLM:
(1) More accurate measurement can sometimes be achieved from a meter measuring combined flows, which can be better-conditioned and, more consistent, and have higher flow rates, than from a single low-volume meter measuring erratic flow with a higher potential for multiple phases of fluid;
(2) The environmental footprint can be reduced by reducing the need for duplicate surface equipment; and
(3) Production accounting can be simplified by reducing the number of meters to inspect and verify.
However, in many situations the advantages of commingling are offset by increased measurement uncertainty, increased potential for measurement bias, and a decrease in the BLM's ability to verify reported production volumes. This is especially true if the properties proposed for commingling are of different ownership, have different royalty rates, or have different royalty distributions.
As explained below, §§ 3173.14 through 3173.21 of the final rule restrict the instances in which the BLM will approve commingling and establish the standards that an operator must meet to obtain an approval. Existing regulations at 43 CFR 3162.7-2 and 3162.7-3 require BLM approval before operators commingle production from a Federal or Indian lease with production from other sources; however, prior to this rule, there were no regulations addressing how or under what circumstance commingling should be approved. The requirements in this final rule are based on and codify the policy outlined by the BLM with respect to commingling approvals in IM 2013-152 (2013), “Reviewing Requests for Surface and Downhole Commingling of Oil and Gas Produced from Federal and Indian Leases.” The principal difference between the provisions of this rule and the BLM's existing IM is that the final rule establishes a new process for the BLM to review existing CAAs when operators apply for their FMP approvals. In contrast, the IM focused solely on new CAAs. Also, in response to public comment and additional internal reviews, the final rule expands the number of exemptions under which an existing or proposed CAA could be commingled if the CAA does not meet the criteria identified in § 3173.14 (a) of the final rule.
To ensure the accuracy and verifiability of the volume and quality measurements on which royalty is based, § 3173.14(a) states that the BLM “may grant a CAA only if the proposed allocation method used for any such commingled measurement does not have the potential to affect the determination of the total volume or quality of production on which royalty owed is determined for all the Federal or Indian leases, unit PAs, or CAs which are proposed for commingling. . . .” Paragraph (a)(1) goes on to identify the conditions under which this occurs.
The most common situation when this occurs is when all the properties proposed for commingling are 100 percent Federal or leased 100 percent by the same Indian tribe, have the same fixed royalty rate, and have the same revenue distribution. In these situations, the allocation method is irrelevant because the total amount of royalty received by the Federal Government or tribal mineral interest owner will be the same regardless of how it is allocated to the individual leases, unit PAs, or CAs that are part of the CAA. Consequently, the BLM can ensure accurate measurement and proper reporting by inspecting and verifying only the commingled point of royalty measurement (
Based on comments received on the proposed rule and additional internal reviews, the BLM revised paragraph (a) and its subparagraphs as outlined below. In paragraph (a) itself, the BLM added language which explicitly states the criteria the BLM uses to approve a commingling application. Paragraphs (a)(1)(i) and (a)(1)(ii) were retained, with modifications for clarity, from the proposed rule. Those provisions recognize that if the leases, unit PAs, or CAs to be commingled are 100 percent Federal or leased 100 percent by the same Indian tribe, and at the same fixed royalty rate, then commingling is generally acceptable, assuming the other requirements of this part are met. Indian allotted leases are not included under paragraph (a) because there would be virtually no instances where the revenue distribution to the allottees would be identical in different leases, unit PAs, or CAs.
Several commenters suggested that commingling among unit PAs or CAs that have less than 100 percent Federal ownership should be recognized as permissible, so long as they have the same proportion of Federal interest. The BLM agrees with this comment and added paragraph (a)(1)(iii) to allow commingling of Federal unit PAs or CAs where each unit PA or CA proposed for commingling has the same proportion of Federal interest, which is subject to the same fixed royalty rate and revenue distribution. Under this provision, the BLM could approve a commingling request where an operator proposes to commingle two Federal CAs of mixed ownership where both are 50 percent Federal/50 percent private, so long as the Federal interests have the same royalty rates and royalty distributions. The BLM also added a new paragraph (a)(1)(iv), which provides a parallel provision for tribal interests, with the key again being identical percentage of tribal participation and royalty rates.
In paragraph (a)(2) of the final rule, the BLM makes it clear that the operator or group of operators that are part of a CAA must provide the BLM with the allocation methodology for the properties from which production is to be commingled, along with an agreement signed by the operators that are parties to the CAA if there is more than one operator. Paragraphs (a)(3) and (a)(4) remain unchanged from the proposed rule.
Paragraph 3173.14(a)(3) requires operators to demonstrate that each of the leases, unit PAs, or CAs proposed for inclusion in a CAA is producing in paying quantities or, in the case of Federal leases, capable of producing in paying quantities. One commenter asked why the BLM wants to know that wells involved in commingling are capable of production in paying quantities. The purpose of this requirement is to ensure that CAAs are not used to extend the terms of a nonproducing lease, by allocating production to it. The BLM did not change the rule as a result of this comment.
Paragraph (a)(4) requires that the FMP(s) for the proposed CAA measure production originating exclusively from the leases, unit PAs, or communitized areas in the proposed CAA. The BLM received no comments on this provision.
Paragraph (b) of final § 3173.14 sets forth the exceptional circumstances in which the BLM will allow commingling even when the circumstances outlined in paragraph (a) are not met because, for example, there is a combination of Federal and non-Federal ownership, Indian allotted leases are involved, or the Federal or Indian leases have different royalty rates. This paragraph includes the two circumstances given in the proposed rule: Economically marginal properties (called low-volume properties in the proposed rule) and overriding considerations, such as environmental impacts. The final rule also adds three additional circumstances where the BLM can approve commingling:
• When the average monthly production over the preceding 12 months for each Federal or Indian lease, unit PA, or CA proposed for the CAA is less than 1,000 Mcf of gas per month, or 100 bbl of oil per month;
• The CAA has been authorized under tribal law or otherwise approved by a tribe; or
• The CAA covers the downhole commingling of production from multiple formations that are covered by separate leases, CAs, or unit PAs where the BLM has deemed the commingling of these formations to be an acceptable practice for the purpose of achieving maximum ultimate economic recovery and resource conservation.
The BLM received numerous comments on this paragraph in the proposed rule, stating that the exceptions granted in paragraph (b) of the proposed rule were not adequate for surface commingling approvals in cases involving low production volumes. The commenters said that this would result in lost oil and gas production, revenue, and royalties from operators forced to shut-in thousands of wells covered by existing CAAs where surface commingling takes place and where the economics did not justify the cost of installing new metering and measurement equipment. In many of these instances, the commenters stated that production volumes have declined to the point where the revenue from continued operation would not be sufficient to justify installing new measurement equipment, particularly in the current low-price environment.
The BLM disagrees with these comments. The provisions for approving a CAA for economically marginal properties (low-volume properties in the proposed rule) in both the proposed rule and the final rule were designed specifically to allow the BLM to determine if a property would truly be shut in if the only alternative was for the operator to achieve non-commingled measurement of production. The BLM believes many of the worst case scenarios flagged by commenters would fit within the economically marginal property exception. Unlike downhole commingling, the costs for surface commingling are relatively easy to define. An operator on the edge of profitability should be able to demonstrate to the BLM under paragraph (b)(1) that the properties proposed for commingling qualify as economically marginal properties. The commenters did not submit any data to substantiate that the existing provisions under paragraph (b)(1) were inadequate as they relate to surface commingling.
Although the BLM did not make any changes to the rule based on these comments, the BLM changed the economic threshold in the final rule based on comments on the definition of low-volume property in the proposed rule. As discussed in connection with § 3173.1, under the new definition of an economically marginal property, the BLM changed the threshold from a 10 percent before-tax rate of return in the proposed rule to an 18-month after-tax payout in the final rule. The BLM believes this change will increase the number of leases, unit PAs, or CAs that would qualify as economically marginal leases and, therefore, might qualify for a CAA under this paragraph. The BLM does not have any data to quantify this increase, however.
Commenters also expressed concern about the workload and timeframes involved with obtaining a commingling approval under paragraph (b). Because the provisions of paragraph (b)(1) of both the proposed and final rule are very similar to the provisions of IM 2013-152, the BLM has experience with the process of reviewing CAAs for economically marginal properties. Based on its experience processing commingling requests under IM 2013-
As a result, the BLM made two changes in the final rule. The first change was to grandfather any existing surface commingling approval where the average production rate over the previous 12 months for each of the Federal or Indian leases, unit PAs, or CAs included in the approval is less than 100 bbl of oil per month or 1,000 Mcf of gas per month (see § 3173.16(a)(1) and (2)). Second, recognizing that such limited production may also occur in connection with new CAA approvals, § 3173.14(b)(2) now allows the BLM to approve new CAAs if the average production rate from the proposed CAA satisfy the thresholds for grandfathering of existing CAAs. The new CAA would also have to comply with § 3173.14(a)(2) through (4); however, under the final rule, the BLM will not require any additional economic analysis from the operator.
The BLM chose these thresholds because properties producing below these thresholds would almost always qualify as economically marginal properties under this rule. Therefore, the BLM can approve commingling requests that qualify under this paragraph with significantly less paperwork burden on both the BLM and industry, and without the in-depth economic analysis that would have been required in the proposed rule. The BLM chose the oil threshold of 100 bbl per month by assuming the cost of achieving non-commingled measurement of oil would be $50,000 (setting a small oil tank, for example). The production rate required to achieve an 18-month payout of this investment, assuming a $60 per bbl oil price and including taxes, royalty payments, and fixed and variable operating costs, would be about 3.5 bbl per day, or approximately 100 bbl per month.
The BLM used a similar approach for determining the gas threshold. The BLM assumed that an operator would have to invest $20,000 to achieve non-commingled measurement of gas (the cost of installing a new meter). The production rate required to achieve an 18-month payout of this investment, assuming a $3 per MMBtu gas price, and including taxes, royalty payments, and operating costs, would be about 30 Mcf/day, or roughly 1,000 Mcf per month.
The BLM added § 3173.14(b)(3) to the final rule, which provides for CAAs that have been authorized under tribal law or otherwise approved by a tribe. The BLM included this provision in response to tribal comments indicating that tribal law or agreements may independently identify circumstances where commingling is appropriate. The BLM added this provision because it believes that tribes should have a say in approving CAAs that involve production from tribal leases.
The BLM received many comments stating that the exceptions provided in § 3173.14(b) of the proposed rule did not address downhole commingling agreements in the New Mexico portions of the San Juan and Permian Basins and elsewhere that would not meet the requirements § 3173.14(a). The commenters said that this omission would result in lost oil and gas production, revenue, and royalties from operators forced to shut-in thousands of wells at existing CAAs where downhole commingling takes place and where the economics do not justify the cost of drilling additional wells or segregating downhole production. Many of the wells, according to the commenters, were drilled specifically to commingle downhole production from multiple leases, CAs, and unit PAs, including combinations of Federal, Indian, fee, and State ownership. The commenters said downhole commingling allows operators to reduce costs and environmental impacts by reducing the number of wellbores because multiple zones can be produced out of a single wellbore. In addition, commenters stated that some individual zones do not have enough production to justify the drilling and completion costs for separate wells. Other commenters stressed that downhole commingling increases the maximum ultimate economic recovery because reservoir energy from lower formations allows oil and gas from highly-depleted upper formations to be produced (
The BLM agrees with commenters that the exceptions listed in the proposed rule, need to be expanded to account for downhole CAAs, to ensure that improvements in measurement accuracy and the BLM's ability to verify production made by this rule do not unnecessarily result in operators shutting in large numbers of existing wells, particularly during times of low commodity prices. The BLM believes that it is in the public interest to receive royalty on a volume of oil or gas that may have heightened levels of uncertainty and may not be perfectly verifiable by the BLM, rather than receiving no royalty at all if the property is shut in to avoid the cost of achieving uncertainty and verifiability goals.
The low-volume exemption in the proposed rule would have provided an objective measure of the economic viability of a lease, CA, or unit PA, as it relates to downhole commingling. However, this economic test has been difficult to implement for downhole commingling applications under IM 2013-152 because the costs associated with achieving non-commingled downhole production are highly speculative and vary by facility and formations. These costs could be in the millions of dollars if an operator had to drill multiple wells in lieu of downhole commingling in one wellbore. It is also difficult to predict or quantify the benefits of increasing the maximum ultimate economic recovery from a well due to the ability to produce more oil and gas from downhole commingling.
As a result of these comments, the BLM made two changes in the final rule. First, the BLM added an exception for certain categories of downhole commingling under paragraph (b)(4). This new exception allows the BLM to approve downhole commingling of production from multiple leases, CAs, and unit PAs if the BLM deems the proposed operation to be an acceptable practice for the purpose of achieving maximum economic recovery and conservation of the oil and gas resource. This exception provides a means for the BLM to recognize downhole commingling practices that have historically been approved in areas where such practices provide the only way to produce the Federal or Indian interest, and therefore are necessary to avoid having some operators prematurely plug existing wells. The addition of this provision gives Field Offices flexibility to approve downhole commingling requests based on local knowledge and experience with the characteristics of a particular oil or gas reservoir. Second, for existing downhole commingling approvals, the BLM added § 3173.16(a)(1), which will grandfather all downhole commingling approvals in existence prior to the effective date of this rule (see discussion under § 3173.16(a)(1)).
Several commenters said that the final regulations should state clearly how the BLM will balance the Federal interest in royalty measurement against competing interests, such as environmental concerns. One commenter
One commenter stated that the added and unnecessary cost to industry to have to build and maintain separate pipelines and facilities without a substantial benefit for the BLM in return is unreasonable. The commenter said that they have a few wells in a field that are not in the unit, but use the same facilities that service the unit. The commenter is concerned that they would not be able to continue commingling in the future without doing a substantial economic study to quantify the cost to build separate facilities including shipping facilities. Another commenter asked the BLM to consider exempting those properties that are in close proximity to an existing gathering system and allowing production from those properties to be commingled with other properties, even if they are not considered to be low-volume properties.
The BLM disagrees with these comments and did not make any changes to the rule as a result. Allocation methods that affect royalty measurement and reporting have the potential to increase measurement uncertainty, introduce bias, and inhibit the BLM's ability to verify and account for oil and gas production removed or sold from a lease, unit PA, or CA. The exceptions that allow for commingling when allocation methods affect royalty are included in paragraph (b) of the final rule; they cover cases where the requirement to achieve non-commingled measurement of production would cause a prudent operator to shut in production or would cause significant and unavoidable environmental impacts. When demonstrating whether a lease, unit PA, or CA is economically marginal, operators can and should include the cost of building additional gathering lines, any new facilities, and mitigating environmental impacts into their capital cost calculations to see if they would qualify for commingling approval under paragraph (b)(1) of this section. If they do not meet the definition, or any of the other exceptions in paragraph (b) of this section, then the operator should be able to construct the additional facilities while still realizing a reasonable return on that investment, rather than shutting in production from a particular well.
One commenter was concerned that, under the CAA requirements, operators who currently commingle small amounts of saleable liquids produced from gas wells (
One commenter representing Native Alaskan interests said it would not be economically feasible to prevent commingling of production from BLM lands that are within a unit PA that has an existing measurement system approved by all parties, when the BLM lands comprise only a small portion of the production. The BLM did not make any changes to the final rule in response to this comment, for two reasons. First, if the BLM portion of the unit PA is very small or the production is low, it might qualify as an “economically marginal property” under the definition of an economically marginal property in § 3173.1. In this case, the BLM could approve commingling with other unit PAs within the unit or other properties outside of the unit. The BLM may also be able to approve commingling under § 3173.14(b)(5) if achieving non-commingled measurement of production addresses some overriding consideration, such as avoiding undue environmental impacts. If, on the other hand, the properties that are proposed for inclusion in a CAA do not meet the definition of economically marginal properties, do not present some other overriding consideration, such as environmental impacts, or otherwise satisfy one of this rule's criteria, then the BLM will require the operator to achieve non-commingled measurement of that unit PA.
A couple of commenters suggested that the BLM is creating new law by establishing standards and requirements for existing CAAs that were not in Order 3. The BLM does not understand the comment. The purpose of the rulemaking process that the BLM is going through is to establish new standards and requirements. By following the BLM's authorizing statues and the procedures established by the Administrative Procedure Act, 5 U.S.C. 551
Several commenters also said the BLM has not analyzed the impacts of the rule on industry and the BLM, and requested clarification on how the BLM will balance the Federal interest in royalty measurement against competing interests. The BLM disagrees that it has not analyzed the impacts on industry or the BLM. As stated earlier in this preamble, the BLM has rigorously weighed and considered the economic impacts that this final rule will have on industry and prepared draft and final regulatory impact analyses for this rulemaking, which are available to the public. The Procedural Matters section of this preamble contains a short discussion of this rule's potential economic impact on industry. The analysis estimates that this rule's CAA requirements will have a one-time cost to industry of $4.9 million to $7.6 million for operators to submit documentation and respond to the BLM's informational requests for existing leases, and $2.7 million to install meters where the BLM rescinds existing commingling agreements. The analysis also estimates there will be an annual paperwork cost to industry from these provisions of $3 million to $4.6 million for new and modified commingling agreements, and $1.6 million in new annual metering installation costs for those FMPs where a commingling agreement is rescinded.
The BLM believes that the final rule provides clear guidance on how the BLM will balance the Federal interest in accurate measurement with competing interests, such as not causing production to be shut in or creating additional environmental impacts. The final rule includes numerous provisions that allow commingling in cases where the public interest is better served by allowing commingling even if it results in potential negative effects to royalty measurement. These instances include properties that the BLM determines to be economically marginal, properties that produce below set thresholds, situations that involve downhole commingling, and where unnecessary or undue degradation or unavoidable environmental impacts or other overriding considerations would result if commingling were denied. The BLM did not make any changes to the rule based on these comments.
Section 3173.15 of the final rule establishes the requirements operators must follow when requesting a CAA, and the information they need to include. Most of these requirements were in the proposed rule, but the final rule includes changes to the amount and type of information operators must include in their applications. The BLM made these changes in response to many comments it received on this section. The following discussion describes those comments and the changes that were made.
One commenter suggested that proposed paragraph (b) be changed to require operators to submit as part of their CAA applications an allocation method, instead of an allocation schedule, which is subject to frequent changes. The BLM agrees that information about a CAA's allocation method would be more useful, and as a result changed the final rule to require an allocation method instead of a schedule.
Several commenters said they did not believe the BLM has the authority to require operators to submit site facility diagrams as part of new CAA approvals for existing facilities, as required in paragraph (e) of the proposed rule. The BLM agrees that it does not need a site facility diagram to approve a CAA application for existing facilities and has eliminated that requirement in the final rule in response to these comments.
One of the commenters asked about the purpose in § 3173.15(e), for requiring operators to provide a map showing the boundaries, FMPs, and location of wellheads and production facilities as part of their commingling and allocation application. In response, the BLM changed paragraph (e) of the final rule to reduce the amount of information that operators must include in maps submitted as part of CAA applications. The required maps need only show the boundaries of any lease, unit, unit PA, or CA from which production is proposed to be commingled and indicate the locations of existing or planned facilities with the relative location of all wellheads (with API numbers), the piping, and existing or proposed FMPs included as part of the CAA request. The BLM needs this information for several reasons, one of which is to determine if all the production flowing through the proposed FMP originates from the leases, unit PAs, or CAs proposed to be part of the CAA. Another reason is to obtain clarity on what leases, unit PAs, or CAs are actually proposed for commingling. This is especially important when unit PAs or CAs are included in the proposal. In these situations, the location of a well or facility in relation to lease, unit PA, or CA boundaries, is critical for the BLM to understand when evaluating a commingling application. For example, one well may be physically located on a Federal lease but only produce from a CA that covers one of the formations under that lease, while another well on the same lease may only produce from a portion of the lease that is not part of the CA. In this case, the BLM would have to understand that even though both wells are physically located on the same lease, a CAA is required to combine their production because their production originates from different properties. The BLM did not make any changes to the rule based on these comments.
One commenter asked whether the BLM planned to monitor which wells are flowing to which FMP and make operational recommendations. While the BLM has no intention of making operational recommendations, it will monitor which wells are flowing to which FMPs if that affects the CAA or the underlying allocation of production. The BLM did not make any changes to the rule based on these comments.
Several commenters wanted to know why, in § 3173.15(k), submission of up to 6 years of gas analyses, including Btu content and all oil gravities, is required for CAA requests. They indicated that it would be too burdensome for CAA applicants to provide historical crude oil gravity and natural gas heating value data, as only current data is relevant for trying to determine the prices received for these products. A couple of other commenters said this information requirement is excessive and would not improve the quality of the application. The BLM does not believe this to be an onerous requirement. First, 6 years' worth of data would not necessarily include a lot of data, especially for lower producing leases, unit PAs, and CAs for which the BLM would consider approving a CAA. For example, under 43 CFR 3175.100, a very-low-volume FMP (producing 35 Mcf per day or less), is only required to have a gas analysis taken once per year, so 6 years of data for that well is only 6 gas analyses. For oil, the API gravity is only determined when an oil sale takes place. A low-producing oil lease may only have an oil sale several times per year, in which case 6 years of API gravities would include only one or two dozen API gravities. Second, operators should already have this information readily available because they are currently required to maintain records for at least 6 years under 43 CFR 3170.7, which retention period has been increased to 7 years for Federal leases under this rule. One of the reasons the BLM needs historical Btu and API gravities is to
Another commenter noted that this information has no royalty impact if the properties are 100 percent Federal or Indian mineral ownership with the same fixed royalty rate and distribution. The BLM agrees with this comment and added a caveat to § 3173.15(k) indicating that this information is required only if the CAA is not approved under § 3173.14(a)(1).
The BLM also determined it was necessary to make other changes to § 3174.15 in the final rule to address considerations related to the administration of the rule. As part of the final rule, the BLM clarifies in paragraphs (f) through (i) which additional approvals operators must seek if their commingling proposals entail new surface disturbance or take place on Indian lands or on lands administered by other Federal surface management agencies, in case operators are unaware of these requirements. Finally, this section clarifies that if off-lease measurement is part of a commingling and allocation proposal, then a separate Sundry Notice under § 3173.23 is not needed as long as the information required under paragraphs (b) through (e) and, where applicable, paragraphs (f) through (i) of § 3173.23 is included as part of the request for approval for commingling and allocation. This revision clarifies that an applicant may submit both proposals in one Sundry Notice request.
Under § 3173.16 of the final rule, the BLM will review an existing CAA when it receives an operator's request for an FMP number for a facility associated with the CAA. The BLM made numerous changes to both the structure and content of this section in the final rule in response to comments.
A new paragraph (a) was added to the final rule that grandfathers existing commingling approvals in some specific situations. Paragraph (a)(1) grandfathers all existing downhole commingling approvals.
Based on the numerous comments the BLM received on downhole commingling approvals (see a discussion of those comments under § 3173.14(b)), the BLM decided to grandfather all existing downhole commingling approvals. The BLM is aware that there are large numbers of wells in the San Juan basin and elsewhere that are currently approved for downhole commingling. The BLM believes that the vast majority of these wells are producing low volumes of oil and gas and that continued production of these wells increases the maximum ultimate recovery of oil and gas. As a result, the BLM has made a determination that it is in the public interest to ensure these wells continue to produce even if the methods used to allocate production to Federal and Indian leases, unit PAs, and CAs potentially result in higher levels of uncertainty, bias, and make verification of production more difficult. The BLM also believes that most of these wells would be approved by the BLM to continue commingling even if the BLM were to perform an evaluation on them as would have been required under this section of the proposed rule. Grandfathering all existing downhole commingling approvals will streamline the review process and reduce the paper work burden on both industry and the BLM. When the BLM receives a request for an FMP for a well that has an existing downhole CAA, the BLM will document that the existing downhole CAA qualifies under § 3173.16(a)(1) of the final rule. The BLM will address any shortcomings of the existing approval, such as the absence of a defined allocation method, on a case-by-case basis during inspections and production audits. The BLM may issue written orders to operators to correct these deficiencies.
Paragraph (a)(2) grandfathers existing surface commingling approvals where each lease, unit PA, or CA that is part of the approval produces less than 100 bbl of oil per month or 1,000 Mcf of gas per month, averaged over the previous 12 months. See the discussion under § 3173.14(b) for an explanation of how the BLM derived these thresholds. As with downhole commingling, the BLM decided to grandfather these existing commingling approvals based on comments received on the proposed rule. However, the BLM does not agree with comments stating that the economic exemptions in the proposed rule were inadequate. The BLM believes that the economic exemptions in both the proposed and final rules are adequate to address those operations where achieving non-commingled measurement of production would truly be uneconomic. In addition, the definition of an economically marginal property in the final rule expands the criteria in the proposed rule by changing the threshold from a 10 percent before tax rate of return to an 18-month after tax payout. The BLM believes this could significantly increase the number of leases, unit PAs, and CAs that would be able to qualify for the economic exemption.
The BLM does, however, agree with comments expressing concern over the paperwork burden associated with preparing and reviewing applications involving lower volume leases, unit PAs, and CAs. The BLM chose to grandfather these existing surface commingling approvals based on the understanding that leases, CA, and unit PAs producing below these thresholds would almost certainly qualify under the definition of an economically marginal property. The purpose of grandfathering these approvals, therefore, was to reduce the paperwork burden for both the BLM and industry.
Under this provision, the operator of any lease, unit PA, or CA that is below these thresholds would retain the existing CAA from the BLM without any further information or analysis required. The BLM would only have to verify that the average monthly production rates of the leases, CAs, and unit PAs included in the approval are below the thresholds listed in this section.
A new provision has been added to paragraph (b), which clarifies that if the grandfathering conditions in paragraph (a) of this section are not met, then the existing CAA must meet the minimum standards and requirements for a CAA under § 3173.14 of the final rule.
This section also sets out a process if the AO identifies deficiencies. Paragraph (b)(1) requires the AO to notify the operator in writing of any inconsistencies or deficiencies with an existing CAA. The operator will then be given 20 days after receipt of such notice to correct any inconsistencies or deficiencies, provide the additional information requested, or request an extension of time. When the AO is satisfied that the operator has corrected
Paragraph (b)(2) clarifies that the AO may terminate an existing CAA and grant a new CAA with new or amended COAs to make the approval consistent with the requirements for CAAs under § 3173.14 of the final rule. Under the proposed rule the AO could simply impose new or amended COAs to an existing commingling approval.
One of the primary goals of paragraph (c) in the final rule (§ 3173.16(a) through (d) of the proposed rule) is to ensure that existing commingling approvals that do not qualify for grandfathering under paragraph (a) of this section, meet the standards for commingling under § 3173.14. Another primary goal is to ensure that, if the existing commingling approval does meet the standards under § 3173.14, it also contains the information required under § 3173.15, to ensure that the BLM can verify the volumes allocated to each lease, unit PA, or CA that are part of the existing CAA.
Under paragraph (c), the BLM will review existing CAAs that do not qualify for grandfathering under paragraph (a), for their consistency with the minimum standards and requirements under § 3173.14 when the operator submits a request for an FMP number. If the BLM determines that the existing CAA does not meet the requirements under § 3173.14, the BLM may take several courses of action. Under paragraph (c)(1), the AO will notify the operator in writing of any inconsistencies or deficiencies that the BLM identifies. The operator will have 20 business days to provide additional information requested by the BLM, request an extension of time in which to reply to the AO, or correct any inconsistencies or deficiencies. Under paragraph (c)(2), the BLM can impose new or amended COAs on an existing CAA to make it compliant with the requirements of this final rule. Paragraph (c)(3) allows the AO to terminate the CAA if the operator fails to correct the deficiencies that the BLM identifies.
The only significant change to paragraph (c)(1) of the final rule relative to paragraph (b) of the proposed rule is that the BLM clarifies that when the operator corrects any inconsistencies or deficiencies, the BLM will terminate the existing CAA and grant a new CAA in its place. The BLM made a similar change to paragraph (c)(2) of the final rule (paragraph (c) of the proposed rule), which clarifies that the BLM will impose new or amended COAs on an existing CAA by terminating the existing CAA and granting a new CAA in its place that includes those COAs.
Under paragraph (d) of the final rule (paragraph (e) of the proposed rule), if the BLM approves a new CAA to replace an existing agreement, it will be effective on the first day of the month following its approval. The BLM also included a new sentence in this paragraph that clarifies that any resulting change in the allocation method will only apply from the effective date of the CAA forward. The BLM added this clause to clarify that changes in the allocation method will not be applied retroactively. The BLM believes that retroactive application of new allocation percentages would impose a large paperwork burden on both industry and the BLM and would not be necessary.
Numerous commenters requested that the BLM consider grandfathering all existing CAA approvals. One commenter said the modifications to their facilities will put up to 87 percent of their production at risk of being shut in and possibly lost forever, along with the royalties to each of the mineral owners. The BLM agrees that there are instances where existing commingling agreements do not need to meet the final rule's commingling standards outlined in § 3173.14(a)(1), and has provided exemptions in § 3173.16(a) that allow operators to maintain existing agreements. See the discussion under § 3173.16(a) for further discussion. In addition, § 3173.14(c) includes three additional circumstances, beyond the three provided under the proposed rule, in which the BLM can approve a CAA. Given the grandfathering provisions and the expanded number of situations where the BLM can approve a CAA under the final rule, the BLM does not believe that any existing CAAs that are truly on the edge of profitability will be impacted by the final rule's requirements.
Other commenters did not like the idea of being required to upgrade existing wells and facilities that comply with existing laws, regulations, and policies. While the BLM notes that standard terms and conditions found in Federal oil and gas leases require compliance with all applicable requirements, including requirements that might be subsequently promulgated by the BLM, the BLM nevertheless believes that this comment has some merit. Most existing surface commingling approvals are for leases, unit PAs, and CAs where production volumes are low enough, or other overriding considerations exist, such that the CAA will comply with the requirements of § 3173.14(a) or (b) of the final rule with little or no changes required. Similarly, any CAA granted under IM 2013-152 should already meet the requirements of the final rule, especially considering that the final rule adds four additional exemptions under which the BLM may grant a CAA as compared to the two exemptions allowed under the IM (for low-volume properties and overriding considerations), and lowers the threshold for leases, unit PAs, and CAs to meet the definition of an economically marginal property. For the relatively few existing CAAs that do not meet the requirements of the final rule, some changes to plumbing or measurement equipment may be required. In these cases, the BLM will determine that a CAA is not justified because these leases, unit PAs, or CAs do not meet the definition of an economically marginal property and no other overriding conditions exist that would allow the BLM to grant a CAA.
One commenter said the proposed rule would require operators to submit all existing authorizations to the BLM for re-approval, and added that many operators and BLM staff spent countless hours negotiating approvals of existing CAAs to ensure they protect environmentally sensitive areas while providing accurate measurement of production. Although the BLM did not make any changes to the rule based on this comment, the final rule includes grandfathering provisions under § 3173.16(a), which would no longer require operators to submit existing downhole commingling authorizations or surface commingling authorizations that qualify under § 3173.16(a)(1) and (2) when applying for an FMP. In addition, for those existing CAAs that do not meet the grandfathering criteria of paragraph (a) of this section, but comply with the requirements of the new rule, the BLM will not require re-approval—these CAAs will be allowed to continue as originally approved.
Several commenters disagreed with the requirement in § 3173.16(c)(1) that operators correct any inconsistencies or deficiencies that the AO finds with an existing CAA within 20 business days. One commenter said North Slope operators have significant weather-related challenges that would make it difficult for them to meet the 20-business-day deadline, while another said that the required fixes could involve installing new piping, which would likely take longer than 20 business days. Several commenters said this final rule will require every existing
In response to these comments, the BLM added language to the final rule at § 3173.16(c)(1) which allows an operator to request an extension during the 20-business-day timeframe. The operator should justify the extension request by explaining the factors that will not allow it to comply within the 20-business-day timeframe, and provide a timeframe under which they can comply. The BLM will consider the request and grant an extension if the justification is adequate. This final rule will not require every existing CAA to undergo significant work to bring it into conformity with the new requirements as one commenter suggested. In fact, the BLM estimates that the majority of existing CAAs will continue operating as they have been because they are exempt from the requirements due to their low production volumes or other factors.
Several commenters said it would be unfair for the BLM to apply new COAs that existing CAAs could not meet, causing production to be shut in. Another commenter said it would be unreasonable for the BLM to impose new or amended conditions of approvals on existing commingling agreements and recommended that § 3173.16(c) be deleted altogether. The BLM does not agree with these comments and did not make any changes to the final rule as a result.
The BLM estimates that only a small percentage of existing CAAs will require new COAs and most of those COAs will be for minor deficiencies such as providing a better explanation of the allocation process. For those new COAs that require additional work to which the operator may object, the BLM has already included a provision in paragraph (c)(2) of the final rule that will allow the existing CAA to continue in effect during the pendency of any appeal of the decision that requires the new COAs. The BLM did not make any changes to the rule based on these comments.
Lastly, some commenters expressed concern that existing CAAs were at risk of being terminated if the BLM did not timely respond to their FMP applications and review their CAA approvals. As stated earlier, operators may continue to produce oil and gas prior to FMP approval and CAA review and may continue to use their lease, unit PA, or CA numbers for reporting production to ONRR as long as they have applied for their FMP numbers within the deadlines specified under § 3173.12. The BLM did not make any changes to the rule based on these comments.
Section 3173.17 clarifies that approval of a CAA does not constitute approval of off-lease royalty-free use of production in facilities located at an off-lease FMP approved under the CAA. The BLM did not make any changes to this section.
One commenter from the San Juan Basin said the new CAA requirements would reduce Federal royalties from existing CAAs because operators would have to install new compressors at each well, resulting in more royalty-free production used as fuel to power those compressors. The commenter provided a diagram that showed a compressor for each lease that they believe would be required if commingling was not approved. For comparison, another diagram showed one large compressor located at an off-lease FMP in lieu of the wellhead compressors, if commingling was approved. The commenter stated that with commingling approval, operators must pay royalty on the fuel used at the commingled off-lease compressor because it does not qualify as royalty-free use.
The BLM disagrees with the premise of this comment because there is nothing in the scenario presented by the commenter that would compel them to install separate lease compressors if the BLM denied commingling. The small amount of royalty the operator would not have to pay if the compressors were located on-lease would never offset the additional capital and ongoing expense of having to install, operate, and maintain three lease compressors as compared to one large compressor located at a central delivery point. Instead, if the BLM did not grant a CAA, a prudent operator would simply use the allocation meters already installed at each property they were proposing to commingle as FMPs, continue to use the large off-lease compressor, and continue to pay royalties on the fuel used to run that compressor as they do now. The BLM did not make any changes to the rule based on this comment.
Another commenter stated that other royalty owners will be burdened by all the downstream losses (fuel, etc.) if the operator must install an on-lease FMP rather than rely on measurements taken at a downstream commingled measurement point.
According to the commenter this raises legal concerns with respect to other agency regulations and contractual agreements between operators. The BLM disagrees with this comment and did not make any changes as a result. The requirement to install an FMP on the lease, unit PA, or communitized area, and pay royalty based on that FMP only applies to Federal and Indian leases. It would not preclude other royalty owners to base their royalty distribution on a down-stream commingled measurement point that is different from the FMP on which the Federal or Indian royalties are based.
Section 3173.18(a) of the final rule identifies the circumstances under which all operators who are parties to a CAA must request a modification, including: Modifications to the allocation agreement; inclusion of additional leases, unit PAs, or CAs into a CAA; or termination of a lease, unit PA, or CA within a CAA. Paragraph (b) identifies the information that must be submitted in connection with a modification request. Paragraph (c) was added to the final rule to clarify that a CAA does not need to be modified when there is a change in operator.
One commenter suggested that the BLM change proposed § 3173.18(a)(1), which allowed operators who are a party to a CAA to modify the CAA when there is a change in the allocation schedule. The commenter said it was not practical or beneficial to update the CAA each time the allocation schedule changes. The BLM agrees that requiring an update to the CAA when the allocation schedule changes is not necessary. The intent of requiring information on the allocation was to ensure that the BLM can verify and re-calculate the volumes reported on the OGORs. Allocation schedules are often based on periodic well testing and can change each time a well test is conducted. As long as the BLM thoroughly understands the allocation methodology, we can request the well testing or other data from which the operator determines the allocation schedule and verify that the allocation was done in accordance with the allocation methodology and was properly reported on the OGOR. Paragraph (a)(1) has been modified to require a CAA modification only when there is a modification to an allocation
One commenter did not like the idea of having a CAA re-evaluated when new leases are proposed to be added to the CAA, as required under § 3173.18(a)(2). The BLM disagrees with this comment and did not make any changes to the rule as a result. The addition of a lease, unit PA, or CA to an existing CAA will affect the allocation of production in a CAA, and therefore the BLM will need to review the addition to ensure that the allocation method is verifiable and provides a fair return to the Federal Government or Indian tribes or allottees.
Finally, several commenters asked whether submission of a “Successor of Operator Sundry Notice” would automatically change the operator of the FMP and the CAA. A Sundry Notice for a change in operator of a well(s) and a facility on a lease, unit PA, or CA will designate that new operator as being responsible for reporting production from the property, and therefore will include the CAA agreement. In response to this comment, the BLM has removed one of the conditions under which a CAA may be modified—when there is a change in operator. Furthermore, a new paragraph (c) has been added to the final rule stating that a change in operator will not trigger the need to modify the CAA. The FMP will automatically transfer since it is part of the facility.
Section 3173.19 (a) and (b) of the final rule identifies the effective date of a CAA after the approval of an application or modification, respectively. Paragraph (c) of this section clarifies that a CAA does not modify any of the terms of any leases, unit PAs, or CAs. The BLM did not receive any public comments on this section and did not change it in the final rule, except to make minor modifications for clarity.
Paragraph (a) of § 3173.20 of this final rule (paragraph (b) of the proposed rule) authorizes the BLM to terminate an approved CAA for any reason, including changes in technology, regulation, or policy, or where the operator has not complied with the terms of the CAA. Paragraph (b) (paragraph (c) of the proposed rule) provides for automatic termination of a CAA if only one lease, unit PA, or CA remains in the CAA. Paragraph (c) (paragraph (a) of the proposed rule) states that an operator may terminate its participation in a CAA by submitting a Sundry Notice to the BLM. Unlike the provision in the proposed rule, paragraph (c) of the final rule clarifies that the termination by one operator does not automatically terminate the CAA as to all other operators, so long as the requirements of this part are met with respect to the remaining participants in the CAA.
After termination of a CAA, paragraph (d) requires the BLM to notify in writing all operators who are a party to the CAA of the effective date of the termination and any inconsistencies or deficiencies with their CAA approval that caused the termination. The BLM modified this provision from the proposed rule to provide that upon receipt of the BLM's notice of termination, the operator has 20 business days to correct any inconsistencies or deficiencies, or provide additional information that the AO has requested or that explains or justifies the inconsistency or deficiency. If the operator does not correct the inconsistency or deficiency within 20 business days after receipt of the BLM's notice, the CAA is terminated as of the effective date in the BLM's notice. The effective date of the termination will not be earlier than the 20 business days outlined in paragraph (d). Paragraph (e) provides that upon termination, each lease, unit PA, or CA may require a new FMP number or a new CAA. Under the final rule, operators will have up to 30 days to apply for a new FMP number or CAA, whichever is applicable. Following termination, while the BLM is processing the application for a new FMP number or CAA, the operator may use the existing FMP number for recordkeeping and production reporting.
Several commenters were concerned that paragraph (a) in the proposed rule would have allowed a party to a CAA to unilaterally terminate the CAA by submitting a Sundry Notice to the BLM, and that paragraph (b) in the proposed rule, or paragraph (a) in the final rule, allows the BLM to terminate a CAA for any reason. One commenter said it would be fine to allow a party to terminate their participation in the CAA, but the remaining operators should have the opportunity to continue with the CAA. One commenter asked that the final rule be changed to allow an existing CAA to continue after one of the parties pulls out, as long as the remaining operator(s) follow the COAs for the CAA.
The BLM agrees with the commenters and believes that the continued operation of a CAA when one operator decides to pull out is in the public interest. All the CAA requirements of this rule are designed to ensure that the CAA is in the public interest by, for example, allowing continued production of low volume properties, addressing other overriding considerations, or allowing the maximum ultimate recovery of oil and gas resources. The BLM does not believe that the decision of one operator to pull out of the CAA would change the BLM's public interest determination and terminating the CAA as a result would only result in additional paperwork for both the BLM and industry. Instead, the operator who wants to terminate its own, individual participation in the CAA should be able to do so. In response to this comment, the BLM removed proposed paragraph (a) in the final rule and re-designated it with modifications as paragraph (c). While paragraph (c) still allows an operator to terminate a CAA through submission of a Sundry Notice, the BLM clarified that paragraph in response to comments to make clear that termination of participation in a CAA by one operator does not necessarily impact all operators, so long as the other requirements of this part are met with respect to that CAA and the other operators submit a Sundry Notice for a new CAA as required by paragraph (e).
An operator who wishes to terminate its participation will need to submit the appropriate paperwork to the BLM as outlined in 3173.20(c). Additionally, if a CAA is terminated, paragraph (e) of the final rule no longer requires separate measurement. Rather, it gives operators 30 days to apply for a new FMP number and/or CAA, if applicable. The old FMP number may be used for recordkeeping and production reporting until a new FMP number is assigned or a new CAA is approved. If more than one lease, unit PA, or CA remains in a CAA, the operator(s) of those leases, unit PAs, or CAs will need to submit a Sundry Notice for a new CAA under § 3173.18.
Another commenter stated that they have established gathering systems that are subject to the existence of CAAs. If the CAA is terminated by the BLM, the commenter states that operators could no longer sell gas into the gathering system, which could result in the shut in of wells, lost production and lost revenues. Instead, the operator suggests that if an operator no longer wants their lease to be part of a CAA, the CAA could be easily modified to include only
Regarding comments that the BLM should not have the authority to terminate existing CAA approvals for any reason, commenters already should be aware that under the terms of all existing CAAs, the BLM retains the right to terminate a CAA for any reason. Thus, the requirements found in paragraph (a) are a codification of existing practices. However, the reasons listed under paragraphs (a)(1) through (a)(3) of this final rule should cover the majority of the situations that could lead to termination of a CAA. If a CAA is not in compliance with this rule's commingling requirements, the BLM will work with the operators on a case-by-case basis to bring the CAA back into compliance to avoid a termination. If a CAA is terminated because of changes in technology, regulation, or BLM policy, operators will be given sufficient time to make any necessary changes. In the event that the BLM does take steps to terminate a CAA, paragraph (c) of this final section provides that the BLM's notice-of-termination letter will describe the inconsistencies or deficiencies that will lead to the CAA termination, along with the effective date of the termination. The parties to a CAA will then have an opportunity to avoid termination of the CAA by correcting those inconsistencies or deficiencies within 20 business days of their receipt of notification.
Section 3173.21 of this final rule identifies certain circumstances in which downhole combining of production is subject to the commingling requirements contained in §§ 3173.14 through 3173.20. Under paragraph (a)(1), the combination of production from a single directional well drilled into different hydrocarbon pools or geologic formations under separate adjacent properties, regardless of ownership, where none of the pools or formations are common to more than one of the properties, constitutes commingling under the final rule, and is therefore subject to the requirements in §§ 3173.14 through 3173.21 of this subpart. If, on the other hand, the pools or geologic formations are common to more than one property, then under paragraph (a)(2), the operator is required to establish a unit PA or CA as opposed to obtaining a CAA. Paragraph (b) clarifies that combining production downhole from different geologic formations on the same lease from a single well, while requiring AO approval, is not considered commingling for purposes of this final rule, unless those formations have different ownership.
The BLM did not receive any public comments on this section, but did make one small change. In paragraph (b), the final rule clarifies that the requirements of §§ 3173.14 through 3173.20 do not apply when operators combine production downhole from different geologic formations on the same lease in a single well.
Sections 3173.22 through 3173.28 of this final rule establish the circumstances in which the BLM will approve measurement of production off of the lease, unit, or CA (referred to as “off-lease measurement”). Prior to this rule, there were no national standards that operators had to meet when applying for off-lease measurement. Neither Order 3 nor other regulations addressed how or under what circumstances the BLM would approve off-lease measurement. This lack of guidance led to much confusion over the location of off-lease measurement points. Off-lease measurement is also often associated with commingling. Meters that measure commingled production are often referred to as central delivery points. In most situations, the meter at the central delivery point is located off of at least one of the Federal or Indian leases, units, or CAs from which the production originates. This configuration requires the BLM to approve both the commingling and the off-lease location of the measurement point.
In the absence of uniform national standards governing off-lease measurement, BLM State Offices created their own policies for approving off-lease measurement applications, which were not necessarily consistent. Sections 3173.22 through 3173.28 of this final rule, discussed below, provide such uniform national standards, addressing the concerns identified by the GAO, the OIG, and the Subcommittee.
Some commenters said that this section contains new record-keeping requirements that are vague and that could cause operators to submit incorrect applications for off-lease measurement. The commenters did not specify the sections that they believe are vague, nor did they provide any explanation as to why they are vague. The BLM did not make any changes to the rule based on these comments. The BLM notes, however, that § 3173.23 contains a complete list all of the information and documentation that operators need to provide to the BLM when applying for off-lease measurement approvals.
Section 3173.22 of the final rule establishes the conditions under which the BLM will consider granting a request for off-lease measurement. It requires such requests to satisfy the requirements of paragraphs (a) through (d). Under paragraph (a), the BLM will consider off-lease measurement of production only from a single CAA or a single Federal or Indian lease, unit PA, or CA. Paragraph (b) requires that the off-lease measurement provide for accurate production accountability and paragraph (c) requires that off-lease measurement be in the public interest. Paragraph (d) requires off-lease measurement to occur at an approved FMP.
Commenters asked that the BLM list the conditions under which off-lease measurement will be approved. The BLM did not make any changes to the rule based on this comment because this section clearly lists the conditions under which off-lease measurement will be considered for approval. Requests that meet the requirements of this section will be approved, while requests that do not will not be approved.
Another commenter requested that the BLM provide exemptions from the off-lease measurement requirements in situations where topography or other environmental issues prevent operators from measuring on-lease. The BLM agrees that there are circumstances when it is physically impractical to measure on-lease or where measuring on-lease could cause additional environmental impacts. Examples include situations where well pads are located at high altitudes that could be inaccessible in the winter or when the BLM has imposed seasonal access restrictions due to environmental concerns. In response to this comment, final paragraph (c) has been changed to allow off-lease measurement when on-lease measurement is not practical due to topographic or environmental concerns. As with any of the requirements in this subpart, an operator may also request a variance to the off-lease measurement requirements on a case-by-case basis.
One commenter said its liquids-gathering system, which is within the boundary of a CAA, should be exempt from the off-lease measurement requirements of § 3173.22 because this
Several commenters said that the new off-lease measurement requirements will result in more FMPs and that off-lease measurement—because it requires fewer FMPs—provides better accuracy and reduces recordkeeping, allowing multiple wells or pads (in a unit operation) to commingle production at a central tank battery. These commenters asserted that this made it easier for the BLM to track production and audit facilities.
The BLM believes the commenters are confused about the definition of off-lease measurement. The operator can locate an FMP, including a central tank battery as mentioned by the commenters, anywhere within the boundary of a lease, a unit, or a CA from which the production originates without meeting the definition of off-lease measurement and without needing approval from the BLM. Although the requirements for approving a CAA in this rule may increase the number of FMPs required, the BLM does not agree that the off-lease measurement requirements of this rule would have any effect on the number of FMPs required. As noted earlier in discussion of § 3173.15(a) of the final rule, if off-lease measurement is a feature of a commingling and allocation proposal, then a separate Sundry Notice application for off-lease measurement is not necessary and the off-lease measurement proposal will be considered as part of the CAA request. The BLM expects that this final rule will have a smaller impact than the proposed rule would have had on existing off-lease measurement approvals tied to CAAs because §§ 3173.14(b) and 3173.16(a) of the final rule includes an expanded list of exemptions that allow commingling as well as grandfathering provisions for some existing CAAs.
Finally, a few commenters said that some existing off-lease measurement approvals could be at risk if they do not meet the BLM's conditions for being “in the public interest,” as outlined in paragraph (c) of this section. We agree that some existing off-lease measurement approvals may not be in the public interest, and they will therefore be terminated. The public interest generally includes minimizing environmental impacts, achieving maximum ultimate economic recovery, and allowing the BLM to verify volumes and qualities of oil and gas reported on the OGORs. Existing approvals that are merely for the convenience of the operator may not be in the public interest. If, for example, an existing off-lease measurement approval allows the FMP to be located on private land that makes BLM access difficult or impossible, and the approval cannot be justified based on environmental circumstances or achieving maximum ultimate economic recovery, it is likely that the BLM will terminate the approval. The BLM estimates that best management practices and environmental and topographic considerations will outweigh the need to terminate many existing off-lease measurement approvals or to deny new ones. The final rule was not changed in response to these comments.
Section 3173.23 of this final rule establishes the requirements operators must follow when applying for an off-lease measurement approval or amending an existing approval, including required supporting information and related documentation.
One commenter said that this section of the rule is unnecessary and redundant and that the off-lease measurement application and approval process should be part of the APD process. The BLM does not agree that this section is unnecessary and redundant because it establishes the process that operators will use to apply for an off-lease measurement approval, which is entirely separate from and independent of the process the BLM uses to process an APD. However, § 3173.23 does not prohibit operators from submitting new off-lease measurement applications with their APDs. The BLM, in fact, would prefer to receive comprehensive proposals upfront from operators when they submit their APDs because it streamlines the BLM's review process by allowing BLM staff to look at a project in its entirety early in the permitting process.
Section 3173.23(a) requires operators to submit their off-lease measurement application via a Sundry Notice. That Sundry Notice package may be submitted at the same time as, but separately from, an operator's APD package(s) and the BLM will process both applications at the same time. The final rule did not change as a result of this comment.
Several commenters said it would be too burdensome to require operators, whose off-lease measurement facilities are located on non-federally owned surface, to include in their off-lease measurement applications written concurrence from the surface owners, including from future owners if the ownership changes, as called for in paragraph (e) of the final rule. The BLM does not agree with these commenters. Operators should already be obtaining concurrences from surface owners as part of the APD process as Onshore Order 1 (Approval of Operations) specifically requires operators to make a good faith effort to obtain a Surface Access Agreement from the surface owner. Therefore, this requirement does not place any additional burden on the operator.
In addition, the BLM must have guaranteed access to the off-lease measurement location. Without this guaranteed access, the BLM may not be able to verify or account for the volumes and qualities of oil and gas on which royalty is due and would therefore deny the off-lease measurement request or terminate the existing off-lease measurement approval. No change to the rule was made in response to this comment.
Finally, one commenter said that the proposed rule did not specifically require operators to obtain the written consent of the owner and operator of measurement facilities. As a result, the commenter said, this rule would subject owners and operators of the measurement facility to the jurisdiction of the BLM without its consent or knowledge. The BLM believes that this is a valid concern. However, the BLM did not make a change to the rule in response to this comment because paragraph (e) (paragraph (f) in the proposed rule) already requires operators to obtain written concurrence signed not only by the surface owner(s), but also by the owner(s) of the measurement facilities.
In addition to these changes, the BLM made a few minor administrative changes to final § 3173.23. These clarifications were consistent with the overall changes made to the final rule and were not made in response to any particular comments. The BLM added a new paragraph (h) to the final rule to clarify that operators, under existing BLM regulations, must obtain approval from the appropriate surface-management agency, if new surface disturbance is proposed for the FMP, and its associated facilities are located on Federal land managed by an agency other than the BLM. The BLM also clarified paragraph (f) to state that an
Other changes we made that were unrelated to public comments include modifications to the type of information operators must submit as part of their off-lease measurement application. In paragraph (c)(2) of the final rule, the BLM no longer requires the operator to identify the land description of all wells, pipelines, and other facilities expected to be installed as part of their proposal. Operators need only identify the relative location of such facilities. Paragraph (e) in the proposed rule required submission of a schematic or engineered drawing showing all new facilities that are part of the off-lease measurement proposal. This requirement is no longer in the final rule. Finally, the requirement in paragraph (e) of the proposed rule that called for the submission of a site facility diagram for existing facilities if changes are being proposed to the facility is removed as unnecessary because the requirements related to site facility diagrams for existing facilities are already addressed by § 3173.11. The BLM elected to make these changes consistent with the changes made to the information-submission requirements for commingling applications under § 3173.15 of the final rule. It is not necessary for the information-collection requirements for commingling applications to be different than the information-collection requirements for off-lease measurement applications.
Section 3173.24 provides that off-lease measurement approvals are effective on the date the BLM issues the approval, unless the BLM specifies a different effective date in the approval. The BLM did not receive any public comments on this provision and did not make any changes to the final rule.
Under this section of the final rule, an existing off-lease measurement approval will be reviewed upon receipt of an operator's request for the assignment of an FMP number to a facility associated with the off-lease measurement approval. Section 3173.25(a) states that the AO reviews the existing off-lease measurement approval for consistency with the minimum standards and requirements in § 3173.22. The AO will notify the operator in writing of any inconsistencies or deficiencies. Under paragraph (b), the operator will have to correct the inconsistencies or deficiencies, provide the additional information that the AO has requested, or request an extension from the AO within 20 business days. If an operator is requesting an extension, they must justify the request by explaining the factors that will not allow the operator to comply within 20 days and provide a timeframe under which the operator can comply.
Under paragraph (c), in connection with approving the requested FMP, the AO may terminate an existing off-lease measurement approval and grant a new off-lease measurement approval with new or amended COAs to make the approval consistent with the requirements of this rule. In addition, paragraph (c) provides that the existing off-lease measurement approval will continue in effect during any pendency of an appeal of the new off-lease measurement approval. If the operator fails to correct the deficiencies, paragraph (d) provides that the AO may terminate the off-lease measurement approval. If the existing off-lease measurement approval under this section is consistent with the requirements under § 3173.22(e) of the final rule allows that existing off-lease measurement be grandfathered and be part of the operator's FMP approval. Under paragraph (f), if the BLM grants a new off-lease measurement approval, that new approval is effective on the first day of the month following its approval.
Several commenters had concerns with the paragraph (a) requirement that the AO review existing off-lease measurement approvals to determine if they comply with the new off-lease measurement requirements in § 3173.22. These commenters requested that the BLM “grandfather in” existing off-lease measurement approvals. Another commenter said that operators spent countless hours negotiating their existing CAAs, along with their off-lease measurement approvals, with BLM field staff, which resulted in protections for environmentally sensitive areas and accurate measurement of production.
The BLM agrees with the comments as they relate to grandfathered CAAs and included language under § 3173.16(a) that also grandfathers existing off-lease measurement approvals that are included as part of those grandfathered CAAs under § 3173.16(a)(1) or (2).
The BLM does not, however, agree that existing off-lease measurement approvals that are not included in § 3173.16(a) should be grandfathered. As we stated earlier in this preamble, a major goal of this final rule is to ensure that new and existing approvals—be they for CAAs or off-lease measurement—allow BLM staff to verify that oil and gas are being measured and reported accurately under these approvals. Without the ability to consistently track where and how oil and gas are measured, the BLM cannot be assured that production reporting is accurate. Section 3173.25 sets up a process for the BLM to review existing non-grandfathered off-lease measurement approvals that were granted before the BLM established guidance and standards that ensure such approvals were structured so that BLM staff can verify production reporting.
For existing off-lease measurement approvals that are associated with a non-grandfathered CAA, the CAA would provide the public interest justification for the off-lease measurement approval, whether that is due to economics, protection of the environment, or to achieve maximum ultimate economic recovery. The BLM estimates that more than 95 percent of existing CAAs will be either grandfathered or approved under the provisions of the final rule. Therefore, the only aspect of non-grandfathered off-lease measurement approval that the BLM will be concerned with is the BLM's access to the proposed off-lease measurement location.
Another commenter said that the proposed rule would have required operators to submit all existing off-lease measurement approvals to the BLM for re-approval. The BLM disagrees. This rule does not require operators to submit all existing authorizations to the BLM for re-approval. It does provide that the AO, when an operator submits an application for an FMP number associated with an existing off-lease measurement approval, the AO will review that existing approval for consistency with the minimum standards and requirements for off-lease measurement under § 3173.22 and notify the operator in writing of any inconsistency or deficiency, or request additional information. No changes to the final rule were made as a result of this comment.
Several commenters were concerned that paragraph (b) gives operators only 20 business days to correct any inconsistencies or deficiencies that the
The BLM believes that some of the commenters have confused the requirements relating to the review of existing off-lease measurement approvals with those relating to the review of existing CAAs under § 3173.16(b). The review of existing off-lease measurement approvals will have nothing to do with allocation methods and will rarely involve any on-the-ground work. The BLM will be concerned with only four issues when reviewing existing off-lease measurement approvals:
1. Does the existing off-lease measurement point only measure production from one lease, unit PA, CA, or CAA?
2. Is the off-lease measurement point reasonably accessible to the BLM for the purpose of production accountability?
3. Is the off-lease measurement approval in the public interest?
4. Does the off-lease measurement occur at an approved FMP?
For the majority of existing off-lease measurement approvals that are associated with a CAA, items 1, 3, and 4 will already be addressed by the CAA. Therefore, the only review the BLM will do is to ensure the off-lease measurement point is reasonably accessible to the BLM. In the rare case where it is not, the BLM may require that the operator either modify the location to make it more accessible to the BLM or, in the most extreme cases, move the measurement facility to a location where it is accessible to the BLM.
Second, in response to these comments, the BLM added language to the final rule that allows an operator to request an extension of the 20-day timeframe. The operator should justify the extension request by explaining the factors that will not allow them to comply within the 20-day timeframe and provide a timeframe under which they can comply.
One commenter objected to a provision in paragraph (c) that allows the AO to impose new or amended COAs on an existing off-lease measurement approval to make the approval consistent with the off-lease measurement requirements in § 3173.22. The commenter was referring to an off-lease measurement approval that is part of an existing CAA. The commenter stated that numerous sales contracts are based on existing approvals and that by changing the approval, gas sales contracts may be at risk of termination. Other commenters expressed concern that new COAs could result in economic burdens that would result in the shut-in of production and loss of Federal or Indian royalty. Other commenters said the new off-lease measurement requirements would force them to reconfigure gathering lines at sites where existing off-lease measurement agreements were not approved, which would be costly and cause additional environmental impacts that may not be necessary.
The BLM did not make any changes to the rule based on this comment because this has little do with the off-lease measurement approval and much more to do with the CAA approvals, discussed previously in the preamble. As discussed in the portion of this preamble dealing with commingling, the primary concern of the BLM when reviewing existing off-lease measurement approvals that are associated with a CAA is to ensure that the BLM has reasonable access to inspect the off-lease measurement facility. Generally, the only COAs that the BLM would impose on an existing off-lease measurement approval that is associated with a CAA would relate to ensuring BLM access to the FMP. These COAs could include remedies such as obtaining express authorization for the BLM to access the facility in situations where the facility is not located on land managed by the BLM, or in rare cases, moving the measurement facility to a location that does provide the BLM reasonable access. This paragraph further provides that if the operator appeals one or more of the new COAs, the existing off-lease measurement approval will continue during the pendency of the appeal.
The BLM would like to reiterate that most of the existing wells in the San Juan Basin, where surface and downhole commingling are occurring together with off-lease measurement, may be exempt from having to meet the new commingling and related off-lease measurement requirements because they qualify for grandfathering under § 3173.16(a). Section 3173.16(a) grandfathers all existing downhole commingling CAAs and any existing surface CAAs if the average production over the past 12 months is less than 1,000 Mcf of gas per month, or 100 bbl of oil per month for each lease, unit PA, or CA included in the CAA. In such cases, the associated off-lease measurement approval would also be grandfathered under § 3173.16(a).
Section 3173.26 of the final rule clarifies that approval of off-lease measurement does not constitute approval of off-lease royalty-free use of production as fuel in facilities located at an approved off-lease FMP. Under NTL-4A, the lessee or operator may claim royalty-free use only for gas or oil used on the same lease, on the unit for the same unit PA, or on the same CA from which the gas or oil was produced. Thus, the lessee or operator may not claim royalty-free use for any of the production used as fuel at an off-lease FMP, absent BLM approval.
One commenter asked that the BLM define the term “royalty-free use” in this rule. As explained in this preamble with respect to § 3173.1, the BLM does not believe such a change is necessary. The definition of royalty-free use in NTL-4A will control unless and until it is replaced.
Section 3173.27(a) of the final rule provides that the BLM may terminate an off-lease measurement approval for any reason. By way of illustration, this paragraph identifies certain circumstances under which the BLM might exercise that authority—such as changes in technology, regulation, or BLM policy; operator non-compliance with the terms or conditions of the off-lease measurement approval; or operator non-compliance with §§ 3173.22 through 3173.26. Under paragraph (b), the BLM will notify the operator in writing of the effective date of the termination and any inconsistencies or deficiencies with the operator's approval that serve as the reason(s) for the termination. Upon receipt of the BLM's notice, the operator will have 20 business days to correct any inconsistencies or deficiencies, or provide any additional information the AO requests. Paragraph (b) also provides
Paragraph (c) provides that an operator may terminate an off-lease measurement approval by submitting to the BLM a Sundry Notice, which must identify the new FMPs for the lease(s), unit PA(s), or CA(s) previously subject to the off-lease measurement approval. Under paragraph (d), each lease, unit PA, or CA that was subject to the off-lease measurement approval may require a new FMP number(s) or a new off-lease measurement approval. Operators will have up to 30 days to apply for a new FMP number or off-lease measurement approval, whichever is applicable. While the BLM processes the application for a new FMP number or off-lease measurement approval, the operator may continue to use the existing FMP number.
The BLM received several comments on this section of the proposed rule, one of which expressed concern that proposed § 3173.27 did not provide an explicit timeframe or process for the BLM to terminate off-lease measurement approvals or for operators to correct the inconsistencies or deficiencies that led to the termination. This commenter recommended that the BLM give operators 9 months to correct their inconsistencies or deficiencies before terminating their approvals. Several other commenters objected to paragraph (a) of the final rule (paragraph (b) of the proposed rule), which authorizes the BLM to terminate an off-lease measurement approval for any reason. One commenter stated that some gas sales contracts involving gathering systems are based on having off-lease measurement approvals and CAAs and that if the BLM terminates the off-lease measurement approval, the operator will no longer be able to sell gas into the gathering system. The commenter stated that operators need to have some confidence that the existing off-lease measurement approval will allow continued operations as long as the operator follows the COA for the off-lease measurement approval. If there are issues to be resolved, the operator should be given a reasonable time to resolve the issues.
The BLM agrees in part with these comments and made several changes to the final rule in response. Under revisions to final paragraph (b), the BLM's notification letter will describe the inconsistencies or deficiencies in the operator's existing off-lease measurement approval that will result in the termination, and state the effective date of the termination. The revisions also give the operator 20 business days from receipt of the letter to correct the inconsistencies or deficiencies identified by the BLM, provide more information, or request an extension of time from the AO in order to avoid termination. The BLM does not agree with a 9-month timeframe as recommended by one commenter because unique circumstances may warrant different timeframes. If an operator believes that correcting the inconsistencies or deficiencies will take longer than 20 days, it may request a reasonable extension of time from the AO in order to make any necessary corrections.
The BLM received several comments on paragraph (d) of the proposed rule. Proposed paragraph (d) said that if an off-lease measurement approval is terminated, each lease, unit PA, or CA subject to the approval reverts to measurement on the respective lease, unit, or communitized area. Commenters said that this requirement should not apply to gathering systems that were installed with BLM approval for the purpose of off-lease measurement. If such an approval were terminated, commenters said, the gathering system could no longer transport gas to the sales meter that is off-lease and wells connected to the gathering system would likely be shut in or plugged as they could no longer sell their gas. The new on-lease measurement system would not be connected to a gas sales line as well, the commenter said. The commenter recommended that the BLM delete the whole section from the final rule.
The BLM disagrees with this comment and did not make any changes to the final rule as a result. The commenter's concern principally relates to the underlying CAA approval, not to the off-lease measurement approval itself. The BLM's primary concern with off-lease measurement approvals that are tied to a CAA is the BLM's access to the off-lease FMP for the purpose of inspection and production accounting. For off-lease measurement approvals that are not tied to a CAA, § 3173.22(c) allows the BLM to consider an operator's ability to achieve maximum ultimate economic recovery from a lease, unit PA, or CA in determining whether it is in the public interest to approve off-lease measurement. This provision gives the BLM the leeway it needs to exempt leases, unit PAs, or CAs from the off-lease measurement requirements in situations where denial of off-lease measurement might result in shut-ins.
Section 3173.28 of the final rule identifies two circumstances that will not be considered off-lease measurement for purposes of the rule. The first is where an FMP is located on a well pad of a directionally drilled well that produces oil or gas from a lease, unit, or CA on which the well pad is not located. The second is where a lease, unit, or CA is made up of separate non-contiguous tracts. If production is moved from one tract to another tract within the same lease, unit, or CA, and the production is not diverted during movement between the tracts before the FMP (except for production used royalty-free), measurement would not be considered to be off-lease.
Several commenters were under the impression that they would need off-lease measurement approval for horizontal and directionally drilled wells where the well pad itself is located off the lease, CA or unit. Under paragraph (a), off-lease measurement approval for such wells is not needed, unless the FMP is also located off of the well pad, regardless of distance. If any of the facilities are located on non-federally owned surface, the operator will still need to obtain written concurrence signed by the surface owner(s), and the operator(s) of the measurement facilities that grants the BLM unrestricted access to the off-lease measurement facility and the surface on which it is located, in order to conduct production verification inspections. The BLM did not make any changes to the rule based on this comment.
One commenter said that, in some cases, there may by reasons to locate the FMP near, but not actually on, the well pad, triggering the need for the operator to obtain off-lease measurement approval. The commenter stated that if the FMP is located a small distance off the well pad, but clearly serves the wells on the pad this should not require an off-lease measurement approval. The BLM disagrees with this comment and did not make any changes to the rule as a result. Paragraph (a) of this section clearly states that the FMP must be located on the well pad to avoid the need for an off-lease measurement approval. Normally, well pads are clearly delineated in the field by a berm, fence, or other easily-identifiable feature. This makes the requirement clear, objective, and enforceable. Adding a provision that would, as suggested by the commenter, include FMPs that are only a short distance off the well pad would render the provision
Another commenter suggested that the BLM add a paragraph to this section that states gas used for fuel at locations that are not considered to be “off lease” under paragraphs (a) and (b) of this section qualifies as royalty-free usage. The BLM did not make any changes to the rule based on these comments because what qualifies as royalty-free use is outside the scope of this rulemaking.
Section 3173.29 expands the number and types of violations that would be subject to immediate assessments. Immediate assessments are not civil penalties and are separate from the civil penalties authorized under Section 109 of FOGRMA, 30 U.S.C. 1719. Unlike the proposed rule, the final rule does not subject purchasers and transporters to immediate assessments—only operators. For violation 7, non-retention of records necessary to determine quantity and quality of production, the final rule clarifies that the applicable regulation is § 3170.7, not § 3173.9(a)(1) and (2). Also, the final rule clarifies that violation 8 could result in an immediate assessment if operators fail to “apply for,” rather than “obtain,” the required FMP approval.
With respect to violations 9, 10, and 11, which pertain to approvals for off-lease measurement and surface or downhole commingling, respectively, the final rule clarifies that removing production from a facility that begins operation after the effective date of the final rule, prior to receiving BLM approval for off-lease measurement or commingling, could result in an immediate assessment. If the facility will be servicing new wells not yet drilled, as well as existing wells already in production, then the existing wells must use their respective existing FMP numbers when reporting production to ONRR's OGOR until the BLM assigns the new FMP number associated with its off-lease measurement or commingling approval.
An existing facility (
Some commenters argued that these immediate assessments are inconsistent with due process because there is no opportunity for an operator to correct its violations before an assessment is imposed. To the contrary, the use of immediate assessments for breaches of the oil and gas operating regulations is well established and is consistent with the notice requirements of due process. Operators obligate themselves to fulfill the terms and conditions of the Federal or Indian oil and gas leases under which they operate. These leases incorporate the BLM's regulations by reference. Thus, the immediate assessments contained in the regulations act as “liquidated damages” owed by operators who have breached their leases by breaching the regulations. See,
Several commenters said there could be instances when an operator is not aware that a violation exists. One commenter said the assessment should be imposed only if the violation was a willful or knowing act of noncompliance. Another commenter suggested the BLM place a Federal seal and notify the operator of the violation instead of issuing an immediate assessment for something that they are not aware of or that might be beyond their control. The BLM disagrees with these comments. Operators have a responsibility to inspect their properties to ensure site security, consistent with all applicable regulations, including this final rule. The violations outlined in this section of the final rule all have substantial adverse impacts on production accountability or royalty income and, thus, the BLM believes the assessments are warranted. No changes to the rule were made in response to these comments.
Numerous commenters said that the increases in the number of immediate assessments related to producing operations, from 1 to 11, and in the dollar amount of the assessments, from $250 to $1,000, are unreasonable. The number of immediate assessments was expanded to include violations that pose particular threats to the integrity of the BLM's production accounting system and that significantly increase the BLM's workload and enforcement costs. The increase to $1,000 is justified because it generally approximates what it will cost the agency, on average, to identify and document a violation and verify remedial action and compliance.
Commenters objected to this section of the proposed rule subjecting purchasers and transporters to immediate assessments. One said that purchasers and transporters should not be involved in retaining records pertaining to the quality and quantity of production. Another commenter said that oil and gas lease agreements are a contract between the government and lessees and that purchasers and transporters are not a party to those agreements and, therefore, should not be subject to these assessments. Other commenters argued that the proposed immediate assessments on purchasers and transporters exceeded the BLM's statutory authority under FOGRMA. Upon consideration of these arguments, and further review and analysis of FOGRMA and other authorities, the BLM has removed the immediate assessments on purchasers and transporters from final § 3173.29.
As explained in the proposed rule, the final rule removes the enforcement, corrective action, and abatement period provisions of Order 3. In their place, the BLM will develop an internal Inspection and Enforcement Handbook that will provide direction to BLM inspectors on how to classify a violation—as either major or minor—what the corrective action should be, and what the timeframes for correction should be. The AO will use the Inspection and Enforcement Handbook in conjunction with 43 CFR subpart 3163, which provides for assessments and civil penalties when lessees and operators fail to remedy their violations in a timely fashion, and for immediate assessments for certain violations.
As previously discussed in the proposed rule, the final rule allows the BLM to make a case-by-case determination of the severity of a violation, based on applicable definitions in the regulations. In deciding how severe a violation is, BLM inspectors must take into account whether a violation could result in “immediate, substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income.” (Definition of “major violation,” 43 CFR 3160.0-5.) Under the existing definition of “major violation,” which is not being revised as
Several commenters objected to the BLM using internal guidance or the Inspection and Enforcement Handbook to address violations, assessments for noncompliance, and corrective actions. Commenters argued that the use of internal enforcement guidance is inconsistent with the APA and that these guidance documents constitute substantive rules that must be developed through notice-and-comment rulemaking. These comments misunderstand the nature of the Internal Inspection and Enforcement Handbook that the BLM will develop. The Handbook will not establish new obligations to be imposed on the regulated community in a manner that will improve consistency in how those BLM personnel excise there discretion in applying existing regulations and addressing instances of non-compliance. Those obligations are spelled out in applicable regulations, orders, and permits, as well as the terms and conditions of leases and other agreements. Rather, the Handbook will provide guidance to BLM personnel as to how to apply the existing regulations and address instances of non-compliance. The overarching enforcement infrastructure of 43 CFR subpart 3163 remains in effect, and the definitions of “major violation” and “minor violation” in § 3160.0-5 remain unchanged. It is these duly promulgated regulations (among other authorities), and not the Inspection and Enforcement Handbook, that will provide the legal basis for the BLM's enforcement actions; the BLM's enforcement actions must be consistent with these regulations irrespective of what may be contained in its Inspection and Enforcement Handbook. It is not necessary for the BLM to develop its Handbook—which does not expand the BLM's authorities or impose binding obligations on the regulated community—through notice-and-comment rulemaking.
The commenters requested that the BLM use a transparent process to develop this internal guidance and that operators be given the opportunity to comment on it. The BLM did not accept these comments; however, the BLM will post the Inspection and Enforcement Handbook on the BLM Web site after it is developed and finalized.
Consistent with the proposed rule, this final rule eliminates the self-inspection provision of Order 3, section III.F., because it has been impractical for the BLM to enforce. Under the self-inspection program, operators were supposed to establish a program for the purpose of periodically measuring production volumes and assuring they were complying with the BLM's minimum site security requirements. But, as discussed earlier in response to comments on this topic during the discussion of § 3173.8, the Order 3 requirements were vague and the BLM never supplemented them with internal guidance or enforcement policy. As a result, the BLM determined that this requirement was of limited utility.
Nonetheless, the BLM received a comment that recommended that instead of removing the requirement, the language should be improved to ensure that an inspection program is established for periodically measuring production volumes and ensuring compliance with the BLM's site security requirements from Order 3. The BLM disagrees with this comment and did not make a change in response. In lieu of reworking or updating this requirement, the final rule strengthens recordkeeping requirements for operators, including for transporters and purchasers, which the BLM believes will ultimately accomplish the same results and be more useful going forward. It should also be noted that although the self-inspection requirement from Onshore Order 3 has been eliminated, the actions that an operator, transporter, or purchaser must take to conduct periodic production volume inspections and ensure site security have been incorporated into this final rule as required elements under §§ 3173.2 through 3173.10 of the final rule.
The BLM received a few comments that were general in nature and do not necessarily relate to a specific provision of the rule.
A number of comments argued that the rule is impermissibly “retroactive.” These comments argued that the rule is retroactive because it will apply to wells, facilities, and authorizations that existed before the rule's effective date. While the BLM agrees that retroactive regulations raise special legal concerns, those concerns are not implicated here because this rule is not a retroactive regulation. The comments misunderstand the nature of the “retroactive” regulations that the law disfavors. “A law does not operate `retrospectively' merely because it is applied in a case arising from conduct antedating the statute's enactment or upsets expectations based in prior law.”
It is often the case that a business will undertake a certain course of conduct based on the current law, and will then find its expectations frustrated when the law changes. This has never been thought to constitute retroactive lawmaking, and indeed most economic regulation would be unworkable if all laws disrupting prior expectations were deemed suspect.
A couple of comments expressed that the BLM was employing discriminatory regulation, and gave as their examples the inequality of producers, operators, and transporters in regard to equity interest in production. The proposed rule would treat producers, operators, and transporters equally even though some of these parties (specifically transporters) have no ownership interest in the oil and gas product generated from Federal or Indian lands. Because they have no interest, it is most likely that the costs they incur will be passed directly on to equity holders, commenters said. Over time, the commenter asserted, because equity holders may deduct transportation costs from royalties owed, this may result in reduced royalty payments for both the government and the tribes. While the BLM recognizes the possibility of some pass through of compliance costs from purchasers and transporters to operators, based on its analysis of the costs of this final rule, it does not believe those costs will be significant. Additionally, this change is consistent with the provisions of FOGRMA, which addresses responsibilities and duties of operators, purchasers, and transporters. By statute, Congress applied these legal requirements to those parties equally.
One commenter pointed out that the regulations fail to recognize the current industry business models, as it pertains to Master Limited Partnerships. Unlike C Corporations, MLPs have no mechanism for capitalizing the required
Many commenters questioned whether the BLM has the resources to implement this and other rules that it has finalized, or will finalize in the coming months, for example the new hydraulic fracturing regulations, which went into effect on June 24, 2015 (currently enjoined by order of the District Court of Wyoming), and the proposed Waste Prevention, Production Subject to Royalties, and Resource Conservation proposed rule, which published on February 8, 2016 (85 FR 6616). Commenters stated that the BLM does not have enough staff to enforce its existing regulations, let alone new ones. Commenters also said that the cumulative economic impact of this final rule should be analyzed together with the economic impacts of the final rules that are updating and replacing Orders 4 and 5.
The BLM does not agree with these comments. Most of the requirements in this final rule are not new—they codify existing requirements that are found in Order 3 or they are standard industry practices that most operators, transporters, and purchasers already follow. Those requirements that are new have been added for two reasons: (1) To give operators the flexibility to use new technology, which could, in the long run, reduce costs for both industry and the BLM; and (2) To address production accountability and site security concerns raised by governmental oversight bodies, such as the Subcommittee, the GAO, and the OIG. The BLM did not change the final rule as a result of these comments.
One commenter stated that the regulations should consider laws and lease provisions that apply only in Alaska, and should more clearly provide for balancing measurement accuracy and environmental considerations. According to the commenter, these laws and lease provisions impose heightened restrictions on development in Alaska with which the site security regulations, in particular the requirements for additional measurement facilities, would conflict. The BLM does not agree with the commenter that changes to the rule are necessary. To the extent trade-offs between measurement accuracy and environmental considerations are appropriate, the BLM has already addressed those issues in the rule—see
As noted at the beginning of this Section-by-Section discussion, the BLM has made other changes to provisions in 43 CFR part 3160. Some of those have already been discussed above in connection with provisions of this final rule to which they relate. The remaining revisions are those noted here.
1. The authority citation for part 3160 is corrected to include 25 U.S.C. 396, the grant of rulemaking authority to the Secretary for allotted Indian leases, which does not appear in the current print edition of the CFR. The BLM did not receive any comments on this change.
2. Section 3160.0-3, Authority, is updated to include the amendments to the Federal Oil and Gas Royalty Management Act of 1982 enacted by the Federal Oil and Gas Royalty Simplification Act of 1996. The BLM did not receive any comments on this change.
3. Section 3161.1, Jurisdiction, is updated to include references to FMPs, the Indian Mineral Development Act, and Tribal Energy Resource Agreements. To see the BLM's response to public comment on these changes, please see the discussion of related changes to § 3170.2 earlier in this preamble.
4. Section 3162.3-2 is revised by adding a new paragraph (d), which refers operators to provisions in subpart 3173 for details on how to apply for approval of FMPs, surface or subsurface commingling from different leases, unit PAs and CAs, or off-lease measurement. The BLM did not receive any comments on this change.
5. Section 3162.4-1, Well records and reports, is amended in a number of respects by this final rule. Consistent with the proposed rule, this final rule revises paragraph (a) to make clear that the new recordkeeping requirements also apply to “source records” that are relevant to “determining and verifying the quality, quantity, and disposition of production from or allocable to Federal or Indian leases.” Similarly, paragraph (d) has been revised to establish the new records-retention period established by the 1996 amendments to FOGRMA, and mirror for part 3160 the provisions in paragraphs (c) through (e) of § 3170.7 of the final rule. A new paragraph (e) lists those “record holders” who would be subject to the new recordkeeping requirements. This section also makes clear that all record holders must maintain their records when directed by the Secretary, or his/her designee, in cases where there is a judicial proceeding or demand involving such records. In this section of the previous rule, the Secretary, or his/her designee, could direct record holders to maintain their records only in cases where there was an audit or investigation.
6. Section 3162.4-3, the provisions regarding the no-longer-used Form 3160-6 (the monthly report of operations), is removed. The BLM did not receive any comments on this change.
7. Section 3162.6, Well and facility identification, is revised to correct the misspelled word “indentification” in paragraph (a) to read “identification.” Paragraph (b) is revised to remove a provision allowing abbreviated sign designations and a “grandfathering” provision for old well signs. Paragraph (c) is revised to extend signage requirements to include facilities at which oil or gas produced from Federal or Indian leases is stored or processed. The fifth sentence of the current paragraph (c) becomes the new paragraph (d), with its wording revised. The current paragraph (d) is now paragraph (e). The BLM did not receive any comments on this change.
8. Section 3162.7-1, Disposition of production. This final rule removes paragraph (f), which currently refers to a 6-year retention period, since the initial statutory retention period for records concerning Federal leases is
9. Section 3162.7-5, Site security on Federal and Indian (except Osage Tribe) oil and gas leases, has been removed. The provisions in the final rule that correspond to, or cover the same subject matter as, the several paragraphs in § 3162.7-5 are shown in the following table:
10. Section 3163.2, Civil penalties, is rewritten in several respects by this final rule. The changes being made to this section as part of this rule are a combination of the changes proposed as part of this rulemaking effort and the proposed rule to update and replace Order 5 (80 FR 61645). In addition, following the publication of those proposed rules, but prior to the publication of this rule, the BLM published an interim final rule—Onshore Oil and Gas Operations—Civil Penalties Inflation Adjustments (81 FR 41860)—that made adjustments for inflation to all of the daily civil monetary penalty maximums found in § 3163.2. The adjustments made by the interim final rule were required by the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (Sec. 701 of Pub. L. 114-74).
The BLM is making the following additional changes to § 3163.2 in this final rule. These changes are not a result of the Federal Civil Penalties Inflation Adjustment Act Improvements Act.
First, the BLM is amending the civil penalty regulations to reflect the fact that purchasers and transporters who fail to maintain and submit records as required by the BLM can be subject to civil penalties under Section 109 of FOGRMA (30 U.S.C. 1719). As explained in the proposed rule, this change is being made because the BLM's existing regulations do not reflect this longstanding statutory authority. In order to effectuate this change the BLM is designating the first sentence of paragraph (a) of the existing § 3163.2 as paragraph (a)(1), and adding a new paragraph (a)(2) that reads as follows:
(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 or gas lease, the authorized officer will notify the purchaser or transporter, as appropriate, in writing of the violation. The second sentence of the existing paragraph (a) (pertaining to the maximum amount of the penalty if the violation is not corrected within 20 days of the date of notice) is redesignated as paragraph (b)(1). The existing paragraph (b) (pertaining to the maximum amount of the penalty if the violation is not corrected within 40 days of the date of notice) is redesignated as paragraph (b)(2).
The BLM received a number of comments asserting that it was unfair to subject purchasers and transporters to the civil penalties under the onshore oil and gas regulations because purchasers and transporters often do not have control over the information provided by operators. The BLM does not agree with these comments. As explained above, this change is being driven primarily by longstanding statutory requirements. Additionally, it should be noted that there are instances where the purchaser or transporter actually owns the oil and gas delivery point, and therefore has control of much of the relevant information. With respect to concerns about the accuracy of information provided by an operator to a purchaser or transporter, while entities are generally responsible for the content of their records, the BLM recognizes that such a situation (
In addition to the changes identified above, the BLM is also revising 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. This change is consistent with the statutory language found in Section 109(a) of FOGRMA (30 U.S.C. 1719(a)). It also clarifies that potential penalty liability exists for parties who contract with operating rights owners or operators to perform activities on Federal or Indian leases and who violate applicable regulations, statutes, permits, 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 certain statutes, regulations, permits, and lease terms. The BLM is revising the regulations in this manner in order to enable the agency to hold contractors directly responsible for violations they commit.
In addition, this rule also removes the regulatory caps on civil penalty assessments found in the current regulations paragraphs (b) (paragraph (b)(2) in the final rule), (d), (e), and (f). As explained in the proposed rule to update and replace Order 5 (80 FR 61645), this change is based on
As the BLM explained, it does not believe that the existing regulatory caps provide an adequate deterrence for unlawful conduct, particularly drilling on Federal onshore leases without authorization and drilling into leased parcels in knowing and willful trespass. Similar concerns were expressed by the Department's OIG in a report, dated September 29, 2014—Bureau of Land Management, Federal Onshore Oil & Gas Trespass and Drilling Without Approval (No. CR-IS-BLM-0004-2014). In that report, the OIG specifically questioned the adequacy of the BLM's policies to deter such activities and recommended that the BLM pursue increased monetary fines. Based on the foregoing, the final rule rewrites paragraphs (b) (paragraph (b)(2) in the final rule), (d), (e), and (f) accordingly, to remove the regulatory caps, while maintaining the statutory limits imposed on the amount that may be assessed on a daily basis (30 U.S.C. 1719(a)-(d)), as amended by the BLM's recent interim final rule adjusting those amounts for inflation.
Due to the removal of the regulatory civil penalty caps, the BLM determined that paragraph (j) is unnecessary given that its requirements would have tiered off the expiration of those caps. As a result, this rule removes paragraph (j). The BLM is also deleting 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) are inconsistent with the BLM's removal of regulatory caps on penalties found in paragraphs (b) (paragraph (b)(2) in the final rule), (d), (e), and (f). With respect to paragraphs (g)(2)(i) and (g)(2)(ii), the BLM is removing 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, this rule removes all of paragraph (g) and redesignates existing paragraph (i) as (g). Existing paragraph (h) is unaffected by this rule.
Finally, the BLM is moving 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. As a result, paragraph (k) is removed as part of this rule.
One commenter on the proposed rule to replace Order 5 objected to the BLM's expansion of the civil penalty provision to “purchasers and transporters” and to the change to “any person,” instead of retaining the existing language that limited § 3163.2 to the operating rights owner or operator. That commenter contended that the BLM lacked authority to impose liability on contractors undertaking activities on a Federal or Indian lease. The BLM disagrees with this comment because this change is consistent with Section 109(a) of FOGRMA (30 U.S.C. 1719(a)), which states that “any person” who violates the mineral leasing laws, any rule or regulation issued under those laws, or the terms of any lease or permit shall be liable for civil penalties.
The BLM also heard a range of opinions on the removal of the regulatory civil penalty caps. Some commenters contended that the provisions would result in the imposition of penalties that are excessive, while others supported the change. As explained early in this section, the existing regulatory caps on civil penalties result in maximum penalties that are small relative to the costs of drilling a modern oil and gas well such that the potential deterrent effect of civil penalties is limited. For example, the maximum penalty that could be assessed under existing paragraph (b) is $600,000, which is only 10 percent of the cost of drilling a typical well, which is potentially insufficient to act as a deterrent to non-compliance.
Finally, several commenters suggested that the BLM amend the proposed regulations to require that any time a purchaser, transporter, or contractor receives an INC, a copy be provided to the operating rights owner. The BLM agrees with commenters that adequate notice of potential violations is important; however, it determined that such changes are unnecessary. By existing policy and practice, the BLM addresses INCs to the party who is the subject of the action and does not believe it is appropriate to automatically copy unrelated third parties. Additionally, the regulations already require that if a party is going to be subject to such penalties, it has to receive notice in writing first from the BLM. Thus, under the scenarios identified by the commenters, if they were going to be penalized they would have to first receive a written notice from the BLM identifying the violation(s) in question.
11. Section 3164.1, Onshore Oil and Gas Orders, is revised to remove the reference to Order No. 3, Site Security, from the table in paragraph (b) because the Order is now replaced by this codified final rule.
12. Section 3165.3, Notice, State Director review and hearing on the record, is rewritten in several respects by this final rule. Specifically, consistent with the changes to § 3163.2 and the proposed rule, this rule amends the notice requirements of the existing regulations at 43 CFR 3165.3 to include a provision regarding notice to a purchaser or transporter (who is not an operating rights owner or operator) of a failure to comply with records maintenance or production requirements. This final rule also adopts the changes proposed as part of the Order 5 rulemaking to revise this section to clarify that any person, not just “an operating rights owner or operator” (as previously provided for in paragraph (a)(1)), is subject to a written notice or order of they fail to comply with any provisions of the lease, the regulations in this part, applicable orders or notices, or any other appropriate order of the authorized officer.
In addition, the BLM has also divided the several sentences of the existing paragraph (a) into numbered paragraphs (a)(1) through (a)(7) and added clarifying, nonsubstantive revisions throughout the section. After the first sentence, which has been redesignated as paragraph (a)(1) (and rephrased into active voice), the BLM has added a new paragraph (a)(2) as set out in the regulatory text of this final rule.
In addition, the second and third sentences of existing paragraph (a) are redesignated as paragraph (a)(3), and the fourth, fifth and sixth and seventh sentences are redesignated as paragraphs (a)(4) through (a)(7). The
The BLM conducted extensive public and tribal outreach on this rule both prior to its publication as a proposed rule and during the public comment period on the proposed rule. Prior to the publication of the proposed rule, the BLM held both tribal and public forums to discussion potential changes to the rule. In 2011, the BLM held three tribal meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico (July 13, 2011); and Billings, Montana (August 24, 2011). On April 24 and 25, 2013, the BLM held a series of public meetings in Washington, DC, to discuss draft proposed revisions to Orders 3, 4, and 5. The meetings were webcast so tribal members, industry, and the public across the country could participate and ask questions either in person or over the Internet. Following those meetings, the BLM opened a 36-day informal comment period, during which 13 comment letters were submitted. The comments received during that comment period were summarized in the preamble for the proposed rule (80 FR 58952).
The proposed rule was made available for public comment from September 30, 2015, through December 14, 2015. During that period, the BLM held tribal and public meetings on December 1 (Durango, Colorado), December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North Dakota). The BLM also held a tribal webinar on November 19, 2015. In total, the BLM received 106 comment letters on the proposed rule, the substance of which are addressed in the Section-by-Section analysis of this preamble.
As explained in the background section of this preamble, three outside independent entities—the Subcommittee, the OIG, and the GAO—have repeatedly found that the BLM's oil and gas measurement rules do not provide sufficient assurance that operators pay the royalties due. Specifically, these groups found that the BLM needed updated guidance on oil and gas measurement technologies, to address existing technological advances, as well as technologies that might be developed in the future. These groups have all found that the BLM's existing guidance is “unconsolidated, outdated, and sometimes insufficient,” and more specifically with respect to Order 3, that:
• There was no uniform means of tracking all onshore meters, including information about meter location, identification number, and owner;
• Some BLM State offices have issued their own guidance, which lacks a national perspective; more specifically there were concerns about the lack of uniform national guidance with respect to the review and approval of commingling and off-lease measurements requests; and
• There was insufficient information collected with respect to on-lease royalty-free use.
The final rule addresses these recommendations by establishing uniform national guidance governing the review and approval of FMPs, CAAs, and off-lease measurements. It also requires operators to provide more information about royalty-free use. The provisions of the final rule specifically address modern oil industry practices with respect to each of these, while also updating relevant documentation and recordkeeping requirements in order to ensure that all production is properly accounted for.
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 not significant.
Executive Order 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use 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. The BLM has developed this rule in a manner consistent with these requirements.
The BLM certifies that this final rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601
Of the 6,460 domestic firms involved in crude oil and gas extraction in 2013, U.S. Census data show that 99 percent (or 6,370) had fewer than 500 employees, which means that nearly all U.S. firms involved in oil and gas extraction in 2013 fell within the SBA's size standard of fewer than 1,250 employees. Of the 2,097 firms participating in oil and gas drilling activities in 2013, U.S. Census data show that 2,044 (97 percent) had fewer than 500 employees, which means that nearly all U.S. firms involved in oil and gas support activities in 2013 fell within the SBA's size standard of fewer than 1,000 employees. In 2012, there were 8,877 firms involved in drilling and other support functions, of which 96 percent (8,561) had annual net receipts of no more than $35 million, with a greater number below the SBA's $38.5 million threshold.
In addition to lessees and operators, we must consider the size of the purchaser and transporter firms. There are multiple NAICS categories that could include firms involved in the purchasing and transporting of petroleum from Federal and Indian leases. For example, petroleum refiners could be identified as purchasers. For petroleum refiners (NAICS code 324110), the SBA standard says a small business cannot have more than 1,500 employees or more than 200,000 bbl per calendar day total operable atmospheric crude oil distillation capacity. In that context, capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement such as an exchange agreement or a throughput agreement. Purchasers could also be wholesalers, truck transporters, or natural gas or pipeline operators. For wholesalers, including petroleum wholesalers (NAICS codes 424710 and 424720), the SBA standard for a small entity is one that has fewer than 200 employees. For truck transporters (NAICS subsector
As discussed above, national data, including number of firms, number of employees by firm, and annual receipts by firm, is not discretely identified for purchasers and transporters of petroleum or natural gas. The potentially affected purchasers and transporters will likely be a minor component in any number of the relevant NAICS categories. Of the few NAICS categories where reported employment, receipt, and production data matches up with the SBA size standards, the preponderance of the firms will be considered small entities as defined by the SBA.
Based on the available national data, the preponderance of firms involved in developing, producing, purchasing, and transporting oil and gas from Federal and Indian lands are small entities as defined by the SBA. As such, it appears a substantial number of small entities could be affected by this final rule.
Using the best available data, the BLM estimates there are approximately 3,700 lessees and operators conducting oil and gas operations on Federal and Indian lands that could be affected by this final rule. Additionally, the BLM estimates there are approximately 200 to 300 purchasers and transporters operating on Federal and Indian lands that potentially could be affected by this final 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. Based on the Economic and Threshold Analysis prepared for this final rule, the BLM anticipates the cost of implementing the provisions could reduce the average annual net income of impacted small entities by less than 0.001 percent. Except for the electronic filing requirement, all of the provisions apply to entities regardless of size. However, entities with the greatest activity will likely experience the greatest increase in compliance costs. As a general matter, smaller business entities are more likely to operate a smaller number of sites and FMPs for which they will have to submit the information and documentation that this final rule requires. Copies of the analysis can be obtained from the contact person listed earlier (see
Based on the available information, we conclude that the final rule will 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 final rule is not a major rule under 5 U.S.C. (2), the Small Business Regulatory Enforcement Fairness Act. This rule will not have an annual effect on the economy of $100 million or more. As explained in the Economic and Threshold Analysis, the final rule will increase the estimated ongoing costs associated with the development of Federal and Indian oil and gas resources by an estimated $11.7 million annually for the regulated community. In addition, there will be an estimated one-time cost to the regulated community to implement the new provisions of $31.2 million. The one-time implementation costs will be spread over 3 years, or about $10.4 million per year. As discussed in the Economic and Threshold Analysis, the BLM anticipates the cost of implementing the provisions could reduce the average annual net income of impacted small entities by approximately 0.01 percent.
This rule replaces Order 3 to ensure that oil and gas produced from Federal and Indian leases is properly and securely handled so that these resources are accurately accounted for.
This rule:
• Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, tribal, or local government agencies, or geographic regions; and
• Will 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.
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
• This rule will not “significantly or uniquely” affect small governments. A Small Government Agency Plan is unnecessary.
• This rule will not produce a Federal mandate of $100 million or greater in any single year.
The rule is not a “significant regulatory action” under the Unfunded Mandates Reform Act. The changes in this rule will not impose any requirements on any non-Federal Governmental entity.
Under Executive Order 12630, the rule will not have significant takings implications. A takings implication assessment is not required. This rule will set minimum standards for ensuring that oil and gas produced from Federal and Indian (except the Osage Tribe) oil and gas leases are properly and securely handled, so as to prevent theft and loss and to enable accurate measurement and production accountability. All such actions are subject to lease terms which expressly require that subsequent lease activities be conducted in compliance with applicable Federal laws and regulations. The rule conforms to the terms of those Federal leases and applicable statutes, and as such the rule is not a governmental action capable of interfering with constitutionally protected property rights. Therefore, the rule will not cause a taking of private property or require further discussion of takings implications under this Executive Order.
In accordance with Executive Order 13132, the BLM finds that the rule would not have significant Federalism effects. A Federalism assessment is not required. This rule will 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 will not have direct, substantive, or significant 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 Departmental Manual 2, the BLM evaluated possible effects of the final rule on federally recognized Indian tribes. The BLM approves proposed operations on all Indian onshore oil and gas leases (except Osage Tribe). Therefore, the final rule has the potential to affect Indian tribes. In conformance with the Secretary's policy on tribal consultation, the BLM held tribal consultation meetings to which more than 175 tribal entities were invited, both before the rule was
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July 13, 2011; and
• Billings, Montana on August 24, 2011.
• Tribal workshop and webcast in Washington, DC, on April 24, 2013.
• The BLM hosted a webinar to discuss the requirements of the proposed rule and solicit feedback from affected tribes on November 19, 2015; and
• In-person meetings were held in:
○ Durango Colorado, on December 1, 2015;
○ Oklahoma City, Oklahoma, on December 3, 2015; and
○ Dickinson, North Dakota, on December 8, 2015.
The BLM also met with interested tribes on a one-on-one basis as requested to address questions on the proposed rule prior to the publication of the final rule. In each instance, the purpose of these meetings was to solicit feedback and comments from the tribes. The primary concerns expressed by tribes related to the subordination of tribal laws, rules, and regulations by the proposed rule; tribal representation on the Department's Gas and Oil Measurement Team; and the BLM's Inspection and Enforcement program's ability to enforce the terms of this rule. In general, the tribes, as royalty recipients, expressed support for the goals of the rulemaking, namely accurate measurement. With respect to tribal representation on the Department's Gas and Oil Measurement Team, it should be noted that the team is internal only. That said, the BLM will continue to consult with tribes on measurement issues that impact them and their resources. None of the tribal comments received were directed specifically at this rule's oil measurement requirements, and therefore no changes were made as a result of these comments. While the BLM will continue to address these concerns, none of the concerns affect the substance of the proposed rule.
Under Executive Order 12988, the Office of the Solicitor has determined that the final rule will not unduly burden the judicial system and meets the requirements of Sections 3(a) and 3(b)(2) of the Executive Order. The Office of the Solicitor has reviewed the final rule to eliminate drafting errors and ambiguity. It has been written to minimize litigation, 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 final rule will not impede facilitating cooperative conservation and will 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 involved Federal, tribal, State, and local governments, private for-profit and nonprofit institutions, other nongovernmental entities and individuals in the decision-making via the public comment process. That process provides 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. Collections of information include requests and requirements that an individual, partnership, or corporation obtain information, and report it to a Federal agency. See 44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information collection activities that require approval by the OMB under the PRA. The BLM included an information collection request in the proposed rule. OMB has approved the information collection for the final rule under control number 1004-0207.
Some of the information collection activities in the rule will add new uses and burdens for BLM Form 3160-5, Sundry Notices and Reports on Wells. Form 3160-5 has been approved by OMB for uses enumerated at 43 CFR 3162.3-2, and is one of 17 information collection activities that are included in control number 1004-0137, Onshore Oil and Gas Operations (43 CFR part 3160) (expiration date January 31, 2018).
The information collection activities in this 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 information collection.
Some of the activities will be one-time-only, while others will be ongoing. Similarly, the BLM recognizes that for some of the activities, there will be both an annual burden for some respondents, and a one-time burden for virtually all respondents in the initial implementation. Because of the way the rule is structured, the one-time burdens that are applicable to all respondents are phased-in over 3 years based on production volumes.
The preamble to the proposed rule solicited public comments on the information collection. Those comments, and responses of the BLM, are discussed above in the preamble. All comments—both those pertaining to information collection and other comments—are addressed in the final rule. The comments and BLM responses pertaining specifically to the collection of information are discussed in the Section-by-Section analysis of the following sections of the final rule:
• 3170.7;
• 3173.6 through 3173.9;
• 3173.11 through 3173.13;
• 3173.15;
• 3173.23; and
• 3173.25.
The information-collection activities in this rule are described below.
The information-collection activity in the current version of § 3162.6 has been approved by OMB under control number 1004-0137. The revisions effected by this rule are not expected to exceed the existing burden hours authorized by control number 1004-0137. This activity is not included in the burdens for this rule.
Section 3170.6, a new regulation, authorizes any party that is subject to the regulations in 43 CFR part 3170 to request a variance from any of the regulations in part 3170. While § 3170.6 states that a request for a variance should be filed using the BLM's electronic system, it also allows the use of paper copies of Form 3160-5 (Sundry Notices). Thus, § 3170.6 represents a new use of Form 3160-5, Sundry Notices and Reports on Wells.
Section 3170.7 applies to lessees, operators, purchasers, transporters, and any other person directly involved in producing, transporting, purchasing, selling, or measuring oil or gas through the point of royalty measurement or the point of first sale, whichever is later. This regulation applies to records generated during or for the period for which the lessee or operator has an interest in or conducted operations on the lease, or in which a person is involved in transporting, purchasing, or selling production from the lease. This information collection activity assists the BLM in accurate accounting of oil and gas production.
In general, records from Federal leases must be maintained for 7 years, and records from Indian leases must be maintained for 6 years. Additional details and exceptions are explained below.
For Federal leases, and units or communitized areas that include Federal leases but do not include Indian leases, the record holder must maintain records for 7 years after the records are generated. If a judicial proceeding or demand involving such records is timely commenced, the record holder must maintain such records until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary, her designee, or the applicable delegated State authorizes in writing an earlier release of the requirement to maintain such records.
For Indian leases, and units or communitized areas that include Indian leases but do not include Federal leases, the record holder must maintain records for 6 years after the records are generated. If the Secretary or her designee notifies the record holder that the Department of the Interior has initiated or is participating in an audit or investigation involving such records, the record holder must maintain such records until the Secretary or his designee releases the record holder from the obligation to maintain the records.
For units and communitized areas that include both Federal and Indian leases, if the Secretary or his designee has notified the record holder within 6 years after the records are generated that an audit or investigation involving such records has been initiated, but a judicial proceeding or demand is not commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the unit or communitized area until the Secretary or her designee releases the record holder from the obligation to maintain the records. If a judicial proceeding or demand is commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the unit or communitized area until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or her designee authorizes in writing a release of the requirement to maintain such records before a final nonappealable decision is made or rendered.
For all types of Federal and Indian leases, the lessee, operator, purchaser, and transporter must maintain an audit trail that includes all records, including source records that are used to determine quality, quantity, disposition, and verification of production attributable to a Federal or Indian lease, unit participating area (unit PA), or CA, must include the FMP number or the lease, unit PA, or CA number along with a unique equipment identifier (
• The name of the operator;
• The lease, unit PA, or CA number; and
• The well or facility name and number.
Section 3170.7(h) requires operators, purchasers, and transporters to submit all records, including source records that are relevant to determining the quality, quantity, disposition, and verification of production attributable to Federal or Indian leases, upon request, in accordance with a regulation, written order, Onshore Order, NTL, or COA.
Section 3173.6 requires submission of information when water is drained from a production storage tank. The information is required from the operator, purchaser, or transporter, as appropriate. Previously, the operator was not required to record the volume of hydrocarbons that are in the tank before and after water is drained. As a result, hydrocarbons could be drained with the water and removed without proper measurement and accounting, and without royalties being paid. This information collection activity assists the BLM in accurate accounting of oil and gas produced from Federal and Indian leases.
The following information is required:
• Federal or Indian lease, unit PA, or CA number(s);
• The tank location by land description;
• The unique tank number and nominal capacity;
• Date for opening gauge;
• Opening gauge of the total oil volume and free-water measurements;
• Unique identifying number of each seal removed;
• Closing gauge of the total oil volume measurement; and
• Unique identifying number of each seal installed.
Section 3173.7 requires the submission of information during hot oil, clean-up, or completion operations, or any other situation where the operator removes oil from storage, temporarily uses it for operational purposes, and then returns it to storage on the same lease, unit PA, or CA.
Previously, the operator was not required to record the volume of hydrocarbons removed from storage with the expectation that they will be returned to storage. As a result, the volume of produced hydrocarbons
The following information is required:
• Federal or Indian lease, unit PA, or CA number(s);
• The tank location by land description;
• The unique tank number and nominal capacity;
• Date of the opening gauge;
• Opening gauge measurement;
• Closing gauge measurement;
• Unique identifying number of each seal installed;
• How the oil was used; and
• Where the oil was used (
Section 3173.8 requires operators, transporters, or purchasers to submit a report (either oral or written) no later than the next business day after discovery of an incident of apparent theft or mishandling of production. All oral reports must be followed up with a written incident report within 10 business days of the oral report. By applying not only to operators but also to transporters and purchasers (who often are the first ones to discover theft and mishandling or to recognize suspicious activity), this information collection activity assists in prompt disclosure of theft or mishandling. The incident report must include the following information:
• Company name and name of the person reporting the incident;
• Lease, unit PA, or CA number, well or facility name and number, and FMP number, as appropriate;
• Land description of the facility location where the incident occurred;
• The estimated volume of production removed;
• The manner in which access was obtained to the production or how the mishandling occurred;
• The name of the person who discovered the incident;
• The date and time of the discovery of the incident; and
• Whether the incident was reported to local law enforcement agencies and company security
Section 3173.9 requires operators to measure and record within ± 3 days of the final day of each calendar month an inventory consisting of TOV in storage (less free water). If the inventory is not taken on the final day of each month, it must be estimated based on two measurements no less than 20 days and no more than 31 days apart, based upon the prorated difference between these inventory levels and any sales that have occurred between the two measurements. This information collection activity assists the BLM in accurate accounting of oil and gas production.
For each seal, the operator must maintain a record that includes the unique identifying number of each seal and the valve or meter component on which the seal is or was used; the date of installation or removal of each seal; for valves, the position (open or closed) in which it was sealed; and the reason the seal was removed.
Section 3173.11 requires a site facility diagram for all facilities. Section 3170.3 of the final rule defines “facility” as a site and associated equipment used to:
• Process, treat, store, or measure oil or gas production from or allocated to a Federal or Indian lease, unit, or CA that is located upstream of or at (and including) the approved point of royalty measurement; or
• Store, measure, or dispose of produced water that is located on a lease, unit, or CA.
A site facility diagram is one of the BLM's primary mechanisms for monitoring operators' compliance with measurement regulations and policy. These information collection activities enable the BLM to verify, among other things, royalty-free-use volumes reported by the operator on its OGORs. These activities also enhance production accountability and respond to key recommendations made by the GAO and the OIG. In the long term, this information collection request will eliminate the need for the BLM to obtain the information in connection with a production verification and accountability review.
Paragraphs (a) through (c) of § 3173.11 require that each site facility diagram be submitted with a completed Sundry Notice.
• Reflect the position of the production and water recovery equipment, piping for oil, gas, and water, and metering or other measuring systems in relation to each other, but need not be to scale;
• Commencing with the header, identify all of the equipment, including, but not limited to, the header, wellhead, piping, tanks, and metering systems located on the site, and include the appropriate valves and any other equipment used in the handling, conditioning, or disposal of production and water, and indicate the direction of flow;
• Identify by API number the wells flowing into headers;
• Indicate which valve(s) must be sealed and in what position during the production and sales phases and during the conduct of other production activities (
• Clearly identify the lease, unit PA, or CA to which the diagram applies and the land description of the facility, and the name of the company submitting the diagram, with co-located facilities being identified for each lease, unit PA, or CA; and
• Clearly identify as an attachment all meters and measurement equipment. Specifically identify all approved and assigned FMPs.
If another operator operates a co-located facility, the site facility diagram must depict the co-located facilities on the diagram or list them on an attachment and identify them by company name, facility name(s), lease, unit PA, or CA number, and FMP number(s). When describing co-located facilities operated by one operator, the site facility diagram must include a skeleton diagram of the co-located facility, showing equipment only. For storage facilities common to co-located facilities operated by one operator, one diagram would be sufficient.
If the operator claims royalty-free use, the site facility diagram must clearly identify on the diagram or as an attachment, the equipment for which the operator claims royalty-free use.
Section 3173.11(d) specifies the timing requirements for submission of an updated site facility diagram for facilities for which the BLM will assign an FMP number under § 3173.12. This section applies to both new and existing facilities.
• For facilities that are in service on or after the effective date of the final
• For facilities that are in service before the effective date of the final rule and that have a site facility diagram on file that meets the minimum requirements of the previous rule (
○ Existing facilities are modified;
○ A non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified; or
○ There is a change in operator.
Section 3173.11(e) specifies the timing requirements for submission of an updated site facility diagram for facilities for which the BLM will not assign an FMP number under § 3173.12. This section applies to both new and existing facilities.
• For facilities that are in service on or after the effective date of the final rule, a site facility diagram must be submitted within 30 days after the BLM assigns an FMP number to the facility.
• For facilities that are in service before the effective date of the final rule and that have a site facility diagram on file that meets the minimum requirements of the previous rule (
○ Existing facilities are modified;
○ A non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified; or
○ There is a change in operator.
Section 3173.11(f) specifies that after a site facility diagram has been submitted that complies with the requirements of § 3173.11, operators have an ongoing obligation to update and amend them within 30 days after such facilities are modified, a non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
Section 3173.12 requires operators to obtain BLM approval of FMPs for all measurement points that are used to determine royalties. An FMP is a BLM-approved point where oil or gas produced from a Federal or Indian lease, unit, or CA is measured and the measurement affects the calculation of the volume or quality of production on which royalty is owed. See 43 CFR 3170.3.
This information collection activity provides the BLM with a formal nationwide process for designating and approving the point at which oil or gas must be measured for the purpose of determining royalty. This activity assists the BLM in verifying production. Upon receiving an initial request for an FMP, the BLM will approve it if it meets the requirements of this rule, and assign each FMP a unique identifying number, which the operator, transporter, or purchaser will use when reporting production results to the Office of Natural Resources Revenue (ONRR).
All requests for an FMP must include the following:
• A complete Sundry Notice;
• The applicable Measurement Type Code specified in the BLM's Well Information System (WIS);
• For gas measurement, identification of the operator/purchaser/transporter unique station number, meter tube size or serial number, and type of secondary device;
• For oil measurement, identification of the oil tank number(s) or tank serial number(s) and size of each tank, and whether the oil was measured by LACT or CMS if not measured by tank gauge;
• Where production from more than one well will flow to the requested FMP, a list of the API well numbers associated with the FMP; and
• FMP location by land description.
Section 3173.12(d) requires operators to request a new FMP for new permanent measurement facilities before any production leaves the facility. Each request must meet the requirements listed above.
Section 3173.13(b)(1) requires operators with an approved FMP to submit a Sundry Notice that details any modifications to the FMP within 30 days after the change. These details include, but are not limited to, tank numbers or serial numbers and sizes for oil FMPs, unique station numbers, meter tube sizes or serial numbers, and type of secondary devices for gas FMPs, and for all FMPs with more than one well, the API numbers for all wells associated with the facility. The Sundry Notice must specify what was changed, the effective date, and include, if appropriate, an amended site facility diagram. This information collection activity assists the BLM in accurate accounting of oil and gas production.
A CAA is a formal allocation agreement to combine production from two or more sources (leases, unit PAs, CAs, or non-Federal or non-Indian properties) before the FMP. See 43 CFR 3173.1. This information collection activity helps the BLM obtain the production data that is necessary to verify production from Federal or Indian leases covered by CAAs.
Section 3173.15 requires the following information:
• A completed Sundry Notice seeking approval of commingling and allocation, and of off-lease measurement, if any of the proposed FMPs are outside the boundaries of any of the leases, units, or CAs whose production would be commingled;
• A proposed allocation agreement and a proposed allocation methodology with an example of how the methodology is applied (including allocation of produced water) signed by each operator of each of the leases, unit PAs, or CAs whose production would be included in the CAA;
• A list of all Federal or Indian lease, unit PA, or CA numbers in the proposed CAA, specifying the type of production (
• A topographic map or maps showing the boundaries of all the leases, units, unit PAs, or communitized areas whose production is proposed to be commingled; the location of all existing or planned facilities and relative location of all wellheads and piping included in the CAA, and FMPs existing or proposed to be installed to the extent known or anticipated;
• Documentation demonstrating that each of the leases, unit PAs, or CAs proposed for inclusion in the CAA is producing in paying quantities (or, in the case of Federal leases, is capable of production in paying quantities) pending approval of the CAA; and
• All gas analyses, including Btu content (if the CAA request includes gas) and all oil gravities (if the CAA request includes oil) for previous periods of production from the leases, units, unit PAs, or CAs proposed for inclusion in the CAA, up to 6 years before the date of the application for approval of the CAA. However, gas analysis and oil gravity data is not
If new surface disturbance is proposed on one or more of the leases, units, or CAs, and the surface is managed by the BLM, the application must include a proposed surface use plan of operations for the proposed surface disturbance.
If new surface disturbance is proposed on BLM-managed land outside any of the leases, units, or CAs whose production would be commingled, the application must include a right-of-way grant application, under 43 CFR part 2880 if the FMP is on a pipeline, or under 43 CFR part 2800, if the FMP is a meter or storage tank. Applications for right-of-way (
If new surface disturbance is proposed on Federal land managed by an agency other than the BLM, the application must include written approval from the appropriate surface-management agency.
If a new surface disturbance is proposed on Indian land outside the lease, unit, or communitized area from which the production would be commingled, a right-of-way grant application must be filed under 25 CFR part 169, with the appropriate BIA office.
Section 3173.18 provides that a CAA must be modified when there is modification to the allocation agreement, additional leases, unit PAs, or CAs are proposed for inclusion in the CAA, or any of the leases, unit PAs, or CAs within the CAA terminate or permanently cease production. The following information would be required in a request to modify a CAA:
• A completed Sundry Notice describing the modification requested;
• A new allocation methodology, if appropriate, and an example of how the methodology is applied; and
• Certification by each operator that it agrees to the CAA modification.
This information collection activity helps the BLM obtain the production data that is necessary to verify production from Federal or Indian leases covered by CAAs.
Upon receipt of an operator's request for assignment of an FMP number to a facility associated with a CAA existing on the effective date of the final rule, (1) The BLM may determine that the CAA meets the requirements (at 43 CFR 3173.16) for grandfathering the CAA; or (2) If grandfathering is not appropriate, the BLM will review the CAA for consistency with the minimum standards and requirements for a CAA under 43 CFR 3173.14. The BLM will notify the operator in writing of any inconsistencies or deficiencies. The operator must then correct any inconsistencies or deficiencies that the AO identifies, provide additional information, or request an extension of time, within 20 business days after receipt of the BLM's notice. When the BLM is satisfied that the operator has corrected any inconsistencies or deficiencies, the BLM will terminate the existing CAA and grant a new CAA based on the operator's corrections. If the existing CAA does not meet the applicable standards and the operator does not correct the deficiencies, the BLM may terminate the existing CAA and deny the request for an FMP number for the facility associated with the existing CAA.
A CAA must be modified when there is a modification to the allocation agreement; additional leases, unit PAs, or CAs are proposed for inclusion in the CAA; or any of the leases, unit PAs, or CAs within the CAA terminate or permanently cease production.
To request a modification of a CAA, all operators must submit to the BLM:
• A completed Sundry Notice describing the modification requested;
• A new allocation methodology, including an allocation methodology which includes allocation of produced water and an example of how the methodology is applied, if appropriate; and
• Certification by each operator in the CAA that it agrees to the CAA modification.
A change in operator does not trigger the need to modify a CAA.
Section 3173.20 authorizes the BLM to terminate an approved CAA and allows for the CAA to be terminated by the operator at their request. The operator must submit a Sundry Notice to the BLM requesting the termination in which the notice must identify the FMP(s) for the lease(s), unit(s), or CA(s) previously subject to the CAA.
These information collection activities assist the BLM in reducing discrepancies between operator-allocated volumes, which operators report to ONRR, and the volumes that the BLM calculates during follow-up audits. In accordance with this final rule, the BLM will allow off-lease measurement of production only from a single Federal or Indian lease, unit PA, CA, or CAA, and only at an approved FMP.
Section 3173.23(a) through (j) requires the following information in an application for approval of off-lease measurement:
• A completed Sundry Notice;
• Justification for off-lease measurement;
• A topographic map of appropriate scale showing the boundary of the lease(s), unit(s), or CA(s) from which the production originates, the location of existing or planned facilities, the relative location of all wellheads (including the API number for each well) and piping included in the off-lease measurement proposal, and existing FMPs or FMPs proposed to be installed to the extent known or anticipated;
• The surface ownership of all land on which equipment is, or is proposed to be, located; and
• A statement that indicates whether the proposal includes all, or only a portion of, the production from the lease, unit, or CA and if the proposal includes only a portion of the production, the application would be required to identify the FMP(s) where the remainder of the production from the lease, unit, or CA is measured or is proposed to be measured.
If any of the proposed off-lease measurement facilities are located on non-federally owned surface, the application must include a written concurrence signed by the owner(s) of the surface and the owner(s) of the measurement facilities, including each owner(s)' name, address, and telephone number, granting the BLM unrestricted access to the off-lease measurement facility and the surface on which it is located, for the purpose of inspecting any production, measurement, water
If a proposed off-lease FMP with facilities on BLM land would involve new surface disturbance and consists of a meter or storage tank, or is on a pipeline, a right-of-way grant application must be submitted. Applications for rights-of-way (SF-299) are authorized under control number 0596-0082, which is administered by the U.S. Forest Service on behalf of several Federal agencies. If new surface disturbance if proposed for an FMP that includes facilities on Federal land managed by an agency other than the BLM, written approval is required from that agency. A right-of-way grant application must also be submitted with the appropriate BIA office if any of the proposed facilities are on Indian lands outside of the producing area.
If the operator proposes to use production from the lease, unit or CA as fuel at the off-lease measurement facility without payment of royalty, the application must include an application for approval of off-lease royalty-free use under applicable rules. The BLM is developing the applicable rules and will seek OMB clearance for the information collection activities in those rules.
Section 3173.23(k) provides that to apply for an amendment of an existing approval of off-lease measurement, the operator must submit a completed Sundry Notice required under paragraph (a), and information listed at paragraphs (b) through (j) of § 3173.23 to the extent the previously submitted information has changed. This information collection activity assists the BLM in reducing discrepancies between operator-allocated volumes, which operators report to ONRR, and the volumes that the BLM calculates during follow-up audits.
Upon receipt of an operator's request for assignment of an FMP number for a facility associated with an off-lease measurement approval existing on the effective date of the final rule, the BLM will review the existing approval for consistency with the requirements at 43 CFR 3173.22. The BLM will notify the operator of any inconsistencies or deficiencies. The operator must correct any of the identified flaws, provide additional information, or request an extension of time from the AO, within 20 business days after receiving the notice. This information collection activity assists the BLM in reducing discrepancies between operator-allocated volumes, which operators report to ONRR, and the volumes that the BLM calculates during follow-up audits.
Section 3173.27 authorizes the BLM to terminate an off-lease measurement approval and allows for the off-lease measurement approval to also be terminated by the operator at their request. The operator must submit a Sundry Notice to the BLM requesting the termination in which the notice must identify the new FMP(s) for the lease(s), unit(s), or CA(s) previously subject to the off-lease measurement approval.
The following table itemizes the estimated hour and cost burdens for the information collection activities.
The BLM prepared an environmental assessment (EA), a Finding of No Significant Impact (FONSI), and Decision Record (DR) that concludes that the final rule will not constitute a major Federal action significantly affecting the quality of the human environment under Section 102(2)(C) of the National Environmental Policy Act (NEPA), 42 U.S.C. 4332(2)(C). Therefore, a detailed statement under NEPA is not required. A copy of the EA, FONSI, and DR are available for review and on file in the BLM Administrative Record at the address specified in the
As explained in the EA, FONSI, and DR, the final rule will not have a significant effect on the human environment because, for the most part, its requirements involve changes that are of an administrative, technical, or procedural nature that apply to the BLM's and the lessee's or operator's management processes. For example, operators are now required to maintain records generated for Federal leases for at least 7 years, consistent with statutory requirements. Similarly, the final rule requires more detailed information on site facility diagrams such as information about the equipment for which an operator claims royalty-free use. The submission of this additional information will not result in any on-the-ground impacts. In contrast with these provisions, compliance with some of the rule's other requirements may result in additional surface-disturbing activities (
A draft of the EA was shared with the public during the public comment period on the proposed rule. During that process the BLM received a handful of comments on the EA. Some commenters questioned the BLM's level of NEPA analysis, specifically whether the BLM had met the “hard look” test of describing the environmental consequences of the proposed action, and the BLM's ability to reach a FONSI based on the level of analysis prepared. One commenter requested a complete NEPA revision with formal scoping on the EA and a meaningful socioeconomic analysis. Many commenters questioned the use of three separate EAs to disclose impacts of three separate orders. Those commenters asserted that CEQ regulations require connected actions to be evaluated in a single document and suggested a single EIS to address all three rules.
CEQ's NEPA regulations at 40 CFR 1508.18 identify new or revised agency rules and regulations as an example of a Federal action. Drafting new agency regulations of a technical or administrative nature is a Federal action that is categorically excluded from NEPA review pursuant to 43 CFR 46.210(i). Instead of relying on the categorical exclusion, the BLM chose to complete a more robust level of NEPA documentation in the form of an EA for each of the proposed rules to replace Orders 3, 4, and 5. By preparing an EA for each of the proposed regulations, the BLM was able to disclose the potential environmental effects of the Federal agency decision on each of the regulations. This analysis addressed the impact of each rule individually, as well as the impact of all three rules cumulatively. With respect to socio-economic impacts, the BLM completed an Economic and Threshold Analyses for each of the rules. These analyses were not referenced in the Draft EAs for the rules, but have been addressed in the EAs for the final rules.
Other commenters stated that the BLM understated the potential surface impacts associated with the new rules and did not: (i) Adequately address potential surface impacts to private land; (ii) Address a reasonable range of alternatives; and (iii) Adequately describe the affected environment. As explained in the EA, the BLM anticipates that in the majority of cases, operators will use existing surface disturbances such as existing well pad locations in connection with activities undertaken in compliance with the final rule, which will minimize new surface construction and surface impacts.
Similarly, the codification of BLM regulations does not hinder or prevent development of private minerals. The likelihood of impacts to private surface is low. It is unclear whether private lands would be affected at all by the denial of off-lease measurement agreements and the resultant re-location of measurement facilities on to a lease, CA or unit PA. In the rare instances when new pipelines or other facilities were found to be necessary on private surface, BLM authorization for activities on split estate would include site-specific NEPA documentation, with appropriate project-level mitigation and BMPs. In short, the impact of these provisions on private lands in terms of surface disturbance is likely to be minimal, and any attempt to estimate these impacts would be speculative.
The BLM's obligation under NEPA is to analyze alternatives that would meet the purpose and need for the proposed action and allow for a reasoned choice to be made. As described in the EA, a number of alternatives were considered, but eliminated from detailed study because they did not meet the purpose and need. Similarly, the discussion of the affected environment should only contain data and analysis commensurate in detail with the importance of the impacts, which the BLM anticipates to be minimal. The EA, FONSI, and DR were updated to address these comments, but did not change the BLM's overall analysis of the potential environmental impacts of the rule.
This final rule will not have a substantial direct effect on the nation's energy supply, distribution or use, including a shortfall in supply or price increase. The final rule strengthens the BLM's production accountability requirements for operators of Federal and Indian oil and gas leases. These changes increase recordkeeping requirements, place additional restrictions on CAAs and on off-lease measurement, and provide for significant new immediate assessments for violations of the regulations. All of these changes in the final rule are administrative in nature and will have a one-time average transition cost of about $8,400 per regulated entity and an ongoing annual average cost of about $3,200 per entity per year. Entities with the greatest activity (
In developing this rule, the BLM 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, 515, 114 Stat. 2763A-153).
The principal authors of this final rule are Michael Wade, Senior Oil and Gas
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 measurement, Public lands—mineral resources.
For the reasons set out in the preamble, the Bureau of Land Management amends 43 CFR chapter II as follows:
25 U.S.C. 396, 396d and 2107; 30 U.S.C. 189, 306, 359, and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.
(a) The regulations in this part apply to all operations conducted on:
(1) All Federal and Indian (except those of the Osage Tribe) onshore oil and gas leases;
(2) All onshore facility measurement points where Federal or Indian (except those of the Osage Tribe) oil or gas is measured;
(3) Indian Mineral Development Act agreements for oil and gas, unless specifically excluded in the agreement; and
(4) Leases and other business agreements for the development of tribal energy resources under a Tribal Energy Resource Agreement entered into with the Secretary, unless specifically excluded in the lease, other business agreement, or Tribal Energy Resource Agreement.
(b) The regulations in this part and 43 CFR part 3170, including subparts 3173, 3174, and 3175, relating to site security, measurement of oil and gas, reporting of production and operations, and assessments or penalties for non-compliance with such requirements, are applicable to all wells and facilities on State or privately owned lands committed to a unit or communitization agreement, which include Federal or Indian lease interests, notwithstanding any provision of a unit or communitization agreement to the contrary.
(d) For details on how to apply for approval of a facility measurement point; approval for surface or subsurface commingling from different leases, unit participating areas and communitized areas; or approval for off-lease measurement, see 43 CFR 3173.12, 3173.15, and 3173.23, respectively.
(a) The operator must keep accurate and complete records with respect to:
(1) All lease operations, including, but not limited to, drilling, producing, redrilling, repairing, plugging back, and abandonment operations;
(2) Production facilities and equipment (including schematic diagrams as required by applicable orders and notices); and
(3) Determining and verifying the quantity, quality, and disposition of production from or allocable to Federal or Indian leases (including source records).
(d) All records and reports required by this section must be maintained for the following time periods:
(1) For Federal leases and units or communitized areas that include Federal leases, but do not include Indian leases:
(i) Seven years after the records are generated; unless,
(ii) A judicial proceeding or demand involving such records is timely commenced, in which case the record holder must maintain such records until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or the applicable delegated State authorizes in writing an earlier release of the requirement to maintain such records.
(2) For Indian leases, and units or communitized areas that include Indian leases, but do not include Federal leases:
(i) Six years after the records are generated; unless,
(ii) The Secretary or his/her designee notifies the record holder that the Department has initiated or is participating in an audit or investigation involving such records, in which case the record holder must maintain such records until the Secretary or his/her designee releases the record holder from the obligation to maintain the records.
(3) For units and communitized areas that include both Federal and Indian leases, 6 years after the records are generated, unless the Secretary or his/her designee has notified the record holder within those 6 years that an audit or investigation involving such records has been initiated, then:
(i) If a judicial proceeding or demand is commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the lease, unit or communitization agreement until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or his/her designee authorizes in writing a release of the requirement to maintain such records before a final nonappealable decision is made or rendered;
(ii) If a judicial proceeding or demand is not commenced within 7 years after
(e) Record holders include lessees, operators, purchasers, transporters, and any other person directly involved in producing, transporting, purchasing, or selling, including measuring, oil or gas through the point of royalty measurement or the point of first sale, whichever is later. Record holders must maintain records generated during or for the period for which the lessee or operator has an interest in or conducted operations on the lease, or in which a person is involved in transporting, purchasing, or selling production from the lease, for the period of time required in paragraph (d) of this section.
The revisions and addition read as follows:
(b) For wells located on Federal and Indian lands, the operator must properly identify, by a sign in a conspicuous place, each well, other than those permanently abandoned. The well sign must include the well number, the name of the operator, the lease serial number, and the surveyed location (the quarter-quarter section, section, township and range or other authorized survey designation acceptable to the authorized officer, such as metes and bounds or longitude and latitude). When specifically requested by the authorized officer, the sign must include the unit or communitization agreement name or number. The authorized officer may also require the sign to include the name of the Indian allottee lessor(s) preceding the lease serial number.
(c) All facilities at which oil or gas produced from a Federal or Indian lease is stored, measured, or processed must be clearly identified with a sign that contains the name of the operator, the lease serial number or communitization or unit agreement identification number, as appropriate, and the surveyed location (the quarter-quarter section, section, township and range or other authorized survey designation acceptable to the authorized officer, such as metes and bounds or longitude and latitude). On Indian leases, the sign also must include the name of the appropriate tribe and whether the lease is tribal or allotted. For situations of one tank battery servicing one well in the same location, the requirements of this paragraph and paragraph (b) of this section may be met by one sign as long as it includes the information required by both paragraphs. In addition, each storage tank must be clearly identified by a unique number. With regard to the quarter-quarter designation and the unique tank number, any such designation established by State law or regulation satisfies this requirement.
(d) All signs must be maintained in legible condition and must be clearly apparent to any person at or approaching the storage, measurement, or transportation point.
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.
(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 specified in paragraph (a) of this section 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 $1,031 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) 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 $10,314 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) 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 chapter, the transporter is liable for a civil penalty of up to $1,031 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 is liable for a civil penalty of up to $20,628 per violation for each day such violation continues, if the person:
(f) Any person is liable for a civil penalty of up to $51,570 per violation for each day such violation continues, if the person:
(g) On a case-by-case basis, the Secretary may compromise or reduce civil penalties under this section. In compromising or reducing the amount of a civil penalty, the Secretary will state on the record the reasons for such determination.
(h) Civil penalties provided by this section are supplemental to, and not in derogation of, any other penalties or assessments for noncompliance in any
(a)
(2) Whenever any 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, applicable orders or notices, or any other appropriate orders of the authorized officer, the authorized officer will give written notice or order to the purchaser or transporter to remedy any violations.
(3) Written orders or a notice of violation, assessment, or proposed penalty will be issued and served by personal service by the authorized officer, or by certified mail, return receipt requested. Service will be deemed to occur when the document is received or 7 business days after the date it is mailed, whichever is earlier.
(4) Any person may designate a representative to receive any notice of violation, order, assessment, or proposed penalty on that person's behalf.
(5) In the case of a major violation, the authorized officer will make a good faith effort to contact such designated representative by telephone, to be followed by a written notice or order. Receipt of a notice or order will be deemed to occur at the time of such verbal communication, and the time of notice and the name of the receiving party will be documented in the file. If the good faith effort to contact the designated representative is unsuccessful, notice of the major violation or order may be given to any person conducting or supervising operations subject to the regulations in this part.
(6) In the case of a minor violation, the authorized officer will only provide a written notice or order to the designated representative.
(7) A copy of all orders, notices, or instructions served on any contractor or field employee or designated representative will also be mailed to the operator. Any notice involving a civil penalty against an operator will be mailed to the operator, with a copy to the operating rights owner.
(d)
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.
The authorities for promulgating the regulations in this part are the Mineral Leasing Act, 30 U.S.C. 181
The regulations in this part apply to:
(a) All Federal onshore and Indian oil and gas leases (other than those of the Osage Tribe);
(b) Indian Mineral Development Act (IMDA) agreements for oil and gas, unless specifically excluded in the agreement or unless the relevant provisions of the rule are inconsistent with the agreement;
(c) Leases and other business agreements for the development of tribal energy resources under a Tribal Energy Resource Agreement entered into with the Secretary, unless specifically excluded in the lease, other business agreement, or Tribal Energy Resource Agreement;
(d) State or private tracts committed to a federally approved unit or communitization agreement (CA) as defined by or established under 43 CFR subpart 3105 or 43 CFR part 3180; and
(e) All onshore facility measurement points where oil or gas produced from the leases or agreements identified earlier in this section is measured.
(a) As used in this part, the term:
(i) A site and associated equipment used to process, treat, store, or measure production from or allocated to a Federal or Indian lease, unit PA, or CA that is located upstream of or at (and including) the approved point of royalty measurement; and
(ii) A site and associated equipment used to store, measure, or dispose of produced water that is located on a lease, unit, or communitized area.
(i)
(ii)
(iii)
(b) As used in this part, the following additional acronyms apply:
(a) All by-passes are prohibited.
(b) Tampering with any measurement device, component of a measurement device, or measurement process is prohibited.
(c) Any by-pass or tampering with a measurement device, component of a measurement device, or measurement process may, together with any other remedies provided by law, result in an assessment of civil penalties for knowingly or willfully:
(1) Taking, removing, transporting, using, or diverting oil or gas from a lease site without valid legal authority under 30 U.S.C. 1719(d)(2) and 43 CFR 3163.2(f)(2); or
(2) Preparing, maintaining, or submitting false, inaccurate, or misleading reports, records, or information under 30 U.S.C. 1719(d)(1) and 43 CFR 3163.2(f)(1).
(a) Any party subject to a requirement of a regulation in this part may request a variance from that requirement.
(1) A request for a variance must include the following:
(i) Identification of the specific requirement from which the variance is requested;
(ii) Identification of the length of time for which the variance is requested, if applicable;
(iii) An explanation of the need for the variance;
(iv) A detailed description of the proposed alternative means of compliance;
(v) A showing that the proposed alternative means of compliance will produce a result that meets or exceeds the objectives of the applicable requirement for which the variance is requested; and
(vi) The FMP number(s) for which the variance is requested, if applicable.
(2) A request for a variance must be submitted as a separate document from any plans or applications. A request for a variance that is submitted as part of a master development plan, application for permit to drill, right-of-way application, or application for approval of other types of operations, rather than submitted separately, will not be considered. Approval of a plan or application that contains a request for a variance does not constitute approval of the variance. A separate request for a variance may be submitted simultaneously with a plan or application. For plans or applications that are contingent upon the approval of the variance request, the BLM encourages the simultaneous submission of the variance request and the plan or application.
(3) The party requesting the variance must file the request and any supporting documents using WIS. If electronic filing is not possible or practical, the operator may submit a request for variance on the Form 3160-5, Sundry Notices and Reports on Wells (Sundry Notice) to the BLM Field Office having jurisdiction over the lands described in the application.
(4) The AO, after considering all relevant factors, may approve the variance, or approve it with COAs, only if the AO determines that:
(i) The proposed alternative means of compliance meets or exceeds the objectives of the applicable requirement(s) of the regulation;
(ii) Approving the variance will not adversely affect royalty income and production accountability; and
(iii) Issuing the variance is consistent with maximum ultimate economic recovery, as defined in 43 CFR 3160.0-5.
(5) The decision whether to grant or deny the variance request is entirely within the BLM's discretion.
(6) A variance from the requirements of a regulation in this part does not constitute a variance from provisions of other regulations, including Onshore Oil and Gas Orders.
(b) The BLM reserves the right to rescind a variance or modify any COA of a variance due to changes in Federal law, technology, regulation, BLM policy, field operations, noncompliance, or other reasons. The BLM will provide a written justification if it rescinds a variance or modifies a COA.
(a) Lessees, operators, purchasers, transporters, and any other person directly involved in producing, transporting, purchasing, selling, or measuring oil or gas through the point of royalty measurement or the point of first sale, whichever is later, must retain all records, including source records, that are relevant to determining the quality, quantity, disposition, and verification of production attributable to Federal or Indian leases for the periods prescribed in paragraphs (c) through (e) of this section.
(b) This retention requirement applies to records generated during or for the period for which the lessee or operator has an interest in or conducted operations on the lease, or in which a person is involved in transporting, purchasing, or selling production from the lease.
(c) For Federal leases, and units or CAs that include Federal leases, but do not include Indian leases, the record holder must maintain records for:
(1) Seven years after the records are generated; unless,
(2) A judicial proceeding or demand involving such records is timely commenced, in which case the record holder must maintain such records until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or his/her designee or the applicable delegated State authorizes in writing an earlier release of the requirement to maintain such records.
(d) For Indian leases, and units or CAs that include Indian leases, but do not include Federal leases, the record holder must maintain records for:
(1) Six years after the records are generated; unless,
(2) The Secretary or his/her designee notifies the record holder that the Department of the Interior has initiated or is participating in an audit or investigation involving such records, in which case the record holder must maintain such records until the Secretary or his/her designee releases the record holder from the obligation to maintain the records.
(e) For units and communitized areas that include both Federal and Indian leases, 6 years after the records are generated. If the Secretary or his/her designee has notified the record holder within those 6 years that an audit or investigation involving such records has been initiated, then:
(1) If a judicial proceeding or demand is commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the lease, unit PA, or CA until the final nonappealable decision in such judicial proceeding is made, or with respect to that demand is rendered, unless the Secretary or his/her designee authorizes in writing a release of the requirement to maintain such records before a final nonappealable decision is made or rendered.
(2) If a judicial proceeding or demand is not commenced within 7 years after the records are generated, the record holder must retain all records regarding production from the unit or communitized area until the Secretary or his/her designee releases the record holder from the obligation to maintain the records;
(f) The lessee, operator, purchaser, or transporter must maintain an audit trail.
(g) All records, including source records, that are used to determine quality, quantity, disposition, and verification of production attributable to a Federal or Indian lease, unit PA, or CA, must include the FMP number or the lease, unit PA, or CA number, along with a unique equipment identifier (
(1) The name of the operator;
(2) The lease, unit PA, or CA number; and
(3) The well or facility name and number.
(h) Upon request of the AO, the operator, purchaser, or transporter must provide such records to the AO as may be required by regulation, written order, Onshore Order, NTL, or COA.
(i) All records must be legible.
(j) All records requiring a signature must also have the signer's printed name.
(a) BLM decisions, orders, assessments, or other actions under the regulations in this part are administratively appealable under the procedures prescribed in 43 CFR 3165.3(b), 3165.4, and part 4.
(b) For any recommendation made by the PMT, and approved by the BLM, a party affected by such recommendation may file a request for discretionary review by the Assistant Secretary for Land and Minerals Management. The Assistant Secretary may delegate this review function as he or she deems appropriate, in which case the affected party's application for discretionary review must be made to the person or persons to whom the Assistant Secretary's review function has been delegated.
Noncompliance with any of the requirements of this part or any order
(a) As used in this subpart, the term:
(i) Add liquids to or remove liquids from any tank or piping system, through a valve or combination of valves or by moving liquids from one tank to another tank; or
(ii) Enter any component in a measuring system affecting the accuracy of the measurement of the quality or quantity of the liquid being measured.
(b) As used in this subpart, the following additional acronyms apply:
(a) All lines entering or leaving any oil storage tank must have valves capable of being effectively sealed during the production and sales phases unless otherwise provided under this subpart. During the production phase, all appropriate valves that allow unmeasured production to be removed from storage must be effectively sealed in the closed position. During any other phase (sales, water drain, or hot oiling), and prior to taking the top tank gauge measurement, all appropriate valves that allow unmeasured production to enter or leave the sales tank must be effectively sealed in the closed position (see Appendix A to subpart 3173). Each unsealed or ineffectively sealed appropriate valve is a separate violation.
(b) Valves or combinations of valves and tanks that provide access to the production before it is measured for sales are considered appropriate valves and are subject to the seal requirements of this subpart (see Appendix A to subpart 3173). If there is more than one valve on a line from a tank, the valve closest to the tank must be sealed. All appropriate valves must be in an operable condition and accurately reflect whether the valve is open or closed.
(c) The following are not considered appropriate valves and are not subject to the sealing requirements of this subpart:
(1) Valves on production equipment (
(2) Valves on water tanks, provided that the possibility of access to production in the sales and storage tanks does not exist through a common circulating, drain, overflow, or equalizer system;
(3) Valves on tanks that contain oil that has been determined by the AO or AR to be waste or slop oil;
(4) Sample cock valves used on piping or tanks with a Nominal Pipe Size of 1 inch or less in diameter;
(5) Fill-line valves during shipment when a single tank with a nominal capacity of 500 barrels (bbl) or less is used for collecting marginal production of oil produced from a single well (
(6) Gas line valves used on piping with a Nominal Pipe Size of 1 inch or less used as tank bottom “roll” lines, provided there is no access to the contents of the storage tank and the roll lines cannot be used as equalizer lines;
(7) Valves on tank heating systems that use a fluid other than the contents of the storage tank (
(8) Valves used on piping with a Nominal Pipe Size of 1 inch or less connected directly to the pump body or used on pump bleed off lines;
(9) Tank vent-line valves; and
(10) Sales, equalizer, or fill-line valves on systems where production may be removed only through approved oil metering systems (
(d) Tampering with any appropriate valve is prohibited. Tampering with an appropriate valve may result in an assessment of civil penalties for knowingly or willfully preparing, maintaining, or submitting false, inaccurate, or misleading reports, records, or written information under 30 U.S.C. 1719(d)(1) and 43 CFR 3163.2(f)(1), or knowingly or willfully taking, removing, transporting, using, or diverting oil or gas from a lease site without valid legal authority under 30 U.S.C. 1719(d)(2) and 43 CFR 3163.2(f)(2), together with any other remedies provided by law.
(a) Components used for quantity or quality determination of oil must be effectively sealed to indicate tampering, including, but not limited to, the following components of LACT meters (see § 3174.8(a)) and CMSs (see § 3174.9(e)):
(1) Sample probe;
(2) Sampler volume control;
(3) All valves on lines entering or leaving the sample container, excluding the safety pop-off valve (if so equipped). Each valve must be sealed in the open or closed position, as appropriate;
(4) Meter assembly, including the counter head and meter head;
(5) Temperature averager;
(6) LACT meters or CMS;
(7) Back pressure valve pressure adjustment downstream of the meter;
(8) Any drain valves in the system;
(9) Manual-sampling valves (if so equipped);
(10) Valves on diverter lines larger than 1 inch in nominal diameter;
(11) Right-angle drive;
(12) Totalizer; and
(13) Prover connections.
(b) Each missing or ineffectively sealed component is a separate violation.
(a) In addition to any INC issued for a seal violation, the AO or AR may place one or more Federal seals on any appropriate valve, sealing device, or oil-metering-system component that does not comply with the requirements in §§ 3173.2 and 3173.3 if the operator is not present, refuses to cooperate with the AO or AR, or is unable to correct the noncompliance.
(b) The placement of a Federal seal does not constitute compliance with the requirements of §§ 3173.2 and 3173.3.
(c) A Federal seal may not be removed without the approval of the AO or AR.
(a) When a single truck load constitutes a completed sale, the driver must possess documentation containing the information required in § 3174.12.
(b) When multiple truckloads are involved in a sale and the oil measurement method is based on the difference between the opening and closing gauges, the driver of the last truck must possess the documentation containing the information required in § 3174.12. All other drivers involved in the sale must possess a trip log or manifest.
(c) After the seals have been broken, the purchaser or transporter is responsible for the entire contents of the tank until it is resealed.
When water is drained from a production storage tank, the operator, purchaser, or transporter, as appropriate, must document the following information:
(a) Federal or Indian lease, unit PA, or CA number(s);
(b) The tank location by land description;
(c) The unique tank number and nominal capacity;
(d) Date of the opening gauge;
(e) Opening gauge (gauged manually or automatically), TOV, and free-water measurements, all to the nearest
(f) Unique identifying number of each seal removed;
(g) Closing gauge (gauged manually or automatically) and TOV measurement to the nearest
(h) Unique identifying number of each seal installed.
(a) During hot oil, clean-up, or completion operations, or any other situation where the operator removes oil from storage, temporarily uses it for operational purposes, and then returns it to storage on the same lease, unit PA, or communitized area, the operator must document the following information:
(1) Federal or Indian lease, unit PA, or CA number(s);
(2) Tank location by land description;
(3) Unique tank number and nominal capacity;
(4) Date of the opening gauge;
(5) Opening gauge measurement (gauged manually or automatically) to the nearest
(6) Unique identifying number of each seal removed;
(7) Closing gauge measurement (gauged manually or automatically) to the nearest
(8) Unique identifying number of each seal installed;
(9) How the oil was used; and
(10) Where the oil was used (
(b) During hot oiling, line flushing, or completion operations or any other situation where the operator removes production from storage for use on a different lease, unit PA, or communtized area, the production is considered sold and must be measured in accordance with the applicable requirements of this subpart and reported as sold to ONRR on the OGOR under 30 CFR part 1210 subpart C for the period covering the production in question.
(a) No later than the next business day after discovery of an incident of
(b) The incident report must include the following information:
(1) Company name and name of the person reporting the incident;
(2) Lease, unit PA, or CA number, well or facility name and number, and FMP number, as appropriate;
(3) Land description of the facility location where the incident occurred;
(4) The estimated volume of production removed;
(5) The manner in which access was obtained to the production or how the mishandling occurred;
(6) The name of the person who discovered the incident;
(7) The date and time of the discovery of the incident; and
(8) Whether the incident was reported to local law enforcement agencies and/or company security.
(a) The operator must perform an end-of-month inventory (gauged manually or automatically) that records: TOV in storage (measured to the nearest
(1) The end-of-month inventory must be completed within +/− 3 days of the last day of the calendar month; or
(2) The end of month inventory must be a calculated “end of month” inventory based on daily production that takes place between two measured inventories that are not more than 31, nor fewer than 20, days apart. The calculated monthly inventory is determined based on the following equation:
(b) For each seal, the operator must maintain a record that includes:
(1) The unique identifying number of each seal and the valve or meter component on which the seal is or was used;
(2) The date of installation or removal of each seal;
(3) For valves, the position (open or closed) in which it was sealed; and
(4) The reason the seal was removed.
(a) The operator must submit a Form 3160-5, Sundry Notices and Reports on Wells (Sundry Notice) for the following:
(1) Site facility diagrams (see § 3173.11);
(2) Request for an FMP number (see § 3173.12);
(3) Request for FMP amendments (see § 3173.13(b));
(4) Requests for approval of off-lease measurement (see § 3173.23);
(5) Request to amend an approval of off-lease measurement (see § 3173.23(k));
(6) Requests for approval of CAAs (see § 3173.15); and
(7) Request to modify a CAA (see § 3173.18).
(b) The operator must submit all Sundry Notices electronically to the BLM office having jurisdiction over the lease, unit, or CA using WIS, unless the submitter:
(1) Is a small business, as defined by the U.S. Small Business Administration; and
(2) Does not have access to the Internet.
(a) A site facility diagram is required for all facilities.
(b) Except for the requirement to submit a Form 3160-5, Sundry Notice, with the site facility diagram, no format is prescribed for site facility diagrams. The diagram should be formatted to fit on an 8
(c) The diagram must:
(1) Reflect the position of the production and water recovery equipment, piping for oil, gas, and water, and metering or other measuring systems in relation to each other, but need not be to scale;
(2) Commencing with the header, identify all of the equipment, including, but not limited to, the header, wellhead, piping, tanks, and metering systems located on the site, and include the appropriate valves and any other equipment used in the handling, conditioning, or disposal of production and water, and indicate the direction of flow;
(3) Identify by API number the wells flowing into headers;
(4) If another operator operates a co-located facility, depict the co-located facility(ies) on the diagram or list them as an attachment and identify them by company name, facility name(s), lease, unit PA, or CA number(s), and FMP number(s);
(5) Indicate which valve(s) must be sealed and in what position during the production and sales phases and during the conduct of other production activities (
(6) When describing co-located facilities operated by one operator, include a skeleton diagram of the co-located facility(ies), showing equipment only. For storage facilities common to co-located facilities operated by one operator, one diagram is sufficient;
(7) Clearly identify the lease, unit PA, or CA to which the diagram applies, the land description of the facility, and the name of the company submitting the diagram, with co-located facilities being identified for each lease, unit PA, or CA;
(8) Clearly identify, on the diagram or as an attachment, all meters and measurement equipment. Specifically identify all approved and assigned FMPs; and
(9) If the operator claims royalty-free use, clearly identify the equipment for which the operator claims royalty-free use. The operator must either:
(i) For each engine, motor, or major component (
(ii) Measure the volume used, by meter or tank gauge.
(d) At facilities for which the BLM will assign an FMP number under
(1) For facilities that become operational after January 17, 2017, within 30 days after the BLM assigns an FMP; or
(2) For a facility that is in service on or before January 17, 2017, and that has a site facility diagram on file with the BLM that meets the minimum requirements of Onshore Oil and Gas Order 3, Site Security, an amended site facility diagram meeting the requirements of this section is not due until 30 days after the existing facility is modified, a non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
(e) At facilities for which an FMP number is not required under § 3173.12 (
(1) For new facilities in service after January 17, 2017, the new site facility diagram must be submitted within 30 days after the facility becomes operational; or
(2) For a facility that is in service on or before January 17, 2017, and that has a site facility diagram on file with the BLM that meets the minimum requirements of Onshore Oil and Gas Order 3, Site Security, an amended site facility diagram meeting the requirements of this section is not due until 30 days after the existing facility is modified, a non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
(f) After a site facility diagram has been submitted that complies with the requirements of this part, the operator has an ongoing obligation to update and amend the diagram within 30 days after such facility is modified, a non-Federal facility located on a Federal lease or federally approved unit or communitized area is constructed or modified, or there is a change in operator.
(a)(1) Unless otherwise approved, the FMP(s) for all Federal and Indian leases, unit PAs, or CAs must be located within the boundaries of the lease, unit, or communitized area from which the production originated and must measure only production from that lease, unit PA, or CA.
(2) Off-lease measurement or commingling and allocation of Federal or Indian production requires prior approval (see 43 CFR 3162.7-2, 3162.7-3, 3173.15, 3173.16, 3173.24, and 3173.25).
(b) The BLM will not approve as an FMP a gas processing plant tailgate meter located off the lease, unit, or communitized area.
(c) The operator must submit separate applications for approval of an FMP that measures oil produced from a lease, unit PA, or CA, or under a CAA that complies with the requirements of this subpart, and an FMP that measures gas produced from the same lease, unit PA, or CA, or under a CAA that complies with the requirements of this subpart. This requirement applies even if the measurement equipment or facilities are at the same location.
(d) For a permanent measurement facility that comes into service after January 17, 2017, the operator must apply for approval of the FMP before any production leaves the permanent measurement facility. This requirement does not apply to temporary measurement equipment used during well testing operations. After timely submission and prior to approval of an FMP request, an operator must use the lease, unit PA, or CA number for reporting production to ONRR, until the BLM assigns an FMP number, at which point the operator must use the FMP number for all reporting to ONRR as set forth in § 3173.13.
(e) For a permanent measurement facility in service on or before January 17, 2017, the operator must apply for BLM approval of an FMP within the time prescribed in this paragraph, based on the production level of any one of the leases, unit PAs, or CAs, whether or not they are part of a CAA. The deadline to apply for an FMP approval applies to both oil and gas measurement facilities measuring production from that lease, unit PA, or CA.
(1) For a stand-alone lease, unit PA, or CA that produced 10,000 Mcf or more of gas per month or 100 bbl or more of oil per month, by January 17, 2018.
(2) For a stand-alone lease, unit PA, or CA that produced 1,500 Mcf or more, but less than 10,000 Mcf of gas per month, or 10 bbl or more, but less than 100 bbl of oil per month, by January 17, 2019.
(3) For a stand-alone lease, unit PA, or CA that produced less than 1,500 Mcf of gas per month or less than 10 bbl of oil per month, January 17, 2020.
(4) For a stand-alone lease, unit PA, or CA that has not produced for a year or more before January 17, 2017, the operator must apply for an FMP prior to the resumption of production.
(5) The production levels identified in paragraphs (e)(1) through (3) of this section should be calculated using the average production of oil or gas over the 12 months preceding the effective date of this section or over the period the lease, unit PA, or CA has been in production, whichever is shorter.
(6) If the operator of any facility covered by this section applies for an FMP approval by the deadline in this paragraph, the operator may continue using the lease, unit PA, or CA number for reporting production to ONRR, until the BLM's assigns an FMP number, at which point the operator must use the FMP number for all reporting to ONRR as set forth in § 3173.13.
(7) If the operator fails to apply for an FMP approval by the deadline in this paragraph, the operator will be subject to an INC and may also be subject to an assessment of a civil penalty under 43 CFR part 3160, subpart 3163, together with any other remedy available under applicable law or regulation.
(f) All requests for FMP approval must include the following:
(1) A complete Sundry Notice requesting approval of each FMP;
(2) The applicable Measurement Type Code specified in WIS;
(3) Information about the equipment used for oil and gas measurement, including, for:
(i) “Gas measurement,” specify operator/purchaser/transporter unique station number, primary element (meter tube) size or serial number, and type of secondary device (mechanical or electronic);
(ii) “Oil measurement by tank gauge,” specify oil tank number or tank serial number and size in barrels or gallons for all tanks associated with measurement at an FMP; and
(iii) “Oil measurement by LACT or CMS,” specify whether the equipment is LACT or CMS and the associated oil tank number or tank serial number and size in barrels or gallons (there may be more than one tank associated with an FMP);
(4) Where production from more than one well will flow to the requested FMP, list the API well numbers associated with the FMP; and
(5) FMP location by land description.
(g) Request for approval of an FMP may be submitted concurrently with separate requests for off-lease measurement and/or CAA.
(a) For an existing facility in service on or before January 17, 2017, an operator must start using an FMP number for reporting production to ONRR on its OGOR for the fourth production month after the BLM assigns
(b)(1) The operator must file a Sundry Notice that describes any changes or modifications made to the FMP within 30 days after the change. This requirement does not apply to temporary modifications (
(2) The description must include details such as the primary element, secondary element, LACT/CMS meter, tank number(s), and wells or facilities using the FMP.
(3) The Sundry Notice must specify what was changed and the effective date, and include, if appropriate, an amended site facility diagram (see § 3173.11).
(a) Subject to the exceptions provided in paragraph (b) of this section, the BLM may grant a CAA only if the proposed allocation method used for any such commingled measurement does not have the potential to affect the determination of the total volume or quality of production on which royalty owed is determined for all the Federal or Indian leases, unit PAs, or CAs which are proposed for commingling, and only if the following criteria are met:
(1) The proposed commingling includes production from more than one:
(i) Federal lease, unit PA, or CA, where each lease, unit PA, or CA proposed for commingling has 100 percent Federal mineral interest, the same fixed royalty rate and, and the same revenue distribution;
(ii) Indian tribal lease, unit PA, or CA, where each lease, unit PA, or CA proposed for commingling is wholly owned by the same tribe and has the same fixed royalty rate;
(iii) Federal unit PA or CA where each unit PA or CA proposed for commingling has the same proportion of Federal interest, and which interest is subject to the same fixed royalty rate and revenue distribution. (For example, the BLM could approve a commingling request under this paragraph where an operator proposes to commingle two Federal CAs of mixed ownership and both CAs are 50 percent Federal/50 percent private, so long as the Federal interests have the same royalty rates and royalty distributions.); or
(iv) Indian unit PA or CA where each unit PA or CA proposed for commingling has the same proportion of Indian interests, and which interest is held by the same tribe and has the same fixed royalty rate; and
(2) The operator or operators provide a methodology acceptable to BLM for allocation among the properties from which production is to be commingled (including a method for allocating produced water), with a signed agreement if there is more than one operator;
(3) For each of the leases, unit PAs, or CAs proposed for inclusion in the CAA, the applicant demonstrates to the AO that a lease, unit PA, or CA proposed for inclusion is producing in paying quantities (or, in the case of Federal leases, capable of production in paying quantities) pending approval of the CAA; and
(4) The FMP(s) for the proposed CAA measure production originating only from the leases, unit PAs, or CAs in the CAA.
(b) The BLM may also approve a CAA in instances where the proposed commingling of production involves production from Federal or Indian leases, unit PAs, or CAs that do not meet the criteria of paragraph (a)(1) of this section (
(1) The Federal or Indian lease, unit PA, or CA meets the definition of an economically marginal property. However, if the BLM determines that a Federal or Indian lease, unit PA, or CA included in a CAA ceases to be an economically marginal property, then this condition is no longer met;
(2) The average monthly production over the preceding 12 months for each Federal or Indian lease, unit PA, or CA proposed for the CAA on an individual basis is less than 1,000 Mcf of gas per month, or 100 bbl of oil per month;
(3) A CAA that includes Indian leases, unit PAs, or CAs has been authorized under tribal law or otherwise approved by a tribe;
(4) The CAA covers the downhole commingling of production from multiple formations that are covered by separate leases, unit PAs, or CAs, where the BLM has determined that the proposed commingling from those formations is an acceptable practice for the purpose of achieving maximum ultimate economic recovery and resource conservation; or
(5) There are overriding considerations that indicate the BLM should approve a commingling application in the public interest notwithstanding potential negative royalty impacts from the allocation method. Such considerations could include topographic or other environmental considerations that make non-commingled measurement physically impractical or undesirable, in view of where additional measurement and related equipment necessary to achieve non-commingled measurement would have to be located.
To apply for a CAA, the operator(s) must submit the following, if applicable, to the BLM office having jurisdiction over the leases, unit PAs, or CAs from which production is proposed to be commingled:
(a) A completed Sundry Notice for approval of commingling and allocation (if off-lease measurement is a feature of the commingling and allocation proposal, then a separate Sundry Notice under § 3173.23 is not necessary as long as the information required under § 3173.23(b) through (e) and, where applicable, § 3173.23(f) through (i) is included as part of the request for approval of commingling and allocation);
(b) A completed Sundry Notice for approval of off-lease measurement under § 3173.23, if any of the proposed FMPs are outside the boundaries of any of the leases, units, or CAs from which production would be commingled (which may be included in the same Sundry Notice as the request for approval of commingling and allocation), except as provided in paragraph (a) of this section;
(c) A proposed allocation agreement, including an allocation methodology (including allocation of produced water), with an example of how the methodology is applied, signed by each operator of each of the leases, unit PAs, or CAs from which production would be included in the CAA;
(d) A list of all Federal or Indian lease, unit PA, or CA numbers in the
(e) A topographic map or maps of appropriate scale showing the following:
(1) The boundaries of all the leases, units, unit PAs, or communitized areas whose production is proposed to be commingled; and
(2) The location of existing or planned facilities and the relative location of all wellheads (including the API number) and piping included in the CAA, and existing FMPs or FMPs proposed to be installed to the extent known or anticipated;
(f) A surface use plan of operations (which may be included in the same Sundry Notice as the request for approval of commingling and allocation) if new surface disturbance is proposed for the FMP and its associated facilities are located on BLM-managed land within the boundaries of the lease, units, and communitized areas from which production would be commingled;
(g) A right-of-way grant application (Standard Form 299), filed under 43 CFR part 2880, if the proposed FMP is on a pipeline, or under 43 CFR part 2800, if the proposed FMP is a meter or storage tank. This requirement applies only when new surface disturbance is proposed for the FMP, and its associated facilities are located on BLM-managed land outside any of the leases, units, or communitized areas whose production would be commingled;
(h) Written approval from the appropriate surface-management agency, if new surface disturbance is proposed for the FMP and its associated facilities are located on Federal land managed by an agency other than the BLM;
(i) A right-of-way grant application for the proposed FMP, filed under 25 CFR part 169, with the appropriate BIA office, if any of the proposed surface facilities are on Indian land outside the lease, unit, or communitized area from which the production would be commingled;
(j) Documentation demonstrating that each of the leases, unit PAs, or CAs proposed for inclusion in the CAA is producing in paying quantities (or, in the case of Federal leases, is capable of production in paying quantities) pending approval of the CAA; and
(k) All gas analyses, including Btu content (if the CAA request includes gas) and all oil gravities (if the CAA request includes oil) for previous periods of production from the leases, units, unit PAs, or communitized areas proposed for inclusion in the CAA, up to 6 years before the date of the application for approval of the CAA. Gas analysis and oil gravity data is not needed if the CAA falls under § 3173.14(a)(1).
Upon receipt of an operator's request for assignment of an FMP number to a facility associated with a CAA existing on January 17, 2017, the AO will review the existing CAA and take the following action:
(a) The AO will grandfather the existing CAA and associated off-lease measurement, where applicable, if the existing CAA meets one of the following conditions:
(1) The existing CAA involves downhole commingling that includes Federal or Indian leases, unit PAs, or CAs; or
(2) The existing CAA is for surface commingling and the average production rate over the previous 12 months for each Federal or Indian lease, unit PA, and CA included in the CAA is:
(i) Less than 1,000 Mcf per month for gas; or
(ii) Less than 100 bbl per month for oil.
(b) If the existing CAA does not meet the conditions of paragraphs (a)(1) or (a)(2) of this section, the AO will review the CAA for consistency with the minimum standards and requirements for a CAA under § 3173.14.
(1) The AO will notify the operator in writing of any inconsistencies or deficiencies with an existing CAA. The operator must correct any inconsistencies or deficiencies that the AO identifies, provide the additional information that the AO has requested, or request an extension of time from the AO, within 20 business days after receipt of the AO's notice. When the AO is satisfied that the operator has corrected any inconsistencies or deficiencies, the AO will terminate the existing CAA and grant a new CAA based on the operator's corrections.
(2) The AO may terminate the existing CAA and grant a new CAA with new or amended COAs to make the approval consistent with the requirements under § 3173.14 in connection with approving the requested FMP. If the operator appeals any COAs of the new CAA, the existing CAA approval will continue in effect during the pendency of the appeal.
(3) If the existing CAA does not meet the standards and requirements of § 3173.14 and the operator does not correct the deficiencies, the AO may terminate the existing CAA under § 3173.20 and deny the request for an FMP number for the facility associated with the existing CAA.
(c) If the AO grants a new CAA to replace an existing CAA under paragraph (b) of this section, the new CAA is effective on the first day of the month following its approval. Any new allocation percentages resulting from the new CAA will apply from the effective date of the CAA forward.
A CAA does not constitute approval of off-lease royalty-free use of production as fuel in facilities located at an FMP approved under the CAA.
(a) A CAA must be modified when there is:
(1) A modification to the allocation agreement;
(2) Inclusion of additional leases, unit PAs, or CAs are proposed in the CAA; or
(3) Termination of or permanent production cessation from any of the leases, unit PAs, or CAs within the CAA.
(b) To request a modification of a CAA, all operators must submit to the AO:
(1) A completed Sundry Notice describing the modification requested;
(2) A new allocation methodology, including an allocation methodology which includes allocation of produced water and an example of how the methodology is applied, if appropriate; and
(3) Certification by each operator in the CAA that it agrees to the CAA modification.
(c) A change in operator does not trigger the need to modify a CAA.
(a) If the BLM approves a CAA, the effective date of the CAA is the first day of the month following first production through the FMPs for the CAA.
(b) If the BLM approves a modification, the effective date is the first day of the month following approval of the modification.
(c) A CAA does not modify any of the terms of the leases, units, or CAs covered by the CAA.
(a) The AO may terminate a CAA for any reason, including, but not limited to, the following:
(1) Changes in technology, regulation, or BLM policy;
(2) Operator non-compliance with the terms or COAs of the CAA or this subpart; or
(3) The AO determines that a lease, unit, or CA subject to the CAA has terminated, or a unit PA subject to the CAA has ceased production.
(b) If only one lease, unit PA, or CA remains subject to the CAA, the CAA terminates automatically.
(c) An operator may terminate its participation in a CAA by submitting a Sundry Notice to the BLM. The Sundry Notice must identify the FMP(s) for the lease(s), unit PA(s), or CA(s) previously subject to the CAA. Termination by one operator does not mean the CAA terminates as to all other participating operators, so long as one of the other provisions of this subpart is met and the remaining operators submit a Sundry Notice requesting a new CAA as outlined in paragraph (e) of this section.
(d) The AO will notify in writing all operators who are a party to the CAA of the effective date of the termination and any inconsistencies or deficiencies with their CAA approval that serve as the reason(s) for termination. The operator must correct any inconsistencies or deficiencies that the AO identifies, provide the additional information that the AO has requested, or request an extension of time from the AO, within 20 business days after receipt of the BLM's notice, or the CAA is terminated.
(e) If a CAA is terminated, each lease, unit PA, or CA that was included in the CAA may require a new FMP number(s) or a new CAA. Operators will have 30 days to apply for a new FMP number (§ 3173.12) or CAA (§ 3173.15), if applicable. The existing FMP number may be used for production reporting until a new FMP number is assigned or CAA is approved.
(a)(1) Combining production from a single well drilled into different hydrocarbon pools or geologic formations (
(2) If any of the hydrocarbon pools or geologic formations underlie or are common to more than one of the properties, the operator must establish a unit PA (see 43 CFR part 3180) or CA (see 43 CFR 3105.2-1-3105.2-3), as applicable, rather than applying for a CAA.
(b) Combining production downhole from different geologic formations on the same lease, unit PA, or CA in a single well requires approval of the AO (see 43 CFR 3162.3-2), but it is not considered commingling for production accounting purposes.
The BLM will consider granting a request for off-lease measurement if the request:
(a) Involves only production from a single lease, unit PA, CA, or CAA;
(b) Provides for accurate production accountability;
(c) Is in the public interest (considering factors such as BMPs, topographic and environmental conditions that make on-lease measurement physically impractical, and maximum ultimate economic recovery); and
(d) Occurs at an approved FMP. A request for approval of an FMP (see § 3173.12) may be filed concurrently with the request for off-lease measurement.
To apply for approval of off-lease measurement, the operator must submit the following to the BLM office having jurisdiction over the leases, units, or communitized areas:
(a) A completed Sundry Notice;
(b) Justification for off-lease measurement (considering factors such as BMPs, topographic and environmental issues, and maximum ultimate economic recovery);
(c) A topographic map or maps of appropriate scale showing the following:
(1) The boundary of the lease, unit, unit PA, or communitized area from which the production originates; and
(2) The location of existing or planned facilities and the relative location of all wellheads (including the API number for each well) and piping included in the off-lease measurement proposal, and existing FMPs or FMPs proposed to be installed to the extent known or anticipated;
(d) The surface ownership of all land on which equipment is, or is proposed to be, located;
(e) If any of the proposed off-lease measurement facilities are located on non-federally owned surface, a written concurrence signed by the owner(s) of the surface and the owner(s) of the measurement facilities, including each owner's name, address, and telephone number, granting the BLM unrestricted access to the off-lease measurement facility and the surface on which it is located, for the purpose of inspecting any production, measurement, water handling, or transportation equipment located on the non-Federal surface up to and including the FMP, and for otherwise verifying production accountability. If the ownership of the non-Federal surface or of the measurement facility changes, the operator must obtain and provide to the AO the written concurrence required under this paragraph from the new owner(s) within 30 days of the change in ownership;
(f) A right-of-way grant application (Standard Form 299), filed under 43 CFR part 2880, if the proposed off-lease FMP is on a pipeline, or under 43 CFR part 2800, if the proposed off-lease FMP is a meter or storage tank. This requirement applies only when new surface disturbance is proposed for the FMP and its associated facilities are located on BLM-managed land;
(g) A right-of-way grant application, filed under 25 CFR part 169 with the appropriate BIA office, if any of the proposed surface facilities are on Indian land outside the lease, unit, or communitized area from which the production originated;
(h) Written approval from the appropriate surface-management agency, if new surface disturbance is proposed for the FMP and its associated facilities are located on Federal land managed by an agency other than the BLM;
(i) An application for approval of off-lease royalty-free use (if required under applicable rules), if the operator proposes to use production from the lease, unit, or CA as fuel at the off-lease measurement facility without payment of royalty;
(j) A statement that indicates whether the proposal includes all, or only a portion of, the production from the lease, unit, or CA. (For example, gas, but not oil, could be proposed for off-lease measurement.) If the proposal includes only a portion of the production, identify the FMP(s) where the remainder of the production from the lease, unit, or CA is measured or is proposed to be measured; and
(k) If the operator is applying for an amendment of an existing approval of off-lease measurement, the operator must submit a completed Sundry Notice required under paragraph (a) of this section, and information required under paragraphs (b) through (j) of this section to the extent the information previously submitted has changed.
If the BLM approves off-lease measurement, the approval is effective on the date that the approval is issued, unless the approval specifies a different effective date.
(a) Upon receipt of an operator's request for assignment of an FMP number to a facility associated with an off-lease measurement approval existing on January 17, 2017, the AO will review the existing approved off-lease measurement for consistency with the minimum standards and requirements for an off-lease measurement approval under § 3173.22. The AO will notify the operator in writing of any inconsistencies or deficiencies.
(b) The operator must correct any inconsistencies or deficiencies that the AO identifies, provide any additional information the AO requests, or request an extension of time from the AO, within 20 business days after receipt of the AO's notice. The extension request must explain the factors that will prevent the operator from complying within 20 days and provide a timeframe under which the operator can comply.
(c) The AO may terminate the existing off-lease measurement approval and grant a new off-lease measurement approval with new or amended COAs to make the approval consistent with the requirements for off-lease measurement under § 3173.22 in connection with approving the requested FMP. If the operator appeals the new off-lease measurement approval, the existing off-lease measurement approval will continue in effect during the pendency of the appeal.
(d) If the existing off-lease measurement approval does not meet the standards and requirements of § 3173.22 and the operator does not correct the deficiencies, the AO may terminate the existing off-lease measurement approval under § 3173.27 and deny the request for an FMP number for the facility associated with the existing off-lease measurement approval.
(e) If the existing off-lease measurement approval under this section is consistent with the requirements under § 3173.22, then that existing off-lease measurement is grandfathered and will be part of its FMP approval.
(f) If the BLM grants a new off-lease measurement approval to replace an existing off-lease measurement approval, the new approval is effective on the first day of the month following its approval.
Approval of off-lease measurement does not constitute approval of off-lease royalty-free use of production as fuel in facilities located at an FMP approved under the off-lease measurement approval.
(a) The BLM may terminate off-lease measurement approval for any reason, including, but not limited to, the following:
(1) Changes in technology, regulation, or BLM policy; or
(2) Operator non-compliance with the terms or conditions of approval of the off-lease measurement approval or §§ 3173.22 through 3173.26.
(b) The BLM will notify the operator in writing of the effective date of the termination and any inconsistencies or deficiencies with its off-lease measurement approval that serve as the reason(s) for termination. The operator must correct any inconsistencies or deficiencies that the BLM identifies, provide any additional information the AO requests, or request an extension of time from the AO within 20 business days after receipt of the BLM's notice, or the off lease measurement approval terminates on the effective date.
(c) The operator may terminate the off-lease measurement by submitting a Sundry Notice to the BLM. The Sundry Notice must identify the new FMP(s) for the lease(s), unit(s), or CA(s) previously subject to the off-lease measurement approval.
(d) If off-lease measurement is terminated, each lease, unit PA, or CA that was subject to the off-lease measurement approval may require a new FMP number(s) or a new off-lease measurement approval. Operators will have 30 days to apply for a new FMP number or off-lease measurement approval, whichever is applicable. The existing FMP number may be used for production reporting until a new FMP number is assigned or off-lease measurement is approved.
(a) If the approved FMP is located on the well pad of a directionally or horizontally drilled well that produces oil and gas from a lease, unit, or communitized area on which the well pad is not located, measurement at the FMP does not constitute off-lease measurement. However, if the FMP is located off of the well pad, regardless of distance, measurement at the FMP constitutes off-lease measurement, and BLM approval is required under §§ 3173.22 through 3173.26.
(b) If a lease, unit, or CA consists of more than one separate tract whose boundaries are not contiguous (
(1) The production is moved from one tract within the same lease, unit, or communitized area to another area of the lease, unit, or communitized area on which the FMP is located; and
(2) Production is not diverted during the movement between the tracts before the FMP, except for production used royalty free.
Certain instances of noncompliance warrant the imposition of immediate assessments upon discovery, as prescribed in the following table. Imposition of these assessments does not preclude other appropriate enforcement actions:
Bureau of Land Management, Interior.
Final rule.
This final rule updates and replaces Onshore Oil and Gas Order Number 4, Measurement of Oil (Order 4) with new regulations codified in the Code of Federal Regulations (CFR). It establishes minimum standards for the measurement of oil produced from Federal and Indian (except Osage Tribe) leases to ensure that production is accurately measured and properly accounted for.
The final rule is effective on January 17, 2017. The incorporation by reference (IBR) of certain publications listed in the rule is approved by the Director of the Federal Register as of January 17, 2017.
Mike McLaren, Petroleum Engineer, BLM Wyoming, Pinedale Field Office, 1625 West Pine St., P.O. Box 768, Pinedale, WY 82941, or by telephone at 307-367-5389, for information about the requirements of this final rule; or Steven Wells, Division Chief, Fluid Minerals Division, 202-912-7143, for information regarding the Bureau of Land Management's (BLM's) Fluid Minerals Program. For questions related 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 Relay Service at 800-877-8339 to contact the above individuals during normal business hours. The Service is available 24 hours a day, 7 days a week to leave a message or question with the above individuals. You will receive a reply during normal business hours.
The BLM developed this rule based on the proposed rule published in the
Like the proposed rule, the final rule addresses the use of new oil meter technology, proper measurement documentation, and recordkeeping; establishes performance standards for oil measurement systems; and includes a mechanism for the BLM to review, and approve for use, new oil measurement technology and systems. The final rule expands the acts of noncompliance that would result in an immediate assessment. Finally, it sets forth a process for the BLM to consider variances from these requirements.
Key changes incorporated into the final rule include provisions that allow operators to use Coriolis measurement systems (CMSs) and automatic tank gauging (ATG) systems without having to obtain variances from the BLM.
This final rule, as well as the final rules to update and replace Onshore Oil and Gas Orders Numbers 3 (Order 3) and 5 (Order 5) related to site security and the measurement of gas, respectively, enhance the BLM's overall production verification and accountability program.
The Secretary has the authority under various Federal and Indian mineral leasing laws to manage oil and gas operations on Federal and Indian (except Osage Tribe) lands. Governing laws include, but are not limited to, the Mineral Leasing Act (MLA), 30 U.S.C. 181
The BLM's onshore oil and gas program is one of the most significant mineral-leasing programs in the Federal Government. In the fiscal year (FY) 2015 sales year, onshore Federal oil and gas lease holders sold 180 million barrels of oil,
As explained in the preamble for the proposed rule, given the magnitude of oil production on Federal and Indian lands, and the BLM's statutory and management obligations, it is critically important that the BLM ensure that operators accurately measure, properly report, and account for that production. However, the BLM's rules governing how that oil 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 final rule addresses the outdated nature of existing requirements and helps achieve the BLM's objective of ensuring accurate measurement by updating and replacing Order 4's requirements with regulations codified in the CFR, at a new 43 CFR subpart 3174. These new regulations reflect changes in oil measurement practices and technology since Order 4 was first promulgated in 1989.
These updated requirements are the result of the BLM's evaluation of its existing requirements, based on its experience in the field, and based on the conclusion of multiple reports and evaluations of the BLM's oil and gas program—one by the Subcommittee, issued in 2007; one by the OIG, issued in 2009; and two reports prepared by the GAO, issued in 2010 and 2015. Each of these is described further below.
In 2007, the Secretary appointed an independent panel—the Subcommittee—to review the Department's procedures and processes related to the management of mineral revenues and to provide advice to the Department based on that review.
• BLM policy and guidance have not been consolidated into a single document or publication, resulting in the BLM's 31 oil and gas field offices using varying policies and guidance (see page 31);
• Some BLM policy and guidance are outdated and some policy memoranda have expired (ibid.); and
• Some BLM State Offices have issued their own “Notices to Lessees and Operators” (NTLs) for oil and gas operations. While such NTLs may have a positive effect on local oil and gas field operations, they nevertheless lack a national perspective and may introduce inconsistencies among the States (ibid.).
The Subcommittee specifically recommended that the BLM evaluate Order 4 to determine whether it includes sufficient guidance for ensuring that accurate royalties are paid on Federal oil production. As explained in the preamble to the proposed rule, the Interior Department formed a Fluid Minerals Team, comprising Departmental oil and gas experts. The team determined that Order 4 should be updated in light of changes in technology, the BLM, and industry practices.
As noted, in addition to the Subcommittee report, findings and recommendation addressing similar issues have been issued by the GAO (Report to Congressional Requesters,
In its 2010 report, 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, the Department's policies for tracking where and how oil and gas are measured are not consistent and effective (GAO 2010 Report, 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 p. 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 2015 Report, 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 OIG made similar recommendations based on the Subcommittee's report observing that the BLM should, “(e)nsure that oil . . . regulations are current by updating and issuing onshore orders . . .” (OIG Report, p. 11).
The GAO's recommendations related to the adequacy of the BLM's oil measurement rules are also significant because they form one of the bases for the GAO's inclusion of the BLM's oil and gas program on the GAO's High Risk List in 2011 (Report to Congressional Committees,
Up-to-date measurement requirements are critically important because they help ensure that oil and gas produced from Federal and Indian leases are properly accounted for, thus ensuring that operators pay the proper royalties due.
As explained in more detail below, the final rule makes a number of changes that modernize and strengthen the existing requirements in Order 4. In general, this final rule will give industry more choices and flexibility for measuring oil produced from Federal and Indian leases and will also make it easier for operators in the future to adopt new technologies and processes as the industry continues to advance.
In addition to updating requirements with respect to existing technologies, the final rule also specifically recognizes advances in measurement technology by affirmatively allowing operators to use a CMS
Similarly, operators in newer well fields have been using ATG systems for internal inventory purposes for over 10 years and only recently have they started using them to measure oil for sales and royalty-determination purposes. The BLM reviewed proprietary ATG test data that operators submitted to the BLM—both as public comment on the proposed rule and in support of variance requests to have ATG systems replace manual tank gauging. Based on that review, the BLM believes that ATG/hybrid systems can meet or exceed this rule's tank-gauging standards and as a result they should be expressly allowed. Affirmatively allowing ATG and hybrid systems will also increase worker safety because eliminating the need for workers to climb on top of tanks, open hatches, and manually measure or sample oil reduces their exposure to the fumes coming out of the tanks.
In recognition that new measurement technologies and processes, like CMSs and ATG systems, will continue to be developed and evolve, the final rule puts in place a process and criteria that will allow for a new Production Measurement Team (PMT) to review, and for the BLM to approve for use nationwide, new measurement technologies that are demonstrated to be reliable and accurate.
Recognizing the newness of the PMT process, the final rule includes a 2-year phase-in for that system. Over the next 2 years, the BLM will develop and post on its Web site an uncertainty calculator that will help the BLM and industry determine if a particular measurement system or a new device meets the rule's uncertainty requirements. As an operator designs a new system, the operator can plug its components into the calculator and know before installing the system whether that system meets the requirements, and could be approved by the PMT. Once the BLM approves a new technology for use, it will post the make, model, size, or software version on its Web site as approved for use for all operators nationwide.
With respect to the PMT, it should be noted that while the final rule provides that the PMT will review requests and make recommendations to the BLM for approval, it is the BLM's intent that such approvals will be issued by a BLM AO with authority over the oil and gas program nationally (
In another important departure from Order 4, this final rule avoids, where possible, cookbook-style lists of requirements for operators to follow when determining oil quantity and quality. Instead, in many instances, the rule simply requires operators to follow the applicable industry standards, which were developed through a consensus process by professional industry groups, with input from Federal oil and gas experts. In each instance, the BLM carefully reviewed the applicable standards and determined they are technically sufficient to meet the BLM's production verification needs and are structured in such a way that they can be enforced by BLM personnel in the field. The incorporation of industry standards into the final rule gives operators more flexibility to comply with the requirements of these regulations. For example, Order 4 had one specific way for operators to measure oil temperature—by inserting a thermometer in the approximate vertical center of the fluid column, not less than 12 inches from the tank shell for 5 minutes. The final rule still allows operators to measure oil temperature using this method, but they can now also follow American Petroleum Institute (API) Chapter 7 standards, which provide for operators to use built-in tank thermometers or to take measurements from the flow lines that lead to the haulers' trucks.
The rule also adopts a number of smaller changes which, taken together, will increase measurement accuracy, increase verifiability, and reduce waste. First, it would prohibit the use of automatic temperature/gravity compensators on lease automatic custody transfer (LACT) systems, which are required equipment under Order 4. These compensators automatically
Finally, the rule requires all oil storage tanks, hatches, connections, and other access points to be installed and maintained in accordance with manufacturers' specifications. This requirement, in effect, requires operators to maintain the pressure-vacuum integrity that manufacturers designed and built into their equipment. This in turn will minimize hydrocarbon gas lost to the atmosphere.
As discussed in the background section of this preamble, the BLM's rules concerning oil measurement found in Order 4 have not kept pace with industry standards and practices, statutory requirements, or applicable measurement technology and practices. The final rule enhances the BLM's overall production accountability efforts by addressing these concerns and ensuring that the oil produced from Federal and Indian (except Osage Tribe) leases is adequately accounted for, ultimately ensuring that all royalties due are paid.
The following table provides an overview of the changes between the proposed rule and this final rule. A similar chart explaining the differences between the proposed rule and Order 4 appears in the proposed rule at 80 FR 58955-58956.
This final rule is codified primarily in a new 43 CFR subpart 3174 within a new part 3170. In addition to this rule, the BLM has also prepared separate rules to update and replace Onshore Oil and Gas Order Number 3 (Order 3) (site security), which will be codified at a new 43 CFR subpart 3173; and Onshore Oil and Gas Order Number 5 (Order 5) (gas measurement), which will be codified at a new 43 CFR subpart 3175. The rules to replace Orders 3 and 5 are being published concurrently with this rule. In addition to establishing a new 43 CFR subpart 3173, the rule to replace Order 3 establishes 43 CFR part 3170 and subpart 3170. Subpart 3170 contains definitions of certain terms common to more than one of these rules, as well as other provisions common to all of the rules, such as provisions prohibiting bypass of and tampering with meters; procedures for obtaining variances from the requirements of a particular rule; requirements for recordkeeping, records retention, and submission; and administrative appeal procedures. All of the definitions and substantive provisions of subpart 3170 also apply to this new subpart 3174.
Certain provisions of this final rule will result in amendments to related provisions in the onshore oil and gas operations rules in 43 CFR part 3160. The amendments to those provisions are also discussed below.
Section 3174.1 defines terms and acronyms used in subpart 3174. Defining these terms and acronyms is necessary to ensure consistent interpretation and implementation of this rule. The BLM received a number of comments on this section. Except as noted in this section, the terms and acronyms in § 3174.1 did not change between the draft and final rule. A summary of the definitions and acronyms that were not changed in the final rule may be found in the proposed rule.
Several commenters recommended that base pressure should be defined as 14.696 pounds per square inch, absolute (psia), as opposed to defining it, as in the proposed rule, as the atmospheric pressure or the vapor pressure of the liquid at 60 °F, whichever is higher. Subsequent research has shown that base pressure should be defined as a fixed amount and therefore the BLM agrees with these comments. As a result, the definition of base pressure has been changed to 14.696 psia in the final rule.
Several commenters had concerns about the definition of Coriolis meter and Coriolis metering system (CMS). They suggested we replace the word “measures” in the definition of Coriolis meter with the word “infers.” The BLM agrees with this comment because the Coriolis meter does not actually measure volume directly as a positive displacement (PD) meter does, by isolating the flowing liquid into segments of known volume, but instead analyzes the interaction between the flowing fluid and the oscillation of the tubes. As a result, the definition of Coriolis has been changed to say that a Coriolis meter infers a mass flow rate. Another commenter said the definition of CMS should be changed to say the CMS reports “net standard oil volume” instead of “net oil volume,” while another commenter noted that the Coriolis meter displays “gross,” not “net” standard volumes. The BLM agrees with these suggestions because the Coriolis meter is capable of correcting to gross standard volume, but not capable of deducting the S&W content to derive net standard volumes. The definition has been changed in the final rule to “gross standard volume” as a result of this comment.
Another commenter requested that we include a definition in the rule for “vapor tight.” The proposed rule at § 3174.5(b)(3) required all oil storage tanks, hatches, connections, and other access points to be vapor tight. The BLM agrees that the term “vapor tight” should be defined and has defined the term to mean capable of holding pressure differential only slightly higher than that of installed pressure-relieving or vapor recovery devices.
A few commenters suggested that all of the definitions in the rule should come from the API standards, rather than be the BLM's own customized definitions. After comparing the API definitions against the BLM's definitions in the rule, the BLM does not agree with this suggestion. Not all API definitions fit the terms used in the rule. For example, one commenter said the BLM should use the API definition for LACT systems, which defines turbine meters as an example of a meter that can be part of a LACT system. The BLM disagrees with this comment because the rule does not allow turbine meters to be used at a FMP. The BLM has used many API definitions in the rule, but not all of them are suitable for this rule, therefore, this rule was not changed as a result of these comments.
Three commenters suggested that we include definitions for the acronyms “AO,” authorized officer; “PA,” participating area; and “CA,” communitization agreement. The definitions for the acronyms AO, PA, and CA are included in the definitions section of 43 CFR subpart 3170, which is in a related rulemaking previously discussed. As a result, no change was made to this rule as a result of these comments.
One commenter suggested that we not use the term “registered volume,” but rather the term “indicated volume.” The
One commenter said the term “resistance thermal device” is not a common industry term and suggested we change it to “resistance thermal detector.” As a result of this comment and a review of comments and changes to other sections, the term and definition for “resistance thermal device” has been removed and replaced by the term “transducer.” Transducer has been defined to be an electronic device that converts a physical property—such as pressure, temperature, or electrical resistance—into an electrical output signal that varies proportionally with the magnitude of the physical property. This defines a broader spectrum of devices and can include a resistance thermal detector. This use of the term “transducer” aligns with common industry practice and better suits the BLM's objective of ensuring that there is sufficient flexibility built into the rule.
One commenter suggested that we change our definition of “turbulent flow” to include a reference to the common measure for determining the flow, which is by Reynolds number. Since the final rule does not contain the turbulent-flow requirements that appeared in the proposed rule at § 3174.8(b)(1), the BLM has removed this term from the definitions section.
Based on changes to other sections resulting in new terms being introduced, a definition for “dynamic meter factor” has been included as meaning a kinetic meter factor derived by linear interpolation or polynomial fit, used for conditions where a series of meter factors have been determined over a range of normal operating conditions. In the revised non-prescriptive structure of the final rule, the term “opaque oil” is no longer used, as such the definition has been removed.
Paragraphs (a) through (d) of § 3174.2 refer the reader to other sections in this rule and to 43 CFR subpart 3173, which is addressed in the rulemaking to replace Order 3. That rulemaking contains the requirements for oil storage tanks, on-lease oil measurement, commingling, and FMP numbers, respectively. All comments received on these paragraphs are addressed in the corresponding section discussions later in this preamble and in the preamble for 43 CFR subpart 3173.
Section 3174.2(e) specifies that all equipment used to measure the volume of oil for royalty purposes at an FMP installed after the effective date of this subpart must comply with the requirements of this subpart. The BLM received no comments on this requirement.
Section 3174.2(f) requires that measuring procedures and equipment used to measure oil for royalty purposes that are in use on the effective date of this rule, must comply with the requirements of this subpart on or before the date the operator is required to apply for an FMP number under 3173.12(e) of this part. Prior to that date, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on the effective date of this rule, must continue to comply with the requirements of Onshore Oil and Gas Order No. 4, Measurement of oil, 54 FR 8086 (Feb 24, 1989), and any COAs and written orders applicable to that equipment.
The proposed rule would have required operators to bring existing equipment used at FMPs into compliance within 180 days after the effective date of the final rule. Many commenters said 180 days is not enough time to plan for and bring existing equipment into compliance. The BLM agrees, and in response, this final rule provides a phase-in period of 1 to 4 years after the rule's effective date to bring existing equipment into compliance.
The 1- to 4-year phase-in period is based on the time-frames established for operators to apply for their FMP numbers, which is provided for in 43 CFR 3173.12 and is addressed in a related rulemaking that is updating and replacing Order 3. This modified implementation timeframe in the final rule links compliance with the oil measurement requirement to an operator's production volumes, with lower-volume producers having more time to comply. Under this new approach, the highest 25 percent of the producing leases, CAs, or unit PAs are required to be in compliance the earliest—within 12 months of the effective date of this rule. All remaining leases, CAs, or unit PAs, based on volume thresholds, are staged out over the following 3 years.
Commenters' greatest concern with the 180-day deadline was that it was not enough time to generate new oil-storage-tank calibration tables that would have allowed them to measure volumes in
In the proposed rule, the BLM proposed switching to the
As discussed later in § 3174.6, the BLM has decided to retain the
Some commenters argued that existing equipment used at FMPs should not have to meet any deadline for coming into compliance with this rule's requirement and should instead be exempted from complying entirely (that is, grandfathered).
For example, one commenter said the BLM should grandfather all existing
Another commenter said, as an alternative to grandfathering, equipment serving low-volume and marginal FMPs should be exempted from the requirements. The BLM does not see a need for this exemption because low-volume or marginal wells will, in most cases, be measured by manual tank gauging. Since the tank-gauging requirements in this final rule have not changed relative to the requirements in Order 4, this change was unnecessary.
Another commenter disagreed with the proposed rule's prohibition of automatic temperature/gravity compensators. These compensators should be grandfathered, the commenter said, as long as an audit trail exists whereby the raw data is available and the final results from the compensators can be recreated from this data. The commenter further stated that systems that cannot provide such data should be grandfathered in the final rule. The BLM disagrees. The fact remains that automatic compensator systems alter the raw data before any audit trail is created. They automatically change a meter's totalizer readings, erasing the raw data that the BLM and the operator need to verify that the compensators are functioning correctly and that the totalizer reading is correct.
Another commenter said that if existing equipment is not grandfathered, operators may need to install new LACT units in order to comply, which in turn would require operators to re-pipe their wells. According to this commenter, this would result in undue surface disturbance, excessive expenses, strain on the labor force, and wells that are currently in secondary recovery or that do not produce large amounts of oil being plugged prematurely, leaving behind undeveloped and valuable resources. The BLM disagrees with this interpretation of the rule's requirements. The only equipment that would have to be replaced at an FMP under both the proposed and final rules is the automatic temperature/gravity compensator, which is only one component of a PD meter of a LACT unit. Operators must replace these devices with temperature averagers, which allow operators to collect and retain the raw data the BLM needs to verify results and confirm and preserve system functionality. Based on the BLM's experience, this replacement can occur without replacing the entire LACT system. Additionally, as explained elsewhere in this preamble, most existing LACT systems do not use automatic temperature/gravity compensators.
One commenter said the midstream sector (the pipeline companies and processing plants at or downstream of the meters) would suffer if the rule does not grandfather existing equipment. The commenter did not explain or specify any negative impacts on the midstream sector from the requirement that operators replace automatic temperature/gravity compensators on LACTs. The BLM is not aware of any negative impacts this would have on the midstream sector and the commenter did not provide any information on how the midstream sector will suffer from accurate, verifiable measurement on a lease, PA, or CA. As a result, the BLM does not agree with the commenter and no change has been made to the rule based on this comment.
Several commenters said properly operating equipment should be grandfathered, and, if it must be replaced, operators should be allowed to negotiate installation timeframes with local BLM field offices. The BLM believes that this recommendation would perpetuate the problem of program requirements being inconsistently applied from state to state or field office to field office and therefore did not change the rule as a result of these comments. One of the primary goals of this final rule is to provide some nationwide consistency as to the application of these requirements.
Another commenter said that existing facilities and equipment should be grandfathered because operators could not afford an “investment of this magnitude” to retrofit equipment to meet the new standards. The commenter did not provide any details regarding what is meant by an “investment of this magnitude.” The BLM disagrees with the implication that replacing automatic temperature/gravity compensators on a LACT is a significant investment. The cost to replace automatic temperature/gravity compensators on LACT systems with temperature averagers is relatively minor—approximately $6,500 per system. No change resulted from this comment.
The BLM does not believe that existing equipment should be grandfathered. For years, the GAO and industry have voiced concerns that the BLM's measurement regulations are outdated and make it harder for the BLM to have reasonable assurance that production is being accurately measured and verified. This rule aims to address these concerns at both new and existing facilities.
Section 3174.2(g) exempts meters that are used for allocation measurement as part of commingling approvals from complying with the requirements of this subpart. Commingling approvals will be governed under new requirements in 43 CFR 3173.14, which are addressed in the rulemaking that is updating and replacing Order 3. One commenter said that meters used for allocating production from wells in approved commingling arrangements or that are in the same unit, PA, or CA should be required to meet API standards for allocation measurement. The commenter did not state a reason for this suggestion. Since the BLM does not want to impose blanket allocation measurement requirements that may not be relevant to every situation, it did not adopt this suggestion. Instead, the final rule retains the AO's discretion to include those requirements as a condition of approval on a case-by-case basis.
This section previously appeared as § 3174.4 in the proposed rule, but based on edits made to the final rule, this section and proposed § 3174.3 have been switched. All comments discussed below were submitted for the previously proposed § 3174.4.
This rule incorporates a number of industry standards and recommended practices, either in whole or in part, without republishing the standards in their entirety in the CFR, a practice known as IBR. These standards have been developed through a consensus process, facilitated by the API, with input from the oil and gas industry and Federal agencies with oil and gas operational oversight responsibilities. The BLM has reviewed these standards
Some of the standards referenced in this section have been incorporated in their entirety. For other standards, the BLM incorporates only those sections that are relevant to the rule, meet the intent of § 3174.3 of the rule, and do not need further clarification.
The incorporation of industry standards follows the requirements found in 1 CFR part 51. The industry standards in this final rule are eligible for incorporation under 1 CFR 51.7 because, among other things, they will substantially reduce the volume of material published in the
All of the API materials that the BLM is incorporating 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 and purchase 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 standards that the BLM has incorporated by reference into this rule:
API Manual of Petroleum Measurement Standards (MPMS) Chapter 2—Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, February 1995; Reaffirmed February 2012 (“API 2.2A”). This standard describes the procedures for calibrating upright cylindrical tanks used for storing oil.
API MPMS Chapter 2—Tank Calibration, Section 2.2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method; First Edition, March 1989; Reaffirmed January 2013 (“API 2.2B”). This standard describes measurement and calibration procedures for determining the diameters of upright welded cylindrical tanks, or vertical cylindrical tanks with a smooth surface and either floating or fixed roofs.
API MPMS Chapter 2—Tank Calibration, Section 2C, Calibration of Upright Cylindrical Tanks Using the Optical-triangulation Method; First Edition, January 2002; Reaffirmed May 2008 (“API 2.2C”). This standard describes a calibration procedure for applications to tanks above 26 feet in diameter with cylindrical courses that are substantially vertical.
API MPMS Chapter 3, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products; Third Edition, August 2013 (“API 3.1A”). This standard describes the following: (a) The procedures for manually gauging the liquid level of petroleum and petroleum products in non-pressure fixed roof tanks; (b) Procedures for manually gauging the level of free water that may be found with the petroleum or petroleum products; (c) Methods used to verify the length of gauge tapes under field conditions and the influence of bob weights and temperature on the gauge tape length; and (d) Influences that may affect the position of gauging reference point (either the datum plate or the reference gauge point).
API MPMS Chapter 3—Tank Gauging, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 2011 (“API 3.1B”). This standard describes the level measurement of liquid hydrocarbons in stationary, above ground, atmospheric storage tanks using automatic tank gauges (ATG). This standard discusses automatic tank gauging in general, accuracy, installation, commissioning, calibration, and verification of ATG that measure either innage or ullage.
API MPMS Chapter 3—Tank Gauging, Section 6, Measurement of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, February 2001; Errata September 2005; Reaffirmed October 2011 (“API 3.6”). This standard describes the selection, installation, commissioning, calibration, and verification of Hybrid Tank Measurement Systems. This standard also provides a method of uncertainty analysis to enable users to select the correct components and configurations to address for the intended application.
API MPMS Chapter 4—Proving Systems, Section 1, Introduction; Third Edition, February 2005; Reaffirmed June 2014 (“API 4.1”). Section 1 is a general introduction to the subject of proving meters.
API MPMS Chapter 4—Proving Systems, Section 2, Displacement Provers; Third Edition, September 2003; Reaffirmed March 2011 (“API 4.2”). This standard outlines the essential elements of meter provers that do, and also do not, accumulate a minimum of 10,000 whole meter pulses between detector switches, and provides design and installation details for the types of displacement provers that are currently in use. The provers discussed in this chapter are designed for proving measurement devices under dynamic operating conditions with single-phase liquid hydrocarbons.
API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth Edition, June 2016 (“API 4.5”). This standard covers the use of displacement and Coriolis meters as master meters. The requirements in this standard are for single-phase liquid hydrocarbons.
API MPMS Chapter 4—Proving Systems, Section 6, Pulse Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed October 2013 (“API 4.6”). This standard describes how the double-chronometry method of pulse interpolation, including system operating requirements and equipment testing, is applied to meter proving.
API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second Edition September 2013 (“API 4.8”). This standard provides information for operating meter provers on single-phase liquid hydrocarbons.
API MPMS Chapter 4—Proving Systems, Section 9, Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2, Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration; First Edition, December 2005; Reaffirmed July 2015 (“API 4.9.2”). This standard covers all of the procedures required to determine the field data necessary to calculate a Base Prover Volume of Displacement Provers by the Waterdraw Method of Calibration.
API MPMS Chapter 5—Metering, Section 6, Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; Reaffirmed November 2013 (“API 5.6”). This standard is applicable to custody-
API MPMS Chapter 6—Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed May 2012 (“API 6.1”). This standard describes the design, installation, calibration, and operation of a LACT system.
API MPMS Chapter 7, Temperature Determination; First Edition, June 2001; Reaffirmed February 2012 (“API 7”). This standard describes the methods, equipment, and procedures for determining the temperature of petroleum and petroleum products under both static and dynamic conditions.
API MPMS Chapter 7.3, Temperature Determination—Fixed Automatic Tank Temperature Systems, Second Edition, October 2011 (“API 7.3”). This standard describes the methods, equipment, and procedures for determining the temperature of petroleum and petroleum products under static conditions using automatic methods.
API MPMS Chapter 8, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; Fourth Edition, October 2013 (“API 8.1”). This standard covers procedures and equipment for manually obtaining samples of liquid petroleum and petroleum products from the sample point into the primary containers.
API MPMS Chapter 8, Section 2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; Third Edition, October 2015 (“API 8.2”). This standard describes general procedures and equipment for automatically obtaining samples of liquid petroleum, petroleum products, and crude oils from a sample point into a primary container.
API MPMS Chapter 8—Sampling, Section 3, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products; First Edition, October 1995; Errata March 1996; Reaffirmed, March 2010 (“API 8.3”). This standard covers the handling, mixing, and conditioning procedures required to ensure that a particular representative sample of the liquid petroleum or petroleum product is delivered from the primary sample container/receiver into the analytical test apparatus or into intermediate containers.
API MPMS Chapter 9, Section 1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method; Third Edition, December 2012 (“API 9.1”). This standard covers the determination, using a glass hydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less.
API MPMS Chapter 9, Section 2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third Edition, December 2012 (“API 9.2”), This standard covers the determination of the density or relative density of light hydrocarbons including liquefied petroleum gases having a Reid vapor pressure exceeding 101.325 kPa (14.696 psi).
API MPMS Chapter 9, Section 3, Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method; Third Edition, December 2012 (“API 9.3”). This standard covers the determination, using a glass thermohydrometer in conjunction with a series of calculations, of the density, relative density, or API gravity of crude petroleum, petroleum products, or mixtures of petroleum and nonpetroleum products normally handled as liquids and having a Reid vapor pressure of 101.325 kPa (14.696 psi) or less.
API MPMS Chapter 10 Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure); Fourth Edition, October 2013; Errata March 2015 (“API 10.4”). This standard describes the field centrifuge method for determining both water and sediment, or sediment only, in crude oil.
API MPMS Chapter 11—Physical Properties Data, Section 1, Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils; May 2004; Addendum 1, September 2007; Reaffirmed August 2013 (“API 11.1”). This standard provides the algorithm and implementation procedure for the correction of temperature and pressure effects on density and volume of liquid hydrocarbons that fall within the categories of crude oil.
API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1, Introduction; Second Edition, May 1995; Reaffirmed March 2014 (“API 12.2.1”). This standard provides standardized calculation methods for the quantification of liquids and the determination of base prover volumes under defined conditions. The standard specifies the equations for computing correction factors, rules for rounding, calculational sequences, and discrimination levels to be employed in the calculations.
API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; Third Edition, June 2003; Reaffirmed September 2010 (“API 12.2.2”). This standard provides standardized calculation methods for the quantification of liquids and specifies the equations for computing correction factors, rules for rounding, calculation sequences, and discrimination levels to be employed in the calculations.
API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3, Proving Report; First Edition, October 1998; Reaffirmed March 2009 (“API 12.2.3”). This standard provides standardized calculation methods for the determination of meter factors under defined conditions. The criteria contained here will allow different entities using various computer languages on different computer hardware (or by manual calculations) to arrive at identical results using the same standardized input data. This document also specifies the equations for computing correction factors, including the calculation sequence, discrimination levels, and rules for rounding to be employed in the calculations.
API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4, Calculation of Base Prover Volumes by the Waterdraw Method; First Edition, December, 1997; Reaffirmed March 2009; Errata July 2009 (“API 12.2.4”). This standard provides standardized calculation methods for the quantification of liquids and the determination of base prover volumes under defined conditions. The criteria contained in this document allow different individuals, using various computer languages on different computer hardware (or manual calculations), to arrive at identical results using the same standardized
API MPMS Chapter 13—Statistical Aspects of Measuring and Sampling, Section 1, Statistical Concepts and Procedures in Measurements; First Edition, June 1985; Reaffirmed February 2011, Errata July 2013 (“API 13.1”). This standard covers the basic concepts involved in estimating errors by statistical techniques and ensuring that results are quoted in the most meaningful way. This standard also discusses the statistical procedures that should be followed in estimating a true quantity from one or more measurements and in deriving the range of uncertainty of the results.
API MPMS Chapter 13, Section 3, Measurement Uncertainty; First Edition, May 2016 (“API 13.3”). This standard establishes a methodology for developing an uncertainty analysis.
API MPMS Chapter 14, Section 3/American Gas Association Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, Section 12, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata July 2013 (“API 14.3”). This standard provides reference for engineering equations and uncertainty estimations.
API MPMS Chapter 18—Custody Transfer, Section 1, Measurement Procedures for Crude Oil Gathered From Small Tanks by Truck; Second Edition, April 1997; Reaffirmed February 2012 (“API 18.1”). This standard describes the procedures, organized into a recommended sequence of steps, for manually determining the quantity and quality of crude oil being transferred under field conditions.
API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from Lease tanks Using Alternative Measurement Methods, First Edition, July 2016 (“API 18.2”). This standard defines the minimum equipment and methods used to determine the quantity and quality of oil being loaded from a lease tank to a truck trailer without requiring direct access to a lease tank gauge hatch.
API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed August 2011 (“API 21.2”). This standard provides for the effective utilization of electronic liquid measurement systems for custody-transfer measurement of liquid hydrocarbons.
API Recommended Practice (RP) 12R1, Setting, Maintenance, Inspection, Operation and Repair of Tanks in Production Service; Fifth Edition, August 1997; Reaffirmed April 2008 (“API RP 12R1”). This recommended practice is a guide on new tank installations and maintenance of existing tanks. Specific provisions of this recommended practice are identified as requirements in this final rule.
API RP 2556, Correction Gauge Tables for Incrustation; Second Edition, August 1993; Reaffirmed November 2013 (“API RP 2556”). This recommended practice provides for correcting gauge tables for incrustation applied to tank capacity tables. The tables given in this recommended practice show the percent of error of measurement caused by varying thicknesses of uniform incrustation in tanks of various sizes.
The BLM received numerous comments addressing the incorporation by reference documents. Several commenters were concerned that the BLM was not incorporating the most recent versions of API standards. The API standards are dynamic standards that are constantly being reviewed and updated. The commenters referred to standards that were updated and published either after the proposed rule published or during the BLM's final internal review process before publishing the proposed rule. The BLM generally agrees with the commenters that the latest editions of industry standards should be incorporated and has made the change here after reviewing the latest version of the standards to confirm they will satisfy the applicable requirements.
Several commenters said that some of the incorporated materials in the proposed rule were in conflict. For example, ASTM D1250-1980 version tables 5A and 6A for temperature and gravity correction factors and API 11.1 for the correction of temperature effects on density and volume provide differing correction factors that may result in different corrected oil volumes. The BLM agrees with these comments and has removed ASTM D1250-1980 tables 5A and 6A from the list of incorporated materials. The final rule now refers to API 11.1 for calculations of temperature and pressure effects on density and volume.
Several commenters expressed concern that the BLM will not be updating the incorporated industry standards as new versions are published. The BLM is aware of the need to continuously monitor the industry standards as they are revised and updated, and intends to draft guidance to ensure that the BLM's rules and the incorporated standards they reference are kept up-to-date as technology and practices change. Under the applicable IBR rules, however, the BLM cannot automatically incorporate updated versions of standards into BLM regulations. The rules require that BLM reference the specific version of any particular standard being incorporated. Recognizing that these standards are continually being updated, the BLM intends to undertake periodic rulemakings to make corresponding updates to the relevant regulations. In the interim, an operator could submit a request to the PMT for a variance to comply with a newer version of a standard in lieu of compliance with the version listed above.
Many commenters said the BLM should rewrite the rule to be less prescriptive, to primarily reference industry standards, and to include additional API standards that would expand industry options for achieving accurate measurement. They argued that a highly prescriptive rule would discourage industry from adopting new technology as it becomes available. Upon careful consideration of these comments, the BLM has decided to take a less prescriptive approach that will achieve the ultimate goal of accurate measurement, while still maintaining our requirements for an audit trail and production accountability, and that will provide reasonable versatility for operators. The rule has been modified to be less prescriptive than the proposed rule and includes more industry standards that operators may choose from to comply with the requirements of the final rule. For example, the tank gauging section at § 3174.6 has been rewritten to refer more to industry standards and less to step-by-step instructions and requirements. Proposed § 3174.6(b)(3) had a list of requirements for taking oil samples prior to the opening gauge and was geared towards manual tank gauging. Section 3174.6(b)(3) of the final rule instead requires operators to follow one of two industry standards for taking oil samples prior to the opening gauge—API 8.1 for manual sampling or API 8.2 for sampling by automatic sampling systems. This paves the way for operators to use hybrid tank measurement systems and any other new technology that may come along in the coming years. Where necessary, the rule enhances or modifies an industry standard to ensure that the BLM's audit trail and production accountability
Several commenters had the opposite view and said the BLM should not incorporate industry standards, but rather make its regulations predominantly prescriptive, explicitly stating what is allowed and required. Their reasoning for this approach was that API RPs are optional for industry to consider following, while industry must follow BLM regulations. The BLM disagrees with the commenter's description of how these rules will be applied. Under the final rule, operators are required to comply with industry standards or practices that are incorporated by reference. As discussed earlier, the BLM has decided to take a less prescriptive approach and, where possible, incorporate multiple industry standards to give operators a choice for achieving a particular measurement standard.
Several commenters said the BLM should incorporate forthcoming industry standards that have not yet been finalized into the rule. The BLM cannot incorporate a standard that an industry trade association has not yet published. An unpublished standard is subject to change. It is possible the trade association creating the standard could completely rewrite the draft standard after the BLM incorporated it into this rule, in ways that would compromise the BLM's ability to enforce audit-trail or production-accountability requirements. The BLM disagrees with these comments and has not incorporated any unpublished standards into the rule.
One commenter suggested the BLM not incorporate industry standards but rather copy industry standard language directly into the rule. Copyright restrictions prevent the BLM from taking this course of action. Also this approach makes it harder for the BLM to update these requirements in the future. The final rule was not revised as a result of this comment.
Another commenter said the BLM is statutorily prohibited from cherry-picking industry standards for inclusion in the rule—picking and choosing which standards to apply and which to ignore. The BLM disagrees with this comment. Some industry standards do not meet the rule's goals and objectives and have not been incorporated. For example, there are industry standards for turbine meters, but the BLM does not allow these meters to be used at an FMP because, in some situations, they do not meet the BLM's accuracy requirements.
Several commenters said that incorporating industry standards puts an unreasonable financial burden on industry because it forces industry to purchase the published standards from the trade groups that create them. The BLM agrees that the cost of purchasing a complete set of industry standards is not insignificant. However, the API provides the public free, read-only access to most of the standards incorporated in this final rule. In addition, all incorporated material is available for inspection at the BLM's Division of Fluid Minerals, 20 M Street SE., Washington, DC 20003, and at all BLM offices with jurisdiction over oil and gas activities. It is also available for inspection at the National Archives and Records Administration (NARA). Several commenters stated that the BLM has not made a good effort to provide these newly required standards for public review. The BLM disagrees with this comment. As stated earlier, all industry standards incorporated by reference are available for inspection at the BLM, Division of Fluid Minerals, and at all BLM offices with jurisdiction over oil and gas activities.
The commenter also said the documents are not available in the BLM's Washington Office or in any particular field office. The BLM disagrees. The documents are available for review in the BLM's Washington Office and in all local offices that have jurisdiction over oil and gas activities. It has come to the BLM's attention that some local office personnel may not be aware of how to access the incorporated standards and, as part of the implementation process for the final rule, the BLM plans to carry out a training program to ensure that field office staff can readily access the standards as needed.
Several commenters expressed concern about who is responsible for complying with the incorporated standards—operators or their contractors. The incorporated standards are regulatory requirements, and operators are responsible for ensuring that third parties that do not have a contractual relationship with the BLM comply with the incorporated industry standards. Existing BLM regulations at 43 CFR 3162.3 state that a contractor on a leasehold will be considered the agent of the operator for such operations with full responsibility for acting on behalf of the operator for purposes of complying with applicable laws, regulations, the lease terms, NTLs, Onshore Oil and Gas Orders, and other orders and instructions of the AO.
Several commenters said the industry standards as written are not enforceable by the BLM. The BLM disagrees. Many of the industry standards employ the terms “shall” and “should,” with “shall” denoting a minimum requirement necessary to conform to the specification, and “should” denoting a recommendation or that which is advised, though is not required, in order to conform to the specification. However, once the standards are incorporated into BLM regulations, operators must comply with them whether the standard uses the word “shall” or “should.” One commenter inquired whether operators will be required to follow a standard, and if any deviation from a standard is a violation. As stated previously, operators must comply with all incorporated standards and material, and any deviation without an approved variance is a violation.
This section was previously published as § 3174.3. Based on edits made to the final rule, this section and previously published § 3174.4 have been switched. All discussion of comments here were submitted under the previous proposed § 3174.3.
Section 3174.4(a)(1) sets volume-based overall performance standards for measuring oil produced from Federal and Indian leases, regardless of the type of meters or measurement method used. The overall volume uncertainty performance goals apply to volumes reported on the OGOR Part B (Production Disposition), commonly referred to as an OGOR B. FMPs measuring greater than or equal to 30,000 bbl per month must achieve an overall measurement uncertainty within ±0.50 percent. FMPs measuring less than 30,000 bbl per month must achieve an overall measurement uncertainty within ±1.50 percent. Existing Order 4 has no explicit statement of performance standards. The BLM will apply the performance standards in this final rule to FMPs as part of the compliance process. The performance goals could result in operating limitations (such as a minimum flow rate through the meter); however, they could also allow flexibility for various operational functions (for example, the
As noted, for FMPs measuring greater than or equal to 30,000 bbl per month, the maximum overall volume measurement uncertainty allowed is ±0.50 percent. The BLM has established the ±0.50 percent uncertainty limit based on uncertainty calculations and public comments received on the proposed rule, discussed below. The overall uncertainty calculation includes the effects of the meter accuracy; maximum allowable meter-factor drift between meter provings; the minimum standard for repeatability during a proving; the accuracy of the pressure and temperature transducers used to determine the correction for pressure on liquids (CPL) factors, and the correction for temperature on liquids (CTL) factors; and the uncertainty of the CPL and CTL calculations. The BLM chose the volume threshold of 30,000 bbl per month for this uncertainty level after determining that at this monthly volume, a one-percentage-point decrease in the expected over- or underpayment of royalties—from ±1.5 percent to ±0.5 percent—evaluated over a 5-year time frame, equals $150,000. This $150,000 amount reflects the cost to purchase a LACT system, based on price quotes from several distributors. In other words, requiring a LACT system, in terms of increased accuracy, will generate benefits that equal or exceed the cost of the new system. In making this calculation, the BLM assumed a 5-year crude oil price average of $67.58 per bbl,
The two-tiered uncertainty performance requirements in the final rule reflect modifications from the proposed rule, based on comments received. First, one commenter noted that the proposed rule did not give guidance on how the uncertainty was to be calculated. The BLM agrees with this comment and the final rule makes it clear that the uncertainty is to be calculated using API 13.1, Statistical Concepts and Procedures; API 13.3, the uncertainty methodologies; the quadrature sum method as described in API 14.3.1, Subsection 12.3, General Equations and Uncertainty Guidelines; or other methods approved by the AO.
Another commenter agreed that it is appropriate to permit a certain amount of measurement uncertainty and to utilize a tiered approach for uncertainty based on volume. However, the commenter disagreed with the proposed rule's three-tiered uncertainty requirement: ± 0.35 percent for FMPs measuring more than 10,000 bbl per month; ± 1 percent for FMPs measuring more than 100 bbl per month and less than or equal to 10,000 bbl per month; and ± 2.5 percent for FMPs measuring less than 100 bbl per month. The commenter said the proposed ± 2.5 percent uncertainty level for FMPs measuring volumes less than 100 bbl/month is both unnecessary and counterproductive. This commenter noted that there are a large number of older, low-volume wells operating on BLM and tribal leases, and argued that the ± 2.5 percent uncertainty for those operations could cause some low-volume operators to shut in their wells, resulting in a significant cumulative loss of Federal revenue from royalties. Commenters instead recommended that the BLM eliminate the lowest-volume category of the three uncertainty levels under proposed § 3174.3(a)(1). They further recommended that all FMPs with monthly volumes averaged over the previous 12 months that are less than 10,000 bbl/month should be subject to an uncertainty level of ± 1.0 percent. The commenters also said that this gives the BLM more discretion over when a less stringent uncertainty level for low-volume operators is appropriate based on site-specific factors.
The BLM partially agrees with these comments. After reanalyzing the uncertainty data and volume thresholds, the BLM has eliminated the lowest tier of uncertainty. However, this rule uses a 30,000 bbl per month volume as the dividing volume between the two tiers, and sets the uncertainty level for the highest-producing tier at ±0.50 percent and the uncertainty level for the lowest-producing tier at ±1.5 percent, which will be high enough for most tank-gauging operations while still ensuring the rules achieve accurate measurement.
The BLM chose the 30,000 bbl per month volume as the dividing line between the two tiers, and their respective uncertainty performance standards, based on what it would cost an operator to install and operate a LACT system, relative to the risk that the operator would under- or overpay royalties if measuring by tank gauging. The calculation for this assumes: A LACT system costs $150,000 and has a 5-year expected equipment lifespan, tank gauging results in a ±1.5 percent uncertainty, the 5-year oil price averages $67.58 per bbl, and the royalty rate is 12.5 percent. The following equation shows the calculation used to arrive at the 30,000 bbl per month volume
One commenter suggested that the performance standards for uncertainty should not be less than ±1.0 percent. A performance standard of less than ±1.0 percent is excessively onerous, the commenter said, and does not provide a substantial benefit compared to a ±1.0 percent standard. This commenter did not justify why a ±1.0 percent uncertainty standard is reasonable or how anything less is onerous. The BLM disagrees with this comment. The root square sum method of calculating the uncertainty of a LACT system with a PD meter configured and operated under the requirements of Order 4 calculates an overall uncertainty of ±0.32 percent. The final rule makes only minor changes to the Order 4 LACT requirements, so a calculated overall uncertainty rate under this rule will be similar to the existing requirements of Order 4. A LACT system with either a PD meter or a Coriolis meter is very capable of achieving the ±0.50 percent uncertainty when constructed and operated according to the requirements of this rule and corresponding API standards; no change was made as a result of this comment.
One commenter said BLM regulations do not need to specify equipment models that are acceptable for use in custody transfer measurement when uniform uncertainty metrics are utilized. The commenter stated that if any equipment meets the established uncertainty-performance standards for a measurement system, and that uncertainty can be validated and maintained, such equipment should then be allowed to be used for oil measurement. The BLM partly agrees with this comment, which is why this final rule establishes a procedure whereby the PMT can review and approve the use of new equipment and measurement methods, so long as the new equipment and methods meet the performance uncertainty and verifiability standards of the rule. The BLM believes that once this equipment has been proven to be capable of meeting the uncertainty performance and verifiability standards of this rule, then that equipment can be approved for use.
The second part of this comment suggests that the volume uncertainty limit of ±0.35 percent in the proposed rule for high-volume producers is excessively small (strict) for measurement installations that measure in excess of 10,000 bbl/month. The commenter further stated that the BLM failed to provide any basis for the proposed allowable volume uncertainty calculations. The proposed rule did not offer any detail as to how the uncertainty limit of ±0.35 percent includes any effects of maximum allowable meter-factor drift between meter proving, the minimum standard for repeatability during proving the accuracy of pressure and temperature transducers for volumetric correction, and the uncertainty in the volume-correction factor correction. The commenter also said the BLM did not disclose the data that it utilized to determine the ±1.0 percent uncertainty limit for FMPs in the 100 to 10,000 bbl/month range.
The BLM conducted an overall uncertainty calculation for a LACT utilizing a PD meter operated and proven under the requirements of Order 4. The results of this calculation provided an overall uncertainty of ±0.32 percent, which was what the BLM used to establish the higher standard in the proposed rule. The commenter did not provide a more appropriate uncertainty calculation to justify their claim that ±0.35 percent is excessively small for installations that measure in excess of 10,000 bbl per month. As a result no specific changes were made in response to this comment; however, as noted elsewhere in this section, the BLM has modified the uncertainty thresholds for larger-volume FMPs.
In order to identify appropriate thresholds, the BLM reviewed a proprietary third-party uncertainty calculation for tank gauging using Order 4 requirements for a 400 bbl tank. The results indicate that the overall uncertainty varies depending upon the volume removed from the tank. The overall uncertainty in the calculation varied from ±0.6 percent for large volumes removed to uncertainties of ±2.50 percent for very small volumes removed. The BLM reviewed overall uncertainty calculations in order to determine reasonable uncertainty requirement in the rule.
Several commenters said the BLM should re-evaluate its proposed measurement uncertainty (±0.35 percent), claiming the methodology appears to be flawed. They further stated the proposed oil measurement rule demands a level of accuracy that would not apply to heavy oil regimes and that would increase operating costs beyond what is necessary or of value. They suggest that operators with heavy oil operations may receive unwarranted and costly penalties at a greater rate than the rest of the petroleum industry, and that heavy oil producers would be disproportionately impacted by the proposed standard. These commenters did not submit justification for their claims, and when the BLM contacted them to clarify this comment, they still failed to justify or explain how heavy oil regimes would be disproportionately impacted by the rule. No change to the rule resulted from these comments.
One commenter requested that the ±0.35 percent performance uncertainty be adjusted to ±1.0 percent for meters measuring 10,000 barrels per day. The commenter agreed with comments that the API submitted to the BLM on the proposed rule and requests that the BLM use the Order 4 proving and uncertainty performance requirements for LACT systems. The BLM has re-analyzed the uncertainty performance requirements and volume thresholds, and, based on the re-evaluation and other comments received showing a different uncertainty calculation resulting in a slightly higher uncertainty than proposed, has changed the rule's uncertainty performance standards to encompass reasonable flexibility in evaluating alternative measurement equipment and methods and adjusted the volume thresholds to match volumes where the risk to royalty would equal the expense of installing a LACT or CMS to require a more accurate measurement.
Another commenter said the overall volume uncertainty limit of ±0.35 percent for measurement installations with throughputs greater than 10,000 bbl/month is unreasonably and excessively strict, given the potential number of sources of measurement error. The error should be calculated to include the uncertainty from all sources of error in the oil volumetric calculation chain. The BLM agrees in part with the comment that a ±0.35 percent uncertainty may be somewhat strict in some applications. The ±0.35 percent has been calculated to include all sources of error in the LACT measurement calculation chain, based on other comments providing similar calculations. The BLM has chosen to use a slightly higher uncertainty level in the final rule to give some leeway when considering approvals for future measurement technology and procedures for use on Federal and Indian leases. This commenter also suggested that systems installed at FMPs that measure less than 100 bbl/month should have the option to pay royalties as if they were producing at the rate of 100 bbl/month and avoid the cost of installing measurement equipment that could make their operations economically infeasible. The BLM
One commenter said they were unable to verify the uncertainty levels proposed without the “calculator” that the BLM is developing. This commenter created its own uncertainty calculation using the following assumptions: A maximum allowable deviation for temperature of 0.25 °F and pressure of 0.25 psi. The uncertainty was calculated to be ±0.46 percent in this one instance.
The BLM appreciates receiving this comment as it provides useful input and actual calculation results to support the commenter's position. As a result of this comment and further analysis, the BLM agrees that this uncertainty calculation could reflect one possible application and has adjusted the rule's lower overall uncertainty performance requirements for the highest-producing tier to ±0.50 percent.
One commenter expressed concern that the cost of complying with this provision will increase as uncertainty standards are updated. However, there is nothing in this provision that provides for the updating of the uncertainty threshold standards.
Under § 3174.4(a)(2), only a BLM State Director, with the written concurrence of the PMT, prepared in coordination with the Deputy Director, can grant an exception to the prescribed uncertainty levels. Granting an exception requires a showing that meeting the required uncertainly levels would involve extraordinary cost or unacceptable adverse environmental effects. By having the State Directors make these decisions, with concurrence of the PMT (prepared in coordination with the Deputy Director), the BLM hopes to ensure that there is consistent application of the performance standards across the Bureau and that approvals for exceptions from the performance standards are granted in limited circumstances. In the proposed rule, the BLM had proposed to require concurrence from the Director; however, upon further review, the BLM modified the written concurrence requirement to require written concurrence from the PMT that has been prepared in coordination with the Deputy Director. The BLM feels this approach would be more appropriate given that the PMT will have the necessary technical expertise, while requiring coordination with the Deputy Director ensures such changes have the necessary national policy perspective.
The BLM received several comments on its approach to exceptions to the proposed rule's uncertainty limits. A few commenters requested that the BLM clarify and limit the criteria a BLM State Director can use to grant exceptions. The BLM does not believe additional clarification is necessary and the rule's description of potential extraordinary circumstance(s) that could result in an exception to the uncertainty levels is sufficient. The BLM cannot identify every situation or event that could warrant an exception. The intent of the rule is that an exception is not a normal occurrence, and to allow exceptions only in limited, special circumstances. No change to the rule resulted from this comment.
Similarly, another commenter urged the BLM to clarify the manner in which exceptions may be granted and to clearly define the term “extraordinary cost.” According to this commenter, a lack of clear guidance on these exceptions will result in unrealistic expectations from operators and inconsistent application by the BLM. Again, there could be numerous circumstances under which an exception could be warranted, and the BLM cannot accurately anticipate and address all of these in the rule. It will be up to the individual or entity applying for the exception to make the case to justify an exception. The process for granting exceptions is more likely to be consistent if decisions are left to State Directors, with written concurrence from the PMT (prepared in coordination with the Deputy Director). No change to the rule resulted from this comment.
One commenter questioned why, on the one hand, the proposed rule would have authorized BLM State Directors to grant exceptions to uncertainty standards for equipment at FMPs (with BLM Director concurrence) and on the other hand, the rule at § 3174.4(d) gives the PMT the authority to recommend and the BLM to decide whether proposed alternative equipment or measurement procedures meets or exceeds the uncertainty standards. The commenter questioned a process that will rely on the availability of the PMT and State Directors to review and evaluate requests for exceptions. The commenter said BLM technical experts are often overworked, and therefore the PMT approval process is likely to take a considerable amount of time and hinder operators' ability to effectively develop Federal oil and gas resources. The BLM agrees that its technical experts have a significant workload and face a number of competing demands. However, one reason for creating a BLM-wide PMT is to relieve field offices of having to review new technology, and to provide a consistent BLM-wide decision-making process. The BLM believes that this structure should minimize the amount of time it will take for the BLM to process requests for evaluation of new equipment, and to evaluate requests for exemptions from the uncertainty requirements. No change to the rule resulted from this comment.
Section 3174.4(b) establishes the degree of allowable bias in a measurement. Bias differs from uncertainty in that bias results in systematic measurement error, whereas uncertainty only indicates a risk of measurement error. While the BLM acknowledges that it is virtually impossible to remove all bias in measurement, the final rule requires that there be no statistically significant bias at any FMPs. When a measurement device is tested against a laboratory device or prover, there is often slight disagreement, or apparent bias, between the two. However, both the measurement device being tested and the laboratory device or prover have some inherent level of uncertainty. If the disagreement between the measurement device being tested and the laboratory device or prover 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, the BLM does not consider apparent bias that is less than the uncertainty of the two devices combined to be statistically significant for purposes of compliance with the final rule. However, if the shift in the mean value of a set of measurements away from the true value of what is being measured exceeds the “statistically combined uncertainty” of the devices, then the BLM requires that known shift to be corrected to as close to the actual value as possible.
The BLM received several comments concerning bias. The first commenter stated the rule does not give any guidance on how bias will be determined, or what the BLM considers to be statistically significant. In order for the bias restriction to be applied uniformly throughout the nation, the commenter asserted that the term needs to be defined in the regulation. The BLM agrees with this comment and has added a new definition for “bias” to 43 CFR subpart 3170, as part of the
Another commenter noted that the BLM presented no data or calculations in the proposed rule to verify that bias issues will not exist under field conditions where many additional variables impact the statistical calculations. The commenter claimed that the rule essentially assumes that uncertainties that can be demonstrated in laboratory conditions can also be demonstrated in field conditions, which are not practical in a production scenario. The commenter asked that the BLM delete paragraph (b) from the final rule. The BLM does not agree with this comment. If a shift in the mean value of a set of measurements away from the true value of what is being measured, exceeds the statistically combined uncertainty of the devices, occurs, then the BLM requires that known shift to be corrected to as close to actual value as possible. An example of where this shift could be discovered is during a transducer verification that results in a reading that is outside of the device's stated uncertainty. This is different from uncertainty, where a potential for measurement error exists. No change to the rule resulted from this comment.
A third commenter recommended that the BLM clarify language in the preamble that discusses statistically significant bias. As noted above, the preamble quantifies statistically significant bias as being a number that is greater than the combined uncertainties of the laboratory device, or prover, and the measured device, or the “statistically combined uncertainty.” The BLM recognizes that there will always be some apparent bias resulting from the uncertainty of all devices. Bias is only considered significant when it exceeds the combined uncertainties of the devices involved. The BLM believes that the final rule accurately explains bias in terms of it being outside of the “statistically combined uncertainty” of the devices being used. No change to the rule resulted from this comment.
Section 3174.4(c) requires that all measurement equipment be subject to independent verification by the BLM that it is performing accurately and that all inputs, factors, and equations that are used to determine quantity or quality are valid. Order 4 already requires that the BLM be able to independently verify measurement methods, as well as bias, so these are not new requirements. The verifiability requirement in this section prohibits the use of measurement equipment that does not allow for independent verification. For example, if a new meter were to be 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 were to be developed that used proprietary methods that precluded the ability to recalculate volumes, its use would also be prohibited.
The BLM received several comments about the verifiability requirements of this rule. One commenter seemed to suggest that the BLM did not take into account the use of automation and other measurement systems advances, such as the use of flow computers handling calculations. The comment further stated that in order to retain the raw data that the BLM needs to manually verify equipment accuracy, operators will be required to use computers that are less efficient and that require more data storage. The BLM agrees that the rule may require operators to acquire more data storage, but does not agree with the commenter that saving raw data for future verification will result in less efficient flow computers, or that it is unnecessary. The BLM manages Federal oil resources on behalf of the American taxpayer and has an affirmative obligation to ensure that the oil produced is accurately measured and accounted for. In order to satisfy those obligations it is critically important that an audit trail exists so that the BLM can verify the production data. As a result, the BLM will continue to manually verify calculations at FMPs. No change to the rule resulted from this comment.
Another commenter suggested any verifiability does not take into account the difference between live calculations at high frequencies versus averaged and accumulated data over time. The commenter also said that independent calculations should only have to fall within a statistically insignificant window. In order for independent calculations to be applied uniformly throughout the nation, they should to be defined in the regulations, the commenter said. The BLM partly agrees with this comment that calculations should be live calculations at high frequencies or calculations averaged and accumulated over time. The Inspection and Enforcement Handbook will address possible methods for the BLM to verify calculations at an FMP. No changes to the rule were made as a result of this comment, but the BLM will include guidance in the Inspection and Enforcement Handbook regarding whether calculations should be based on live calculations or averaged over time. Under the final rule, all volume calculations at an FMP must be verifiable.
One commenter asked whether the requirement that new equipment undergo independent verification will preclude new technology. The BLM does not intend to prevent or exclude new technology. In fact, this rule, by establishing performance standards, adopting industry standards, and standing up the PMT process, has been designed explicitly to provide flexibility for the BLM to adopt new technology and practices as they are developed. No changes were made in response to this comment.
Another commenter said that paragraph (c) would require the BLM to contract with an independent laboratory to verify equipment, which could take 6 months per device and cost upwards of “$500M” for each device. The BLM disagrees with this comment because § 3174.4(c) merely requires operators to have FMP equipment that can produce the source records that provide the data and equations the BLM needs to independently recalculate oil production volume and quality during production audits. No changes were made in response to this comment.
Section 3174.4(d) clarifies that the operator can propose the use of alternative equipment, provided that it meets or exceeds the uncertainty requirements of this section. The PMT will make a determination under § 3174.13 of this subpart regarding whether proposed alternative equipment or measurement procedures meets or exceeds the objectives and intent of this section. See § 3174.13 for discussion of comments concerning the PMT and the PMT review process.
Section 3174.5(a) specifies the general requirements for oil measurement by tank gauging as a means to accurately determine the quantity and quality of oil removed from an FMP. The BLM received many comments on this section of the proposed rule. Almost all of these comments requested that the BLM consider permitting the use of ATG systems for custody transfer applications. Order 4 allows only manual tank gauging. In the proposed rule, the BLM indicated that it was considering including provisions in the final rule allowing for the use of ATG systems, and requested data regarding whether these systems can meet the BLM's performance standards for manual tank gauging with respect to uncertainty and verifiability. The BLM requested additional data regarding ATG measurement systems because it recognizes the significant safety advantages they provide.
The majority of the commenters indicated that ATG systems are much safer for workers when compared to manual tank gauging systems, especially when workers are measuring hydrocarbon fluids such as those found in the Bakken, which have higher gravity and higher vapor pressure, and thus emit higher volumes of toxic fumes. The BLM agrees that safety concerns associated with manual tank gauging can be reduced if operators have the option of using ATG systems as well as the other measurement methods addressed in this final rule. Based on data provided in response to the proposed rule—both as public comment on the proposed rule and in support of project-specific variance requests to use ATG systems on tanks—the BLM has determined that ATG systems can meet or exceed the uncertainty thresholds for tank gauging. As a result, the rule has been changed to allow for the use of ATG systems.
The BLM received one comment that recommended the BLM prohibit the practice of oil measurement by manual tank gauging because, according to the commenter, the practice is an antiquated and considerably less reliable method of measurement. The BLM disagrees that properly conducted manual tank gauging operations are antiquated or less reliable than other methods of measurement and will continue to give operators the option of using this widely accepted practice for oil measurement, which is generally used at lower-volume facilities. However, the BLM hopes for a shift towards ATG in areas where the nature of the produced oil presents a safety concern.
In the proposed rule, § 3174.5(b) required that all oil storage tanks, hatches, connections, and other access points be vapor tight and that each oil storage tank, unless connected to a vapor recovery system, must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. Pressure-vacuum relief valves would provide for normal inflow and outflow venting at an outlet pressure that is less than the thief hatch exhaust pressure and at an inlet pressure that is greater than the thief hatch vacuum setting. The intent is to minimize hydrocarbon gas lost to the atmosphere by ensuring that venting is done under controlled conditions through the pressure-vacuum relief valve primarily in response to changes in ambient temperature. The requirement that all access points be vapor tight has been expressly included in this rule in order to eliminate confusion over the intent of Order 4, which specified all the same equipment, but did not specify the manner in which it was supposed to be operated. The implied intent of Order 4 was always that the tanks be operated such that they are vapor tight.
The BLM received numerous comments on this section, the majority of which said the proposed requirements could conflict with U.S. Environmental Protection Agency (EPA) air quality regulations and the BLM's separately proposed Methane and Waste Prevention Rule (81 FR 6616). Some of the same commenters also complained about the potential costs associated with retrofitting some of the tank batteries. The BLM disagrees with these comments. The intent of the requirement is to conserve the quantity and quality of the liquid hydrocarbons in storage by controlling the storage conditions, not to create a potential conflict with the EPA's regulations for release of harmful pollutants. The BLM also disagrees with claims made by some commenters that the potential costs associated with retrofitting existing tank batteries to make them vapor-tight would be too high. Pressure vacuum vent line valves and thief hatches are already required equipment for the existing tank battery installations under Order 4. Paragraphs (b)(3) and (4) of the proposed rule have been changed and merged into a new paragraph (b)(3) in the final rule, which now requires that all oil storage tanks be vapor tight, and, unless connected to a vapor recovery or flare system, must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. All hatches, connections, and other access points must be installed and maintained in accordance with manufacturers' specifications.
Several commenters recommended that the BLM add the requirement that oil storage tank hatches (“thief hatches” or other access points) have pressure indicators that provide a clear and immediate visual indicator of tank pressures and potential gas/vapor release hazard should the tank need to be accessed. One of the commenters said pressure indicators on tank access hatches visually display the presence of gas/vapor pressure in a tank, allowing a trained worker to make risk-based decisions before accessing a tank, including actuating a remote venting valve, venting gas to a flare, or using appropriate respiratory protection, such as a self-contained breathing apparatus or an air-line respirator. The BLM recognizes that having such information could potentially be useful to personnel in the field; however, the BLM did not make any changes in response to this comment because the pressure indicators proposed by the commenter would have no bearing on determining measured volume, and therefore are outside the scope of this rule. It should also be noted that in general the Occupational Safety and Health Administration takes the lead on adopting and enforcing employee safety requirements.
Several commenters stated it is imperative that tanks be maintained vapor tight and that there be a monitoring or inspection program to ensure compliance. The BLM agrees and the final rule has maintained the vapor tight integrity requirement for oil storage tanks. The BLM's inspection and enforcement program will continue to ensure compliance with this and all other oil and gas regulations. No additional changes were made to the final rule as a result of these comments.
One commenter stated that if the oil is weathered or stabilized, there is no need for hatches and other connections to be vapor tight. The commenter did not explain how weathered or stabilized oil could negate the need for hatches and other connections to be vapor tight. The BLM disagrees that stabilized product does not require a vapor-tight storage condition. The vapor tight integrity is an implied requirement of the current Order 4 and therefore will not require the operator to retrofit any existing equipment. In a unique situation where a variance could be justified, the operator could seek a variance through the appropriate BLM field office following the process outlined in § 3170.6 of this part, a related rulemaking that is replacing Order 3, with approval by the AO. No additional changes were made to the final rule. This section in the final rule is now identified as § 3174.5(b)(3).
Section 3174.5(b)(5) of the proposed rule specified that all oil storage tanks must be clearly identified and have a unique number stenciled on them, maintained in a legible condition. Order 4 did not have a similar requirement. The BLM received several comments that said this section did not adequately communicate how the numbering system would work and how numbers are assigned to the tanks. The BLM agrees that this section was not clear. As a result of these comments, the final rule has been changed to specify that all oil storage tanks must be clearly identified with an operator-generated number that is unique to the lease, unit PA, or CA stenciled on the tank and maintained in a legible condition. This section now appears as § 3174.5(b)(4) in the final rule.
Section 3174.5(b)(6) of the proposed rule required each oil storage tank associated with an approved FMP by tank gauging to be set and maintained level. Several commenters said this requirement is unwarranted and unnecessary without offering any details. The BLM disagrees, as this is not a new requirement. Order 4 has a similar requirement, and the BLM believes that not requiring a tank to be set or maintained level would be unacceptable because it could result in uncertainty in measurement. Industry standards also dictate that tanks used for gauging operations should be level. No change resulted from these comments. This section now appears as § 3174.5(b)(5) in the final rule.
Section 3174.5(b)(7) of the proposed rule specified each oil storage tank associated with an approved FMP that has a tank-gauging system must be equipped with a distinct gauging reference point, with the height of the reference point stamped on a fixed bench-mark plate or stenciled on the tank near the gauging hatch, and maintained in a legible condition. One commenter, without offering any justification, said this requirement should apply only to tanks that are manually gauged. The BLM disagrees as this gauging reference point is also needed during the verification and calibration of an ATG system, not just for tanks that are measured by manual gauging. No change was made to the final rule as a result of this comment. This section now appears as § 3174.5(b)(6) in the final rule.
Section 3174.5(c) in the proposed rule required the operator to accurately calibrate each oil storage tank associated with an approved FMP that has a tank-gauging system, under either API 2.2A or API RP 2556. Order 4 had a similar requirement. The BLM received a few comments on this section. One commenter pointed out that under the proposed rule, sales tank calibrations apparently can only be made using API MPMS Chapter 2.2A—Tank Strapping by Manual Method, when in fact other methodologies in Chapter 2 are available. The BLM agrees that industry standards provide additional methods for calibrating sales tanks. As a result of this comment, the BLM changed the final rule to incorporate industry standards API 2.2A, API 2.2B, or API 2.2C; and API RP 2556. One commenter stated the proposed rule did not clarify when or how often a sales tank calibration is required. The BLM disagrees. Section 3174.5(c)(2) clearly states when a sales tank calibration is required—if the tank is relocated, repaired, or the capacity is changed as a result of denting, damage, installation, removal of interior components or other alterations. No changes were made to the final rule as a result of this comment.
One commenter said operators should be allowed to use formulas for estimating tank volumes. The formula of 1.67 bbl/inch is a tool operators use to estimate the volume stored in the tank. When the oil is sold, the commenter said, a more accurate measurement will be taken, ensuring that the operator is properly paid for the oil being sold, which will in turn result in the correct royalty payment to the government. This rule seeks to ensure accurate oil measurement, not volume estimates. This comment is not relevant to sales tank calibration. The final rule was not changed as a result of this comment.
Section 3174.5(c)(1)(i) of the proposed rule specified the strapping table unit volume must be in barrels. The BLM received no comments and made no changes to this paragraph.
Section 3174.5(c)(1)(ii) of the proposed rule specified the incremental height measurement on all tanks must be in
Section 3174.5(c)(2) requires operators to recalibrate a sales tank if it is relocated or repaired, or the capacity is changed as a result of denting, damage, installation, removal of interior components, or other alterations. Order 4 had a nearly identical requirement. The BLM received a few comments on this section, all of which said there is no definition of how large the dent or alteration would need to be to trigger this requirement. The commenters also stated that the BLM must clarify the amount of volume displacement that would require action on the part of the operator. The final point that the commenters made also suggested that the BLM should offer a range of options that operators could take in response to denting, including tank inspection, and provide them an opportunity to avoid being in violation. For example, an insulated tank may be dented on the outside but the dent would have no impact on the inside due to several inches of insulation. Upon review of these comments, the BLM has made no change to the rule for the following reasons. The volume displacement from tank denting cannot be known until the dent has been measured and the impacts analyzed. To measure the impacts, this section requires re-strapping of the tank. The BLM has chosen not to allow an operator to “estimate” the impact of denting on a tank used for tank gauging as there would be no enforceable requirement to properly determine the resulting volume impacts. Denting of the insulation on a tank may or may not result in denting of the sales tank. If denting is observed on the insulation of a tank, it is the operator's responsibility to verify that no internal tank denting has occurred under the insulation.
Section 3174.5(c)(3) requires operators to submit sales tank calibration charts (tank tables) to the AO within 30 days after calibration. Order 4 required them to be submitted to the AO upon request. The BLM received several comments on this section. A few commenters recommended extending the 30-day time period to 45 days to allow for more coordination time between transporter and operator. After considering these comments, the BLM agrees that transporters and operators may need more time to submit the tank tables to the BLM. As a result of these comments, the final rule now requires that tank tables must be submitted to the AO within 45 days after calibration. Tank tables may be in paper or electronic format. A couple of
The BLM has an affirmative obligation to maintain an audit trail supporting Federal and tribal oil production. A couple of commenters requested that the BLM continue to use the Order 4 requirement that operators submit their latest tank calibration charts when the AO requests them, in order to avoid confusion and give operators notice that an inspection is imminent. The BLM disagrees because the new requirement will serve as verification that the operator has had the tanks strapped as required, and enables the BLM to perform the required inspection activities. Additionally, the BLM has no obligation to provide operators notice that an inspection is imminent.
One commenter said marginal producing leases should be exempt from tank-gauging requirements. The BLM disagrees. Marginal leases are already subject to tank-gauging requirements. Under this final rule, operators on marginal-producing leases are allowed to continue using manual tank gauging, which imposes only modest economic impact on these leases.
Section 3174.6 paragraphs (a) and (b) require operators to take the steps in the order prescribed in the following paragraphs to manually determine by tank gauging the quality and quantity of oil measured under field conditions at an FMP. The BLM received several comments on this section. The comments said the detailed tank-gauging procedures in this section do not align with the industry standard. The BLM partly agrees, in that industry standards for certain activities have several options for operators to follow for achieving the desired outcome. The proposed rule did not reflect all of those options. As a result of these comments, the final rule has been changed to reference the appropriate industry standards and remove any unnecessarily prescriptive requirements to ensure accurate measurement using tank gauging.
Section 3174.6(b)(1) contains the requirement in Order 4 and the proposed rule that the tank be isolated for at least 30 minutes to allow contents to settle before proceeding with tank gauging operations. The BLM received a couple of comments on this section. The commenters said this requirement would be costly and is unnecessary, as this activity will not increase the accuracy of measurements. The BLM disagrees. This requirement will ensure that the tank is isolated and that the crude oil layer is still, with no surface foaming. In many liquid manual sampling applications, the product to be sampled contains a heavy component (such as free water) that tends to separate from the main component. In these instances, it should be recognized that until the heavy component completely settles out, sampling will likely result in varying sample qualities. No change was made to the final rule as a result of these comments.
Section 3174.6(b)(2) contains the requirements for determining the temperature of oil contained in a sales tank that is used as an FMP. Operators must comply with paragraphs (b)(2)(i) through (iii) of this section and API 7 and API 7.3. The BLM received numerous comments on this section. Several commenters requested that the BLM eliminate the reference to mercury in paragraph (b)(2)(i). In the proposed rule, that paragraph required glass thermometers to be clean, be free of mercury separation, and have a minimum graduation of 1.0 °F. The BLM agrees that the mercury reference should be removed because the EPA has banned mercury thermometers from use. As a result of these comments, the final rule has been changed to say that glass thermometers must be “free of fluid separation.”
The BLM received a comment concerning paragraphs (ii) through (iv), which said the reported graduation and accuracy requirements for temperature measurement devices are different based on the technology employed (minimum graduation of 1.0 °F for liquid-in-glass thermometer vs. minimum graduation of 0.1 °F for portable electronic thermometers (PET)). The commenter did not elaborate, but we assume the commenter believes PETs should be as accurate as glass thermometers. This comment is not consistent with the mandate of keeping the uncertainty in the measured quantity to within a specified value, nor is it consistent with existing industry standards (API MPMS Chapter 7). The BLM disagrees in part with this comment since the BLM used the minimum graduations from the industry standard, of 1.0 °F for glass and 0.1 °F from electronic thermometers. For consistency, and as a result of this comment, the BLM is requiring an accuracy of ±0.5 °F for both glass and electronic thermometers.
Several commenters questioned the thermometer immersion times required in the proposed rule under paragraph (b)(2)(iii), which referenced API 7, Table 6. They also asked the BLM to allow alternate methods for determining opening oil temperatures, to alleviate potential safety and economic concerns. The BLM disagrees in part as the immersion times are an industry standard, but also agrees in part to allow alternate methods under API 7. The prescriptive requirements under paragraph (b)(2)(iii) have been removed because the final rule already states that operators must comply with API 7, which includes the Table 6 requirements. Furthermore, the BLM changed the rule to give operators more flexibility by allowing them to use alternate methods for temperature determinations under API 7 and API 7.3, as well as the option of using ATG/hybrid tank measurement systems, in order to address the safety concerns identified by commenters. As a result of these comments and changes, the final rule eliminates paragraph (b)(2)(iii) of the proposed rule, resulting in the renumbering of paragraph (b)(2)(iv) in the proposed rule to paragraph (b)(2)(iii) in this final rule.
Section 3174.6(b)(3) of the proposed rule specified that sampling of oil removed from an FMP tank must yield a representative sample of the oil and its physical properties, and must comply with the procedures listed in paragraphs (i) through (iii) of this section and API 8.1. The BLM received several comments requesting that the final rule give operators other sampling options. The BLM agrees that other sampling options can still achieve the desired measurement uncertainty. As a result of these comments, the BLM removed the prescriptive requirements in paragraphs (b)(3)(i) through (iii), and added a reference to API 8.2's standards for automatic sampling procedures to the final rule.
Section 3174.6(b)(4) of the proposed rule specified that tests for oil gravity must comply with paragraphs (b)(4)(i) through (iv) of this section and API 9.3. The BLM received a couple of comments on this section. One commenter said that API Chapter 9 contains additional methods for determining gravity that can be more appropriate to use (based on the conditions of the oil at sample time). Therefore, the commenter asserted that the final rule should simply specify that any API Chapter 9 methodology is appropriate for determining gravity. The commenter said the procedure outlined in the proposed section was not consistent with API 9.3. Another commenter stated that proposed paragraph (b)(4)(i), which required the use of a thermohydrometer for API gravity (density) measurement, would limit the use of new, automated, more accurate technology such as Coriolis meters and density gauges. The commenter said allowance should be made for other methods that can meet the uncertainty requirements of the regulation. The BLM agrees that this provision of the proposed rule was too prescriptive and unnecessarily limited potential compliance options. As a result of these comments, the following changes were made to the final rule:
• This section now incorporates by reference API 9.1, API 9.2, or API 9.3 to allow additional methods to measure API gravity;
• Paragraph (b)(4)(i) is changed to include the use of a hydrometer in addition to a thermohydrometer;
• Proposed paragraph (b)(4)(ii) has been removed consistent with the BLM's determination that the provision was too prescriptive;
• Proposed paragraph (b)(4)(iii) is now paragraph (b)(4)(ii) and has been revised to require operators to allow the temperature to stabilize for at least 5 minutes; and
• Proposed paragraph (b)(4)(iv) is now paragraph (b)(4)(iii) and has been revised to require operators to read and record the observed API oil gravity to the nearest 0.1 degree, and to read and record the temperature reading to the nearest 1.0 °F.
Section 3174.6(b)(5) of the proposed rule required operators to take and record the tank opening gauge only after upper, middle, and outlet samples have been taken. It further required gauging to comply with paragraphs (b)(5)(i) through (b)(5)(v) of this section and API 3.1A. One commenter said the opening measurement should be taken with a matched (bob and tape) and currently “certified” gauging tape. The comment recommended that the rule specify that the tape and bob shall be certified within the last year as specified in API 3.1A. The BLM agrees with this recommendation, as it is consistent with API standards. As a result, the BLM has included API 3.1A in this paragraph and has eliminated prescriptive language that repeats API 3.1A.
Similar to the proposed rule, § 3174.6(b)(5)(i) of the final rule contains the requirements for manual gauging. But in response to commenters' requests that the BLM allow automatic and hybrid tank gauging, as discussed earlier in this preamble, this section in the final rule includes a new paragraph (b)(5)(ii), which contains the requirements for ATG. During the initial years of rule implementation, the BLM will not limit which ATG makes or models operators can use, but starting 2 years after the effective date of this rule, operators will only be permitted to use the ATG makes and models that the BLM approves for use and lists on its Web site. To ensure that ATG equipment in use at that time meet with BLM approval, the BLM encourages operators, manufacturers, or other entities (
Section 3174.6(b)(6) of the proposed rule required operators to determine S&W content using the oil samples in the centrifuge tubes collected from the upper and outlet fluid column (see paragraph (b)(3) of this section), and determine the S&W content of the oil in the sales tanks, according to paragraphs (b)(6)(i) through (iii) of this section and API 10.4. The BLM received a few comments on this section. The commenters all addressed the fact that API 10.4 has been updated since the BLM published the proposed rule, and that the prescriptive requirements in paragraphs (b)(6)(i) through (iii) were not consistent with the revised industry standard. The BLM agrees that the API standard has been updated and that the requirements in paragraphs (b)(6)(i) through (iii) of the proposed rule are too prescriptive and inconsistent with the revised industry standard. Based on its review of the revised standard and as a result of these comments, the BLM removed the prescriptive requirements in paragraphs (b)(6)(i) through (iii). The final rule requires operators to determine S&W content by using API 10.4, which has been incorporated into the final rule by reference.
Without saying why, one commenter said the BLM should incorporate all sections of API Chapter 10 into the final rule. The BLM disagrees. Since the oil measurement at issue in this rule is inherently a “field procedure,” in which the S&W content is required to be determined and documented on the run ticket at the completion of the tank gauging/custody transfer procedure, the BLM determined that the only applicable section is 10.4. This comment did not result in a change to the final rule.
Section 3174.6(b)(7) requires operators, after conducting the S&W determination, to conduct the transfer operation and seal the effected valves under §§ 3173.2 and 3173.5 of this part. There were no comments to this section.
Section 3174.6(b)(8) requires operators to determine the tank closing temperature following procedures discussed in paragraph (b)(2) of this section. Any comments concerning temperature determination have been addressed earlier in the paragraph (b)(2) discussion.
Section 3174.6(b)(9) requires operators to take the closing gauge using procedures in paragraph (b)(5) of this section. Any comments concerning gauging operations have been addressed in the paragraph (b)(5) discussion.
Section 3174.6(b)(10) requires operators to end their tank-gauging operations by completing a measurement ticket in accordance with § 3174.12. The proposed rule included seven activities in paragraphs (b)(10)(i) through (vii) that dictated how operators should derive the data required for the measurement tickets. Some commenters said this list of activities was too prescriptive. In an effort to be less prescriptive, the BLM deleted paragraphs (b)(10)(i) through (vii) in the final rule and refers operators to the rule's measurement-ticket requirements.
Paragraphs (a) through (c) of this section in both the proposed and final rule refer operators to other sections of this rule for construction and operation requirements for LACT systems, proving requirements, and measurement tickets. The proposed rule in paragraph (a) included a reference to API standards and in paragraph (c) a table that listed the requirements and components of a LACT system, along with references to the sections of the proposed rule containing the minimum standards for each of those components. The BLM received several comments on these paragraphs.
Several commenters said the BLM should not be so prescriptive and should instead require compliance with
Several commenters were uncertain about whether the LACT requirements only applied to new facilities, with existing facilities grandfathered. Most of the commenters also suggested that bringing existing facilities into compliance within the 180-day implementation timeframe was either too expensive, impossible, or both. In response to these comments, and as discussed previously in this preamble, the BLM has clarified in the final rule that all facilities are subject to the new requirements, with operators required to come into compliance on a staggered schedule of between 1 and 4 years, depending on their levels of production. This was achieved by tying compliance to the requirement to apply for an FMP found in the new 43 CFR subpart 3173. These significantly extended time frames will give operators time to plan and budget for expenses in advance, while limiting the chances that there will be local or national shortages of equipment or technical expertise, as might have resulted from the original proposed, 180-day implementation period.
Several commenters noted that in proposed paragraph (c), the BLM limited LACTs to those with PD meters, and suggested that other types of meters should be allowed. Most of those commenters specifically requested that Coriolis meters be allowed, but some requested that any type of meter permitted in API standards be allowed. This would include PD, Coriolis, and turbine meters. The BLM partly agrees and has changed the rule to allow Coriolis meters to be used with LACTs. However, the BLM does not agree that turbine meters should be allowed. In the BLM's experience, confirmed by many industry sources, turbine flowmeters are less accurate than PD and Coriolis meters and are more subject to wear and/or damage. As a result, the BLM will continue to disallow turbine meters in LACTs. The change to allow Coriolis meters in LACTs is found in § 3174.8(a)(1). The definition of, proving standards for, and other specific requirements related to the use and operation of Coriolis meters are addressed by other sections of the final rule.
One commenter stated that § 3174.7(b) would require operators to generate an additional run ticket before proving, and that the BLM should take into account the additional cost associated with that extra run ticket. The BLM did analyze the financial impacts of increased run tickets in its Paperwork Reduction Act analysis, which was discussed in the proposed rule preamble. Another commenter pointed out that this additional run ticket is unnecessary in LACTs with flow computers as a flow computer is capable of implementing a new meter factor in the middle of a month without the operator having to close it. The BLM agrees and as a result of this comment, the BLM changed § 3174.12(b)(1) of the rule to remove the requirement that operators close a run ticket prior to proving LACT systems that utilize flow computers, which will reduce the overall cost to operators.
One commenter said the BLM should remove requirements in proposed §§ 3174.7(c) and 3174.8(b)(7) for S&W monitors at LACTs because there is no such thing as an “S&W monitor.” There are water monitors or water probes, the commenter continued, but water monitors are not part of any oil measurement system. Rather, operators use water monitors to divert the flow back to tanks for additional processing to remove large amounts of water from their production stream. The BLM agrees with this commenter's assessment. From a regulatory perspective, a water monitor should not be required equipment at a LACT because it does not help the BLM verify accurate measurement and net oil volumes. In the final rule, the BLM has incorporated LACT requirements from API 6.1 and eliminated the table in § 3174.7(c), along with the S&W monitor requirements in § 3174.8(b)(7).
Section 3174.7 paragraphs (d) and (e) retain current requirements that all components of a LACT system be accessible for inspection by the AO and that the AO be notified of all LACT system failures that may have resulted in measurement error. Numerous commenters stated that the term “notify” in paragraph (e)(1) was ambiguous and requested that the BLM define what forms of notification are acceptable and the time frame for notifying the AO. The BLM agrees that this term needs to be defined and has defined “notify” to mean “to contact by any method, including but not limited to electronically (email), in-person, by telephone, by form 3160-5 (Sundry Notice), letter, or Incident of Noncompliance.” This definition has been added to the definitions listed in 43 CFR 3170.3, part of the rulemaking that is replacing Order 3.
Numerous commenters stated that the 24-hour time frame in proposed paragraph (e)(1) regarding notifying the BLM of LACT system failure was: (1) Impractical, (2) Too restrictive; (3) Potentially unnecessary if the failure was small (less than 0.05 percent); (4) Unlikely to significantly affect the net oil volume; (5) Too expensive for operators to implement because additional monitoring equipment would be required; and (6) Would require speculation on the part of the operators as to when a malfunction occurred when no one was present at the time of the malfunction. Most commenters suggested requiring reporting within 7 days after discovery. The BLM partly agrees, and paragraph (e)(1) of the final rule now requires notification within 72 hours after discovery. This time frame will ensure that the BLM is able to verify that all oil volumes are properly derived and accounted for, and verify any alternative measurement method, meter repairs, or meter provings within a reasonable time frame without placing unnecessary burdens on the operator. Requiring notification within 72 hours will allow operators to deal with urgent situations while still being able to timely notify the BLM.
Section 3174.7 paragraph (f) of the proposed rule would have retained the current Order 4 requirement that any tests conducted on oil samples taken from the LACT system samplers for determination of temperature, oil gravity, and S&W content meet the same minimum standards set in the manual tank gauging sections. However, the section of the preamble describing proposed § 3174.7(f) incorrectly said the oil samples themselves had to comply with the standards in the manual tank gauging section, rather than the testing procedures used to measure temperature, gravity (density), and S&W content. One commenter pointed out that this section not only incorrectly implied that temperature is somehow calculated from the oil in the sample pot, it also incorrectly referred to the standard testing procedures designed for manual tank gauging, not for testing using automated samplers as required in LACTs. The commenter stated that the BLM should use the standards in API
Paragraph § 3174.7(g) prohibits the use of automatic temperature/gravity compensators on LACT systems. Although Order 4 requires these devices, this rule will require those automatic compensators to be replaced using an electronic temperature averaging device. Automatic temperature/gravity compensators are designed to automatically adjust the LACT totalizer reading to compensate for changes in temperature and, in some cases, for changes in oil gravity as well. Unfortunately, the accuracy or operation of these devices cannot be verified in the field and there is no record of the original, uncorrected, totalizer readings. As a result, there is no ability to create an audit trail for these systems. As explained in the proposed rule, the BLM believes that the use of these devices inhibits its ability to verify the reported volumes because there is no source record generated, and the devices degrade the accuracy of measurement. Because there are relatively few LACT systems that still employ automatic temperature/gravity compensators, the BLM does not believe this requirement will result in significant costs to the industry.
Several commenters objected to this requirement, stating that temperature averagers are expensive and not necessarily any more accurate than temperature compensators, and that this change would require operators to replace functioning equipment at significant cost for no readily apparent benefit. One commenter stated that existing equipment should be grandfathered as long as an audit trail exists, and that the BLM should provide scientific evidence that automatic temperature/gravity compensators are less accurate than temperature averaging devices. Other commenters said that the simultaneous demand for temperature averaging devices would drive up the cost of purchasing and installing these devices on LACT systems. Several commenters indicated that rather than bear such a cost, some operators would choose to shut in wells and cease production activities.
In response to these comments, the BLM conducted field surveys of the companies that made the comments and determined that, in fact, they had very few LACTs that are still using automatic temperature/gravity compensators. Indeed, one of the companies had only one such LACT. The fact that very few LACTs still use automatic temperature/gravity compensators was confirmed by a major LACT manufacturer who stated that they sell very few automatic temperature/gravity compensators domestically, and that nearly all LACTs are currently equipped with temperature averagers. Further, this rule now provides for a phase-in of this new equipment over the next 1 to 4 years, based on when operators receive their FMP approvals, and the cost is relatively inexpensive (roughly $6,500 per LACT for the equipment). Regarding scientific studies or other data showing temperature averagers are more accurate, the BLM is not aware of any studies that show this. The main reason for the prohibition is that a temperature compensator is a mechanical device that does not have the capability for recording an “audit trail,” and therefore is inconsistent with the BLM's production accountability obligations. For these reasons, no change was made in this final rule.
Section 3174.8 contains LACT system components and operating requirements.
This section is closely related to § 3174.7 in that § 3174.7 contains general requirements for LACTs and states that LACTs must meet the construction and operation requirements and minimum standards of § 3174.8. Section 3174.8 goes into detail on what those requirements and standards are. Consequently, many of the comments on this section are closely related to comments received on § 3174.7.
In the proposed rule, § 3174.8(a) listed the components that each LACT must include. Several commenters said the BLM should not be so prescriptive and should instead require operators to comply with the appropriate API standards. One commenter stated this change would eliminate confusion and make it clear that Coriolis meters would be allowed as part of LACTs. In general, the BLM agrees that the original language was too prescriptive and may have inadvertently disallowed the use of Coriolis meters with LACTs. As a result of these comments, the final rule now simply requires LACTs to meet the standards prescribed in the applicable API sections. The list of all of the components required in LACTs has now been deleted from paragraph (a) and replaced with a statement that each LACT must include all equipment listed in API 6.1, with certain listed exceptions. The LACT components listed in § 3174.8(a) are related to requirements for PD and Coriolis meters and electronic temperature averaging devices, and allow multiple means of applying back pressure to the LACT to ensure single-phase flow. LACTs must consist of meters that have been reviewed by the PMT, approved by the BLM, and identified and described on the nationwide approval list at the BLM Web site (
One commenter stated that proposed § 3174.8 did not refer to industry standards for automatic sampling systems used with LACT and Coriolis meter systems, and that failure to provide minimal requirements could result in samples which were not representative, and therefore erroneous. The commenter also stated that proposed paragraph (b)(4), pertaining to standards for mixing of samples, should instead prescribe compliance with API 8.3, which contains the appropriate standards. Another commenter stated that proposed § 3174.8(a) did not mention an inline mixer or any pressure/temperature instrumentation, and asked if these items were prohibited or just not considered necessary. The same commenter stated that proposed § 3174.8(b)(2) discussed sample probe locations when standards for automatic sampling had not yet been incorporated into the rule, and requested that rather than restating portions of the standards in the rule, the BLM should incorporate API MPMS Chapters 8.2 and 8.3 into the rule.
The BLM agrees with the points raised in these comments and so, in the interest of eliminating uncertainty and errors, the final rule includes industry
One commenter stated that the requirement in proposed § 3174.8(a)(10) and (b)(13) to have a back pressure valve and check valve downstream of the LACT could be met by allowing operators to use another common industry practice of placing a pump downstream. The BLM agrees that this arrangement would meet the intent of the requirement, which is to ensure single-phase flow through the meter, and has changed the rule accordingly. The revised requirement is more flexible and is found in the renumbered final rule at § 3174.8(a)(3).
One commenter noted that in proposed § 3174.8(a)(7), the BLM limited LACTs to only using a PD meter, and said that any type of meter permitted in API standards should be allowed. These standards include PD, Coriolis, and turbine meters. The BLM partly agrees and has changed the rule to allow Coriolis meters because field and laboratory testing have proven the Coriolis meter to be reliable and accurate. However, the BLM does not agree that turbine meters should be allowed. In the BLM's experience, confirmed by many industry sources, turbine flowmeters are less accurate and are more subject to wear or damage. As a result, the BLM will continue to prohibit the use of turbine meters in LACTs. The change to allow Coriolis meters in LACTs is reflected in § 3174.8(a)(1) of the final rule. References to the definition of, proving standards for, and other specific requirements for Coriolis meters are contained throughout the rule in appropriate sections.
Section 3174.8(b) describes the system operating requirements for LACTs. Multiple comments were received on this section, many of which focused on making the requirements less prescriptive and instead referencing API standards more extensively.
In general, in response to numerous comments that the proposed rule lacked flexibility, we have removed most of the prescriptive requirements in proposed § 3174.8(b). This section now requires operators to follow the sampling-process standards in API 8.2 and API 8.3 (the equipment and procedures to obtain and properly mix a representative sample); the standards for measuring the gravity (density) and S&W content of those samples in API 9.1, API 9.2, API 9.3, and API 10.4; the standards for flow measurement using electronic meter systems in API 21.2; the standards for temperature determination in API 7; and the standards for calculating net oil volumes for each run ticket in API 12.2.1 and API 12.2.2. All of these API standards are incorporated by reference and listed in § 3174.3.
One commenter objected to the BLM's requirement in proposed § 3174.8(b)(1) that LACTs include an electrically driven pump sized to ensure: (1) A discharge pressure compatible with the meter used; and, (2) That the flow in the LACT main stream piping is turbulent, such that the measurement uncertainty levels proposed in § 3174.3 are met. Instead, the commenter suggests that the BLM should require LACTs to meet uncertainty requirements without being so prescriptive. Another commenter stated that the BLM should be more flexible about the types of S&W monitors that would be allowed under proposed § 3174.8(b)(7) because some manufacturers do not make the types of plastic-coated probes that this section required. The commenter also suggested that existing S&W monitoring technologies should be grandfathered. Several other commenters stated that the requirement for a back pressure valve in proposed § 3174.8(b)(13) was too prescriptive and did not give operators the flexibility to use other methods to achieve the same result that back pressure valves provide—maintaining single-phase (oil-only) flow through the LACT meter. As discussed earlier, the BLM is keeping the requirement that LACT systems contain a back-pressure valve in the final rule at § 3174.8(a)(3), but we agree with commenters that the requirement needs to be more flexible, and we have added language that gives operators the option of using other controllable means of applying back pressure to ensure single-phase flow. Also in response to these comments, the BLM removed most of the prescriptive requirements in proposed § 3174.8(b) and replaced them with a requirement that operators meet the LACT system operating standards outlined in the applicable API standard incorporated by reference into the proposed rule. The only requirements that are spelled out in paragraph (b) are those requirements that are in addition to or different from standard API practices or that clarify which API standards are applicable.
Several commenters expressed concern that retrofitting or replacing existing equipment to meet the requirements of § 3174.8 was unnecessary and prohibitively expensive, and that existing facilities should be grandfathered, with some also suggesting that bringing existing facilities into compliance within the proposed 180-day implementation timeframe was either too expensive, impossible, or both. In response to these comments, the BLM has clarified in § 3174.2 in the final rule that all equipment must comply with the new requirements, with operators required to come into compliance on a staggered schedule of between 1 and 4 years, depending on when they receive their FMP approvals, which is based on their production levels. This significantly extends the compliance timeframe and gives operators time to budget and plan for any required changes, while limiting the chances that there will be local or national shortages of equipment or technical expertise, such as might have resulted from the proposed 180-day implementation period.
One commenter stated that proposed § 3174.8(b) should be revised to include a densitometer as optional equipment in the list of components, and that if density is provided, recordable, auditable, and verifiable, then the sampler and sample pot should not be required, which would save operators the cost of those components and lab analyses to determine S&W content. The commenter further said that if the sampler is not included in the list of components, then S&W content must be reported as zero percent, and the entire volume passing through the LACT meter would be reported as 100 percent oil. The BLM understands that there may be cases in which the operator would be willing to consider the entire produced stream as 100 percent oil, but the BLM believes that omitting the sampler and sample pot would create the potential for added confusion, and it is likely that most purchasers are going to require a sample grind-out anyway. For these reasons, no change was made to the rule as a result of this comment.
One commenter pointed out that proposed § 3174.8(b)(11)(ii), which required a temperature averaging device to take a temperature reading at least once per barrel, did not accord with API 21.2, Subsection 9.2.8.1, which requires such devices to be flow proportional and take a reading at least once every 5 seconds. The BLM agrees and has changed the rule accordingly. This provision in the final rule has been renumbered as § 3174.8(b)(6)(ii) and now reads: “The electronic temperature averaging device must be volume-weighted and take a temperature reading following API 21.2, Subsection 9.2.8 (incorporated by reference, see § 3174.3).”
Sections 3174.9 and 3174.10 pertain to CMS, which are not addressed in Order 4. Order 4 allows only for the use of PD meters with LACT systems. The use of Coriolis meters in this rule is based on technological advancements that provide for measurement accuracy that meets or exceeds the overall performance standards in § 3174.4. Field and laboratory testing of Coriolis meters has proven them to be reliable and accurate meters when installed, configured, and operated correctly.
One commenter said the final rule should allow operators to use truck-mounted CMS and submitted summarized data to support their view. The summarized data indicates significant differences between manual-gauged volumes and truck-mounted Coriolis-metered volumes. A summary of these volume differences indicated that the truck-mounted Coriolis meter measured as much as 22.44 bbl less that the manual gauge measured. Missing from the data is the volume of the entire load. The BLM needs this information to understand how significant these variations are. The data also indicates significant differences in measured oil temperature (as much as 23 °F) and gravity (as much as 5 degrees) when compared to manual methods. The commenter did not explain these differences or explain or justify the data submitted. The BLM decided not to include the use of truck-mounted Coriolis metering in the final rule. Operators may seek approval to use the truck-mounted option through the PMT approval process, which is outlined in § 3174.13. The rule was not changed based on this comment.
Another commenter suggested that the CMS could be used for gas measurement, in addition to oil measurement. The BLM has noted this comment; however, this subpart is dedicated to the measurement of oil. The rulemaking that is replacing Order 5 is a more appropriate venue for considering this comment, and this comment was directed to that rule team. The comment did not result in a change to this rule.
Several commenters stated that the term “CMS” should not be used for a Coriolis LACT as it is simply a LACT. The BLM agrees with this comment and has no intention of replacing the term “LACT” with the term “CMS.” The rule as proposed was intended to allow the Coriolis meter to be used in a LACT as an alternative to the PD meter, or as a standalone meter independent of a LACT system. The term CMS refers only to the latter option. To clarify this issue, the final rule has been edited to state that a Coriolis meter may be used in a LACT
Section 3174.9(b) specifies that Coriolis meters that have been reviewed by the PMT, approved by the BLM, and identified and described on the nationwide approval list at the BLM Web site (
One commenter said requiring each operator to have its CMS approved would result in a large financial burden. The BLM disagrees because the PMT only needs to approve a particular make or model of Coriolis meters once. Once a meter make or model has been reviewed, approved, and posted on the BLM's Web site, the meter can be installed at any facility, subject to any COAs imposed by the PMT for its use. Existing installations that already meet the requirements in §§ 3174.9 and 3174.10 do not require additional BLM approval.
Section 3174.9(c) requires that a CMS be proved following the frequency established under § 3174.11. This proving frequency will ensure that operators periodically prove the CMS to provide verification that the meter is within the allowable tolerances. There were no comments on this section.
Section 3174.9(d) requires that measurement (run) tickets be completed as required by § 3174.12(b). This establishes the measurement-ticket time periods and minimum requirements for information that must be included on the tickets. There were no comments on this section.
Section 3174.9(e) identifies the applicable API standards for the components that must be installed with a CMS at an FMP, and includes some additional requirements that operators using a CMS for oil measurement must follow. The proposed rule listed the components in exact order from upstream to downstream of a CMS. The BLM has opted to be less prescriptive in the final rule and is requiring operators to follow API 5.6 for the setup and installation of a CMS system.
One of the prescriptive requirements in proposed § 3174.9(e)(7) was for operators to install a density measurement verification point. One commenter asked that this term be defined. Since the BLM has removed the prescriptive requirements and this particular term from the rule, a definition is no longer needed. No change resulted from this comment.
Another commenter said the BLM needs to allow for a connection point for a pycnometer. As discussed earlier, the BLM has removed the prescriptive, step-by-step requirements in this section. Should an operator wish to use this density-determination option, API 5.6 does allow for a density verification point that could be used as the point for installing the pycnometer. There was no change to the rule as a result of this comment.
Section 3174.9(e)(1) and (2) sets accuracy thresholds for temperature and pressure measurement devices that are part of a CMS. These devices are required to calculate the CPL and CTL correction factors. The uncertainties of these devices will be used in the overall uncertainty calculation to ensure that the CMS meets or exceeds the uncertainty levels required by § 3174.4. There were no comments on this section.
Section 3174.9(e)(3) covers the options for handling S&W content when determining net volume. Measurement by LACT requires a composite sampling system and determines net oil volume by deducting S&W content. The CMS does not require a composite sampling system, but rather leaves the option to the operator to either install a composite sampling system to determine S&W content for deduction in net oil determination or to make no S&W content deduction in net oil determination. In practice, Coriolis meters may be used at the outlet of a separator. It may not be feasible to use a composite sampling system at the outlet of a separator due to high separator pressure, thus effectively precluding the ability to determine S&W content. Without the ability to accurately determine S&W content, § 3174.9(e)(3) will require operators to report the S&W content as zero. The BLM may consider options to use other
Several commenters stated that if the rule does not allow corrections for S&W content, operators will be required to report an inaccurate volume. The BLM agrees that failing to correct for S&W content could result in an inaccurate measurement of net volume of product sold. However, this rule gives the operator the option to determine S&W content; if the operator chooses not to install the necessary equipment to determine the accurate S&W content, then no deduction will be allowed. The inclusion of the CMS as a method to measure production does not make this the sole means of measurement. It will be at the discretion of the operator to determine which method of measurement is most effective for their operation. In certain operations where a composite sampling system cannot be installed, and the operator determines reporting S&W content as zero is inappropriate for their operation, other measurement options may be available, though the operator will have to seek review through the PMT. No change to the rule resulted from these comments.
Relatedly, several commenters stated that the BLM should allow other methods to determine S&W content. The BLM agrees that other methods could be allowed, but the BLM does not currently have the data to review those options. As noted, under the final rule, an operator wishing to use a different option for determining S&W content will have to seek approval through the PMT process, as outlined in § 3174.13. No change resulted from this comment.
Section 3174.9(e)(4) requires single-phase flow through the CMS by means of applied back pressure. The proposed rule would have required operators to use a back pressure valve downstream of the Coriolis meter to achieve single-phase flow. Several commenters stated that there are other means of applying back pressure that are just as effective as using a back pressure valve, such as pumps downstream of the CMS. The BLM agrees and has changed the rule as a result of this comment. Instead of allowing only a back pressure valve, the BLM will allow the operator to use any means to apply sufficient back pressure to ensure single phase flow, so long as the approach meets the requirements of API 5.6.
Section 3174.9(f) allows the API oil gravity to be determined by using one of two methods: (1) From a sample taken from a composite sample container; or (2) Directly from the average density measured by the Coriolis meter. This choice accommodates situations in which it is not feasible or an operator chooses to not install a composite sampling system due to economic or operating constraints. The BLM may consider other methods for determining the API gravity of the fluid, such as in-line densitometer devices. However, the BLM will only approve alternative methods if resulting overall uncertainty is within the limits in § 3174.4.
One commenter suggested that the BLM should incorporate by reference the guidelines in API 8.2 and API 8.3 on composite sampling. Because a sample from a composite sample container is an acceptable method for determining the API oil gravity, the BLM agrees that the industry standard should be included and has incorporated API 8.2 for automatic sampling and API 8.3 for mixing and handling of samples into § 3174.8(b)(1) of the final rule.
Another commenter stated that the use of Tables 5A and 6A is inappropriate and that the flowing density should be corrected in accordance with API 11.1. The BLM agrees that Tables 5A and 6A are outdated and should not be used and has removed the language that referenced Tables 5A and 6A and replaced it with a reference to API 11.1.
Another commenter stated that abnormal events should be excluded from the average density calculation. The BLM assumes the commenter is referring to the fact that water, sand, or gas breakout may occur during a normal flowing regime. Excluding these abnormal events from the average density is allowed under the final rule, so long as an audit trail is maintained showing the full-flow density, including the period of flow that has been removed from the average density calculation. There is no change to the final rule as a result of this comment.
Another commenter said that during proving, a density correction factor should be applied if the densitometer within the Coriolis meter varies from a master densitometer at the density verification point. The BLM disagrees with this comment. During the proving verification of the densitometer within the Coriolis meter, the density reading is compared to an independent density measurement. The difference between the indicated density determined from the Coriolis meter and the independently determined density must be within the specified density reference accuracy specification of the Coriolis meter. If the Coriolis densitometer exceeds the manufacturer's specification density tolerance, then the meter must be repaired or replaced, or an alternative method of density determination must be approved for use. Any alternative method must result in an overall uncertainty that is within the limits in § 3174.4.
Section 3174.9(g) requires that the net standard volume be calculated following API 12.2.1 and API 12.2.2. The proposed rule listed this requirement in § 3174.10(g) and gave very prescriptive requirements for the calculation. However, in order to make the final rule less prescriptive and to rely on industry standards wherever possible and appropriate, the requirement has been moved to § 3174.9(g), and the prescriptive language has been removed in favor of the guidelines listed in API 12.2.1 and API 12.2.2.
Several commenters said that net standard volume cannot be calculated by current Coriolis meters or any flow meter for that matter. The BLM agrees with these comments and for that reason there are no requirements in this rule that the CMS, or any meter, calculate and display net standard volume. No change was made to the rule as a result of these comments.
Another commenter stated that operators should be allowed to apply a shrinkage factor to the net standard volume. The BLM disagrees because past experience in reviewing net oil determinations shows that applying a calculated shrinkage factor results in very high uncertainty for the metering systems. The resulting overall uncertainty would exceed the limits of § 3174.4. Should new methods or technology for applying shrinkage factors be developed and proposed for use in the future, the PMT process described in § 3174.13 would be used for review and approval of those methods or technologies. No change to the final rule has been made as a result of this comment.
Section 3174.10(a) establishes the minimum pulse resolution (
Section 3174.10(b) establishes the minimum standards and specifications
One commenter recommended that the BLM remove the requirement for maintaining and submitting to the BLM upon request the Coriolis meter specifications found in § 3174.10(b). The commenter said this requirement is not necessary for uncertainty-based measurement limits. The BLM disagrees. In order for the BLM to conduct a complete inspection of the CMS, it is necessary that all information required by this section be available to ensure that the Coriolis meter is operating within its design parameters, on which the uncertainty for the meter is based. No change in the final rule was made as a result of this comment.
Proposed § 3174.10(b)(iv) required that the minimum amounts of straight piping be installed upstream and downstream of the meter. Several commenters said that Coriolis meters do not require any specific amount of straight piping. The BLM agrees that pipe-length restrictions in Coriolis meter installations do not affect accurate measurement and has removed any reference to straight-pipe requirements for Coriolis meters from the rule.
Section 3174.10(c) requires a non-resettable totalizer for indicated volume. This is to allow verification over multiple run tickets of gross production prior to any adjustments to net standard volume. There were no comments on this requirement.
Proposed § 3174.10(c) had a requirement for meter orientation. One commenter said the BLM should remove this requirement because it is too prescriptive and should instead require operators to follow API standards. The BLM agrees that the proposed language was too prescriptive. The final rule, in § 3174.10(e), now requires operators to follow API 5.6.
Section 3174.10(d) of the proposed rule required that the operator must notify the AO within 24 hours of any changes to any Coriolis meter internal calibration factors including, but not limited to, meter factor, pulse-scaling factor, flow-calibration factor, density-calibration factor, or density-meter factor. One commenter suggested that 24 hours is an unreasonably short period of time for this requirement, especially if the applicable changes occur on a weekend. The commenter recommended a period of at least 10 days, or a monthly report from the PLC log. After consideration of this proposed requirement, the submitted comment, and the proving requirements in the final rule, the BLM has decided to remove this notification requirement from the rule because any changes to a Coriolis meter internal calibration factor will require immediate proving of the meter as required in § 3174.11(d)(8). An additional notification provides no benefit to the BLM.
Section 3174.10(d) (paragraph (f) in the proposed rule) requires verification of the meter zero reading before proving the meter or any time the AO requests it. The proposed rule described the process for verifying the meter zero value. The BLM has changed the wording in the final rule to be less prescriptive and to require the operator to follow manufacturer guidelines. This gives the operator flexibility during the verification procedure.
Several commenters said that requiring flow to be stopped during meter verification is an additional step and may disrupt normal operations. The BLM agrees that in order to verify that the meter is operating within the manufacturers' specifications, operators are required to verify the meter zero with no fluid flow. However, the BLM disagrees that meter zero verification is a disruption to normal operations. According to API standards and manufacturer recommendations, Coriolis meter zero verification is a part of normal operations. As discussed above, the final rule has been changed to require operators to follow manufacturer guidelines for meter zero verification; however, the requirement to verify meter zero remains in the final rule.
Section 3174.10(e)(1) through (e)(4) (paragraphs (i)(1) through (i)(4) in the proposed rule) lists the information that the Coriolis meter must display onsite. As part of the BLM's verification process during field inspections, the AO must be able to access this information without the use of a laptop or other special equipment. A log must be maintained of all meter factors, zero verifications, and zero adjustments, and must be made available to the AO upon request. The proposed rule would have required operators to maintain the log onsite.
The BLM received several comments stating that the requirement for a log to be maintained onsite containing the meter factor, zero verification, and zero adjustments is not practical. Because this information will not need to be readily available onsite for the AO to complete an inspection, the BLM agrees with the commenters and has changed the final rule in § 3174.10(e)(4) to require that the log containing the meter factor, zero verification, and zero adjustments must be made available upon request.
One commenter stated that the requirement in paragraph (e)(2) for the meter to display the instantaneous pressure has no valid use. The BLM disagrees with this statement as this information is needed as part of routine inspections conducted by the AO to verify the flowing volume in a meter. No changes were made as a result of this comment. Another commenter said that some Coriolis meters do not have the ability to display the density in pounds per barrel as originally required by the proposed rule. After contacting Coriolis system manufacturers, the BLM has confirmed that not all Coriolis meters have the ability to display this particular unit of measurement. Therefore, as a result of this comment, the requirement to display the density in pounds per barrel has been removed and other units of measurement (pounds per gallon or degrees API) have been added in § 3174.10(e)(2)(i). One commenter said that daily volume totals may not be available for display. The BLM contacted manufacturers and confirmed that Coriolis meters are capable of displaying daily volume totals. As a result, there was no change in the final rule from this comment.
Section 3174.10(f) requires that audit trail information listed in § 3174.10(f)(1) through (4) be retained for the time period required in § 3170.7, which is part of the rulemaking to replace Order 3. One commenter said that the requirements in § 3174.10(f)(2) and (4) may force operators to add a flow computer to a Coriolis LACT, which exceed the requirements of a PD LACT. This comment does not make sense because a Coriolis meter almost always has a flow computer. If an operator chooses to configure a Coriolis meter in a LACT without utilizing a flow computer, and display only a totalizer reading, then the requirements of § 3174.10(f)(2) and (4) would not apply. No change resulted from this comment.
Section 3174.10(g) requires that each Coriolis meter have an operable backup power supply or nonvolatile memory capable of retaining all data. This is to ensure that during a failure, all audit trail data is preserved to maintain compliance with these regulations. There were no comments on this section.
Proposed § 3174.11(a) and (b) would have established that a meter would not be eligible to be used for royalty determination unless it is proven to the
A table in proposed paragraph (b) referred readers to the applicable paragraphs of this proposed section that contained the minimum standards for proving FMP meters. The BLM received no comments on this table. Nevertheless, the BLM did not include the paragraph (b) table in the final rule because the table did not provide substantive clarity or expedite reader access to the relevant paragraphs. This change resulted in the re-lettering of all subsequent section paragraphs in the final rule.
Paragraph (c) in proposed § 3174.11 (re-lettered to paragraph (b) in the final rule), established the acceptable types of meter provers that can be used to prove an FMP LACT or CMS. The BLM received a few comments objecting to the meter-proving requirements in this section of the final rule because they are not consistent with the referenced API specifications. These comments are addressed in the following text.
Section 3174.11(b)(1) through (3) of the final rule describe and detail the requirements for acceptable meter provers, which include the master meters and displacement provers that are currently allowed under Order 4. Coriolis master meters, which were not addressed in Order 4, have been included in the final rule. The BLM believes that Coriolis technology has advanced to the point where Coriolis meters meet the accuracy and verifiability requirements required for master meters. The final rule does not allow tank provers to be used as an acceptable device for proving a meter. According to API standards, tank provers are not recommended for use on viscous liquids, which include most crude oils. Because there are few tank provers currently in use on Federal and Indian leases, this requirement will not result in a significant cost to industry. One commenter on paragraph (b)(1) stated that the BLM requirement for master meter repeatability of 0.0002 (0.02 percent) is inconsistent with API 4.5, which requires a repeatability of 0.0005 (0.05 percent). The BLM agrees with the commenter and made a change to the final rule consistent with the comment. The BLM believes that the paragraph (b)(1) repeatability requirement for master meter provers in the proposed rule was too restrictive and the API 4.8 (as referenced in API 4.5) specification of 0.0005 (0.05 percent) repeatability is within the uncertainty (±0.027 percent) of BLM requirements.
The BLM also made a change to the final rule based on a comment that the calibration of the master meter prover in the proposed rule was too frequent. The proposed rule required master meter provers to be calibrated no less frequently than once every 90 days. The BLM agrees that the 90-day frequency for proving master meters may be too frequent. The final rule changes the master meter calibration frequency to no less than once every 12 months, which is consistent with API 4.8, Subsection 10.2, which is referenced in API 4.5.
One comment on paragraph (b)(2) of this section said the BLM displacement prover calibration requirements contradict API Chapter 4.9. The BLM disagrees with the commenter since API 4.9 addresses calibration methods for displacement provers and not calibration frequency for displacement provers as specified in API 4.8. The BLM changed paragraph (b)(2) in the final rule by removing the prescriptive language found in paragraphs (b)(2)(i) and (ii) in the proposed rule, and by incorporating calibration frequency requirements of API 4.8, Subsection 10.
Section 3174.11(b)(3) of the final rule (§ 3174.11(c)(3) of the proposed rule) requires the base prover volume of a displacement prover must be calculated under API 12.2.4. The BLM received no comments and made no changes to this requirement.
Section 3174.11(b)(4) (paragraph (c)(4) in the proposed rule) establishes displacement prover sizing standards. These standards ensure that fluid velocity within the prover is within the limits recommended by API 4.2, Subsection 4.3.4. Displacement velocities that are too low (prover is oversized) can result in unacceptable pressure and flow-rate changes and higher uncertainty due to possible displacement device “chatter.” Displacement velocities that are too high (prover is undersized) can cause damage to the components of the prover. One commenter recommended replacing the proposed prover design language that referenced API 4.2 with language that references operating provers within design parameters set forth by the manufacturer and by API 4.8 and API 4.9.2. The BLM disagrees with the commenter that paragraph (b)(4) should reference API 4.8 and API 4.9.2 since these standards deal with prover operation and are not relevant to paragraph(b)(4) design standards. Paragraph (b)(4) is specific to displacement prover design, which is covered under API 4.2. The BLM did not change the final rule in response to this comment.
Section 3174.11(c) (paragraph (d) in the proposed rule) establishes the requirements for meter proving runs with respect to proving both the FMP LACT and CMS and the conditions required for proving these meter systems. The BLM received many comments objecting to certain requirements in proposed § 3174.11(d) that deal with meter proving runs. The BLM responds to these comments as follows.
Section 3174.11(c)(1) (paragraph (d)(1) in the proposed rule) expands on the current Order 4 requirement to prove a meter under “normal” operating conditions. This section defines limits of flow rate, pressure, temperature, and API oil gravity that must exist during the proving to be considered “normal” operating condition. The BLM added this requirement because it realized that the meter factor can change with changes in these parameters. For example, a meter factor determined at an abnormally low flow rate may not represent the meter factor at a higher flow rate where the meter normally operates. This paragraph also requires a multi-point meter proving if the LACT or CMS is subject to highly variable conditions. The multi-point meter proving establishes a minimum of three meter factors—one at the low end of the normal operating range, one at the midpoint, and one at the high end. An appropriate meter factor will then be applied according to § 3174.11(c)(6).
One commenter noted that paragraph (c)(1) (paragraph (d)(1) in the proposed rule) lacks specifics on what normal operating temperature conditions mean and another commenter said the language should be changed to reflect situations where normal operating conditions vary, such as at multi-metering sites, and suggested a language change to “average for the batch period.” The BLM agrees with the commenter that normal operating conditions, as they apply to oil temperature, were not adequately addressed in the proposed rule and that in some instances it may be difficult to identify the “normal operating conditions” of flowrate, pressure, temperature, and fluid density. The BLM added paragraph (c)(1)(iii) to the final rule to address normal oil operating temperature limits, which must be within 10 °F of the normal operating temperature. With this addition, paragraphs (d)(1)(iii) and (d)(1)(iv) in the proposed rule have been renumbered to paragraphs (c)(1)(iv) and (c)(1)(v) in the final rule.
The BLM made no change to the final rule regarding normal operating conditions to reflect variable metering conditions since this situation may be specific to regions and areas of the country and can be more adequately addressed by the specific BLM field office through the variance request process as outlined in § 3170.6, which has been established as part of the rulemaking to replace Order 3.
Section 3174.11 paragraphs (c)(2) through (c)(5) (paragraphs (d)(2) through (d)(5) in the proposed rule) provide the details for minimum proving requirements, such as requiring a minimum proving pulse resolution of 10,000 pulses per proving run or requiring the use of pulse interpolation, if this cannot be met, and setting a requirement to continue repeating proving runs until the calculated meter factor from five consecutive runs is within a 0.05 percent tolerance between the highest and lowest value. The new meter factor will be the arithmetic average of the five meter factors or average pulses from the five consecutive proving runs. This section also requires the meter factors to be calculated following the sequence described in API 12.2.3. We received two comments on paragraph (c)(2) of this section. One commenter addressed the requirement that, during proving runs, there be a sufficient volume to generate at least 10,000 pulses from the FMP meter that is being proved. The commenter did not believe that the 10,000-pulse requirement is reasonable and said it would disallow the use of small-volume provers (SVPs). The BLM disagrees with the commenter on both points. The 10,000-pulse-per-proving-run resolution in the rule follows the API standard and the rule specifically allows small-volume provers as long as they meet the additional requirements in paragraph (c)(2). The BLM did not change the final rule in response to this comment. However, the BLM believes that it is appropriate to add clarifying language to paragraph (c)(2) in the final rule that reminds readers of the 10,000-pulse requirement in API 4.2, Subsection 4.3.2. Another commenter asked why the proposed rule did not specifically address SVPs. SVPs come under the requirements for displacement provers and, under paragraph (c)(2), are required to use pulse interpolation as outlined in API 4.6, since their volume generates less than 10,000 meter pulses per proving run. The BLM did not change the final rule due to this comment.
Two commenters on paragraph (c)(3) objected to the requirement that the five consecutive meter-proving runs have a repeatability of 0.0005 (0.05 percent), saying that three proving runs could accomplish the same uncertainty. The BLM disagrees with these commenters and has decided to retain Order 4's requirement of a minimum of five proving runs. The BLM believes that this requirement achieves the desired consistency and uncertainty levels. The BLM made no change to the final rule due to these comments.
One commenter on paragraph (c)(4) recommended that the BLM adopt the use of an average meter factor as determined from API 12.2.3. Upon review of this comment, the BLM agrees with the commenter that guidance on the calculation of the average meter factor is appropriate. Due to this comment, the BLM changed the final rule to incorporate API 12.2.3, Subsection 9 for purposes of calculating the average meter factor.
Section 3174.11(c)(5) of the final rule (§ 3174.11(d)(5) of the proposed rule) requires that meter factor computations must follow the sequence described in API 12.2.3. The BLM received no comments and made no changes to this requirement.
Section 3174.11(c)(6) (paragraph (d)(6) in the proposed rule) gives operators two methods for determining the multiple meter factors that are required under § 3174.11(c)(1)(v). The first method is to combine the meter factors into a single arithmetic average. The second method is to curve-fit the meter factors and incorporate a real-time dynamic meter factor into the flow computer (this will apply primarily to CMS). Neither multi-point provings nor multi-point meter factors are discussed in Order 4. One commenter indicated that averaging meter factors was only valid in regions where impacts of nonlinearities are minimal and recommended deleting § 3174.11(c)(6)(i). The BLM conducted further research into this comment and agrees with the commenter that averaging meter factors is only valid under certain conditions. Additional language pertaining to how to use the multiple meter factors is added to the final rule in paragraph (c)(6). This language will only permit the use of averaging meter factors if all meter factors in the range are within approximately ±0.10 percent of the average. It will also limit the use of the dynamic meter factor option to prevent any two neighboring meter factors that differ by more than approximately 0.2 percent from being used to derive a dynamic meter factor.
Sections 3174.11(c)(7) and (c)(8) (paragraphs (d)(7) and (d)(8) in the proposed rule) set the minimum and maximum values that are allowed for a meter factor, both between meter provings and for initial meter factors for newly installed or repaired meters. These meter-factor ranges are not changed from Order 4. The BLM received no comments on paragraphs (c)(7) and (8).
Section 3174.11(c)(9) (paragraph (d)(9) in the proposed rule) allows back pressure valve adjustment after proving only within the normal operating fluid flow rate and fluid pressure as prescribed in proposed § 3174.11(c)(1). If the back pressure valve is adjusted after proving, the “as left” fluid flow rate and fluid pressure must be documented on the proving report. The BLM is requiring this documentation based on its field observations, which have shown this practice to affect the meter factor in certain areas of the country. Specifically, the BLM has observed that a change in back pressure outside the proving conditions can, in some cases, result in operators reporting incorrect volumes. Allowing back pressure valve adjustment after proving is not intended as a means to circumvent the displacement prover minimum and maximum velocity requirements in § 3174.11(b)(4) of the final rule. Order 4 has no specific requirements relating to the adjustment of the back pressure valve after proving. The BLM received no comments on paragraph (c)(9).
Section 3174.11(c)(10) (paragraph (d)(10) in the proposed rule) sets standards for the pressure used to calculate a CPL factor for a LACT's composite meter factor. It also prohibits the use of a composite meter factor for Coriolis meters because they have the capability to use a true average pressure over the measurement ticket period in the calculation of an average CPL factor. The use of a composite meter factor is intended to make measurement tickets easier to complete because the CPL factor is already included in the meter factor. This is typically not an issue with a Coriolis meter because of the advanced capability of the flow computer to which it is connected. One commenter stated that most Coriolis meters in the field do not have the capability to calculate a CPL factor and replacing them with a Coriolis meter that could calculate a CPL factor would be prohibitively costly. The BLM agrees with the commenter regarding the CPL factor capability currently available in existing Coriolis meters. However, the final rule does not require operators to have a Coriolis meter with this CPL factor feature. Therefore, the BLM made no change to the final rule as a result of this comment.
Section 3174.11(d) (paragraph (e) in the proposed rule) establishes the minimum FMP meter-proving frequencies, and specifies certain events that will trigger additional meter provings. This section contains the meter-proving requirements that were previously located in the LACT section of Order 4 and consolidates in one place all of the meter-proving requirements for both LACTs and CMSs.
The BLM received many comments that objected to the provision in paragraph (d)(2) (paragraph (e)(2) of the proposed rule) that sets a threshold for when operators who run large volumes of oil through their meters must conduct additional FMP meter provings. The proposed rule would have required operators to prove their FMP meters each time the registered volume flowing through their meters increased by 50,000 bbl or quarterly, whichever occurred first. Currently under Order 4, an FMP meter must be proven at least quarterly, unless total throughput exceeds 100,000 bbl per month, in which case the meter must be proven monthly.
The BLM's rationale in the proposed rule for changing the proving threshold to 50,000 bbl/month was that it would have affected only about 5 percent of existing LACT systems nationwide, yet would have ensured that meter-factor changes would be corrected before large volumes of production were measured incorrectly, which could have an adverse impact on Federal or Indian royalty determinations.
Many commenters objected to the proposed meter-proving-frequency threshold of 50,000 bbl/month. Most commenters said this new meter-proving frequency would require them to perform excessive and costly meter provings in locations where the meters may not be easy to access, especially in bad weather. The BLM agrees that the 50,000 bbl/month threshold may be excessively costly and, after reviewing potential economic impacts, has decided to use a 75,000 bbl meter-proving frequency threshold in the final rule. This 75,000 bbl throughput threshold was determined by performing a statistical analysis to determine the volume at which the expected value of royalty under- or overpayment due to meter factors equals the $550 average cost of proving a meter. The royalty revenue impact depends not only on volumes but also on oil prices. The 50,000 bbl/month threshold in the proposed rule was determined when the U.S. Energy Information Administration's (EIA) 10-year West Texas Intermediate crude oil spot price was expected to average $95/bbl. Since then, the EIA's predicted 5-year average crude oil price has dropped significantly, to $67.58 per barrel. The BLM does not find the 50,000/bbl meter-proving threshold to be appropriate under this predicted lower oil-price environment.
The BLM also revised the maximum and minimum proving frequencies for meter proving on higher-volume FMPs. Under Order 4, operators were required to prove their meters at least quarterly or, if total throughput exceeded 100,000 bbl/month, then they were required to prove monthly. In this final rule, operators must prove their meters every 3 months (quarterly), or each time the registered volume flowing through the meter increases by 75,000 bbl, but no more frequently than monthly. For example, if a meter hits the 75,000 bbl threshold every 6 weeks, the operator must prove it every 6 weeks. If a meter has a 75,000 bbl throughput every 2 weeks, the operator must prove it once a month. The final rule was changed to include this new language.
Two commenters on paragraph (d)(2) said meter-proving frequencies should be increased, based on a lower volume of throughput threshold, and another commenter said that frequent proving would increase accuracy. The BLM does not agree that the final rule should further increase the proving frequency beyond what was presented in the proposed rule. The comments lacked any substantive basis and did not justify how an increased proving frequency would result in increased accuracy or how the costs of those additional provings would be justified by any reduction in royalty risk. The BLM believes the proving frequency in the final rule is justified and results in the required accuracy. The BLM did not change the final rule in response to these comments.
One commenter on paragraph (d)(6) of § 3174.11 (paragraph (e)(6) of the proposed rule) said that requiring a meter proving due to a change in normal operating conditions was not practical and not needed. The BLM disagrees with this commenter and agrees with another commenter who, in his comment on paragraph (e), pointed out that temperature extremes in places like Alaska or North Dakota have a large impact on meter-factor change between different proving runs. Because a change in the normal operating conditions could significantly affect the meter factor, and therefore the accurate measurement of the oil volumes, the BLM made no change to the final rule due to this comment.
Paragraph (d)(7) in § 3174.11 (paragraph (e)(7) in the proposed rule) also expands the current Order 4 requirement that operators prove their meters after repair. The new requirements require proving any time the mechanical or electrical components of the meter have been changed, repaired, or removed. In addition to those circumstances, paragraph (d)(8) requires an operator to also prove its meter after internal calibration factors have been changed or reprogrammed. One commenter asked whether meters used in flowback operations are subject to the requirements in this section. Flowback meters are not required to comply with this rule's meter-proving requirements because flowback operations take place prior to the operator's receipt of an FMP approval under § 3173.12, and more importantly meters used in these operations are not FMPs. The BLM did not change the final rule based on this comment.
One commenter said that after initial meter installation, a period of 2 weeks should pass before the meter is proved. The commenter did not justify a 2-week delay. The BLM believes that a meter should be proved as soon as is reasonably possible. The BLM expects that meters will be proven immediately after installation. The BLM did not change the final rule based on this this comment.
One commenter said that paragraph (d)(7) (paragraph (e)(7) in the proposed rule) is vague. The commenter specifically complained about language that required a meter proving after the mechanical or electrical components of the meter have been, among other things, “opened.” The BLM agrees with the commenter and changed the final rule so that the paragraph, in its entirety, now requires a meter proving after “the mechanical or electrical components of the meter have been changed, repaired, or removed”, and added (d)(8) to prove after “internal calibration factors have been changed or reprogrammed.” Another commenter questioned the need to reprove a meter each time its secondary element (transducer) or tertiary device is changed. The commenter contends that these elements have no direct effect on the meter performance. The BLM agrees with the commenter in part. An element can impact the accuracy of the measurement if it is not measuring temperature and pressure accurately. Changing out either of these elements would not require the meter to be reproved, but would require the new element(s) (transducers) to be verified upon their replacement as is required under §§ 3174.11(f) and (g), and temperature and pressure transducer verification, respectively, during a
Section 3174.11(e) (§ 3174.11(f) in the proposed rule) establishes what operators must do when there is excessive FMP meter factor deviation. This situation occurs when a meter factor, which is established in two successive provings, exceeds the allowable meter factor deviations. This section requires operators to take steps to bring the FMP meter back into compliance. It also requires operators to re-calculate the amount of production that was measured during the time period between these instances of excessive meter factor deviation. Paragraph (e) also requires operators to show the most recent meter factor and describe all subsequent repairs and adjustments on the proving reports that are required in paragraph (i) of this section.
Section 3174.11(e) maintains the Order 4 requirements for excess meter factor deviation and the required actions if proving reflects a deviation in meter factor that exceeds ±0.0025 between two successive meter provings.
The BLM received comments objecting to the paragraph (e) requirement that the FMP meter be removed from service when found defective or when the meter factor is outside the proposed accuracy range. The comments raised the issue of temperature extremes, in places like Alaska or North Dakota, having a large impact on meter factor change from proving to proving, making it impossible for operators to meet the meter factor deviation requirement. The BLM agrees that changing temperatures do affect the proving meter factors. This situation could easily justify more frequent provings as the temperatures change, the commenter said. The BLM believes this issue is field office specific and is more appropriately addressed through the BLM's variance process, which is outlined in § 3170.6, part of the rulemaking that is replacing Order 3.
One commenter recommended changing the meter-factor deviation limits for meters from ±0.0025 to ±0.0050 because, the commenter said, it is standard industry practice to consider volume measurements as accurate if the meter factor changes by plus or minus 0.0025 or less. It typically is not until the differences in the meter factors are between plus or minus 0.0025 and 0.0050 that a correction is applied. The BLM reviewed API 4.8 to verify the commenter's claims on meter-factor deviation limits that are the industry standard. API 4.8 states common practice for custody transfer applications is to accept new meter factors within the range of 0.10 percent and 0.50 percent of the previous meter factor. The BLM did not accept this recommended change for several reasons: The commenter agrees it is standard industry practice to consider volume measurements as accurate if the meter factor changes by plus or minus 0.0025 or less, ±0.0025 deviation between meter proving runs is currently the maximum deviation allowed under existing Order 4, proposed deviation falls within the acceptable deviation range recommended in API 4.8, and it will not increase current reporting requirements or add costs, but will ensure measurement accuracy. The BLM made no changes to the final rule based on these comments.
Section 3174.11(f) (paragraph (g) in proposed rule) establishes standards for the verification procedure and the test equipment used in the temperature transducer verification. It states the limit threshold value required by the verifying sources as they pertain to the normal operating temperature of the tested fluid. It also requires that the temperature transducer and devices used as part of a LACT or CMS be verified as part of every proving.
The BLM received quite a few comments objecting to the new requirement that operators verify the temperature transducers during the meter-proving process. One commenter said that the proposed rule's meter-proving frequencies would result in excessive and costly transducer verifications if the temperature transducers had to be verified during each meter proving, since the proposed rule would have required operators to prove their meters each time they measured 50,000 bbl of oil, or quarterly, whichever occurred first. The BLM believes that this concern is no longer valid. Section 3174.11(d)(2) in the final rule has been revised and now requires operators to prove their meters every 3 months (quarterly), or each time the registered volume flowing through the meter increases by 75,000 bbl, but no more frequently than monthly. These changes reduced the burdens associated with the proving requirements in the proposed rule. Therefore, the BLM did not change the final rule in response to this comment.
One commenter objected to the requirement that operators use an insulated water bath in the field to perform the temperature transducer verification process, stating that this type of process belongs in a laboratory-type environment and not in a field environment. The BLM disagrees with this commenter since an insulated water bath is a common, acceptable method of verification. The rule also states the transducer may be verified by utilizing a test thermometer well located within 12 inches of the probe of the temperature transducer. The BLM did not change the final rule in response to this comment.
One commenter said that requiring operators to verify the temperature transducer as part of a LACT or CMS proving may require operators to acquire additional equipment and incur costs. The BLM agrees with the commenter that verifying the transducer will require an additional piece of equipment and potentially an initial cost to acquire test equipment, but believes third-party proving contractors already own such equipment. Moreover, the BLM believes routine transducer verification is vital to assure proper performance and to obtain an accurate liquid temperature for use in correcting for the thermal effects on the liquid, ensuring accurate oil measurement, and royalty determination. As a result, the BLM made no change to the final rule in response to this comment.
Another commenter said the requirement for verification of temperature averaging devices in § 3174.11(f) of the proposed rule conflicts with requirements in § 3174.6(b)(2) for temperature resolution and accuracy. The commenter did not say how this requirement conflicts. The BLM disagrees that there is a conflict because the temperature accuracy required for temperature verification is 0.5 °F, which is consistent with temperature accuracies presented in other sections of the final rule and with manufacturer's recommendations. For example, the temperature display minimum graduation must be to the 0.1 °F, as required in § 3174.8(b)(5)(iv), which means there is no practical difficulty in assessing compliance with the verification limits. The BLM made no change to the final rule in response to this comment.
Section 3174.11(f)(3)(i) and (ii) of the final rule (§ 3174.11(g)(3)(i) and (ii) of the proposed rule) requires that if the displayed reading of instantaneous temperature from the temperature averager or the temperature transducer and the reading from the test thermometer differ by more than 0.5 °F, the temperature averager or temperature transducer must be either: (1) Adjusted to match the reading of the test
Section 3174.11(g) of the final rule (paragraph (h) in the proposed rule) establishes the verification requirements for the pressure transducer during the meter-proving operations and states the threshold limit value required by the verifying sources as they pertain to the normal operating pressure of the tested fluid. It requires that the pressure transducer and devices used as part of a LACT or CMS be verified as part of every FMP proving and establishes standards for the verification procedure and the test equipment used in the pressure transducer verification. The BLM received many comments objecting to the new requirement that operators verify the pressure transducer during the meter-proving process. Two commenters said that the proposed rule's meter-proving frequencies would result in excessive and costly transducer verifications if the pressure transducers had to be verified during each meter proving. The BLM believes that this concern is no longer valid. As noted elsewhere, the proving burdens under this final rule have been reduced relative to the proposed rule. The proposed rule would have required operators to prove their meters each time they measured 50,000 bbl of oil, or quarterly, whichever occurred first. Section 3174.11(d)(2) of the final rule now requires operators to prove their meters every 3 months (quarterly), or each time the registered volume flowing through the meter increases by 75,000 bbl, but no more frequently than monthly. As a result, the BLM made no changes to the final rule in response to these comments.
One commenter said that requiring operators to verify the pressure transducer as part of a LACT or CMS meter proving may require operators to acquire additional equipment and incur costs. The BLM agrees that verifying the transducer will require an additional piece of equipment and potentially an initial cost to acquire test equipment, but we believe that third-party proving contractors already own or can acquire such equipment. The BLM believes routine transducer verification is vital to accurate oil measurement and royalty determination. The BLM made no change to the final rule in response to this comment.
One commenter had concerns with the requirement in paragraph (g)(1) (paragraph (h)(1) in the proposed rule) that the pressure sensor must be verified against a NIST-traceable device that is at least twice as accurate as the reference accuracy of the pressure sensor, saying the operator may not have test equipment capable of this accuracy. The commenter suggested that the BLM should allow equipment to be used that does not meet this accuracy requirement, and should provide guidance on how lower-accuracy equipment can be used. The BLM realizes that this high level of accuracy may not be achievable with test equipment the operator currently has and as a result has changed the rule in § 3174.11(g)(1) to require the test-pressure device to have a stated maximum uncertainty of no more than one-half of the accuracy required from the transducer being verified.
Section 3174.11(h) (paragraph (i) in proposed rule) establishes the density verification requirements during the meter proving operations and states the limit threshold values required by the verifying sources as they pertain to the normal operating density of the tested fluid. For Coriolis meters, paragraph (h) requires verification using API 5.6, Subsection 9.1.2.1 if measured density is used to determine API oil gravity (instead of a hydrometer or thermohydrometer, which is generally required under § 3174.6(b)(4)). This provides an independent verification that the Coriolis meter's density determination function is within the accuracy specification for that meter.
The BLM received a few comments objecting to the new requirement for density verification during the FMP meter-proving process for a variety of reasons. One commenter recommended that the final rule refer to API 8.1, API 8.2, and API 8.3 if the compared density samples come from a sampling system. The BLM agrees with this recommendation and changed the final rule by adding references to API 8.1, API 8.2, and API 8.3. These references provide guidance to operators for performing composite sampling to verify oil density as required in the final rule under § 3174.11(h).
One commenter said that using a CMS meter instead of a PD meter would impose additional costs on operators to verify the CMS' density measurement. The BLM agrees in part that using a CMS would require additional density verification over what would be required on a PD meter. However, it is up to the operator to choose which meter type to use. The BLM did not change the final rule as a result of this comment.
One commenter objected to the requirement for density verification during the FMP meter-proving process because, the commenter said, it would be costly and excessive to verify the transducer during each meter proving. The BLM believes that this concern has been addressed. The proposed rule would have required operators to prove their meters each time they measured 50,000 bbl of oil, or quarterly, whichever occurred first. Section 3174.11(d)(2) in the final rule has been revised and now requires operators to prove their meters every 3 months (quarterly), or each time the registered volume flowing through the meter increases by 75,000 bbl, but no more frequently than monthly.
Section 3174.11(i) (paragraph (j) in the proposed rule) requires operators to report to the AO all meter-proving operations and volume adjustments made after any LACT system or CMS malfunction. This section provides additional requirements for data that need to be included on the meter-proving report beyond what is currently required under Order 4. In one change to Order 4 requirements, the final rule requires operators to provide the unique meter or station ID number on each proving report as required under § 3174.11(i)(2)(i). This section includes requirements for verification of the temperature averager or temperature transducer, verification of the pressure transducer, and an addition to the final rule for density verification documentation, as applicable, as well as any “as left” conditions if the back pressure valve is adjusted after proving, which operators also would have to document on the proving report.
Many commenters asked that we clarify aspects of paragraph (i) (proposed paragraph (j)). One commenter recommended that we change § 3174.11(i)(2)(iii) and (iv) to only require temperature and pressure transmitter information, if verified. The BLM disagrees with this commenter on when to report temperature and pressure transducer data, since this information has to be verified as part of each FMP meter proving. The BLM made no change to the rule in response to this comment. Three commenters asked the BLM to specify the format of the meter proving reports since
In addition to the comments on specific provisions above, the BLM received a few general comments on § 3174.11. One commenter said the new regulations would impact marginal-producing wells and may force a premature abandonment of wells and a loss of public hydrocarbon resources. The commenter proposed that marginal and/or existing wells be exempt from both subpart 3174 and subpart 3175. The BLM disagrees that these regulations will force operators to abandon marginal wells. If an operator believes these regulations will force it to abandon a marginal well, that operator can obtain a variance from the regulations under § 3170.6, which is part of the rulemaking that is replacing Order 3. The BLM made no change to the final rule in response to this comment.
One commenter said the maximum and minimum velocity for PD meter provers was not relevant to SVPs and royalty issues associated with their use. The commenter recommended that the BLM adopt language that says, “Provers must be operated within the design parameters of the manufacturer.” The BLM disagrees with the commenter because the prover design requirements, including sizing by prover velocity, are found in the API standards incorporated in this rule. If the operator believes it can meet or exceed these requirements by other means, then the rule allows the operator to use the variance process outlined in § 3170.6. The BLM did not change the final rule in response to this comment.
Two comments, made by the same commenter, voiced concerns that the proposed rule was suited to lighter oil regimes and did not address the differences in measurement that characterize heavy oil, steamflood, and cyclic steam operations. The commenter was concerned that the proposed rule's accuracy requirements would increase operating costs for heavy-oil operators, resulting in possible violations of the measurement requirements. The BLM agrees with the commenter that these rules do not specifically address the measurement of heavy oil. However, these issues are field office specific and can be appropriately addressed through the variance process outlined in § 3170.6.
Section 3174.12 specifies the data requirements for measurement tickets (run tickets) based on which method of oil measurement an operator uses,
The BLM received several comments on this section. Some comments questioned the requirement to complete a run ticket prior to proving a LACT or CMS utilizing flow computers. One commenter stated that this requirement is unnecessary as a flow computer is capable of implementing a new meter factor in the middle of a run without closing the run. The commenter asserted that the flow computer does this by applying the original meter factor to deliveries that occurred from the beginning of the month up to the point of proving and then applying the new meter factor after the point of proving until the end of the month. The BLM agrees that flow computers are capable of utilizing two meter factors as the commenter described, and of retaining an audit trail capability to track this. As a result of this comment, § 3174.12(b)(1) of the final rule has been changed to remove the requirement to close a run ticket prior to proving for LACT systems utilizing flow computers.
One commenter stated that the proposed rule's run-ticket requirements for tank gauging did not specify a frequency for when run tickets will be required. The BLM disagrees with this comment as the proposed rule stated that measurement tickets must be completed “immediately after oil is measured by manual tank gauging.” The BLM believes that this language is clear as to how frequently a measurement ticket needs to be completed but modified the final rule to say, “After oil is measured by tank gauging under §§ 3174.5 and 3174.6. . . .” This change was made because the final rule allows the use of ATG equipment. The BLM made no changes to the rule as a result of this comment but did modify the requirements' language due to the inclusion of ATG equipment. The final rule now states “After oil is measured by tank gauging under §§ 3174.5 and 3174.6 of this subpart, the operator, purchaser, or transporter, as appropriate, must complete a uniquely numbered measurement ticket, in either paper or electronic format.”
We received several comments requesting that we remove the requirement to list on measurement tickets the name of the operator's representative certifying the measurements. It was suggested that operators do not have enough field personnel to witness every oil tank haul and therefore would not be able to “certify” every tank sale. The commenters argued that this requirement could increase confusion and expense, requiring operators to schedule a sale only when a “company man” can be present, and creating undue financial strain on operators having to hire staff to witness tank sales and nothing else. Another commenter said that the BLM needs to define the term “certify.” Upon reviewing this requirement and the comments, the BLM agrees with the commenters, and deleted this requirement in proposed § 3174.12(a)(14) from the rule. It should be noted, however, the operators remain responsible for the accuracy of information found on run tickets, irrespective of any requirement to certify the run ticket.
Several commenters requested that the BLM remove from the rule the requirement that operators notify the AO within 7 days regarding their reasons for disagreeing with a tank gauge measurement. The commenters said this requirement is impractical because, in the field, it may take up to 30 days for a transporter's run ticket to show up in the operator's accounting system. One commenter said that operators should be able to correct relatively minor run-ticket discrepancies without having to report them to the BLM. Upon reviewing these comments, the BLM believes this requirement may create confusion both within the BLM and among operators as to when exactly the AO should be notified. For example, would a simple calculation error warrant AO notification? Would the operator need to explore a potential discrepancy before notifying the AO? The BLM believes this requirement could lead to significant confusion, with minimal benefit to the BLM. Therefore, this requirement in proposed § 3174.12(a)(15) was removed from the rule. Instead, the BLM will address any run ticket discrepancies on a case-by-
One commenter stated that it may not be possible to reset temperature- and pressure-averaging equipment and density-determining equipment back to zero upon closing a run ticket, as is required by paragraph (b)(2) of this section, which could result in some operators having to replace equipment. The BLM is not aware of any non-resettable averaging equipment in use on Federal leases. This requirement is in the rule to ensure that the temperature, pressure, and density, which are required to be included on each run ticket, represent the average temperature, average pressure, and average density of the oil that actually flowed through the meter during the run-ticket period. If there is any non-resettable averaging equipment in use on any Federal or tribal lease, operators will be required to replace it. No change to the rule resulted from this comment.
One commenter recommended that the BLM require hauler signatures on run tickets, but at the same time admitted that anyone can write or type someone else's name on a run ticket and not be the individual who is actually performing the task. The BLM agrees that a signature could identify a specific individual who filled out a run ticket, in case questions arise. But past experience with signature requirements resulted in BLM inspectors spending a lot of time tracking down signatures for no quantifiable benefit. For this reason, the BLM decided to not include a signature requirement. BLM regulations at 43 CFR 3163.2(f)(1) include penalties for any person who knowingly or willfully prepares, maintains or submits false, inaccurate or misleading reports, notices, affidavits, records, data or other written information. The BLM believes this provision addresses any circumstance under which someone falsely enters another person's name on a run ticket. By only requiring the name(s) of the individual(s) performing the tank gauging, we will be acquiring the data we need for our verification requirements. No change was made to the rule as a result of this comment.
Section 3174.13(a) provides that using any method of oil measurement other than tank gauging, LACT system, or CMS at an FMP requires prior BLM approval. Under § 3174.13(b), the BLM will use the PMT as a central advisory body within the BLM to review and recommend approval of industry measurement technology not addressed in these regulations. The PMT is a panel of BLM employees who are oil and gas measurement experts.
The process outlined in § 3174.13(b) for reviewing new equipment allows the BLM to keep up with technology as it advances and approve its use without having to update its regulations. Under the rule, if the PMT recommends new equipment or measurement methods, and the BLM approves, the BLM will post the make, model, range or software version, or measurement method on the BLM Web site (
The PMT will consider new measurement technologies on a case-by-case basis. The BLM believes this process will be used as other technologies or methods are developed and their reliability is established. For example, the BLM considered other meters for inclusion in this rule, such as turbine meters and ultrasonic meters; however, it ultimately decided not to include them in this rule because at this time there is insufficient testing to validate their accuracy and reliability under all operating conditions. However, if in the future the data demonstrates that these meters meet the performance standards of the rule, the PMT will be able to recommend that these meters be approved for use.
If the PMT is able to make the required determination, it will recommend that the BLM approve the use of the applicable equipment or method, as is or subject to certain conditions. Such equipment or methods, and any applicable COAs, will be posted to the BLM Web site and be identified as being appropriate for use at an FMP for oil measurement without additional approvals from the BLM, subject to any limitations or conditions of use imposed by the PMT. Subsequent users of the same technology will not have to go through the PMT process, provided only that they comply with the identified conditions of use.
Section 3174.13(c) provides that the procedures for requesting and granting a variance under § 3170.6 cannot be used as an avenue for approving new technology or equipment. An operator can obtain approval of alternative oil measurement equipment or methods only through review, recommendation, and approval by the PMT under § 3174.13.
One commenter suggested that field-office staff are often in a better position than national office staff to collaborate with operators on pilot projects intended to prove alternative measurement methods. The BLM disagrees. Field-office staff typically do not have the necessary time and measurement expertise to conduct a complete analysis for approval of new technology. This rule includes a process for the BLM—through the PMT—to assess new technology and approve it when appropriate. Additionally, this rule responds in part to concern on the part of the Subcommittee, the GAO, and the OIG that the BLM lacked uniform national standards governing measurement. Leaving decisions about new equipment to field office staff would not address that concern.
Several commenters wanted to know what they will have to do to get equipment approved for use through the PMT and included on the BLM Web site. One commenter objected to any requirement that operators pay for third-party testing of equipment in order to receive approval by the PMT. Upon reviewing the rule and careful consideration of this comment, the BLM re-evaluated the approval process for equipment and transducers that will be listed on the BLM Web site and changed the rule to clarify that an operator requesting approval must submit performance data, actual field test results, laboratory test data, or any other supporting data or evidence that demonstrates that the proposed equipment will meet or exceed this rule's objectives. The final rule is revised by adding in § 3174.2(g) to explain how operators and manufacturers can obtain BLM approval for ATG equipment and specific meters, including approval of a particular make, model, and size, by submitting test data used to develop performance specifications to the PMT for review. Neither the proposed nor the final rule requires operators to pay for third parties to test equipment in order to receive PMT approval. However, should the submitted data fail to demonstrate to the PMT that the proposed equipment will meet or exceed this rule's objectives, the BLM may require additional testing before it grants approval.
One commenter objected to the creation of the PMT, claiming it will stifle innovation, not provide timely reviews, and discourage development of new technology by increasing “red tape.” The BLM disagrees and in fact believes the PMT will increase the utilization of new technology and expedite new approvals. The BLM believes that once the PMT is fully staffed, reviews could take 30 to 60 days, assuming that operators and manufacturers have performed the proper testing and that all pertinent data is submitted to the PMT. Once the PMT reviews the data and makes a recommendation, and the BLM
This commenter also said the BLM, the public, and industry would benefit from allowing companies to determine how they will meet the requirements of the regulation once it is in place, without the agency determining what equipment it will allow to fulfill the requirements of its regulation. The BLM agrees that a company should have the flexibility to determine how to best satisfy the performance requirements of the rule, but disagrees that the BLM should not be evaluating and approving equipment. The BLM has an affirmative obligation to determine that measurements on Federal oil and gas leases are meeting the applicable performance and verifiability standards. The final rule provides flexibility by including provisions that allow for variances for alternatives that meet or exceed the minimum requirements of the regulations and by including the PMT approval process in the rules to evaluate and approve new technology and measurement methods. The BLM believes that the final rule has already addressed the intent of this comment—to allow flexibility in measurement approaches. No change to the rule resulted from this comment.
One commenter suggested that the BLM should list approved technology and not specific makes and models of equipment. The BLM partly agrees with the commenter, in that the PMT will be evaluating new technology and the list will include new technology as it is approved, but it will be approved and listed by make and model of the specific equipment based on the performance data. The BLM believes that there will always be manufacturing control and software differences that affect individual meter performance between competing manufacturers and these differences need to be captured in the uncertainty calculator. No changes to the rule resulted from these comments.
Section 3174.14 does not change Order 4's existing requirements for determining volumes of oil that cannot be measured as a result of spillage or leakage. This section includes, but is not limited to, oil that is classified as slop or waste oil.
The BLM received two comments on this section. The first commenter said the section requires the operator to confirm “slop oil” is not recoverable, and cannot be treated and sold, and provide documentation to this effect. According to the commenter: (1) The proposed rule did not define a process for the operator to follow; (2) This requirement could impact water disposal when bottoms are pulled from a tank; and (3) The language is very open ended. The BLM disagrees that the rule does not define a process. The language found in this section is simply a codification of existing requirements and practices. Additionally, the proposed and final rules state that the first determination the operator must make is the amount of production that cannot be measured due to spillage or leakage. The second determination the operator must make is whether the production is waste oil or slop oil. And the third step that an operator must take, depending on whether it is waste or slop oil, is to either demonstrate to the AO that it is not economically feasible to put the product into marketable condition or get AO approval to sell or dispose of the slop oil.
Regarding the second issue, the BLM notes that this is not a new requirement and it should not surprise operators that the requirements of this section could impact water disposal when bottoms are pulled from tanks should the contents meet the definition of waste oil or slop oil.
As for the third issue, the BLM agrees that the language is somewhat open-ended because it is intended to address all potential situations that might occur in the field. No change has been made to the rule as a result of this comment.
The second commenter said the rule should be changed to better define slop oil. The definition of slop oil is found in the definitions section of § 3170.3, part of the rulemaking that is replacing Order 3. This issue was addressed as part of that rulemaking; however, it should be noted that the BLM does not believe this definition is insufficient. No change has been made to the final rule as a result of this comment.
Section 3174.15 identifies certain acts of noncompliance that are subject to immediate assessments. This section includes violations that are not subject to immediate assessment under existing regulations at 43 CFR 3163.1(b). These assessments are not civil penalties and are separate from the civil penalties authorized in Section 109 of FOGRMA, 30 U.S.C. 1719.
Order 4 does not provide for immediate assessments beyond those specified in 43 CFR 3163.1(b). However, the BLM continues to incur costs associated with correcting the violations identified in § 3174.15. Accordingly, this rule adds five new violations that are subject to immediate assessments.
As is explained in the proposed rule, the authority for the BLM to impose these assessments was explained in the preamble to the 1987 final rule in which 43 CFR 3163.1 was originally promulgated:
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 [sic] 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 (53 FR 5384, 5387, Feb. 20, 1987).
All of the immediate assessments under this rule are set at $1,000 per violation. The BLM chose the $1,000 figure because it generally approximates what it would cost the agency to identify and document each of the violations in question and verify remedial action and compliance.
Some commenters argued that the immediate assessments in § 3174.15 are
A number of commenters said the $1,000 assessment amounts are “excessive.” One commenter said the BLM should adjust the assessment amounts on a case-by-case basis. The BLM does not agree. The $1,000 assessments are in line with the amounts needed for the BLM to recover costs for staff and processing time associated with the inspection process. A fixed schedule of assessments also ensures their impartiality and uniformity. No changes to the rule resulted from these comments.
As explained in the proposed rule, the final rule removes the enforcement, corrective action, and abatement period provisions of Order 3. In their place, the BLM will develop an Internal Inspection and Enforcement Handbook that will provide direction to BLM inspectors on how to classify a violation—as either major or minor—what the corrective action should be, and what the timeframes for correction should be. The AO will use the Inspection and Enforcement Handbook in conjunction with 43 CFR subpart 3163, which provides for assessments and civil penalties when lessees and operators fail to remedy their violations in a timely fashion, and for immediate assessments for certain violations.
As previously discussed in the proposed rule, the final rule allows the BLM to make a case-by-case determination of the severity of a violation, based on applicable definitions in the regulations. In deciding how severe a violation is, BLM inspectors must take into account whether a violation could result in “immediate, substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income.” (Definition of “major violation,” 43 CFR 3160.0-5.) Under the existing definition of “major violation,” which is not being revised as part of this rulemaking, the same violation could be major or minor, depending on the context.
Several commenters objected to this approach for a number of reasons. One concern was that if the BLM publishes an internal guidance document “after the fact,” meaning after the rule is final, industry will be precluded from commenting on or assessing the impact of such a document on their operations. Another concern was that a guidance document will create inconsistency between field offices and operators. However, the commenter provided no explanation as to how an internal guidance document will create inconsistency between field offices and operators, or what confusion industry will have concerning how the BLM enforces the regulations. In general, these comments misunderstand the nature of the Internal Inspection and Enforcement Handbook that the BLM will develop. The new Handbook will not establish new obligations to be imposed on the regulated community. Those obligations are spelled out in applicable regulations, orders, and permits, as well as the terms and conditions of leases and other agreements.
Other commenters questioned why the Inspection and Enforcement Handbook was not part of the public notice and comment process. Internal guidance documents that direct agency personnel how to implement existing agency policies are not required to follow the public notice and comment process. No change to the rule resulted from this comment.
Additional comments suggested that the BLM may not promulgate new binding regulations in internal “guidance” documents. The BLM agrees with this comment and will not be promulgating any binding regulations within the internal guidance document. The overarching enforcement infrastructure of 43 CFR subpart 3163 remains in effect, and the definitions of “major violation” and “minor violation” in § 3160.0-5 remain unchanged. It is these duly promulgated regulations (among other authorities), and not the Inspection and Enforcement Handbook, that will provide the legal basis for the BLM's enforcement actions; BLM's enforcement actions must be consistent with these regulations irrespective of what may be contained in its Inspection and Enforcement Handbook. As noted above, it is this rule and other duly promulgated regulations that establish the standards to which an operator will be held.
Several commenters asserted that removing internal enforcement provisions from the regulations that were promulgated with public notice and comment, and “concealing” them in non-public policy documents that can be altered without notice and in the absence of public input, is inconsistent with the requirements of the Administrative Procedures Act (APA). The BLM does not agree with these comments as they misunderstand the nature of the new Handbook. The operative requirements to which operators are subject are spelled out in duly promulgated regulations, consistent with APA requirements. Internal agency guidance documents on how to implement those requirements are not subject to the APA's notice and comment requirements. No change to the rule resulted from these comments.
A few other commenters said industry has a right to know by what standards they are being judged and penalized. The BLM agrees and believes this rule very clearly describes the standards industry must meet in the oil measurement context. As stated above, in deciding how severe a violation is, BLM inspectors will take into account whether a violation could result in “immediate, substantial, and adverse impacts on production accountability, or royalty income” (definition of “major violation”, 43 CFR 3160.0-5.) One commenter suggested that the BLM provide internal standards to industry at the earliest opportunity. The BLM agrees and will make the internal Inspection and Enforcement Handbook available to the public once it is completed.
Several commenters expressed concern that industry has not seen any proposed violations that may result in enforcement actions prior to the BLM's adoption of the Inspection and Enforcement Handbook. The BLM wishes to further clarify what a violation is. Any deviation from the rules and regulations, without an approved variance from the AO, is a violation, and any violation will result in enforcement action. The Handbook will not alter that fundamental structure in any way.
Additional commenters said the BLM's process for developing violations and corrective actions is not transparent. Again, these comments misunderstand the nature of the forthcoming internal guidance. Operators are obligated to follow the
Because this rule replaces Order 4, the BLM is making two related changes to provisions in 43 CFR part 3160.
1. Section 3162.7-2, Measurement of oil, has been rewritten to be consistent with this rule.
2. Section 3164.1, Onshore Oil and Gas Orders, the table has been revised to remove the reference to Order 4.
The BLM received no comments on these sections and they remain as proposed.
The BLM received numerous comments that said the cumulative economic impact of this and other rules that the BLM has adopted or plans to finalize in the coming months will result in unnecessary and restrictive regulations, increased burdens and costs to both industry and the BLM without any documented financial benefits to taxpayers, and job loss in the oil and gas industry. The commenters noted that in addition to this rulemaking, the BLM is finalizing rules that will update and replace Orders 3 and 5. In addition, on February 8, 2016, the BLM published in the
Other commenters said that the costs to retrofit many of the facilities to bring them into compliance with this rule and the BLM's proposed rules on gas measurement and site security would outweigh any foreseeable economic benefits to operators and government entities. The commenters contend that the proposed rule would impose significant and harmful burdens on operators and the industry as a whole causing operators to shut in, plug, and abandon producing wells, possibly leading to a loss of royalty and tax revenue for the Federal Government, as well as tribal, State, and local governments. Several commenters recommended that the BLM withdraw the proposed rule at this time due to its negative economic impacts, and argued that the BLM could accomplish much of what it seeks to do through this proposed rule by simply updating the content of Orders 4 and 5 to reflect current voluntary consensus standards developed by professional industry groups. The BLM disagrees with the suggestion that these rules are unnecessary and will result in plugged wells, or lost jobs. First, the current economic conditions in the oil and gas sector identified by the commenters are a direct result of the significant drop in oil prices over the last year and a half, which has been accounted for in the threshold analyses performed by the BLM. For example, the recent drop in oil prices led the BLM to change the various thresholds between draft and final rule, as explained in this preamble. Second, with respect to the suggestion that BLM should have simply updated Orders 4 and 5 with references to the relevant industry standards, it must be noted that such an approach was not available to the BLM. Order 4 was promulgated using the APA's Notice and Comment procedures; therefore any updates to it required BLM to undertake Notice and Comment rulemaking. Under those procedures, the BLM is forbidden from incorporating industry standards, unless it is incorporating them into codified regulations, which is the primary reason this rule is being codified.
With respect to the concerns about cost, the BLM believes that this rule will increase opportunities for operators to reduce costs thanks to the rule's built-in flexibility. As noted, this rule includes specific performance standards that will enable operators to identify and evaluate alternative methods and equipment for oil measurement. In addition, the rule includes provisions expressly authorizing ATG systems and the use of Coriolis meters (either as a component of a LACT system or as a standalone metering system). Finally, as explained elsewhere, the rule incorporates the latest industry standards and establishes a PMT to evaluate new equipment and methodologies, so that the BLM can review and approve such equipment and methodologies as they are developed. This flexibility is not available in the current Order 4, which requires operators to obtain case-by-case variances before they may use new equipment or methods.
A number of commenters argued that the rule is impermissibly “retroactive.” These comments argued that the rule is retroactive because it will apply to measurement systems whose existence pre-dates the rule's effective date. While the BLM agrees that truly retroactive regulations raise legal concerns, those concerns are not implicated here because this rule is not retroactive. The comments misunderstand the nature of the “retroactive” regulations that the law disfavors. “A law does not operate `retrospectively' merely because it is applied in a case arising from conduct antedating the statute's enactment or upsets expectations based in prior law” (
It is often the case that a business will undertake a certain course of conduct based on the current law, and will then find its expectations frustrated when the law changes. This has never been thought to constitute retroactive lawmaking, and indeed most economic regulation would be unworkable if all laws disrupting prior expectations were deemed suspect.
The National Technology Transfer and Advancement Act of 1995 (NTTAA), codified as a note to 15 U.S.C. 272, directs agencies to utilize technical standards that are developed by voluntary consensus standards bodies. In this rule, the BLM is adopting certain oil measurement standards developed by the API. Some commenters argued that the NTTAA obligates the BLM to adopt
The BLM conducted extensive public and tribal outreach on this rule both prior to its publication as a proposed rule and during the public comment period on the proposed rule. Prior to the publication of the proposed rule, the BLM held both tribal and public forums to discussion potential changes to the rule. In 2011, the BLM held three tribal meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico (July 13, 2011); and Billings, Montana (August 24, 2011). On April 24 and 25, 2013, the BLM held a series of public meetings to discuss draft proposed revisions to Orders 3, 4, and 5. The meetings were webcast so tribal members, industry, and the public across the country could participate and ask questions either in person or over the Internet. Following those meetings, the BLM opened a 36-day informal comment period, during which 13 comment letters were submitted. The comments received during that comment period were summarized in the preamble for the proposed rule (80 FR 58952).
The proposed rule was made available for public comment from September 30, 2015 through December 14, 2015. During that period, the BLM held tribal and public meetings on December 1 (Durango, Colorado), December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North Dakota). The BLM also held a tribal webinar on November 19, 2015. In total, the BLM received 106 comment letters on the proposed rule, the substance of which are addressed in the Section-by-Section analysis of this preamble.
As explained in the background section of this preamble, three outside independent entities—the Subcommittee, the OIG, and the GAO—have repeatedly found that the BLM's oil measurement rules do not provide sufficient assurance that operators pay the royalties due. Specifically, these groups found that the BLM needed updated guidance on oil measurement technologies, to address existing technological advances, as well as technologies that might be developed in the future. These groups have all found that the BLM's existing guidance is “unconsolidated, outdated, and sometimes insufficient,” and more specifically, that:
• BLM policy and guidance have not been consolidated into a single document or publication, resulting in the BLM's 31 oil and gas field offices using varying policy and guidance;
• Some BLM policy and guidance is outdated and some policy memoranda have expired; and
• Some BLM State offices have issued their own NTLs for oil and gas operations, which lack a national perspective and may introduce inconsistencies among the States with respect to the same types of operations.
The final rule addresses these recommendations by establishing nationwide performance requirements for oil measurement that addresses uncertainty factors, bias, and the verifiability of measurement. The rule specifically addresses technological advances in oil metering technology since Order 4 was promulgated. It affirmatively allows the use of those technologies that have been shown to be sufficiently reliable and accurate. It also updates the BLM's requirements related to proper measurement, documentation, and recordkeeping. Going forward the final rules establishes a process for the BLM to review, and approve for use, new oil measurement technology and systems.
Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs (OIRA) will review all significant rules. OIRA has determined that this rule is not significant.
E.O. 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the nation's regulatory system to promote predictability, to reduce uncertainty, and to use 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. The BLM has developed this rule in a manner consistent with these requirements.
The BLM certifies that this final rule will not have a significant economic effect on a substantial number of small entities as defined under the Regulatory Flexibility Act (5 U.S.C. 601
Of the 6,460 domestic firms involved in onshore oil and gas extraction in 2013, U.S. Census data show that 99 percent (or 6,370) had fewer than 500 employees, which means that nearly all U.S. firms involved in oil and gas extraction in 2013 fell within the SBA's size standard of fewer than 1,250 employees. Of the 2,097 firms participating in oil and gas drilling activities in 2013, U.S. Census data show that 2,044 had fewer than 500 employees, which means that nearly all U.S. firms involved in oil and gas support activities in 2013 fell within the SBA's size standard of fewer than 1,000 employees. There were another 8,877 firms involved in drilling and other support functions in 2012. Of the firms providing support functions, 96 percent (8,561) had annual net receipts of no more than $35 million, with a greater number below the SBA's $38.5 million threshold.
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 number of small entities potentially could be affected by this rule. Using the best available data, the BLM estimates there are approximately 3,700 lessees/operators conducting oil operations on Federal and Indian lands that could be affected by this rule.
On an ongoing basis, we estimate the changes to the LACT meter proving frequency requirements based on volume throughput will increase the regulated community's total annual costs by $67,650. This amount corresponds to the cost of an estimated 123 additional annual provings per year at 28 LACT systems on 19 leases, CAs, or PAs flowing between 31,250 bbl/month/meter and 100,000 bbl/month/meter. This includes 75 additional provings ($41,250 in cost) for 22 LACT systems on 15 leases, CAs, or PAs flowing at least 31,250 bbl/month/meter and below 75,000 bbl/month/meter, and 48 additional provings ($26,400 in cost) for six LACT systems on four leases, CA, or PA's flowing at least 75,000 bbl/month/meter and below 100,000 bbl/month/meter. Currently, LACT systems for both of these groups of systems would be proven monthly for LACTs measuring 100,000 bbl/month or greater, or once every 3 months (four times per year). Under the new rule, meters at the first group of LACT systems (31,250 bbl/month/meter up to 75,000 bbl/month/meter) would be proven every 75,000 bbl, or from 5 to 11 times per year, while meters in the second group of LACT systems (75,000 bbl/month/meter up to 100,000 bbl/month/meter) would be proven monthly, or 12 times each year. There would be no change in proving frequency for properties producing at or above 100,000 bbl/month/meter (one proving per month, or 12 per year) or below 31,250 bbl/month/meter (one proving per quarter, or four per year).
In addition, there will be a one-time cost to retrofit an estimated 20 percent of existing LACT systems of about $1.9 million, or a one-time average cost of about $6,500 for each of an estimated approximately 296 existing LACT systems. This amounts to an average one-time cost of $519 for each of the approximately 3,700 lessees/operators conducting oil production operations on Federal or Indian leases. The requirement for operators to conduct tank strappings to submit revised calibration tables to the BLM will have an annual cost to operators of $4.0 million per year (approximately $1,080 per entity), plus an additional $0.2 million in industry paperwork costs for submitting these tables, and $0.2 million in additional costs to the BLM to process these paperwork submissions. When adding the additional cost of hourly recordkeeping and non-hourly provisions in the final rule, the BLM estimates that the rule will have a total impact of $3.3 million in one-time costs and $4.6 million in annual costs. When the one-time costs are annualized for the first 3 years following the enactment of the final rule, and combined with annual costs for these years, the BLM estimates a total annualized cost of $5.7 million per year, or $1,540 per entity per year, for years 1-3 after the final rule's effective date. After year three, costs will equal the estimated annual cost of $4.6 million, or $1,240 per entity per year. All of the provisions apply to entities regardless of size. However, entities with the greatest activity likely will experience the greatest increase in compliance costs.
Based on the available information, we conclude that the final rule will not have a significant impact on a substantial number of small entities. The final rule will cost each entity an average of less than $2,000 per year, which will impact expected annual operator net income by less than 0.01 percent, as described in the Regulatory Impact Analysis for this rule. Therefore, a final Regulatory Flexibility Analysis is not required, and a Small Entity Compliance Guide is not required.
This final rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule will not have an annual effect on the economy of $100 million or more. As explained under the preamble discussion concerning E.O. 12866, Regulatory Planning and Review, changes to oil measurement under this final rule relative to the existing requirements of Order 4 will increase the cost associated with the development and production of crude oil resources under Federal and Indian oil and gas leases by about $4.8 million annually. Of this amount, about $3.9 million/year will be borne by industry, and $0.9 million/year by the BLM. There will also be a one-time cost of about $1.9 million to retrofit an estimated 20 percent of existing LACT systems, borne entirely by industry.
Based on the cost figures above, the estimated annual increased cost to the estimated 3,700 lessees/operators conducting oil production operations on Federal or Indian leases for implementing these changes is about $1,055 per year, and a one-time average cost of about $520 per entity.
This final rule:
• Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, tribal, or local government agencies, or geographic regions; and
• Will 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.
In accordance with the Unfunded Mandates Reform Act (2 U.S.C. 1501
• This final rule will not “significantly or uniquely” affect small
• This final rule will not produce a Federal mandate of $100 million or greater in any single year.
The final rule is not a “significant regulatory action” as it will not require anything of any non-Federal governmental entity.
Under E.O. 12630, the final rule would not have significant takings implications. A takings implication assessment is not required. This final rule will establish the minimum standards for accurate measurement and proper reporting of oil produced from Federal and Indian leases, unit PAs, and CAs, by providing a system for production accountability by operators and lessees. All such actions are subject to lease terms that expressly require that subsequent lease activities be conducted in compliance with applicable Federal laws and regulations. The final rule conforms to the terms of those Federal leases and applicable statutes, and as such the final rule is not a governmental action capable of interfering with constitutionally protected property rights. Therefore, the final rule will not cause a taking of private property and does not require further discussion of takings implications under this E.O.
In accordance with E.O. 13132, the BLM finds that the final rule will not have significant Federalism effects. A Federalism assessment is not required. This final rule will not change the role of or shift responsibilities among Federal, State, and local governmental entities. It does not relate to the structure and role of the States and will not have direct, substantive, or significant 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 Departmental Manual 2, the BLM evaluated possible effects of the final rule on federally recognized Indian tribes. The BLM approves proposed operations on all Indian (except Osage Tribe) onshore oil and gas leases. Therefore, the final rule has the potential to affect Indian tribes. In conformance with the Secretary's policy on tribal consultation, the BLM held tribal consultation meetings to which more than 175 tribal entities were invited, both before the rule was proposed and during the public comment period on the proposed rule. The consultations were held in:
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July 13, 2011; and
• Billings, Montana on August 24, 2011.
• Tribal workshop and webcast in Washington, DC on April 24, 2013.
• The BLM hosted a webinar to discuss the requirements of the proposed rule and solicit feedback from affected tribes on November 19, 2015; and
• In-person meetings were held in:
○ Durango Colorado, on December 1, 2015;
○ Oklahoma City, Oklahoma, on December 3, 2015; and
○ Dickinson, North Dakota, on December 8, 2015.
The BLM also met with interested tribes on a one-on-one basis, if requested to address questions on the proposed rule prior to the publication of the final rule. In each instance, the purpose of these meetings was to solicit feedback and comments from the tribes. The primary concerns expressed by tribes related to the subordination of tribal laws, rules, and regulations by the proposed rule; tribal representation on the Department's Gas and Oil Measurement Team; and the BLM's Inspection and Enforcement program's ability to enforce the terms of this rule. In general, the tribes, as royalty recipients, expressed support for the goals of the rulemaking, namely accurate measurement. With respect to tribal representation on the Department's Gas and Oil Measurement Team, it should be noted that the team is internal to BLM. That said, the BLM will continue to consult with tribes on measurement issues that impact them and their resources. None of the tribal comments received were directed specifically at this rule's oil measurement requirements, and therefore no changes were made as a result of these comments. While the BLM will continue to address these concerns, none of the concerns affect the substance of the proposed rule.
Under E.O. 12988, the Office of the Solicitor has determined that the final rule will not unduly burden the judicial system and meets the requirements of Sections 3(a) and 3(b)(2) of the E.O. The Office of the Solicitor has reviewed the final rule to eliminate drafting errors and ambiguity. It has been written to minimize litigation, provide clear legal standards for affected conduct rather than general standards, and promote simplification and burden reduction.
Under E.O. 13352, the BLM has determined that this final rule will not impede cooperative conservation and will 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 involved Federal, tribal, State, and local governments, private for-profit and nonprofit institutions, other nongovernmental entities and individuals in the decision-making via the public comment process. That process provides 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. Collections of information include requests and requirements that an individual, partnership, or corporation obtain information, and report it to a Federal agency. See 44 U.S.C. 3502(3); 5 CFR 1320.3(c) and (k).
This rule contains information collection activities that require approval by the OMB under the Paperwork Reduction Act. The BLM included an information collection request in the proposed rule. OMB has approved the information collection for the final rule under control number 1004-0209.
The information collection activities in this rule are described below along with estimates of the annual burdens. Included in the burden estimates are the time for reviewing instruction, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing each component of the proposed information collection.
The information collection activities in the final rule are discussed below.
The final rule, at 43 CFR 3174.4(a), requires each FMP to achieve certain overall uncertainty levels. An operator may seek an exception to the prescribed uncertainty levels by submitting a request to a BLM State Director. The operator must show that meeting the required uncertainly level would involve extraordinary cost or unacceptable adverse environmental effects. The State Director may grant such a request only with written concurrence from the PMT (prepared in coordination with the Deputy Director). This provision enables the BLM to determine whether or not it is reasonable to grant an exception to uncertainty requirements.
Section 3174.5(c)(3) requires submission of tank calibration tables to the BLM within 30 days after calibration. This provision ensures that BLM personnel will have the latest charts when conducting inspections or audits.
The procedures for oil measurement by tank gauging must comply with the requirements outlined in 43 CFR 3174.6. Beginning on January 17, 2019, only the specific makes and models of ATG that are identified and described at the BLM Web site (
If an operator chooses to use a particular make or model of ATG equipment, the operator (or the manufacturer of the ATG equipment) must seek and obtain BLM approval of the particular make and model of that equipment by submitting a request to the PMT, consisting of a panel of BLM employees who are oil and gas measurement experts. The submission must describe the test data used to develop performance specifications. After reviewing the test data, the PMT will recommend whether or not to approve the ATG equipment. This information collection activity enables the BLM to consider approving new technologies not yet addressed in its regulations.
The operator must inspect its ATG equipment and verify its accuracy at least once a month, or prior to sales, whichever is later. In addition, the BLM may request inspection and verification at any time.
If the operator finds ATG equipment to be out of tolerance, the operator must calibrate the equipment prior to sales, and must maintain a log of field verifications. That operator must make the log available to the BLM upon request. The log must include the following information:
• The date of verification;
• The as-found manual gauge readings;
• The as-found ATG readings; and
• Whether the ATG equipment was field-calibrated.
If the ATG equipment was field-calibrated, the as-left manual gauge readings and as-left ATG readings must be recorded. This information collection activity enables the BLM to ensure the accuracy of tank gauging by ATG systems.
Section 3174.7(e)(1) requires the operator to notify the BLM within 72 hours of any LACT system failures or equipment malfunctions which may have resulted in measurement error. As defined at proposed § 3174.1, a LACT system consists of components designed to provide for the unattended custody transfer of oil produced from a lease, unit PA, or Communitized Area (CA) to the transporting carrier while providing a proper and accurate means for determining the net standard volume and quality, and fail-safe and tamper-proof operations. This information collection requirement enables the BLM to verify that operators account for all oil volumes.
Section 3174.8(a)(1) requires each custody transfer meter to be a PD meter or a Coriolis meter. A PD meter measures liquid by constantly and mechanically isolating flowing liquid into segments of known volume. A Coriolis meter measures liquid via the interaction between a flowing fluid and oscillation of tubes. Beginning on January 17, 2019, only the specific make, models, and sizes of PD meters and Coriolis meters and associated software that are identified and described at
If an operator chooses to use a particular make or model of PD meter or Coriolis meter, the operator (or the manufacturer of the meter) must seek and obtain BLM approval of that particular make and model by submitting a request to the PMT. The submission must describe the test data used to develop performance specifications. After reviewing the test data, the PMT will recommend whether or not to approve the meter. This information collection activity enables the BLM to consider approving new technologies not yet addressed in its regulations.
Section 3174.10(b)(2) requires the operator to submit Coriolis meter specifications to the BLM upon request. The meter specification of a Coriolis meter must clearly identify the make and model of the Coriolis meter to which they apply and must include the following:
• The reference accuracy for both mass flow rate and density, stated in either percent of reading, percent of full scale, or units of measure;
• The effect of changes in temperature and pressure on both mass flow and fluid density readings;
• The effect of flow rate on density readings;
• The stability of the zero reading for volumetric flow rate;
• Design limits for flow rate and pressure; and
• Pressure drop through the meter as a function of flow rate and fluid viscosity.
Section 3174.10(d) requires the operator to provide the BLM with a copy of the zero value verification procedure upon request.
Section 3174.10(e)(4) requires the operator to maintain a log of all meter factors, zero verifications, and zero adjustments. For zero adjustments, the log must include the zero value before adjustment and the zero value after adjustment. The log must be made available to the BLM upon request.
Section 3174.10(f) requires the operator to record and retain, and submit to the BLM upon request, the following information:
• Quantity transaction record (QTR) in accordance with the requirements for a measurement ticket (at 43 CFR 3174.12(b));
• Configuration log that contains and identifies all constant flow parameters used in generating the QTR;
• Event log of sufficient capacity to record all events such that the operator can retain the information under the recordkeeping requirements of 43 CFR 3170.7; and
• Alarm log that records the type and duration of any of the following alarm conditions:
○ Density deviations from acceptable parameters; and
○ Instances in which the flow rate exceeded the manufacturer's maximum recommended flow rate or were below the manufacturer's minimum recommended flow rate.
Section 3174.11 specifies the minimum requirements for conducting volumetric meter proving for all FMP meters. Meter proving verifies the accuracy of a meter.
Under 43 CFR 3174.11(i)(1), an operator must report to the BLM all meter-proving and volume adjustments after any LACT system or CMS malfunction. The operator must use the appropriate form in API 12.2.3 or API 5.6 (both incorporated by reference at 43 CFR 3174.3), or use a similar format showing the same information as the API form, provided that the calculation of meter factors maintains the proper calculation sequence and rounding.
In addition, a meter-proving report must show the:
• Unique meter ID number;
• Lease number, CA number, or unit PA number;
• The temperature from the test thermometer and the temperature from the temperature averager or temperature transducer;
• For pressure transducers, the pressure applied by the pressure test device and the pressure reading from the pressure transducer at the three points required under paragraph (g)(3) of this section;
• For density verification (if applicable), the instantaneous flowing density (as determined by Coriolis meter), and the independent density measurement, as compared under 43 CFR 3174.(h); and
• The “as left” fluid flow rate and fluid pressure, if the back pressure valve is adjusted after proving as described in 43 CFR 3174.11(c)(9).
Under § 3174.11(i)(3), the operator must submit the meter-proving report to the BLM no later than 14 days after the meter proving. The proving report may be either in a hard copy or electronic format.
These information collection activities will assist in ensuring the accuracy of meters.
A run ticket is the evidence of receipt or delivery of oil issued by a pipeline, other carrier, or purchaser. The amount of oil transferred from storage is recorded on a run ticket. The amount of payment for oil is based upon information contained in the run ticket.
Tank gauging (43 CFR 3174.12(a))—After oil is measured by tank gauging, the operator, purchaser, or transporter, as appropriate, must complete a uniquely numbered measurement ticket, in either paper or electronic format, with the following information:
• Lease, unit, or CA number;
• Unique tank number and nominal tank capacity;
• Opening and closing dates and times;
• Opening and closing gauges and observed temperatures in °F;
• Observed volume for opening and closing gauge;
• Total gross standard volume removed from the tank;
• Observed API oil gravity and temperature in °F;
• API oil gravity at 60 °F;
• S&W percent;
• Unique number of each seal removed and installed;
• Name of the individual performing the manual tank gauging; and
• Name of the operator.
LACT or CMS (43 CFR 3174.12(b))—The operator, purchaser, or transporter, as appropriate, must complete a uniquely numbered measurement ticket, in either paper or electronic format, at the beginning of every month, and (unless a flow computer is being used in accordance with 43 CFR 3174.10) before conducting proving operations on a LACT system. The following information is required:
• Lease, unit, or CA number;
• Unique meter ID number;
• Opening and closing dates;
• Opening and closing totalizer readings of the indicated volume;
• Meter factor, indicating if it is a composite meter factor;
• Total gross standard volume removed through the LACT system or CMS;
• API oil gravity;
• The average temperature in °F;
• The average flowing pressure in psig;
• S&W percent;
• Unique number of each seal removed and installed;
• Name of the purchaser's representative; and
• Name of the operator.
Section 3174.13 requires prior BLM approval for any method of oil measurement other than manual tank gauging, LACT system, or CMS at an FMP. Any operator requesting approval to use alternate oil measurement equipment must submit to the BLM:
• Performance data;
• Actual field test results;
• Laboratory test data; or
• Any other supporting data or evidence that demonstrates that the proposed alternate oil measurement equipment would meet or exceed the objectives of the applicable minimum requirements at 43 CFR subpart 3174 and would not affect royalty income or production accountability.
The PMT will review and make recommendations in response to requests to use alternate oil-measurement equipment. This information collection activity enables the BLM to consider approving new technologies not yet addressed in its regulations.
When production cannot be measured due to spillage or leakage, the amount of production must be determined by using any method the BLM approves or prescribes. This category of production includes, but is not limited to, oil that is classified as slop oil or waste oil.
No oil may be classified or disposed of as waste oil unless the operator can demonstrate to the satisfaction of the BLM that it is not economically feasible to put the oil into marketable condition.
The operator may not sell or otherwise dispose of slop oil without prior written approval from the BLM. Following the sale or disposal of slop oil, the operator must notify the BLM in writing of the volume sold or disposed of and the method used to compute the volume.
The following table itemizes the estimated hour burdens for this rule:
The BLM prepared an environmental assessment (EA), a Finding of No Significant Impact (FONSI), and a Decision Record (DR) that conclude that the final rule would not constitute a major Federal action significantly affecting the quality of the human environment under NEPA, 42 U.S.C. 4332(2)(C). Therefore, a detailed environmental impact statement (EIS) under NEPA is not required. A copy of the EA, FONSI, and DR are available for review and on file in the BLM Administrative Record at the location specified in the
As explained in the EA, FONSI, and DR, the final rule would not have a significant effect on the human environment because, for the most part, its requirements involve changes that are of an administrative, technical, or procedural nature that apply to the BLM's and the lessee's or operator's administrative processes. For example, the rule allows operators to use a CMS or an ATG/hybrid tank measurement system without receiving a variance from the BLM as they must do now. The final rule also adopts a process and criteria that will allow for the PMT to review any new measurement system or method approval requests submitted to the BLM.
Overall these changes will enhance the agency's ability to account for the oil and gas produced from Federal and Indian lands, but should have minimal to no impact on the environment. Some of these standards, such as the requirement that operators replace their automatic temperature/gravity compensators with temperature averaging devices, may result in increased human presence and traffic on existing disturbed surfaces, but these activities are expected to have a negligible impact on the quality of the human environment, as discussed in the final EA.
A draft of the EA was shared with the public during the public comment period on the proposed rule. As part of that process, the BLM received comments on the EA. Commenters questioned the BLM's level of NEPA documentation, whether or not the BLM had met the “hard look” test of describing the environmental consequences of the proposed action, and the BLM's ability to reach a FONSI based on the level of analysis. One commenter requested a complete NEPA revision with formal scoping of the EA and a meaningful socioeconomic analysis. Many commenters questioned the use of three separate EAs to disclose impacts of Order 3, Order 4, and Order 5, stating that the Council on Environmental Quality (CEQ) regulations require connected actions to be evaluated in a single document. These commenters suggested a single EIS to address all three rules.
CEQ's NEPA regulations at 40 CFR 1508.18 identify new or revised agency rules and regulations as an example of a Federal action. Drafting new agency regulations that “are of an administrative . . . technical, or
Other commenters stated the BLM did not adequately address potential surface impacts to private land, minimized environmental surface impacts, did not address a reasonable range of alternatives, and did not adequately describe the Affected Environment. The BLM anticipates that in the majority of cases, operators will use existing surface disturbances such as existing well pad locations in connection with activities undertaken in compliance with the final rule, which will minimize new surface construction and surface impacts. Any new facilities will likely be constructed on a lease, relocated to an existing facility, or retrofitted to an existing facility. Similarly, the codification of BLM regulations does not hinder or prevent development of private minerals. The likelihood of impacts to private surface is low. In the rare instance that new pipelines or other facilities must be developed on private surface to comply with this rule, BLM authorization for activities on split estate would include site-specific NEPA documentation, with appropriate project-level mitigation. The BLM's obligation under NEPA is to analyze alternatives that would meet the Bureau's purpose and need and allow for a reasoned choice to be made. As described in the EA, a number of alternatives were considered, but eliminated from detailed study because they did not meet the purpose and need. Discussion of the affected environment should only contain data and analysis commensurate in detail with the importance of the impacts, which the BLM anticipates to be minimal.
The EA, FONSI, and DR were updated to address these comments, but the updates did not change the BLM's overall analysis of the potential environmental impacts of the rule.
Although this rule amends the BLM's oil production regulations, it will not have a substantial direct effect on the nation's energy supply, distribution, or use, including a shortfall in supply or price increases. Changes in this rule strengthen the BLM's production accountability requirements for operators holding Federal and Indian oil leases. As discussed previously, among other things, this rule establishes objective measurement performance standards, updates recordkeeping requirements, and establishes uniform national requirements for operators who wish to use CMSs or ATG systems. As explained in detail in the BLM's regulatory impact analysis, all of these changes will increase the regulated community's annual costs by about $3.9 million, or about $1,055 per entity per year.
The BLM expects that the rule will not result in a net change in the quantity of oil that is produced from Federal and Indian leases.
In developing this rule, the BLM 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, 515, 114 Stat. 2763A-153).
The principal authors of this final rule are Mike McLaren, Petroleum Engineer, BLM Pinedale Field Office; Tom Zelenka, Petroleum Engineer, BLM New Mexico State Office; Chris DeVault, I&E Coordinator, BLM Montana State Office; Jeff Prude, Petroleum Engineer, BLM Bakersfield Field Office; and Frank Sanders, Petroleum Engineer, BLM Worland Field Office. The team was assisted by Faith Bremner, Jean Sonneman and Ian Senio, Office of Regulatory Affairs, BLM Washington Office; Michael Ford, Economist, BLM Washington Office; Barbara Sterling, Natural Resource Specialist, BLM Colorado State Office; Bryce Barlan, Senior Policy Analyst, BLM, Washington Office; Michael Wade, BLM Washington Office; Rich Estabrook, BLM Washington Office; Dylan Fuge, Counselor to the Director, BLM Washington Office; Christopher Rhymes, Attorney Advisor, Office of the Solicitor, Department of the Interior; and Geoffrey Heath (now retired).
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 measurement, Public lands—mineral resources.
For the reasons set out in the preamble, the Bureau of Land Management is amending 43 CFR parts 3160 and 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 oil removed or sold from a lease, communitized area, or unit participating area must be measured under subpart 3174 of this title. All measurement must be on the lease, communitized area, or unit from which the oil originated and must not be commingled with oil originating from other sources, unless approved by the authorized officer under the provisions of subpart 3173 of this title.
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 acronyms carry the meaning prescribed:
(a) Oil may be stored only in tanks that meet the requirements of § 3174.5(b) of this subpart.
(b) Oil must be measured on the lease, unit PA, or CA, unless approval for off-lease measurement is obtained under §§ 3173.22 and 3173.23 of this part.
(c) Oil produced from a lease, unit PA, or CA may not be commingled with
(d) An operator must obtain a BLM-approved FMP number under §§ 3173.12 and 3173.13 of this part for each oil measurement facility where the measurement affects the calculation of the volume or quality of production on which royalty is owed (
(e) Except as provided in paragraph (h) of this section, all equipment used to measure the volume of oil for royalty purposes installed after January 17, 2017 must comply with the requirements of this subpart.
(f) Except as provided in paragraph (h) of this section, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on January 17, 2017, must comply with the requirements of this subpart on or before the date the operator is required to apply for an FMP number under 3173.12(e) of this part. Prior to that date, measuring procedures and equipment used to measure oil for royalty purposes, that is in use on January 17, 2017 must continue to comply with the requirements of Onshore Oil and Gas Order No. 4, Measurement of oil, § 3164.1(b) as contained in 43 CFR part 3160, (revised October 1, 2016), and any COAs and written orders applicable to that equipment.
(g) The requirement to follow the approved equipment lists identified in §§ 3174.6(b)(5)(ii)(A), 3174.6(b)(5)(iii), 3174.8(a)(1), and 3174.9(a) does not apply until January 17, 2019. The operator or manufacturer must obtain approval of a particular make, model, and size by submitting the test data used to develop performance specifications to the PMT to review.
(h) Meters used for allocation under a commingling and allocation approval under § 3173.14 are not required to meet the requirements of this subpart.
(a) Certain material specified in 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. Operators must comply with all incorporated standards and material, as they are listed in this section. To enforce any edition other than that specified in this section, the BLM must publish a rule 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 2—Tank Calibration, Section 2A, Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method; First Edition, February 1995; Reaffirmed February 2012 (“API 2.2A”), IBR approved for § 3174.5(c).
(2) API MPMS Chapter 2—Tank Calibration, Section 2.2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method; First Edition, March 1989, Reaffirmed January 2013 (“API 2.2B”), IBR approved for § 3174.5(c).
(3) API MPMS Chapter 2—Tank Calibration, Section 2C, Calibration of Upright Cylindrical Tanks Using the Optical-triangulation Method; First Edition, January 2002; Reaffirmed May 2008 (“API 2.2C”), IBR approved for § 3174.5(c).
(4) API MPMS Chapter 3, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products; Third Edition, August 2013 (“API 3.1A”), IBR approved for §§ 3174.5(b), 3174.6(b).
(5) API MPMS Chapter 3—Tank Gauging, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging; Second Edition, June 2001; Reaffirmed August 2011 (“API 3.1B”), IBR approved for § 3174.6(b).
(6) API MPMS Chapter 3—Tank Gauging, Section 6, Measurement of Liquid Hydrocarbons by Hybrid Tank Measurement Systems; First Edition, February 2001; Errata September 2005; Reaffirmed October 2011 (“API 3.6”), IBR approved for § 3174.6(b).
(7) API MPMS Chapter 4—Proving Systems, Section 1, Introduction; Third Edition, February 2005; Reaffirmed June 2014 (“API 4.1”), IBR approved for § 3174.11(c).
(8) API MPMS Chapter 4—Proving Systems, Section 2, Displacement Provers; Third Edition, September 2003; Reaffirmed March 2011, Addendum February 2015 (“API 4.2”), IBR approved for §§ 3174.11(b) and (c).
(9) API MPMS Chapter 4, Section 5, Master-Meter Provers; Fourth Edition, June 2016, (“API 4.5”), IBR approved for § 3174.11(b).
(10) API MPMS Chapter 4—Proving Systems, Section 6, Pulse Interpolation; Second Edition, May 1999; Errata April 2007; Reaffirmed October 2013 (“API 4.6”), IBR approved for § 3174.11(c).
(11) API MPMS Chapter 4, Section 8, Operation of Proving Systems; Second Edition, September 2013 (“API 4.8”), IBR approved for § 3174.11(b).
(12) API MPMS Chapter 4—Proving Systems, Section 9, Methods of Calibration for Displacement and Volumetric Tank Provers, Part 2, Determination of the Volume of Displacement and Tank Provers by the Waterdraw Method of Calibration; First Edition, December 2005; Reaffirmed July 2015 (“API 4.9.2”), IBR approved for § 3174.11(b).
(13) API MPMS Chapter 5—Metering, Section 6, Measurement of Liquid Hydrocarbons by Coriolis Meters; First Edition, October 2002; Reaffirmed November 2013 (“API 5.6”), IBR approved for §§ 3174.9(e), 3174.11(h) and (i).
(14) API MPMS Chapter 6—Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems; Second Edition, May 1991; Reaffirmed May 2012 (“API 6.1”), IBR approved for § 3174.8(a) and (b).
(15) API MPMS Chapter 7, Temperature Determination; First Edition, June 2001, Reaffirmed February 2012 (“API 7”), IBR approved for §§ 3174.6(b), 3174.8(b).
(16) API MPMS Chapter 7.3, Temperature Determination—Fixed Automatic Tank Temperature Systems; Second Edition, October 2011 (“API 7.3”), IBR approved for § 3174.6(b).
(17) API MPMS Chapter 8, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products; Fourth Edition, October 2013 (“API 8.1”), IBR approved for §§ 3174.6(b), 3174.11(h).
(18) API MPMS Chapter 8, Section 2, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products; Third Edition, October 2015 (“API 8.2”), IBR approved for §§ 3174.6(b), 3174.8(b), 3174.11(h).
(19) API MPMS Chapter 8—Sampling, Section 3, Standard Practice for Mixing
(20) API MPMS Chapter 9, Section 1, Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method; Third Edition, December 2012 (“API 9.1”), IBR approved for §§ 3174.6(b), 3174.8(b).
(21) API MPMS Chapter 9, Section 2, Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer; Third Edition, December 2012 (“API 9.2”), IBR approved for §§ 3174.6(b), 3174.8(b).
(22) API MPMS Chapter 9, Section 3, Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method; Third Edition, December 2012 (“API 9.3”), IBR approved for §§ 3174.6(b), 3174.8(b).
(23) API MPMS Chapter 10, Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure); Fourth Edition, October 2013; Errata March 2015 (“API 10.4”), IBR approved for §§ 3174.6(b), 3174.8(b).
(24) API MPMS Chapter 11—Physical Properties Data, Section 1, Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products and Lubricating Oils; May 2004, Addendum 1 September 2007; Reaffirmed August 2012 (“API 11.1”), IBR approved for §§ 3174.9(f), 3174.12(a).
(25) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1, Introduction; Second Edition, May 1995; Reaffirmed March 2014 (“API 12.2.1”), IBR approved for §§ 3174.8(b), 3174.9(g).
(26) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2, Measurement Tickets; Third Edition, June 2003; Reaffirmed September 2010 (“API 12.2.2”), IBR approved for §§ 3174.8(b), 3174.9(g).
(27) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3, Proving Report; First Edition, October 1998; Reaffirmed March 2009 (“API 12.2.3”), IBR approved for § 3174.11(c) and (i).
(28) API MPMS Chapter 12—Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4, Calculation of Base Prover Volumes by the Waterdraw Method; First Edition, December 1997; Reaffirmed March 2009; Errata July 2009 (“API 12.2.4”), IBR approved for § 3174.11(b).
(29) API MPMS Chapter 13—Statistical Aspects of Measuring and Sampling, Section 1, Statistical Concepts and Procedures in Measurements; First Edition, June 1985 Reaffirmed February 2011; Errata July 2013 (“API 13.1”), IBR approved for § 3174.4(a).
(30) API MPMS Chapter 13, Section 3, Measurement Uncertainty; First Edition, May, 2016 (“API 13.3”), IBR approved for § 3174.4(a).
(31) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata July 2013 (“API 14.3.1”), IBR approved for § 3174.4(a).
(32) API MPMS Chapter 18—Custody Transfer, Section 1, Measurement Procedures for Crude Oil Gathered From Small Tanks by Truck; Second Edition, April 1997; Reaffirmed February 2012 (“API 18.1”), IBR approved for § 3174.6(b).
(33) API MPMS Chapter 18, Section 2, Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, First Edition, July 2016 (“API 18.2”), IBR approved for § 3174.6(b).
(34) API MPMS Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 2, Electronic Liquid Volume Measurement Using Positive Displacement and Turbine Meters; First Edition, June 1998; Reaffirmed August 2011 (“API 21.2”), IBR approved for §§ 3174.8(b), 3174.9(f), 3174.10(f).
(35) API Recommended Practice (RP) 12R1, Setting, Maintenance, Inspection, Operation and Repair of Tanks in Production Service; Fifth Edition, August 1997; Reaffirmed April 2008 (“API RP 12R1”), IBR approved for § 3174.5(b).
(36) API RP 2556, Correction Gauge Tables For Incrustation; Second Edition, August 1993; Reaffirmed November 2013 (“API RP 2556”), IBR approved for § 3174.5(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;
(a)
(2) Only a BLM State Director may grant an exception to the uncertainty levels prescribed in paragraph (a)(1) of this section, and only upon:
(i) A showing that meeting the required uncertainly level would involve extraordinary cost or unacceptable adverse environmental effects; and
(ii) Written concurrence of the PMT, prepared in coordination with the Deputy Director.
(b)
(c)
(d)
(a)
(b)
(2) Each oil storage tank must be connected, maintained, and operated in compliance with §§ 3173.2, 3173.6, and 3173.7 of this part.
(3) All oil storage tanks, hatches, connections, and other access points must be vapor tight. Unless connected to a vapor recovery or flare system, all tanks must have a pressure-vacuum relief valve installed at the highest point in the vent line or connection with another tank. All hatches, connections, and other access points must be installed and maintained in accordance with manufacturers' specifications.
(4) All oil storage tanks must be clearly identified and have an operator-generated number unique to the lease, unit PA, or CA, stenciled on the tank and maintained in a legible condition.
(5) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be set and maintained level.
(6) Each oil storage tank associated with an approved FMP that has a tank-gauging system must be equipped with a distinct gauging reference point, consistent with API 3.1A (incorporated by reference, see § 3174.3). The height of the reference point must be stamped on a fixed bench-mark plate or stenciled on the tank near the gauging hatch, and be maintained in a legible condition.
(c)
(1) Determine sales tank capacities by tank calibration using actual tank measurements;
(i) The unit volume must be in barrels (bbl); and
(ii) The incremental height measurement must match gauging increments specified in § 3174.6(b)(5)(i)(C);
(2) Recalibrate a sales tank if it is relocated or repaired, or the capacity is changed as a result of denting, damage, installation, removal of interior components, or other alterations; and
(3) Submit sales tank calibration charts (tank tables) to the AO within 45 days after calibration. Tank tables may be in paper or electronic format.
(a) The procedures for oil measurement by tank gauging must comply with the requirements outlined in this section.
(b) The operator must follow the procedures identified in API 18.1 or API 18.2 (both incorporated by reference, see § 3174.3) as further specified in this paragraph to determine the quality and quantity of oil measured under field conditions at an FMP.
(1)
(2)
(i) Glass thermometers must be clean, be free of fluid separation, have a minimum graduation of 1.0 °F, and have an accuracy of ±0.5 °F.
(ii) Electronic thermometers must have a minimum graduation of 0.1 °F and have an accuracy of ±0.5 °F.
(iii) Record the temperature to the nearest 1.0 °F for glass thermometers or 0.1 °F for portable electronic thermometers.
(3)
(4)
(i) The hydrometer or thermohydrometer (as applicable) must be calibrated for an oil gravity range that includes the observed gravity of the oil sample being tested and must be clean, with a clearly legible oil gravity scale and with no loose shot weights.
(ii) Allow the temperature to stabilize for at least 5 minutes prior to reading the thermometer.
(iii) Read and record the observed API oil gravity to the nearest 0.1 degree. Read and record the temperature reading to the nearest 1.0 °F.
(5)
(i) For manual gauging, comply with the requirements of API 3.1A and API 18.1 (both incorporated by reference, see § 3174.3) and the following:
(A) The proper bob must be used for the particular measurement method,
(B) A gauging tape must be used. The gauging tape must be made of steel or corrosion-resistant material with graduation clearly legible, and must not be kinked or spliced;
(C) Either obtain two consecutive identical gauging measurements for any tank regardless of size, or:
(
(
(D) A suitable product-indicating paste may be used on the tape to facilitate the reading. The use of chalk or talcum powder is prohibited; and
(E) The same tape and bob must be used for both opening and closing gauges.
(ii) For automatic tank gauging (ATG), comply with the requirements of API 3.1B, API 3.6, and API 18.2 (all incorporated by reference, see § 3174.3) and the following:
(A) The specific makes and models of ATG that are identified and described at
(B) The ATG must be inspected and its accuracy verified to within ±
(C) A log of field verifications must be maintained and available upon request. The log must include the following information: The date of verification; the as-found manual gauge readings; the as-found ATG readings; and whether the ATG was field calibrated. If the ATG was field calibrated, the as-left manual gauge readings and as-left ATG readings must be recorded.
(iii) For dynamic volume determination under API 18.2, Subsection 10.1.1, (incorporated by reference, see § 3174.3), the specific makes and models of in-line meters that are identified and described at
(6)
(7)
(8)
(9)
(10)
(a) A LACT system must meet the construction and operation requirements and minimum standards of this section, § 3174.8, and § 3174.4.
(b) A LACT system must be proven as prescribed in § 3174.11 of this subpart.
(c) Measurement tickets must be completed under § 3174.12(b) of this subpart.
(d) All components of a LACT system must be accessible for inspection by the AO.
(e)(1) The operator must notify the AO, within 72 hours after discovery, of any LACT system failures or equipment malfunctions that may have resulted in measurement error.
(2) Such system failures or equipment malfunctions include, but are not limited to, electrical, meter, and other failures that affect oil measurement.
(f) Any tests conducted on oil samples extracted from LACT system samplers for determination of temperature, oil gravity, and S&W content must meet the requirements and minimum standards in § 3174.6(b)(2), (4), and (6) of this subpart.
(g) Automatic temperature compensators and automatic temperature and gravity compensators are prohibited.
(a)
(1) The custody transfer meter must be a positive displacement meter or a Coriolis meter. The specific make, models, and sizes of positive displacement or Coriolis meter and associated software that are identified and described at
(2) An electronic temperature averaging device must be installed.
(3) Meter back pressure must be applied by a back pressure valve or other controllable means of applying back pressure to ensure single-phase flow.
(b)
(1) Sampling must be conducted according to API 8.2 and API 8.3 (both incorporated by reference, see § 3174.3) and the following:
(i) The sample extractor probe must be inserted within the center half of the flowing stream;
(ii) The extractor probe must be horizontally oriented; and
(iii) The external body of the extractor probe must be marked with the direction of the flow.
(2) Any tests conducted on oil samples extracted from LACT system samplers for determination of oil gravity and S&W content must meet the requirements of either API 9.1, API 9.2, or API 9.3, and API 10.4 (all incorporated by reference, see § 3174.3).
(3) The composite sample container must be emptied and cleaned upon completion of sample withdrawal.
(4) The positive displacement or Coriolis meter (see § 3174.10) must be equipped with a non-resettable totalizer. The meter must include or allow for the attachment of a device that generates at least 8,400 pulses per barrel of registered volume.
(5) The system must have a pressure-indicating device downstream of the meter, but upstream of meter-proving connections. The pressure-indicating device must be capable of providing pressure data to calculate the CPL correction factor.
(6) An electronic temperature averaging device must be installed, operated, and maintained as follows:
(i) The temperature sensor must be placed in compliance with API 7 (incorporated by reference, see § 3174.3);
(ii) The electronic temperature averaging device must be volume-weighted and take a temperature reading following API 21.2, Subsection 9.2.8 (incorporated by reference, see § 3174.3);
(iii) The average temperature for the measurement ticket must be calculated by the volumetric averaging method using API 21.2, Subsection 9.2.13.2a (incorporated by reference, see § 3174.3);
(iv) The temperature averaging device must have a reference accuracy of ±0.5 °F or better, and have a minimum graduation of 0.1 °F; and
(v) The temperature averaging device must include a display of instantaneous temperature and the average temperature calculated since the measurement ticket was opened.
(vi) The average temperature calculated since the measurement ticket was opened must be used to calculate the CTL correction factor.
(7) Determination of net standard volume: Calculate the net standard volume at the close of each measurement ticket following the guidelines in API 12.2.1 and API 12.2.2 (both incorporated by reference, see § 3174.3).
The following Coriolis measurement systems section is intended for Coriolis measurement applications independent of LACT measurement systems.
(a) A CMS must meet the requirements and minimum standards of this section, § 3174.4, and § 3174.10.
(b) The specific makes, models, and sizes of Coriolis meters and associated software that have been reviewed by the PMT, as provided in § 3174.13, approved by the BLM, and identified and described at
(c) A CMS system must be proven at the frequency and under the requirements of § 3174.11 of this subpart.
(d) Measurement tickets must be completed under § 3174.12(b) of this subpart.
(e) A CMS at an FMP must be installed with the components listed in
(1) The pressure transducer must meet the requirements of § 3174.8(b)(5) of this subpart.
(2) Temperature determination must meet the requirements of § 3174.8(b)(6) of this subpart.
(3) If nonzero S&W content is to be used in determining net oil volume, the sampling system must meet the requirements of § 3174.8(b)(1) through (3) of this subpart. If no sampling system is used, or the sampling system does not meet the requirements of § 3174.8(b)(1) through (3) of this subpart, the S&W content must be reported as zero;
(4) Sufficient back pressure must be applied to ensure single phase flow through the meter.
(f)
(1) Determined from a composite sample taken pursuant to § 3174.8(b)(1) through (3) of this subpart; or
(2) Calculated from the average density as measured by the CMS over the measurement ticket period under API 21.2, Subsection 9.2.13.2a (incorporated by reference, see § 3174.3). Density must be corrected to base temperature and pressure using API 11.1 (incorporated by reference, see § 3174.3).
(g)
(a)
(b)
(i) The reference accuracy for both mass flow rate and density, stated in either percent of reading, percent of full scale, or units of measure;
(ii) The effect of changes in temperature and pressure on both mass flow and fluid density readings, and the effect of flow rate on density readings. These specifications must be stated in percent of reading, percent of full scale, or units of measure over a stated amount of change in temperature, pressure, or flow rate (
(iii) The stability of the zero reading for volumetric flow rate. The specifications must be stated in percent of reading, percent of full scale, or units of measure;
(iv) Design limits for flow rate and pressure; and
(v) Pressure drop through the meter as a function of flow rate and fluid viscosity.
(2) Submission of meter specifications: The operator must submit Coriolis meter specifications to the BLM upon request.
(c)
(d)
(e)
(2) For each Coriolis meter, the following values and corresponding units of measurement must be displayed:
(i) The instantaneous density of liquid (pounds/bbl, pounds/gal, or degrees API);
(ii) The instantaneous indicated volumetric flow rate through the meter (bbl/day);
(iii) The meter factor;
(iv) The instantaneous pressure (psi);
(v) The instantaneous temperature (°F);
(vi) The cumulative gross standard volume through the meter (non-resettable totalizer) (bbl); and
(vii) The previous day's gross standard volume through the meter (bbl).
(3) The following information must be correct, be maintained in a legible condition, and be accessible to the AO at the FMP without the use of data collection equipment, laptop computers, or any special equipment:
(i) The make, model, and size of each sensor; and
(ii) The make, range, calibrated span, and model of the pressure and temperature transducer used to determine gross standard volume.
(4) A log must be maintained of all meter factors, zero verifications, and zero adjustments. For zero adjustments, the log must include the zero value before adjustment and the zero value after adjustment. The log must be made available upon request.
(f)
(1)
(2)
(3)
(4)
(i) Density deviations from acceptable parameters; and
(ii) Instances in which the flow rate exceeded the manufacturer's maximum recommended flow rate or was below the manufacturer's minimum recommended flow rate.
(g)
(a)
(b)
(1) Master meters must have a meter factor within 0.9900 to 1.0100 determined by a minimum of five consecutive prover runs within 0.0005 (0.05 percent repeatability) as described in API 4.5, Subsection 6.5 (incorporated by reference, see § 3174.3). The master meter must not be mechanically compensated for oil gravity or temperature; its readout must indicate units of volume without corrections. The meter factor must be documented on the calibration certificate and must be calibrated at least once every 12 months. New master meters must be calibrated immediately and recalibrated in three months. Master meters that have undergone mechanical repairs, alterations, or changes that affect the calibration must be calibrated immediately upon completion of this work and calibrated again 3 months after this date under API 4.5, API 4.8, Subsection 10.2, and API 4.8, Annex B (all incorporated by reference, see § 3174.3).
(2) Displacement provers must meet the requirements of API 4.2 (incorporated by reference, see § 3174.3) and be calibrated using the water-draw method under API 4.9.2 (incorporated by reference, see § 3174.3), at the calibration frequencies specified in API 4.8, Subsection 10.1(b) (incorporated by reference, see § 3174.3).
(3) The base prover volume of a displacement prover must be calculated under API 12.2.4 (incorporated by reference, see § 3174.3).
(4) Displacement provers must be sized to obtain a displacer velocity through the prover that is within the appropriate range during proving under API 4.2, Subsection 4.3.4.2, Minimum Displacer Velocities and API 4.2, Subsection 4.3.4.1, Maximum Displacer Velocities (incorporated by reference, see § 3174.3).
(5) Fluid velocity is calculated using API 4.2, Subsection 4.3.4.3, Equation 12 (incorporated by reference, see § 3174.3).
(c)
(1) Meter proving must be performed under normal operating fluid pressure, fluid temperature, and fluid type and composition, as follows:
(i) The oil flow rate through the LACT or CMS during proving must be within 10 percent of the normal flow rate;
(ii) The absolute pressure as measured by the LACT or CMS during proving must be within 10 percent of the normal operating absolute pressure;
(iii) The temperature as measured by the LACT or CMS during the proving must be within 10 °F of the normal operating temperature; and
(iv) The gravity of the oil during proving must be within 5° API of the normal oil gravity.
(v) If the normal flow rate, pressure, temperature, or oil gravity vary by more than the limits defined in paragraphs (c)(i) through (c)(iv) of this section, meter provings must be conducted, at a minimum, under the three following conditions: At the lower limit of normal operating conditions, at the upper limit of normal operation conditions, and at the midpoint of normal operating conditions.
(2) If each proving run is not of sufficient volume to generate at least 10,000 pulses, as specified by API 4.2, Subsection 4.3.2 (incorporated by reference, see § 3174.3), from the positive displacement meter or the Coriolis meter, then pulse interpolation must be used in accordance with API 4.6 (incorporated by reference, see § 3174.3).
(3) Proving runs must be made until the calculated meter factor or meter generated pulses from five consecutive runs match within a tolerance of 0.0005 (0.05 percent) between the highest and the lowest value in accordance with API 12.2.3, Subsection 9 (incorporated by reference, see § 3174.3).
(4) The new meter factor is the arithmetic average of the meter generated pulses or intermediate meter factors calculated from the five consecutive runs in accordance with API 12.2.3, Subsection 9 (incorporated by reference, see § 3174.3).
(5) Meter factor computations must follow the sequence described in API 12.2.3 (incorporated by reference, see § 3174.3).
(6) If multiple meters factors are determined over a range of normal operating conditions, then:
(i) If all the meter factors determined over a range of conditions fall within 0.0020 of each other, then a single meter factor may be calculated for that range as the arithmetic average of all the meter factors within that range. The full range of normal operating conditions may be divided into segments such that all the meter factors within each segment fall within a range of 0.0020. In this case, a single meter factor for each segment may be calculated as the arithmetic average of the meter factors within that segment; or
(ii) The metering system may apply a dynamic meter factor derived (using,
(7) The meter factor must be at least 0.9900 and no more than 1.0100.
(8) The initial meter factor for a new or repaired meter must be at least 0.9950 and no more than 1.0050.
(9) For positive displacement meters, the back pressure valve may be adjusted after proving only within the normal operating fluid flow rate and fluid pressure as described in paragraph (c)(1) of this section. If the back pressure valve is adjusted after proving, the operator must document the as left fluid flow rate and fluid pressure on the proving report.
(10) If a composite meter factor is calculated, the CPL value must be calculated from the pressure setting of the back pressure valve or the normal operating pressure at the meter. Composite meter factors must not be used with a Coriolis meter.
(d)
(1) Initial meter installation;
(2) Every 3 months (quarterly) after the last proving, or each time the registered volume flowing through the meter, as measured on the non-resettable totalizer from the last proving, increases by 75,000 bbl, whichever comes first, but no more frequently than monthly;
(3) Meter zeroing (Coriolis meter);
(4) Modification of mounting conditions;
(5) A change in fluid temperature that exceeds the transducer's calibrated span;
(6) A change in pressure, density, or flow rate that exceeds the operating proving limits;
(7) The mechanical or electrical components of the meter have been changed, repaired, or removed;
(8) Internal calibration factors have been changed or reprogrammed; or
(9) At the request of the AO.
(e)
(2) The arithmetic average of the two successive meter factors must be applied to the production measured through the meter between the date of the previous meter proving and the date of the most recent meter proving.
(3) The proving report submitted under paragraph (i) of this section must clearly show the most recent meter factor and describe all subsequent repairs and adjustments.
(f)
(1) The temperature averager or temperature transducer must be compared with a test thermometer traceable to NIST and with a stated accuracy of ±0.25 °F or better.
(2) The temperature reading displayed on the temperature averager or temperature transducer must be compared with the reading of the test thermometer using one of the following methods:
(i) The test thermometer must be placed in a test thermometer well located not more than 12″ from the probe of the temperature averager or temperature transducer; or
(ii) Both the test thermometer and probe of the temperature averager or temperature transducer must be placed in an insulated water bath. The water bath temperature must be within 20 °F of the normal flowing temperature of the oil.
(3) The displayed reading of instantaneous temperature from the temperature averager or the temperature transducer must be compared with the reading from the test thermometer. If they differ by more than 0.5 °F, then the difference in temperatures must be noted on the meter proving report and:
(i) The temperature averager or temperature transducer must be adjusted to match the reading of the test thermometer; or
(ii) The temperature averager or temperature transducer must be recalibrated, repaired, or replaced.
(g)
(2) The pressure reading displayed on the pressure transducer must be compared with the reading of the test pressure device.
(3) The pressure transducer must be tested at the following three points:
(i) Zero (atmospheric pressure);
(ii) 100 percent of the calibrated span of the pressure transducer; and
(iii) A point that represents the normal flowing pressure through the Coriolis meter.
(4) If the pressure applied by the test pressure device and the pressure displayed on the pressure transducer vary by more than the required accuracy of the pressure transducer, the pressure transducer must be adjusted to read within the stated accuracy of the test pressure device.
(h)
(i)
(2) In addition to the information required under paragraph (i)(1) of this section, each meter-proving report must also show the:
(i) Unique meter ID number;
(ii) Lease number, CA number, or unit PA number;
(iii) The temperature from the test thermometer and the temperature from the temperature averager or temperature transducer;
(iv) For pressure transducers, the pressure applied by the pressure test device and the pressure reading from the pressure transducer at the three points required under paragraph (g)(3) of this section;
(v) For density verification (if applicable), the instantaneous flowing density (as determined by Coriolis meter), and the independent density measurement, as compared under paragraph (h) of this section; and
(vi) The “as left” fluid flow rate and fluid pressure, if the back pressure valve is adjusted after proving as described in paragraph (c)(9) of this section.
(3) The operator must submit the meter-proving report to the AO no later than 14 days after the meter proving. The proving report may be either in a hard copy or electronic format.
(a)
(1) Lease, unit PA, or CA number;
(2) Unique tank number and nominal tank capacity;
(3) Opening and closing dates and times;
(4) Opening and closing gauges and observed temperatures in °F;
(5) Observed volume for opening and closing gauge, using tank specific calibration charts (see § 3174.5(c));
(6) Total gross standard volume removed from the tank following API 11.1 (incorporated by reference, see § 3174.3);
(7) Observed API oil gravity and temperature in °F;
(8) API oil gravity at 60 °F, following API 11.1 (incorporated by reference, see § 3174.3);
(9) S&W content percent;
(10) Unique number of each seal removed and installed;
(11) Name of the individual performing the tank gauging; and
(12) Name of the operator.
(b)
(i) Lease, unit PA, or CA number;
(ii) Unique meter ID number;
(iii) Opening and closing dates;
(iv) Opening and closing totalizer readings of the indicated volume;
(v) Meter factor, indicating if it is a composite meter factor;
(vi) Total gross standard volume removed through the LACT system or CMS;
(vii) API oil gravity. For API oil gravity determined from a composite sample, the observed API oil gravity and temperature must be indicated in °F and the API oil gravity must be indicated at 60 °F. For API oil gravity determined from average density (CMS only), the average uncorrected density must be determined by the CMS;
(viii) The average temperature in °F;
(ix) The average flowing pressure in psig;
(x) S&W content percent;
(xi) Unique number of each seal removed and installed;
(xii) Name of the purchaser's representative; and
(xiii) Name of the operator.
(2) Any accumulators used in the determination of average pressure, average temperature, and average density must be reset to zero whenever a new measurement ticket is opened.
(a) Any method of oil measurement other than tank gauging, LACT system, or CMS at an FMP requires prior BLM approval.
(b)(1) Any operator requesting approval to use alternate oil measurement equipment or measurement method must submit to the BLM performance data, actual field test results, laboratory test data, or any other supporting data or evidence that demonstrates that the proposed alternate oil equipment or method would meet or exceed the objectives of the applicable minimum requirements of this subpart and would not affect royalty income or production accountability.
(2) The PMT will review the submitted data to ensure that the alternate oil measurement equipment or method meets the requirements of this subpart and will make a recommendation to the BLM to approve use of the equipment or method, disapprove use of the equipment or method, or approve use of the equipment or method with conditions for its use. If the PMT recommends, and the BLM approves new equipment or methods, the BLM will post the make, model, range or software version (as applicable), or method on the BLM Web site
(c) The procedures for requesting and granting a variance under § 3170.6 of this part may not be used as an avenue for approving new technology, methods, or equipment. Approval of alternative oil measurement equipment or methods may be obtained only under this section.
(a) Under 43 CFR 3162.7-2, when production cannot be measured due to spillage or leakage, the amount of production must be determined by using any method the AO approves or prescribes. This category of production includes, but is not limited to, oil that is classified as slop oil or waste oil.
(b) No oil may be classified or disposed of as waste oil unless the operator can demonstrate to the satisfaction of the AO that it is not economically feasible to put the oil into marketable condition.
(c) The operator may not sell or otherwise dispose of slop oil without prior written approval from the AO. Following the sale or disposal of slop oil, the operator must notify the AO in writing of the volume sold or disposed of and the method used to compute the volume.
Certain instances of noncompliance warrant the imposition of immediate assessments upon the BLM's discovery of the violation, as prescribed in the following table. Imposition of any of these assessments does not preclude other appropriate enforcement actions.
Bureau of Land Management, Interior.
Final rule.
This final rule updates and replaces Onshore Oil and Gas Order No. 5 (Order 5) with a new regulation codified in the Code of Federal Regulations (CFR). Like Order 5, this rule establishes minimum standards for accurate measurement and proper reporting of all gas removed or sold from Federal and Indian (except the Osage Tribe) leases, units, unit participating areas (PAs), and areas subject to communitization agreements (CAs). It provides a system for production accountability by operators, lessees, purchasers, and transporters. This rule establishes overall gas measurement performance standards and includes, among other things, requirements for the hardware and software related to gas metering equipment and reporting and recordkeeping. This rule also identifies certain specific acts of noncompliance that may result in an immediate assessment and provides a process for the Bureau of Land Management (BLM) to consider variances from the requirements of this rule.
The final rule is effective on January 17, 2017. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of January 17, 2017.
Richard Estabrook, Petroleum Engineer, Division of Fluid Minerals, 707-468-4052, or Steven Wells, Division Chief, Division of Fluid Minerals, 202-912-7143, for information regarding the BLM's Fluid Minerals Program. 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 Relay Service at 1-800-877-8339 to contact the above individual during normal business hours. The Service 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.
Under applicable laws, royalties are owed on all production removed or sold from Federal and Indian oil and gas leases. The basis for those royalty payments is the measured volume and quality of the production from those leases. In fiscal year (FY) 2015, onshore Federal oil and gas lease holders sold 180 million barrels of oil,
As explained in the preamble for the proposed rule, given the magnitude of this production and the BLM's statutory and management obligations, it is critically important that the BLM ensure that operators accurately measure, report, and account for that production. The final rule helps achieve that objective by updating and replacing Order 5's requirements with respect to the measurement of gas with regulations codified in the CFR that reflect changes in applicable laws, metering technology, and industry standards since Order 5 was first promulgated in 1989.
The basis for this rule is the Secretary of the Interior's authority under various Federal and Indian mineral leasing laws to manage oil and gas operations, which authority has been delegated to the BLM. In implementing that authority, the BLM issued onshore oil and gas operating regulations that are codified at 43 CFR part 3160. 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.
Consistent with updating and replacing Order 5, this rule also supersedes various statewide NTLs that have been issued from time-to-time to provide additional guidance regarding compliance with the requirements of Order 5, including:
• 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; and
• CO NTL 2014-01, May 19, 2014.
Although this rule supersedes Order 5 and various statewide NTLs, the existing requirements of Order 5 and those NTLs remain in effect during the phase-in periods—specified in § 3175.60(b)—for the rule's new requirements.
The requirements in this rule help ensure that the Department of the Interior (DOI or the Department) meets it responsibility to collect royalties on gas extracted from Federal onshore and Indian (except the Osage Tribe) leases. The proper measurement of gas is essential to ensure that the American
As explained in the preamble to the proposed rule, these changes were prompted by internal and external concerns about the adequacy of the BLM's existing gas measurement rules. Notably, these concerns were highlighted in several external reviews of the BLM's measurement program by three independent outside entities—the Secretary of the Interior's (Secretary's) Subcommittee on Royalty Management (the Subcommittee) in 2007, the DOI's Office of the Inspector General (OIG) in 2009, and the Government Accountability Office (GAO) in 2010, 2011, 2013, and 2015—all of which have repeatedly recommended that the BLM evaluate its gas measurement guidance and regulations to ensure that operators are properly accounting for production from Federal and Indian leases and are paying the proper royalties. Specifically, these groups found with respect to gas measurement that the DOI 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 new technologies or processes are developed that are not yet addressed by existing rules. As explained in the Section-by-Section analysis, the provisions of this final rule respond to these recommendations.
In 2007, the Secretary appointed an independent panel—the Subcommittee—to review the Department's procedures and processes related to the management of mineral revenues and to provide advice to the Department based on that review.
Specifically, the Subcommittee report expressed concern that the applicable “BLM policy and guidance is outdated” and “some policy memoranda have expired” (Subcommittee report, p. 31). It also noted that “BLM policy and guidance have not been consolidated in a single document or publication,” which has led to the “BLM's 31 oil and gas field offices using varying policy and guidance” (
This rule also addresses findings and recommendations made in two GAO reports and one OIG report: (1) GAO Report to Congressional Requesters,
Consistent with the Subcommittee's findings, 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 (
In total, the GAO made 19 recommendations to improve the BLM's ability to ensure that oil and gas produced from Federal and Indian lands are accurately measured and properly reported (GAO Report 10-313), a number of which relate to gas measurement. For example, the report recommends that the BLM establish goals that would allow it to witness gas sample collections; however, it recognized that the BLM must first establish gas sampling standards as a basis for inspection and enforcement actions. This final rule establishes those standards. Similarly, the 2015 GAO report recommends, among other things, that the BLM issue new regulations pertaining to gas measurement, which this rule accomplishes.
It should also be noted that the GAO's recommendations regarding 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 (GAO-13-283 (2013) and GAO-
In addition to these external reports and assessments, the provisions of this rule are also based on the BLM's own internal assessment of the adequacy of the existing requirements of Order 5. For example, because many improvements in technology and industry standards have occurred since Order 5 was issued, the BLM has had to develop a number of statewide NTLs and/or approve a number of site-specific variances. This final rule addresses these issues and supersedes the statewide NTLs.
The following summarizes and briefly explains the most significant provisions in this final rule. Each of these is 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 summary discussion.
The most significant requirements of the final rule are related to 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. Therefore, 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. Because the flow equation uses the square root of relative density, a 10 percent error in relative density would only result in a 5 percent error in the volume calculation. Both heating value and relative density are determined from the same gas sample.
Currently, 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 in Order 5 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 of 180 gas facility measurement points (FMPs) that found significant sample-to-sample variability in heating value and relative density. The “BLM Gas Variability Study Final Report,” dated 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 (statistical range of error that indicates the risk of measurement error) in heating value and relative density in this study was ±5.09 percent, which, across the board, could amount to ±$127 million in royalties based on 2008 total onshore Federal and Indian royalty payments of about $2.5 billion (p. 16).
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 several 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 rule strengthens the BLM's regulations on measuring heating value and relative density by requiring operators to sample all meters more frequently than required under Order 5, except very-low-volume meters (measuring 35 Mcf/day or less), for which annual sampling remains sufficient. Low-volume FMPs (measuring more than 35 Mcf/day, but less than or equal to 200 Mcf/day) must be sampled every 6 months; high-volume FMPs (measuring more than 200 Mcf/day, but less than or equal to 1,000 Mcf/day) must initially be sampled every 3 months; very-high-volume FMPs (measuring more than 1,000 Mcf/day) must initially be sampled every month. In developing this 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 that has very consistent heating values from one sample to the next. If a high- or very-high-volume FMP did not meet these heating-value uncertainty limits, the BLM will adjust the sampling frequency at that FMP until the heating value meets the uncertainty standards. If a very-high-volume FMP continues to exceed the uncertainty standards, the final rule includes a provision that allows the BLM to require the installation of composite samplers or on-line gas chromatographs (GCs), which automatically sample gas at frequent intervals.
The rule also sets 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 addition to prescribing uncertainty standards and more frequent sampling, this rule also improves measurement and reporting of heating values and relative density by setting standards for gas sampling and analysis. These standards specify sampling locations and methods, analysis methods, and the minimum number of components that must be analyzed. The standards also set requirements for how and when operators report the results to the BLM and the Office of Natural Resources Revenue (ONRR), and define the effective date of the heating value and relative density that is determined from the sample.
This rule requires 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. Under this rule, basic meter tube inspections are required once every 5 years at low-volume FMPs, once every 2 years at high-volume FMPs, and
The rule changes routine meter verification or calibration requirements from current requirements under Order 5. Verification frequency is decreased at all very-low-volume FMPs and low-volume FMPs using electronic gas measurement (EGM) systems. Verification frequency is unchanged from current regulations for low-volume FMPs using mechanical recorders and high- and very-high-volume FMPs. Currently, under Order 5, all meters are required to undergo routine verification every 3 months, regardless of the throughput volume.
The rule restricts the use of mechanical chart recorders to low- and very-low-volume FMPs because the accuracy and performance of mechanical chart recorders is not defined well enough for the BLM to quantify the overall measurement uncertainty. Between 80 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 currently address them. Instead, the BLM has regulated their use through statewide NTLs, which do not address many aspects unique to EGMs, such as volume calculation and data-gathering and retention requirements. This rule includes many of the existing NTL requirements for EGM systems and adds some new requirements relating to onsite information, gauge lines, verification, test equipment, calculations, and information generated and retained by the EGM systems. The rule includes a significant change in those requirements by revising the maximum flow-rate uncertainty that is currently allowed under existing statewide NTLs. Under the NTLs, flow-rate equipment at FMPs that measure more than 100 Mcf/day is required to meet a ±3 percent uncertainty level. The rule maintains that level of uncertainty for high-volume FMPs although the threshold is raised to 200 Mcf/day. Under this rule, equipment at very-high-volume FMPs must comply with a new ±2 percent uncertainty requirement. Flow-rate equipment at FMPs that measure less than 200 Mcf/day is exempt from these uncertainty requirements. The BLM is maintaining this exemption because it believes that compliance costs for these FMPs could cause some operators to shut in their wells instead of making improvements. The BLM believes the royalties lost by such shut-ins would exceed any royalties that might be gained through upgrades at such facilities.
One area that this rule addresses, which is not addressed by existing NTLs, 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 are programmed into the flow computers, to calculate volumes and flow rates. Currently, the BLM must accept transducer 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 rule requires operators or manufacturers to “type test” transducers at a qualified testing facility using a standard testing protocol defined in this rule or, for transducers that are already in use at FMPs, submit existing test data to the BLM for review. The purpose of this review is to quantify the uncertainty of the transducers using actual test data, rather than relying on the manufacturer's performance specifications. The BLM will then incorporate the test results into the calculation of overall measurement uncertainty based on each transducer tested. The rule also requires operators or manufacturers to test flow computers and flow-computer software at qualified testing facilities, using a standard testing protocol defined in this rule, to assess the ability of those flow-computers and software versions to accurately calculate flow rate, volume, and other values that are used in the BLM's verification process. Only those flow computers and flow computer software versions that demonstrate the ability to perform these calculations within the tolerances established by the BLM will be allowed for use on Federal and Indian leases.
An integral part of the BLM's evaluation process is the Production Measurement Team (PMT), made up of measurement experts designated by the BLM.
As discussed in the Background and Overview section of this preamble, the provisions of Order 5 have not kept pace with industry standards and practices, statutory requirements, or applicable measurement technology and practices. This final rule updates and replaces those requirements by establishing the minimum standards for accurate measurement and proper reporting of all gas sold from Federal and Indian (except the Osage Tribe) leases, units, unit PAs, and areas subject to CAs, by providing a system for production accountability by operators, lessees, purchasers, and transporters. The following table provides an overview of the changes between the proposed rule and this final rule. A similar chart explaining the differences between the proposed rule and Order 5 appears in the proposed rule at 80 FR 61650 (October 13, 2015).
This section presents and responds to general comments on the proposed rule received by the BLM. Comments on specific provisions of the proposed rule are addressed in the Section-by-Section analysis as part of the explanation of the provisions included in this final rule.
The BLM received numerous comments stating the new rule will cause additional delays and backlogs for both the BLM and industry because of all the additional paperwork and inspections required by the new rule. The BLM has analyzed and disclosed the burdens for industry in the Economic and Threshold Analysis prepared as part of this rulemaking process and in the Paperwork Reduction Act portion of this preamble. Some of the burdens are usual and customary, since they are required by gas sales contracts and/or industry standards. The BLM has determined that the remaining burdens are necessary in order to ensure accurate measurement and reporting.
The BLM also acknowledges that implementation of the rule will require additional BLM staff time. The BLM has analyzed and disclosed the Federal burdens that will result from this rule. The BLM is taking steps to address the issue of streamlining administrative processes, including strategic investments in technology and repeatedly requesting additional resources during the appropriations process. The BLM will continue to pay attention to this issue during the implementation period. The BLM did not make any changes to the rule in response to these comments.
As was stated in the preamble of the proposed rule, this final rule removes the enforcement, corrective action, and abatement period provisions of Order 5. In their place, the BLM will develop an Internal Inspection and Enforcement Handbook that will provide direction to BLM inspectors on how to classify a violation—as either major or minor—what the corrective action should be, and what the timeframes for correction should be. The Authorized Officer (AO) will use the Inspection and Enforcement Handbook in conjunction with 43 CFR subpart 3163, which provides for assessments and civil penalties, when lessees and operators fail to remedy their violations in a timely fashion, and for immediate assessments for certain violations. As explained in the proposed rule, this change allows the BLM to make a case-by-case determination of the severity of a particular violation, based on applicable definitions in the regulations.
Several comments objected, saying that this course of action was inconsistent with the APA. One such commenter stated its objection as follows:
BLM's proposal would completely eliminate the enforcement infrastructure prescribed in Onshore Order No. 5, including major and minor violations, corrective actions, and abatement periods. . . . Removing the enforcement provisions from the realm of transparent, publicly reviewable regulations that were promulgated with notice and comment, and concealing them in non-public policy documents that can be altered in the absence of public input, is inconsistent with the requirements of the APA. BLM-2015-0005-0058 (December 15, 2015).
In general, these comments misunderstand the nature of the Internal Inspection and Enforcement Handbook that the BLM will develop. The new Handbook will not establish new obligations to be imposed on the regulated community. Those obligations are spelled out in applicable regulations, orders, and permits, as well as the terms and conditions of leases and other agreements. Moreover, the overarching enforcement infrastructure of 43 CFR subpart 3163 remains in effect, and the definitions of “major violation” and “minor violation” in § 3160.0-5 remain unchanged. It is these duly promulgated regulations (among other authorities), and not the Enforcement Handbook, that will provide the legal basis for the BLM's enforcement actions. Put another way, BLM's enforcement actions must be consistent with these regulations irrespective of what may be contained in its Inspection and Enforcement Handbook. It should also be noted, it is this rule and other duly promulgated regulations that establish these standards to which an operator will be held consistent with Administrative Procedure Act (APA) requirements.
As to the concern about public notice and comment processes, it should be noted that internal guidance documents that direct agency personnel on how to implement existing agency policies are not required to follow the public notice and comment process. No change to the rule resulted from these comments.
One commenter suggested that the BLM should retain discretionary case-by-case enforcement of requirements as is currently done under Order 5. Although the BLM disagrees with the premise of the comment regarding the existing requirements of Order 5, the intent of the Inspection and Enforcement Handbook is to provide guidance to BLM inspectors on how to apply the provisions of its oil and gas rules in a consistent manner. As noted above, it will not establish new requirements or obligations. It also will not alter the BLM's case-by-case discretion with respect to any particular enforcement action. The BLM did not make any changes to the rule based on this comment.
Several commenters suggested that the BLM should post the Inspection and Enforcement Handbook on the website. The BLM agrees with this comment and will post the enforcement handbook upon its completion, and will otherwise make it available to the public at any BLM office.
One commenter suggested that the BLM should develop the Inspection and Enforcement Handbook with input from industry. The BLM disagrees with this comment since the handbook is
One commenter asked if the BLM will publish the Inspection and Enforcement Handbook at the same time as the final rule. For the preceding reasons, the BLM has determined that it is not necessary to release the handbook with this final rule. However, the BLM intends to develop the Handbook within 1 year of the effective date of the proposed rule, which is the earliest date by which the provisions of this rule will go into effect. The BLM did not make any changes to the rule as a result of this comment.
One commenter asked that the BLM provide the economic analysis of developing an Inspection and Enforcement Handbook instead of including enforcement actions in the rule and for moving away from the more discretionary enforcement approach to more immediate assessments. The BLM does not agree with the characterization of Order 5 and the current approach. Also, there have always been immediate assessments, and the BLM has simply expanded the list of actions potentially subject to an immediate assessment. With respect to the requested economic analysis, the BLM does not believe that there is any economic impact in removing enforcement guidance from the rule and placing it in an enforcement handbook. Additionally, because the BLM assumes compliance for purposes of assessing the impact of a rule, the BLM does not believe that it is appropriate to analyze the economic impacts of immediate assessments. The BLM did not make any changes to the rule as a result of this comment.
One commenter stated that, per the National Technology Transfer and Advancement Act (NTTAA), codified as a note to 15 U.S.C. 272, the BLM must adopt API standards in whole or justify to the Office of Management and Budget (OMB) why this does not meet the agency mission. The NTTAA directs agencies to utilize technical standards that are developed by voluntary consensus standards bodies. Some commenters argued that the NTTAA obligates the BLM to adopt all gas measurement standards developed by voluntary consensus standards bodies.
The commenters' assertion overstates the requirements of the NTTAA. The NTTAA does not require an agency to adopt voluntary consensus standards where it would be “impractical.” NTTAA section 12(d)(3). The OMB's guidance for implementing the NTTAA defines “impractical” to include circumstances in which use of certain standards “would fail to serve the agency's regulatory, procurement, or program needs; be infeasible; be inadequate, ineffectual, inefficient, . . . or impose more burdens, or be less useful, than those of another standard” (OMB Circular A-119, p. 20). Furthermore, the OMB has explained that the NTTAA “does not preempt or restrict agencies' authorities and responsibilities to make regulatory decisions authorized by statute . . . [including] determining the level of acceptable risk and risk-management, and due care; setting the level of protection; and balancing risk, cost, and availability of alternative approaches in establishing regulatory requirements” (OMB Circular A-119, p. 25). The BLM has studied the available voluntary consensus standards for gas measurement and has chosen to adopt a workable suite of these standards that will meet the BLM's regulatory needs in an effective and feasible manner. To adopt all available voluntary consensus standards would be “impractical” in that it would involve the adoption of standards the BLM has judged to be less effective, less feasible, or less useful. In addition, the commenters' reading of the NTTAA would, contrary to OMB guidance, inappropriately preempt the BLM's statutory authority to promulgate rules and regulations that it deems “necessary” to accomplish the purposes of the applicable statutory directives, including the Mineral Leasing Act (MLA) and the Federal Oil and Gas Royalty Management Act (FOGRMA).
Several commenters argued that the rule is impermissibly “retroactive.” These comments argued that the rule is retroactive because it will apply to existing measurement systems that predate the rule's effective date. The comments misunderstand the nature of the “retroactive” regulations that the law disfavors. “A law does not operate `retrospectively' merely because it is applied in a case arising from conduct antedating the statute's enactment or upsets expectations based in prior law” (
It is often the case that a business will undertake a certain course of conduct based on the current law, and will then find its expectations frustrated when the law changes. This has never been thought to constitute retroactive lawmaking, and indeed most economic regulation would be unworkable if all laws disrupting prior expectations were deemed suspect.
This rule does not impose liability for nor require changes to measurements made prior to the rule's enactment; rather the rule requires measurements taken as required by the rule after the effective date of the rule (that is, going forward) at both new and existing facilities to satisfy the performance standards established by the final rule. Thus, despite the fact that this rule may require operators to update or modify their existing measurement systems, the rule is prospective—not retroactive—in nature.
The BLM received comments arguing that the incorporated API and GPA standards were not adequately available to the public during the comment period. The BLM's obligation to make the incorporated standards available to the public derives from the Freedom of Information Act (FOIA), which requires agencies to publish “substantive rules of general applicability adopted as authorized by law” in the
Some commenters stated that local BLM offices were unable to provide them with access to the incorporated standards. These occurrences resulted from the fact that, although all the local BLM offices have electronic access to the incorporated standards, not all local office personnel were aware of how to access the incorporated standards. The BLM plans to carry out a training program to ensure that personnel at local BLM offices can readily access the incorporated standards and provide them to interested members of the public when requested. Given the multiple avenues available for accessing the incorporated standards, we do not believe that the handful of reported occurrences in which staff were unable to access the standards prevented stakeholders from accessing and reviewing the documents as part of their review of the proposed rule. Therefore the BLM has met its obligations under FOIA and the APA with respect to those standards.
It should be noted that the BLM received numerous comments regarding the adoption of specific API and GPA standards in the proposed rule. Most of these comments are addressed in connection with the relevant sections of the rule (§§ 3175.30, 3175.40, 3175.110, 3175.130, and 3175.140; see section II. C of this preamble below).
The BLM received one comment stating that this rule is duplicative of State rules. During the development of this rule, the BLM researched existing State rules related to gas measurement and crafted the rule to avoid conflicts with applicable State standards. The commenter did not identify any inconsistencies.
Moreover, the BLM is issuing this rule in fulfillment of its fiduciary obligation to assure that Federal and Indian gas is properly measured and that all royalties due under Federal law are paid. The fact that some States may have similar requirements does not render this rule duplicative, as the BLM has an independent responsibility to meet its fiduciary obligations for the resources it manages.
One commenter stated that separately publishing the proposed rules to update and replace Order 3 (site security), Order 4 (oil measurement), and Order 5 made the definitions hard to find. The BLM does not agree with this comment. The proposed rule to replace Order 3 also established a new part 3170 that will contain all three rules to replace Orders 3, 4, and 5, including a definitions section containing provisions common to all three rules. The proposed rules, in most instances, contained all of the key definitions unique to each subpart. For example, definitions specific to gas measurement are found in the definitions section of this rule. Definitions that are used in two or more subparts are found in the definitions section of subpart 3170 in order to reduce redundancy and ensure consistency. Additionally, the BLM extended the comment periods for all three proposed rules to ensure that they were all open and available for comments at the same time.
Moreover, since all three final rules to replace Orders 3, 4, and 5 will appear in the CFR in a new part 3170, this will ensure that the definitions will be easy to find during implementation. The BLM did not make any changes to the rule in response to this comment.
The BLM received several comments stating the proposed rule did not contain a description of all the calculations, assumptions, and enforcement actions, nor an explanation of why certain industry standards were or were not incorporated by reference. The BLM believes that a thorough description of the assumptions and rationale for the proposed changes was provided in the preamble to the proposed rule. The BLM also published heating value variability and uncertainty calculations in the BLM Gas Variability Study, which was referenced numerous times in the preamble and posted as a supporting document on the
With respect to incorporated industry standards, the BLM incorporated the standards that are relevant and appropriate to the proposed rules. These include standards that directly relate to the measurement of volume and heating value typical of the technologies currently used at BLM points of royalty measurement (now called FMPs). To adopt all available voluntary consensus standards would be “impractical” in that it would involve the adoption of standards the BLM has judged to be less effective, feasible, or useful, or standards that cover equipment and processes that are very rarely used for gas measurement at the lease level, such as those covering Coriolis meters, turbine meters, or ultrasonic meters. That said, the PMT may, on a case-by-case basis, consider recommending for approval the use of such standards in lieu of compliance with the identified standards if and when it is asked to review such requests for approval to employ such standards in the field in the future. The commenters' questions regarding enforcement were addressed previously. The BLM did not make any changes to the rule based on these comments.
Numerous comments objected to the equipment standards in the proposed rule and suggested that the BLM only rely on performance goals because the equipment standards will become obsolete as technology progresses. The BLM agrees that some of the equipment standards may become obsolete as technology progresses. As a result, the BLM included performance standards in § 3175.31 of the final rule (§ 3175.30 in the proposed rule), along with a process for the BLM—through the PMT—to assess and approve new technologies over time. The BLM also agrees that, with appropriate oversight, performance goals should be sufficient without the explicit equipment standards. The BLM fully supports the concept of allowing industry to determine the best and most cost-effective way to meet performance goals. As a result, this rule allows the BLM to approve technologies and processes that are different from the specific equipment standards in the rule as long as they meet or exceed the stated performance goals in § 3175.31. It should be noted that unlike the existing variance process, which requires local field office approval on a case-by-case basis, the PMT process outlined in the proposed and final rules is structured such that the PMT needs to review and approve technology only once on a
While the BLM recognizes the value of performance-based standards, it is nevertheless providing equipment standards for two reasons. First, the BLM has over 4,000 operators of Federal and Indian leases and the vast majority of these operators are small companies without measurement personnel on staff. Requiring a small operator to achieve, for example, an overall meter measurement uncertainty of ±3 percent, without any equipment standards, would likely require the operator to hire measurement specialists to determine the equipment and operating conditions necessary to meet the uncertainty requirement on their leases. The BLM equipment standards provide a “cookbook” for how to achieve the performance goals established in the rule for operators that do not have the expertise, resources, or interest in innovating new technology or processes to meet a performance goal. In the BLM's experience, this cookbook approach is useful to smaller operators and is a feature of Order 5 that was retained in the final rule.
Second, it would be virtually impossible for the BLM to enforce a performance goal without a full understanding of the technology and process the operator is using to achieve that goal. In addition, this would require customized enforcement procedures for every meter installation. For the BLM to implement this approach, it would need to approve all new FMP installations on a case-by-case basis, which would include: (1) Conducting a detailed analysis on the operator's proposal regarding how they would achieve the performance goals in the rule; and (2) Developing the enforcement procedures specific to that approval. This would unnecessarily drive up costs for both the BLM and industry and could result in backlogs of new measurement applications, both of which the BLM (and likely industry as well) would prefer to avoid.
Under this rule, the BLM has to approve only those technologies and processes that are different from the equipment standards listed in the rule. The BLM did not make any changes to the rule based on these comments.
The BLM received several comments stating that Order 5 works well as written and a new rule is not needed. The BLM disagrees with these comments. Order 5 incorporates one industry standard—AGA Report No. 3 from 1985. This standard addresses the installation requirements for orifice meters and the calculation of flow rate from an orifice meter. Installing an orifice meter using this standard can cause significant bias in measurement. This standard has been revised numerous times since 1985 based on new data and better calculation techniques. In addition, Order 5 does not incorporate standards for the calculation of volume from orifice meters, the calculation of supercompressibility used in flow-rate calculations, or the collection and analysis of gas samples. Further, Order 5 does not state overall performance goals or include a process to analyze and apply new technology on a national basis. Lastly, Order 5 does not cover EGM systems that now make up approximately 90 percent of all gas meters in the field. These deficiencies are what led the Subcommittee, the OIG, and the GAO to conclude that the BLM's gas measurement regulations are outdated and in need of an update. Management of onshore Federal oil and gas resources is on the GAO's High Risk List, in large part due to its outdated measurement regulations. The BLM did not make any changes to the rule as a result of these comments. Further evidence regarding the inadequacy of Order 5 can be found in the fact that the BLM has had to issue NTLs supplementing its requirements.
One commenter stated that no third-party proof exists to demonstrate that the proposed changes would improve measurement. The BLM did not make any changes to the rule based on this comment. While the rulemaking process does not require third-party confirmation that the proposed changes would improve measurement, the BLM is confident that the rule will result in substantial improvements to both the accuracy and verifiability of measurement.
For example, existing Order 5 has only one requirement relating to the determination of heating value—that it be determined once per year. Order 5 has no requirements as to where the sample is taken, how it is taken, how it is analyzed, or how it is reported. Nor does Order 5 incorporate any industry standards relating to sampling and analysis, even though those have been developed. As illustrated in the Background Section of this preamble, inaccurate heating value determination has the same impact on royalty calculations as errors in volume determination. As explained in the preamble to the proposed rule, the BLM has shown that Order 5's existing requirement to sample once per year is inadequate. BLM's Gas Variability Study demonstrated significant variability in heating value for individual facilities that would not be captured by once per year sampling and that may be correlated to the lack of any BLM standards on how it is determined. This final rule, on the other hand, incorporates five consensus industry standards relating to the sampling and analysis of heating values and sets standards on heating value uncertainty, sample probes, sample cylinders, GCs, and reporting.
One commenter stated that the new rule will not aid in consistency. The BLM disagrees with this comment. Order 5 included a variance process to address new technology and to allow the BLM to approve alternate methodology that accomplished the goals of the Order. Unfortunately, Order 5 did not state what those goals were and left the review and approval process at the field office level. This resulted in inconsistent review of variances from office to office, an issue which was raised by industry, the GAO, and the OIG. This final rule establishes a new national process for the review and approval of new technology and/or alternate measurement methodologies through a centralized team, the PMT. Once approved, the BLM will post the device or process on the BLM website along with any conditions for its use developed by the PMT. Operators can rely on those approvals without seeking a subsequent authorization. This centralized review will dramatically improve consistency over the current process. The BLM did not make any changes to the rule as a result of this comment.
One commenter suggested a variance process for small operators who cannot comply with API standards. Consistent with the comment, the final rule includes a standard process for any operator to obtain BLM approval for an alternate methodology, as long as that methodology meets or exceeds the performance goals set out in § 3175.31. Recognizing the economics of lower-volume properties, the final rule adopts changes relative to the proposed rule that will reduce the requirements on those properties, which will reduce compliance costs for operators, many of which could be smaller operators. Those specific changes are discussed later in the preamble, in the Section-by-Section analysis. The BLM did not make any changes to the rule as a result of this comment.
The BLM received numerous comments objecting to the provision in the proposed rule to require transporters to keep measurement records. It should be noted at the outset that this change was the result of statutory requirements imposed by Congress under FOGRMA and the changes in the proposed rule are consistent with that statutory direction. Commenters objected to the requirement that both the operator and the transporter keep duplicate records and noted that transporters will have to modify their computer systems to comply with BLM requirements, including the requirement to store the FMP number. Based on other comments (see the discussion of §§ 3175.101(b)(4) and 3175.104(a)(1) in section II.C. of this preamble), the BLM has decided that it will not require operators, purchasers, or transporters to include the FMP number as part of the flow-computer display or include it on audit trail records. Parties may continue to use unique meter station identifiers. The FMP number is now only required on the Oil and Gas Operations Reports (OGORs) that the operator submits to ONRR. The BLM realizes that this requirement could result in duplicate sets of records in some cases. However, when the BLM audits an FMP that is owned by a transporter or purchaser rather than the operator, the operator may not have access to the complete audit trail. In these cases, the records held by the transporter would not be duplicates.
A few commenters asked for clarification of which records the transporter or purchaser will be responsible for maintaining. The transporter or purchaser is responsible for maintaining all records required by this subpart for FMPs that are owned by the transporter or purchaser for the timeframes listed in 43 CFR 3170.7. The BLM did not make any changes to the rule based on these comments.
One commenter stated that there is no indication that the records currently maintained by the transporter or purchaser are inadequate. If the records owned by the transporter or purchaser are adequate, as implied by the comment, then this rule should not have any additional impact on the transporter or purchaser. The BLM did not make any changes to the rule based on this comment.
One commenter stated that transporters and purchasers should not be subject to immediate assessments. The BLM agrees with this comment and has removed purchasers and transporters from the immediate assessment section in § 3175.150 (see discussion under that section).
The BLM received many comments stating that the proposed rule would deter development on Federal and Indian oil and gas leases and result in lower royalty due to operators shutting in their production rather than complying. The commenters stated that the cost, complexity, delays, and new reporting requirements are primary reasons. One commenter stated that the rule would be especially burdensome for small operators. In response to comments on specific parts of the proposed rule, the BLM made numerous changes in the final rule that should provide significant economic relief to operators on Federal and Indian leases. These changes include:
• The threshold between very-low- and low-volume is raised from 15 Mcf/day to 35 Mcf/day, and the threshold between low- and high-volume is raised from 100 Mcf/day to 200 Mcf/day;
• Existing meter tubes at low- and high-volume FMPs are grandfathered
• Flow-computer software at very-low-, low-, and high-volume FMPs are grandfathered and flow computers no longer have to display the FMP number;
• Accounting systems no longer have to include the FMP number;
• Composite sampling systems or on-line GCs are no longer required on high-volume FMPs, and they were never required for very-low- and low-volume FMPs;
• Gauge lines with a
• Implementation of the requirement for PMT approval of existing equipment and gas analysis input into the Gas Analysis Reporting and Verification System (GARVS) is delayed for 2 years after the effective date of the final rule;
• Long-term stability tests for transducers is longer required;
• The PMT has the ability to approve existing transducers using existing data from manufacturers;
• Multiple analyses for laboratory GCs are no longer required; and
• C9+ analysis is only required periodically for high- and very-high-volume FMPs and only if the mole percentage for C6+ exceeds 0.5 percent.
Several commenters stated that the new rules could reduce royalty by increasing the costs of metering, which, in turn, operators could claim as a transportation deduction. The BLM consulted ONRR on this comment and ONRR confirmed that there are no circumstances in which an operator could claim the costs of metering as a transportation deduction even if the meter was owned by a transporter or purchaser. The BLM did not make any changes to the rule as a result of this comment.
The BLM received a number of comments stating that the Economic and Threshold Analysis did not adequately account for all costs associated with the proposed rule. Several commenters said that the estimated cost of the rule should include the costs to the government of reduced royalty payments, as well as lost tax revenues that will result from reduced State and local employment. However, the premise of this argument is based upon the commenter's assumption that operators would have had to shut in wells as a result of the rule. The numerous revisions to reduce the cost of the final rule described above will significantly reduce costs from the requirements of the proposed rule. The BLM does not believe that a significant number of shut-ins will occur as a result of this rule. Although the BLM made significant changes to the rule based on concerns over cost, the BLM did not make any changes based on these specific comments.
Several commenters stated that the BLM should have done a cost-benefit analysis of the rule in which the estimated costs are compared against the resultant improvement in expected royalty revenue. There are several flaws in this argument. Notably, commenters are presuming that the only purpose of the rule is to eliminate measurement bias, and that FMPs are currently biased to read low. Bias is mismeasurement that results in a measured quantity that is either predictably higher than or predictably lower than the actual value of the quantity. If the BLM were aware that FMPs were biased to read low, then the commenter's assertions would be correct. In other words, if the sole intent of the rule were to eliminate bias to the low side and the BLM were able to quantify that bias, then the BLM could perform a cost-benefit analysis comparing the cost of the rule to the
Whether the rule will result in an increase in royalty, a decrease in royalty, or no change in royalty was not a consideration in the rule-making process. The rule is intended to obtain accurate measurement of the gas produced from Federal and Indian leases. The BLM did not make any changes to the rule based on these comments.
Two commenters recommended that the BLM withdraw the rule because it is incomplete and potentially devastating to the industry. The commenters did not elaborate as to why the rule is incomplete or why it would potentially be devastating to the industry. The BLM believes the proposed rule was complete and met all legal requirements of a proposed rule under the APA. The BLM also made significant changes to the proposed rule aimed at reducing costs, especially at low-volume facilities. These specific changes are discussed elsewhere. The BLM did not make any changes to the rule as a result of these comments.
One commenter objected to the tone of the rule stating that the rule implies that operators are intentionally trying to underpay royalty. The commenter did not provide any specific examples. The BLM does not agree with this comment and did not intend to make such an implication. The BLM recognizes that measurement error goes in both directions and, as result, it might result in either over- or under-reporting of production. The BLM did not make any changes to the proposed rule as a result of this comment.
The BLM received several comments stating that no data were presented to support the assertion that the rules will not affect the energy supply, as required by Executive Order (E.O.) 13211. The commenters stated that the rule will result in delays in distribution due to the backlog of new equipment that the BLM is requiring for existing FMPs. One commenter stated that the BLM needs to study the effects of the rule on transportation.
E.O. 13211 requires an agency to prepare a “Statement of Energy Effects” when it undertakes a “significant energy action.” There are two ways in which an agency's action can constitute a significant energy action: (1) The action is a “significant regulatory action” under E.O. 12866 if it is “likely to have a significant adverse impact on the supply, distribution, or use of energy”; or, (2) The action is designated as a significant energy action by the Office of Information and Regulatory Affairs (OIRA). This rule is not a significant energy action because it will not have a significant adverse impact on the supply, distribution, or use of energy, and it has not been designated as a significant energy action by OIRA. The BLM's conclusion that this rule is not a significant energy action is based on its analysis of the economic impact of the proposed rule.
Additionally, in response to comments received, the BLM made numerous changes to the proposed rule that will reduce compliance costs and the potential for any approval backlogs for new equipment that may have resulted from the proposed rule. These changes include:
• The grandfathering of 98.7 percent of all meter tubes in place at FMPs as of January 17, 2017 from having to meet the construction and installation standards of API 14.3.2 (2000);
• The grandfathering of 88.7 percent of all flow computers in place at FMPs as of January 17, 2017 from having to use the latest flow-rate calculation methods of API 14.3.3 (2013);
• The grandfathering of 100 percent of all transducers in place as of January 17, 2017, from the testing protocol required in § 3175.43, if the manufacturers submit existing test data to the PMT and the BLM approves the transducer based on that existing data; and
• Elimination of the requirement for flow computers to display the FMP number, which may have required some older model flow computers to be replaced.
This section describes the various regulatory changes made by this final rule. First, it describes the content of the specific sections of subpart 3175, explains any changes between the proposed and final rules, and responds to section-specific comments on the proposed rule received by the BLM during the comment period. Following that discussion, it describes changes and revisions being made to 43 CFR 3162.7-3, 3163.1, and 3164.1. The proposed rule to replace Order 5 also proposed changes to 43 CFR 3163.2 and 3165.3. The proposed revisions are addressed in the final rule to replace Order 3 (being released concurrently with this rule) and are not discussed further here.
Section 3175.10 includes numerous new definitions unique to this rule because much of the terminology used in the rule is technical in nature and may not be readily understood by all readers or may have a specific meaning in the context of this rule. As explained in the preamble to the proposed rule, the BLM also added other definitions because their meanings, as used in the rule, may be different from what is commonly understood, or the definition includes a specific regulatory requirement.
Definitions of terms commonly used in gas measurement or which are already defined in 43 CFR parts 3000, 3100, 3160, or subpart 3170 are not discussed in this preamble.
The rule defines 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 found on Federal and Indian leases. 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
One commenter recommended that the BLM include linear meters in the definition of “primary device.” The definition of primary device in the proposed rule was specific to differential-type meters. The BLM did not make any changes to the rule based on this comment. The rule allows the PMT to recommend approval of linear devices by make, model, and size. In its recommendation, the PMT can include requirements for a linear meter along with a definition of a linear-meter primary device, if needed. However, the performance standards in this rule are based around differential-type meters. As a result, there are many requirements pertaining specifically to the primary device of differential-type meters. A definition of “primary device” is in § 3175.10 of the rule to avoid having to describe what a primary device is every time it is mentioned in the rule. Adding linear meters to the definition would make the requirements in the rule confusing and cumbersome. For example, § 3175.47 requires operators or manufacturers to test primary devices other than orifice plates under API 22.2, which is specific to differential types of primary devices. If linear-meter primary devices were added to the definition, then the requirement in § 3175.47 would have to specify that it applies only to differential types of primary devices, largely defeating the purpose of having the definition, especially considering there are no current or proposed API testing protocols for linear meters.
The “secondary device” measures the differential pressure along with static pressure and temperature. The “secondary device” consists of the differential-pressure, static-pressure, or temperature transducers in an EGM system or a mechanical recorder (including the differential pressure, static pressure, and temperature elements, and the clock, pens, pen linkages, and circular chart). The BLM did not receive any comments on this definition.
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 BLM did not receive any comments on this definition.
The rule adds 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 § 3175.31(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 needs to be able to identify the make, model, and upper range limit (URL) of each transducer because the uncertainty of the transducer varies among 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. The BLM did not receive any comments on this definition.
Other EGM systems are assembled using a variety of transducers and flow computers and cannot be identified by a single make and model number. Instead, the BLM would identify each transducer by its own make and model. These are defined as “component” EGM systems. Component systems include EGM systems that started out as self-contained systems, but one or more of whose transducers have been changed to a different make and model. The BLM did not receive any comments on this definition.
The rule adds a definition for “hydrocarbon dew point” (HCDP). The HCDP is the temperature at which liquids begin to form within a gas mixture. Because it is not common to determine HCDPs for wellhead metering applications on Federal and Indian leases, the BLM established 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 HCDP. 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 HCDP at the primary device because the liquid and gas phases would again be in equilibrium. The AO may approve a different HCDP if data from an equation-of-state, chilled mirror, or other approved method are submitted. The BLM did not receive any comments on the definition of HCDP.
The rule adopts the definitions of “lower calibrated limit” and “upper calibrated limit” from the API Manual of Petroleum Measurement Standards (MPMS) 21.1. The upper and lower calibrated limits are the maximum and minimum values, respectively, for which the transducer was calibrated using certified test equipment. These terms replace the term “span” as used in the statewide NTLs for EFCs. The BLM did not receive any comments on these definitions.
The term “redundancy verification” is added to address verifications done by comparing the readings from two sets of transducers installed on the same primary device. The BLM did not receive any comments on this definition.
The proposed rule defined four terms to describe categories of FMPs: “Marginal volume,” “low volume,” “high volume,” and “very high volume.” The BLM proposed these categories for purposes of delineating applicable requirements based on the average flow rate measured by an FMP. The proposed categories were as follows: A marginal-volume FMP would have had an average flow rate of 15 Mcf/day or less; a low-volume FMP would have had an average flow rate greater than 15 Mcf/day, but less than or equal to 100 Mcf/day; a high-volume FMP would have had an average flow rate greater than 100 Mcf/day, but less than or equal to 1,000 Mcf/day; and, a very-high-volume FMP would have had an average flow rate greater than 1,000 Mcf/day. Based on comments received on the proposed rule, changes in market conditions, and additional internal analysis, the BLM has modified two of the three thresholds separating the categories in the final rule. The revised definitions in the final rule are as follows: A very-low-volume FMP (marginal-volume FMP in the proposed rule) has an average flow rate of 35 Mcf/
The proposed rule defined “marginal-volume FMP” as an FMP that measures a default volume of 15 Mcf/day or less. The BLM replaced the term “marginal-volume FMP” with “very-low-volume FMP” in the final rule to avoid confusion with other rules that use the term “marginal well.” As with the proposed rule, “very-low-volume” FMPs are exempt from many of the requirements in this rule.
The proposed rule's 15 Mcf/day threshold for a very-low-volume FMP 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 applicable to facilities 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
• A 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 if the lease, unit PA, or CA were shut in. 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. At that time, the U.S. Energy Information Administration projected 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. Assuming a $4/MMBtu gas price from Figure 1, a 15 percent ROR could be achieved for meters with initial flow rates of at least 15 Mcf/day, for an initial investment in metering equipment up to about $8,000. For wells with initial flow rates less than 15 Mcf/day, our analysis indicated that it may not have been profitable to invest in the necessary equipment to meet the proposed requirements for a low-volume FMP. Instead, it would have been more economic for an operator to shut in the FMP. Therefore, 15 Mcf/day was proposed as the default threshold for a very-low-volume FMP, with the AO permitted to approve a higher threshold where circumstances warrant.
The proposed rule would have defined “low-volume FMP” as an FMP flowing at more than 15 Mcf/day, up to 100 Mcf/day. Low-volume FMPs must meet minimum requirements to ensure that measurements are not biased, but they are exempt from the rule's minimum uncertainty requirements. It was anticipated that this classification in the proposed rule would have encompassed 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 at the time the proposed rule was written because costs were 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 the various statewide NTLs covering EFCs.
The proposed rule would have defined “high-volume FMP” as an FMP flowing more than 100 Mcf/day, but not more than 1,000 Mcf/day. Requirements for high-volume FMPs will ensure that there is no statistically significant bias in the measurement and it will achieve an overall volume measurement of uncertainty of ±3 percent or less and an annual average heating-value uncertainty of ±2 percent. The BLM anticipates that the higher flow rates would make retrofitting to achieve minimum uncertainty levels more
Finally, the proposed rule would have defined “very-high-volume FMP” as an FMP flowing more than 1,000 Mcf/day. The BLM requires that very-high-volume FMPs achieve lower uncertainty than is required for high-volume FMPs (±2 percent, compared to ±3 percent for volume; and ±1 percent, compared to ±2 percent for average annual heating value) and would have increased the frequency of primary device inspections and secondary device verifications. Stricter measurement accuracy requirements for very-high-volume facilities are appropriate due to the risk that mismeasurement will have 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.
Many commenters questioned how the BLM determined the flow-rate ranges for the four categories of FMPs in the proposed rule (very-low-, low-, high-, and very-high-volume). Several of the commenters stated that the BLM used economics to determine the very-low-/low-volume threshold, but arbitrarily assigned the other thresholds. The BLM does not agree that the low-/high-volume and high-/very-high-volume thresholds in the proposed rule were “arbitrary.” The BLM did not have the same level of detail in its cost data to do the same level of detailed analysis on the thresholds for the higher-volume categories. The BLM nevertheless did consider existing thresholds in Order 5 and practical considerations for achieving lower uncertainties in setting those thresholds. Ultimately, though, the BLM determined that the cost estimates it had prepared were reasonable and formed a proper basis to set the thresholds used in the final rule. As explained elsewhere in this preamble, the thresholds were set at the point at which the cost of the additional requirements with respect to measurement equals the reduction in royalty risk achieved.
One commenter recommended that the BLM should determine all three thresholds on a cost-benefit basis, setting the thresholds at the level at which the cost of required meter improvements is offset by reduced uncertainty as a result of making the improvement. The commenter also recommended that the BLM should use a 1.5-year “payout” methodology instead of the rate-of-return methodology that the BLM used in the proposed rule. The BLM partially agrees with these comments and developed a Threshold Analysis to support the thresholds used in the final rule (see the discussion on thresholds below and the BLM Threshold Analysis). The requirements in the rule for low-volume FMPs represent the most lenient requirements the BLM can reasonably accept while also meeting its fiduciary obligations to ensure royalty-quality measurement. The only rationale for exempting very-low-volume FMPs from those requirements is to reduce costs to the point that operators truly on the edge of profitability will not shut in production as a result of the rule. The threshold for very-low-volume FMPs, therefore, is the flow rate below which a prudent operator can no longer afford to comply with the requirements for a low-volume FMP and would shut in production if the rule did not include the additional, very-low-volume category. Put differently, the BLM established the very-low-/low-volume threshold based on the minimum flow rate at which a prudent operator could afford to meet the standards for a low-volume FMP.
For the final rule, the BLM accepted the 1.5-year payout methodology suggested by the commenter in lieu of the rate-of-return methodology used in the proposed rule. Also, instead of using an assumed $8,000 investment required to meet the measurement standards for a low-volume FMP, the BLM re-examined the cost differences between the very-low-volume requirements and the low-volume requirements in the final rule. This cost difference was considered the “investment” in the payout methodology. The BLM does not agree that the reduction in uncertainty should be the basis for the “income” side of the payout method. While this may be useful for comparing uncertainty improvement as a function of cost, the BLM does not believe the overall premise is correct. First, the determination of uncertainty reduction between the very-low-volume and low-volume categories is highly speculative. Second, and perhaps more importantly, uncertainty indicates the risk of mismeasurement and does not denote whether that mismeasurement is high or low. The use of uncertainty to determine payout may be misleading to the reader who could incorrectly assume that uncertainty equates to under-measurement in all cases.
Instead of using the reduction in uncertainty as the “income,” the BLM used the total income from the well(s) flowing through the FMP. The premise of the payout method for the very-low/low-volume threshold was to simulate the decision-making process of a prudent operator, faced with a choice of either investing the money required to meet the standards of a low-volume FMP or of shutting-in the well(s). In this scenario, the prudent operator would consider the income provided by the continuation of production if they were able to meet the requirements of a low-volume FMP. All of this income would be lost if the well(s) were shut in.
The commenter recommended using the payout approach to set all of the thresholds. The BLM does not believe the payout approach is applicable to the low-/high-volume and high-/very-high-volume thresholds. Instead of using a payout method recommended by the commenter, the BLM used a royalty-risk methodology to determine the low-/high- and high-/very-high-volume thresholds. The BLM determined that it is fair and reasonable to set these thresholds for the higher-volume facilities at the point at which the cost of the additional requirements equals the reduction in royalty risk due to the additional requirements. This approach is appropriate for high-volume facilities because the costs of installing additional measurement equipment at these facilities do not impact their economic viability, since they are producing at a high-enough rate that they generate significant revenues, well in excess of operating costs. For example, a required $30,000 upgrade for a meter flowing at 1,000 Mcf/day would have a payout of 7 days, after operating costs, royalties, and taxes, well below the payout range of 6 to 18 months given by the commenter. A prudent operator would not shut in production in this scenario.
One commenter suggested that the BLM should incorporate the percent Federal or Indian ownership in the determination of flow-rate threshold categories. The BLM did not make any changes to the rule based on this comment because generally the accuracy of the FMP should be based on the flow rate it is measuring regardless of ownership. Implementing this suggestion would also be complex and cumbersome for both operators and the BLM. For example, a BLM inspector would have to multiply the average flow rate of the FMP by the Federal or Indian mineral interest in the agreement in order to determine which requirements the FMPs need to meet.
One commenter raised a concern about an FMP that is operating just over one of the volume thresholds because the operator would still have to spend the money to comply with the threshold, but the FMP would only be making slightly more money than if it
The BLM received many comments suggesting alternative thresholds for the four categories of FMPs. The following table compares the Mcf/day thresholds from the proposed rule with the alternative suggestions received in the comments:
Comments also included recommendations for removing the very-low-volume category in its entirety and extending the requirements for low-volume FMPs from zero Mcf/day to 100 Mcf/day. Another commenter suggested removing the very-high-volume category and extending the requirements for high-volume FMPs with no upper limit of flow rate. Based on all of the above comments, the BLM re-evaluated the economics of each category and developed new Mcf/day thresholds:
The study used to determine these thresholds is available on the
One commenter stated that volume thresholds do not account for the fact that the economics of natural gas have changed with the Henry Hub wholesale price decreasing from $4 to $2/MMBtu, and therefore that the BLM's reliance on prices greater than $2/MMBtu is not reasonable. The BLM does not agree with this comment. First, natural gas prices are seasonal and $2/MMBtu gas is not permanent—for instance, the Henry Hub price can and does regularly exceed this level in response to cold weather under current market conditions. Second, it is unlikely that natural gas prices will remain at this $2/MMBtu level through the 3-year timeframe that the Threshold Analysis uses to determine the minimum payout volume for the very-low-/low-volume threshold or the 10-year timeframe that it uses to determine the low-/high-volume and high-/very-high-volume thresholds. The Energy Information Administration's (EIA's) Annual Energy Outlook for 2016
In the proposed rule, the BLM would have determined the FMP category by averaging the flow rate of that FMP over the previous 12 months or the life of the FMP, whichever was shorter. The BLM received several comments expressing concern about the proposed 12-month averaging period for FMPs that measure the flow rate from wells having high production-decline rates. Several of the commenters stated that as a result of the proposed 12-month averaging period, the operator would have to invest a lot of money to achieve the requirements for a high or very-high-volume FMP, only to have the volume drop to low- or even very-low-volume in a short period of time. One commenter recommended that the BLM should not include the first month of production in the average flow rate calculation.
The BLM agrees with the concept presented by the commenters and developed a definition for “averaging period” that applies to the category definitions in this rule and the uncertainty thresholds in the oil measurement rule (43 CFR subpart 3174). The definition, which appears in the subpart 3170 definitions section, retains a 12-month averaging period, but excludes any production from newly drilled wells prior to the second full month of production from the average calculation. In other words, if an FMP is installed to measure the production from a newly drilled well, and the well is put into production on May 10, the production reported in May and June would not be used in the calculation of average flow rate when determining the FMP's flow-rate category. In this example, May is not a full month of production; therefore, June is the first full month of production and July is the second full month of production. The 12-month averaging period starts with the July production figures.
The BLM received numerous comments asking for clarification on how an operator would determine the flow-rate category of an FMP. Some of the comments expressed confusion over the time period that the BLM would use to determine the average flow rate; whether this would be a 12-month average, a 6-month average, a daily rate, or based on previous-day flow rate available on the display of an EGM system. One commenter requested clarification on how an operator would determine the category if there were less than 12 months of data. The category definitions in the proposed rule and the new definition of “averaging period” in the final rule both specify that the average is taken over 12 months or the life of the FMP, whichever is shorter. The BLM did not make any further changes to the rule based on these comments. The BLM believes that the requirement for how the BLM will
The proposed rule defined “bias” as a shift in the mean value of a set of measurements away from the true value of what is being measured. In the final rule the BLM changed the word “shift” to “systematic shift” to better match other statistical definitions. The word “systematic” was also added to stress that bias is present if a shift in mean value occurs even after averaging repeated measurements of the value across the entire measurement system.
One commenter stated that the term “bias” as used in the proposed rule implies that the operator is intentionally causing a meter to read high or low. The BLM did not make any changes to the rule based on this comment because neither the definition nor the use of the word “bias” in the rule implies that any bias is intentional. “Bias” is a term of art in the measurement context and does not refer to underlying intent.
The proposed rule did not define the term “uncertainty” and used both the terms “certainty” and “uncertainty” interchangeably. One commenter stated that there is no definition of “certainty” or “uncertainty” in proposed § 3175.10. Based on this comment the BLM used only the term “uncertainty” in the final rule, and included a definition for that term. The BLM made this change because “uncertainty,” unlike the term “certainty,” is a term that is commonly used and understood within the oil and gas measurement context. “Uncertainty” is defined to mean the range of error that could occur between a measured value and the true value being measured, calculated at a 95 percent confidence level. The BLM selected a 95 percent confidence level because it is commonly used in oil and gas measurement. A 95 percent confidence level means that the calculated uncertainty indicates the maximum amount of error that is expected to occur between the measured value and the true value being measured 95 percent of the time. There is a 5 percent chance that the risk of mismeasurement is greater than the calculated uncertainty.
The proposed rule defined “significant digit” as any digit of a number that is known with certainty. The definition was included in the proposed rule to support § 3175.104(a)(2), which required certain data in the QTR to be reported to five significant digits. Based on comments received, the requirement in the final rule was changed from five significant digits to a specified number of decimal places. Therefore, the definition of “significant digit” is no longer necessary and is deleted in the final rule.
Section 3175.10 of the proposed rule included definitions for “statistically significant” and “threshold of significance.” Because the final oil measurement rule (43 CFR subpart 3174) also uses these terms, the BLM moved the definitions to subpart 3170. The BLM did not make any changes to the definitions.
The BLM added a definition of “heating value variability” to the final rule in response to numerous comments expressing confusion over what this term means and how the BLM would determine it. These comments are discussed under § 3175.31(b).
The BLM added a definition for “AGA Report No. (followed by a number)” to the final rule to be consistent with the definitions for GPA and API that pertain to standards incorporated by reference (see § 3175.30). The proposed rule did not incorporate any AGA (American Gas Association) standards; however, the final rule incorporates two AGA standards (AGA Report No. 3 (1985) and AGA Report No. 8 (1992)). As explained elsewhere in the preamble, the BLM incorporated standards from AGA Report No. 3 because the final rule includes grandfathering provisions (see § 3175.61) relating to meter tube construction that allow operators of grandfathered meters to meet the older standards in lieu of the latest API standards. AGA Report No. 8 was adopted because the BLM determined it was the more appropriate reference for the calculation of supercompressibility. In the proposed rule, the incorporation by reference was for API 14.2; both standards are identical in content.
There are numerous other terms that were defined in both the proposed rule and the final rule. These include, “as-found,” “as-left,” “atmospheric pressure,” “Beta ratio,” “British thermal unit,” “configuration log,” “discharge coefficient,” “effective date of a spot or composite sample,” “electronic gas measurement,” “element range,” “event log,” “heating value,” “integration,” “live input variable,” “mean,” “mole percent,” “normal flowing point,” “quantity transaction record,” “Reynolds number,” “senior fitting,” “standard cubic foot (scf),” “standard deviation,” “transducer,” “turndown,” “type test,” “upper range limit (URL),” and “verification.” The BLM did not receive any comments on these definitions and did not change any of these definitions from the proposed rule. One commenter stated that there is no definition of “AO,” “FMP,” “PA,” “PMT,” or “uncertainty” in proposed § 3175.10. The terms “AO,” “FMP,” “PA,” and “PMT” are defined under subpart 3170 because they apply to all the rules published under that part including subparts 3173, 3174, and 3175. Therefore, those definitions were not added to subpart 3175 in the final rule
Proposed § 3175.20 would have required 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). The BLM received a comment suggesting the requirements of § 3175 should only apply to those units or agreements above a set percentage of Federal interest. The BLM disagrees for the reasons discussed under the definition of the flow-rate categories and did not make any changes to this section based on this comment.
The BLM received another comment objecting to the proposed requirement to measure all gas on leases, pointing out that many times leases are part of units or CAs, and may have combined measurement points for multiple leases within these agreements. The BLM believes the commenter has misinterpreted the requirement. The final rule requires all gas removed or sold from Federal and Indian leases, unit PAs, or CAs to comply with 43 CFR subpart 3175. If a lease is part of a unit PA or CA, the measurement requirements in subpart 3175 apply only to the FMP where gas is removed or sold from the unit PA or CA. This is because the BLM considers unit PAs and CAs to be individual cases—comparable to large “leases”—with regards to measurement. As a result, operators do not have to measure the gas produced from individual leases within a CA or unit PA. Internal measurement points, such as those flagged by the commenter, that combine production from individual leases or wells within a CA or unit PA are not subject to this subpart, assuming they are not used to measure gas that is removed or sold
The BLM did make a change to this section based on an internal review of the wording in the proposed rule. The proposed rule stated that “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.” The BLM realized that this language does not account for situations where the BLM has granted commingling and allocation approval (CAA) under 43 CFR part 3173. Where the BLM has granted a CAA, the allocation meters are not considered FMPs and, therefore, do not have to comply with the requirements of this rule (see the definition of FMP under subpart 3173). As a result, gas will be removed or sold from the lease, unit PA, or CA without being measured in accordance with the standards in this rule, which is contrary to the language of the proposed rule. To address this, the BLM changed the wording of this sentence to “Measurement of all gas at an FMP must comply with the standards of this subpart . . . . ” It should be noted that if a gas allocation meter were to become an FMP in the future, it would have to comply with the applicable requirements of this rule.
This section previously appeared as § 3175.31 in the proposed rule, but based on edits made to the final rule, this section and final § 3175.30 have swapped places.
This final rule incorporates 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 American Petroleum Institute (API), the American Gas Association (AGA), the Gas Processors Association (GPA), and the Pipeline Research Council International (PRCI) with input from the oil and gas industry and Federal agencies with oil and gas operational oversight responsibilities.
The BLM has reviewed these standards and determined that they will achieve the intent of §§ 3175.31 through 3175.125 of this rule. The legal effect of incorporation by reference is that the incorporated standards become regulatory requirements. With the approval of the Director of the Federal Register, this rule generally incorporates the current versions of the standards listed below. However, the BLM is also incorporating older versions of several standards due to the “grandfathering” of some existing equipment in the final rule
Some of the standards referenced in this section have been incorporated in their entirety. For other standards, the BLM incorporates only those sections that are relevant to the rule, meet the intent of § 3175.31 of the rule, or do not need further clarification.
The incorporation of industry standards follows the requirements found in 1 CFR part 51. The industry standards in this final rule are eligible for incorporation under 1 CFR 51.7 because, among other things, they will substantially reduce the volume of material published in the
All of the API, AGA, GPA, and PRCI materials that the BLM is incorporating 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 also available for inspection and purchase 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, GPA, APA, and PRCI standards that the BLM is incorporating by reference into this rule:
• API Manual of Petroleum Measurement Standards (MPMS) Chapter 14—Natural Gas Fluids Measurement, Section 1, Collecting and Handling of Natural Gas Samples for Custody Transfer; Seventh Edition, May, 2016 (“API 14.1”). This standard provides comprehensive guidelines for properly collecting, conditioning, and handling representative samples of natural gas that are at or above their hydrocarbon dew point.
• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata, July 2013 (“API 14.3.1”). This standard provides engineering equations and uncertainty estimations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.
• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 2, Specification and Installation Requirements; Fifth Edition, March 2016 (“API 14.3.2”). This standard provides construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.
• API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, November 2013 (“API 14.3.3”). This standard is an application guide for the calculation of natural gas flow through a flange-tapped, concentric orifice meter.
• API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas Applications, Third Edition, August 1992 (“API 14.3.3 (1992)”). This standard is an application guide for the calculation of natural gas flow through a flange-tapped, concentric orifice meter.
• 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; Reaffirmed February 2014 (“API 14.5”). This standard presents procedures for calculating, at base conditions from composition, the
• API MPMS Chapter 21, Section 1, Flow Measurement Using Electronic Metering Systems—Electronic Gas Measurement; Second Edition, February 2013 (“API 21.1”). This standard describes the minimum specifications for electronic gas measurement systems used in the measurement and recording of flow parameters of gaseous phase hydrocarbon and other related fluids for custody transfer applications utilizing industry recognized primary measurement devices.
• API MPMS Chapter 22—Testing Protocol, Section 2, Differential Pressure Flow Measurement Devices; First Edition, August 2005; Reaffirmed August 2012 (“API 22.2”). This standard is a testing protocol for any flow meter operating on the principle of a local change in flow velocity, caused by the meter geometry, giving a corresponding change of pressure between two reference locations.
• GPA Standard 2166-05, Obtaining Natural Gas Samples for Analysis by Gas Chromatography; Adopted as a Tentative Standard, 1966; Revised and Adopted as a Standard, 1968; Revised 1986, 2005 (“GPA 2166-05”). This standard recommends procedures for obtaining samples from flowing natural gas streams that represent the compositions of the vapor phase portion of the system being analyzed.
• GPA Standard 2261-13, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography; Adopted as a Tentative Standard, 1961; Revised and Adopted as a Standard, 1964; Revised 1972, 1986, 1989, 1990, 1995, 1999, 2000 and 2013 (“GPA 2261-13”). This standard establishes a method to determine the chemical composition of natural gas and similar gaseous mixtures within set ranges using a gas chromatograph (GC).
• GPA Standard 2198-03, Selection, Preparation, Validation, Care and Storage of Natural Gas and Natural Gas Liquids Reference Standard Blends; Adopted 1998; Revised 2003. (“GPA 2198-03”). This standard establishes procedures for selecting the proper natural gas and natural gas liquids reference standards, preparing the standards for use, verifying the accuracy of composition as reported by the manufacturer, and the proper care and storage of those standards to ensure their integrity as long as they are in use.
• GPA Standard 2286-14, Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography; Adopted as a Standard 1995; Revised 2014 (“GPA 2286-14”). This method is intended for the compositional analysis of natural gas and similar gaseous mixtures where precise physical property data of the hexanes and heavier fractions are required. The procedure is applicable for mixtures which may contain components of nitrogen, carbon dioxide, and/or hydrocarbon compounds C1-C14.
• AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Second Edition, September 1985 (“AGA Report No. 3 (1985)”). This standard provides construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters.
• AGA Report No. 8, Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases; Second Edition, November 1992 (“AGA Report No. 8”). This standard presents detailed information for precise computations of compressibility factors and densities of natural gas and other hydrocarbon gases, calculation uncertainty estimations, and FORTRAN computer program listings.
• PRCI NX 19, Manual for the Determination of Supercompressibility Factors for Natural Gas; December 1962 (“PRCI NX 19”). This standard presents detailed information for computations of compressibility factors and densities of natural gas and other hydrocarbon gases.
Several commenters suggested that the BLM should adopt API and GPA standards in their entirety rather than incorporating only parts of them. Some of the commenters stated that the BLM should incorporate all of API MPMS Chapter 1 (Terms and Definitions), all of Chapter 14 (Natural Gas Fluids Measurement), all of Chapter 21 (Flow Measurement Using Electronic Metering Systems), and all of Chapter 22 (Testing Protocols).
The BLM did not make any changes as a result of these comments. The rule incorporates five industry standards in whole and seven industry standards in part. API and GPA standards are written for industry to use as guidelines in designing and operating measurement facilities, generally for custody-transfer applications, were not designed for the regulatory environment, and present potential enforcement challenges and limitations. As such, these standards are often difficult to adopt without modification as regulations. The BLM can only enforce requirements that are objective, clearly defined, and relevant to the BLM's goal of ensuring accurate and verifiable measurement. Many of the API and GPA standards referenced by the commenters do not meet this threshold. For example, API 21.1, Section 6, sets standards for data availability. API 21.1, Subsection 6.2, requires, among other things, that onsite data include at least 7 days of hourly QTRs. While this may be a useful requirement for industry, the BLM is not concerned in this rule with how long data are maintained onsite. The FOGRMA of 1982 (as amended by the Royalty Simplification and Fairness Act of 1996) requires all records for Federal leases to be maintained for a period of 7 years from the date they are generated. Whether they are maintained onsite or offsite is irrelevant to the BLM's goals. In addition, it would be very difficult for BLM inspectors to enforce such a provision and it would serve no purpose for them to do so.
The following table lists the API standards that the commenters suggested the BLM should adopt and our response.
Of the 22 standards in Chapters 1, 14, 21, and 22 that the commenters recommended for incorporation, the BLM is incorporating eight standards. Two of the remaining standards have not yet been published by API, four apply only to liquid measurement, and two are for informational uses only. The BLM did not incorporate the remaining six recommended standards because they are not relevant to royalty measurement, were not published in time to include in the final rule, or the BLM determined that they either had the potential to conflict with BLM requirements or did not help achieve the purposes of the rule or the underlying legal requirements.
One commenter stated that API 14.1 and GPA 2166 are clear and enforceable as written and should be incorporated in whole. The rule incorporates portions of these two standards. While there are portions of API 14.1 and GPA 2166 that are clear and enforceable as written, many parts of these standards are not. For example, API Chapter 14.1, Subsection 6.3.2.1 states: “Sample distortion due to chemical and physical adsorption can be minimized by prudent selection of sampling system materials. In general, materials and coatings that are chemically inert and of minimum porosity are the best choices.” While this statement has important educational value, it would be virtually impossible for a BLM inspector to ascertain whether a sampling system material is in accordance with the standard or to take an enforcement action against an operator for not making a “best choice.” The BLM did not make any changes to the rule based on this comment.
Several commenters suggested that the BLM should automatically incorporate the latest version of a standard rather than specifying a year and edition of the standard. The BLM did not make any changes to the rule based on these comments. To promulgate a rule, all Federal agencies must follow the APA, which establishes specific requirements for Federal agencies to follow. In general, the agency must provide notice to the
If the rule were structured to incorporate “the latest version” of a particular standard, the requirements of the rule would automatically change whenever a particular standard is updated in the future. Changing a substantive rule in this manner, without the opportunity for public input, would be inconsistent with the notice-and-comment requirements of the APA, and therefore would not be legally permissible. The BLM will, however, evaluate new standards as they are issued by API, GPA, and others, and will determine if it is appropriate to initiate a rulemaking process to update the reference in subpart 3175 to incorporate the then-current version of those standards. In the interim, an operator could request a variance to follow the more recent version of a particular standard in lieu of the one incorporated by reference in this rule. Such requests would be evaluated by the PMT as outlined in this rule.
Several commenters suggested incorporating the latest version of GPA 2261-13, instead of GPA 2261-00. The BLM agrees with this comment and has changed the incorporation by reference to refer to the latest version of this standard. See the portion of the preamble that describes § 3175.118 for further discussion of these comments.
Several commenters suggested incorporating GPA 2286-14, relating to taking extended analyses. The BLM agrees with this comment and incorporated this standard by reference because § 3175.119(b) requires operators to do extended analyses in some instances. See the portion of the preamble that discusses § 3175.117 for further discussion of these comments.
As discussed in connection with § 3175.10, the BLM did incorporate two AGA standards in the final rule: AGA Report No. 3 (1985) and AGA Report No. 8. The BLM incorporated AGA Report No. 3 because the final rule includes meter tube construction standards for certain grandfathered facilities (see § 3175.61) in lieu of the latest standards in API 14.3.2. The BLM also changed the incorporation by reference for the calculation of supercompressibility. In the proposed rule the incorporation by reference was for API 14.2; however, this was changed to AGA Report No. 8 in the final rule because the BLM determined this was a more appropriate reference. Both standards are identical in content.
Note that the performance requirements appeared under § 3175.30 in the proposed rule. In the final rule, the BLM switched the provisions in §§ 3175.30 and 3175.31 for formatting purposes.
Section 3175.31 sets overall performance standards for measuring gas produced from Federal and Indian leases, regardless of the type of technology used. The performance standards provide specific objective criteria that the BLM can use to analyze meter systems not specifically allowed under the final rule. The performance standards also form the basis of determining the individual equipment standards that apply to each flow-rate class of meter (
Section 3175.31(a) establishes limits on the maximum allowable flow-rate measurement uncertainty. Uncertainty indicates the risk of measurement error. For high-volume FMPs (flow rate greater than 200 Mcf/day, but less than or equal to 1,000 Mcf/day), the maximum allowed overall flow-rate measurement uncertainty is ±3 percent. For very-high-volume FMPs (flow rate of more than 1,000 Mcf/day), the maximum allowable flow-rate uncertainty is reduced to ±2 percent, because uncertainty in higher-volume meters presents greater royalty risks than in lower-volume meters. In addition, upgrades necessary to achieve an uncertainty of ±2 percent for very-high-volume FMPs will be more economical given these FMPs' higher overall production levels. Not only do the higher flow rates make these necessary upgrades more economical, many of the measurement uncertainty problems associated with lower-volume FMPs, such as intermittent flow, are not as prevalent with higher-volume FMPs.
The ±3 percent uncertainty requirement for high-volume FMPs is the same as what is currently required in all of the statewide NTLs for EFCs. However, the ±3 percent uncertainty requirement in the statewide NTLs applies to all FMPs measuring more than 100 Mcf/day. Section 3175.31(a), by contrast, applies only to high- (±3 percent) and very-high- (±2 percent) volume FMPs. Under the new rule, therefore, meters measuring between 100 Mcf/day and 200 Mcf/day are no longer required to meet an uncertainty standard. Consistent with the existing requirements of the statewide NTLs, meters measuring less than 100 Mcf/day are not subject to uncertainty requirements.
Section 3175.31(a)(3) specifies 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. This section 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 QTR. However, daily QTRs 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 QTR is not available to the AO, the next best source for uncertainty determinations would be the average flowing parameters from the previous day, which will be required under § 3175.101(b)(4)(i) through (iii) of this final rule (§ 3175.101(b)(4)(i) through (iv) of the proposed rule).
The BLM received numerous comments on this section. One commenter stated that the new performance requirements would cause wells to be shut in, although no support for that claim was included in the comment. The BLM conducted a detailed economic analysis to support the new flow category thresholds discussed under proposed § 3175.10, which included the costs of any upgrades necessary to meet the new uncertainty requirements (see the BLM Threshold Analysis). The flow-rate uncertainty of ±3 percent for high-volume FMPs is actually less restrictive than the current uncertainty requirement in the statewide NTLs for EFCs. The NTLs require an overall uncertainty of ±3 percent or better for all meters measuring more than 100 Mcf/day. The final rule expands that limit to 200 Mcf/day. Therefore, FMPs measuring between 100 Mcf/day and 200 Mcf/day, which would have been subject to the ±3 percent uncertainty limit under the statewide NTLs, are now exempt from any uncertainty requirement. The new uncertainty limit of ±2 percent for very-high-volume FMPs is only required for FMPs measuring more than 1,000 Mcf/day, which applies to just over 1 percent of all FMPs, according to data maintained by the BLM about current production. The BLM believes that a ±2 percent uncertainty will not be difficult to achieve on very-high-volume FMPs because the flow tends to be more stable
Several commenters expressed a concern that reduced uncertainty will not necessarily increase revenue or royalty. Uncertainty is the risk of mismeasurement, and the goal of reducing uncertainty is to reduce that risk regardless of whether the end result is greater royalty, less royalty, or no change in royalty. Reducing the risk of mismeasurement ensures that the measurement is more accurate, which is one of the primary goals of this rule. As reflected in other provisions of this rule, the BLM has developed measurement standards that impose uncertainty requirements commensurate with the royalty risk posed by a particular facility. For these reasons, no changes to the rule were made.
One commenter stated that any increase in transportation costs, such as meter upgrades, would increase transportation allowances under the ONRR valuation regulations, thereby reducing royalty. The BLM has confirmed with ONRR that there are no circumstances under which an operator can claim expenses relating to measurement as a transportation allowance. The BLM did not make any changes to the rule based on this comment.
The BLM received several comments objecting to what they said is a lack of justification for the uncertainty limits in the proposed rule. The BLM does not agree with these comments. The preamble to the proposed rule provided a detailed explanation of how the BLM developed the uncertainty limits and why they were developed. The BLM did not make any changes to the final rule based on these comments.
The BLM will enforce flow-rate measurement uncertainty using standard calculations such as those found in API 14.3.1, which are incorporated into the BLM uncertainty calculator (
The BLM received numerous comments stating that the BLM has not published the calculations used in the BLM uncertainty calculator, making it difficult to comment on the uncertainty calculation. The BLM disagrees with this comment. A user's manual and detailed description of every calculation used in the uncertainty calculator has been posted on both the BLM Web site (
The BLM received several comments stating that the BLM should have published the uncertainty calculations in the proposed rule and asked for clarification of what those calculations would be. The BLM agrees with this comment and incorporated by reference API 14.3.1, Section 12, which includes the uncertainty calculations that the BLM accepts and uses in the BLM uncertainty calculator. Section 3175.31(a)(4) was added to the final rule to reference the uncertainty calculations in API 14.3.1, Section 12.
Section 3175.31(b) establishes an uncertainty requirement for the measurement of heating value. This was included 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. Virtually all of the gas sold domestically in the United States is priced on a $/MMBtu basis. The royalty is computed by the following equation:
Thus, a 5 percent error in heating value would result in the same error in royalty as a 5 percent error in volume measurement.
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 taken would be relatively small. The opposite would be true if the previous heating values had a wide range of variability. Therefore, the uncertainty of the heating value calculated from spot sampling will be determined by performing a statistical analysis of the historical variability of heating values over the past year for high- and very-high-volume FMPs. If an operator installs a composite sampling system or an on-line GC, the BLM will consider that device as having met the heating-value uncertainty requirements of this section.
The uncertainty limits 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 § 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 the heating value. For very-high-volume FMPs, 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 rule therefore prescribes these respective levels as the allowed average annual heating-value uncertainty for high- and very-high-volume FMPs.
The BLM received numerous comments on this section stating that the new performance requirements
Several commenters stated that there is no reason the heating-value uncertainty limits should be more restrictive than the flow-rate uncertainty limits. For flow rate, an uncertainty of ±3 percent for high-volume FMPs and ±2 percent for very-high-volume FMPs is required. For heating value, an average annual uncertainty of ±2 percent uncertainty for high-volume FMPs and ±1 percent uncertainty for very-high-volume FMPs is required. As described in the preamble and in the BLM Threshold Analysis, the BLM determined the uncertainties for volume and heating value separately based on cost of compliance versus royalty risk resulting from the uncertainty requirement. For example, the flow-rate uncertainty and costs associated with achieving that uncertainty are dependent on the size, quality, configuration, and operation of the primary, secondary, and tertiary devices. For heating value, the uncertainty and costs associated with achieving that uncertainty are a function of the heating-value variability and sampling frequency or sampling method (
The BLM received several comments suggesting other uncertainty limits from those listed in the proposed rule. One commenter suggested that both the flow rate and heating-value uncertainties should be reduced to ±1 percent for high- and very-high-volume FMPs and an uncertainty requirement of ±5 percent should be added for very-low and low-volume FMPs. Another commenter suggested that the heating-value uncertainty should be ±7.5 percent when the heating value is above 1,200 Btu/scf and ±5 percent when the heating value is below 1,200 Btu/scf. Another commenter suggested that the BLM establish uncertainty levels for heating values by working with trade groups. Commenters submitted little rationale to support any of these suggested uncertainty levels. The BLM believes that the uncertainty levels given in the proposed rule are fair, reasonable, and achievable based on its experience in the field. They were established by determining the point at which the cost of compliance equals the risk to royalty. The BLM did not make any changes to the proposed rule based on these comments.
Several commenters stated that the BLM is confusing variability with uncertainty when establishing an uncertainty limit for average annual heating value. The BLM disagrees with these comments. The commenters appear to be assuming that the BLM used the term “uncertainty” interchangeably with “variability.” This is not the case, as described in detail in the BLM Gas Variability Study and as used in this rule. With respect to heating value, the term “variability” refers to the statistical variation from the mean heating value based on a certain number of previous gas analyses. For example, the heating values from five previous gas samples are shown in the table below, and the mean value of those five heating values is 1,256 Btu/scf. The variability of these five samples is the standard deviation of the five heating values (±14.3 Btu/scf) multiplied by the “student-t” function that yields a 95 percent confidence. For the five samples, the student-t function is 2.78, and the variability of this FMP is ±40 Btu/scf (±14.3 Btu/scf × 2.78), or ±3.2 percent of the average heating value. The BLM considers the variability a quasi-static property of the meter. The cause of the variability could be actual changes in gas composition over the time period analyzed, sampling technique, analysis technique, or other factors such as temperature at the time of sampling. Whatever the cause, this particular FMP has a variability of ±3.2 percent and will most likely continue to have a variability of approximately ±3.2 percent, unless something significant changes, such as the gas sampling or analysis technique or, for example, a new well is connected to the meter. When the BLM refers to heating-value uncertainty, it is specific to the average annual heating value uncertainty, not the uncertainty of an individual sample. The average annual heating value uncertainty is how close the average heating value from an FMP, as determined from gas samples taken over a 1-year time span, will be to the true average heating value of that FMP over the same time span. The true average annual heating value is a hypothetical value assuming the heating value was measured continuously over that year by an instrument with no uncertainty.
In the BLM Gas Variability Study, the BLM determined the relationship between variability and uncertainty in the average annual heating value. The relationship is defined by the following equation:
Although the variability of this FMP is ±3.2 percent, the average annual heating-value uncertainty is reduced by taking more samples over the year. In this example, the samples were taken twice per year, or roughly once every 180 days. Using the equation directly above, the uncertainty of the average annual heating value at this sampling frequency is reduced to ±2.1 percent. Sampling four times per year (every 90 days) would reduce the average annual heating-value uncertainty to ±1.5 percent. In summary, the average annual heating-value uncertainty requirement in the final rule governs uncertainty not variability. While variability is a factor in determining uncertainty, uncertainty can be reduced for a given level of variability by taking more frequent samples. The BLM added § 3175.31(b)(3) to the final rule as a result of these comments, in order to clarify and define the relationship between average annual heating-value uncertainty and variability. The equations presented in § 3175.31(b)(3) are the same equations that were presented in the heating value variability study repeatedly referenced in the preamble to the proposed rule. The study was also included in the supporting documentation posted on
One commenter asked that the BLM exempt central delivery point (CDP) meters from the heating-value uncertainty limits because achieving these limits would be difficult due to the constantly changing gas composition as different wells produce through the meter. The commenter provided an example of where a CDP meter, which would qualify as a very-high-volume FMP under the proposed rule, has a heating-value variability of ±3.5 percent. Assuming that the commenter determined the variability in the same manner as the BLM does, and took monthly samples at a very-high volume as required in the rule for the initial 1-year timeframe, the average annual heating-value uncertainty would be ±0.87 percent, based on the equation directly above, which is well within the uncertainty of ±1 percent required for very-high-volume FMPs. The BLM did not make any changes to the rule based on this comment.
Several commenters requested that the BLM provide the calculation methodology for average annual heating-value uncertainty. The BLM agrees with this comment and included the methodology in the final rule, under § 3175.31(b)(3). The methodology was also included in the BLM Gas Variability Study, which was posted as a supporting document on
One commenter stated that the cost of compliance for existing FMPs outweighs any measurable benefit. However, the volume cutoff points between low- and high-volume and between high- and very-high-volume FMPs in the final rule were established to represent the point at which the cost of compliance is equal to or less than the resulting reduction in royalty risk resulting from the improvements required by the rule. Royalty risk is the measurement uncertainty expressed in royalty dollars. The BLM did not make any changes to the rule based on this comment.
One commenter stated that the data used in the BLM Gas Variability study were not vetted or scrubbed to control for the conditions under which the samples were taken. The implication of the comment is that the BLM study is not statistically valid. While the BLM acknowledges that that the data were not controlled for the conditions under which they were taken, the data
One commenter stated that the BLM Gas Variability Study does not reflect the accuracy of custody-transfer meters because most of the measurement points from which the BLM obtained the analyses were on-lease meters. The BLM believes that the commenter misunderstands the purpose of the study, which was to assess the variability of meters on which Federal and Indian royalty is based. These meters are often on-lease meters rather than custody-transfer meters on which the operator is paid. The BLM is not concerned with sales or custody-transfer meters that are not used in the determination of royalty. Therefore, the data used in the study are directly applicable to meters used for royalty determination, which are generally the on-lease meters. The BLM did not make any changes to the rule based on this comment.
Several commenters stated that composite samplers and on-line GCs are not economical on location because they do not work well with rich gas. The commenters did not supply any data to support this claim. Based on this comment and on the BLM Threshold Analysis, the BLM eliminated the provision in the proposed rule that would have required composite samplers or on-line GCs on high-volume FMPs, if the required ±2 percent average annual heating-value uncertainty could not be achieved by spot sampling. The BLM made this change for economic reasons, not because it accepts that these devices do not work well with rich gas. The BLM did not remove the provision in the rule that requires composite samplers on very-high-volume FMPs when the required ±1 percent average annual heating-value uncertainty cannot be achieved through spot sampling.
One commenter suggested that the determination of heating-value uncertainty should be on a field-wide basis rather than on a well or FMP basis. The commenter did not provide any data to substantiate this suggestion. The BLM does not agree with this comment. While the determination of heating-value uncertainty on a regional or formation-wide basis may seem like a reasonable approach, the data analyzed by the BLM (BLM Gas Variability Study) showed that heating-value variability is not correlated by region or formation. One possible reason for this is that the heating-value variability is not only dependent on the formation, but also on human factors, such as gas sampling and analysis techniques. The BLM did not make any changes to the rule in response to this comment.
Section 3175.31(c) establishes the degree of allowable bias in a measurement. Bias, unlike uncertainty, results in systematic measurement error; uncertainty only indicates the risk of measurement error. For all FMPs, except very-low-volume FMPs, no statistically significant bias is 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. This approach is consistent with existing BLM policy. Although bias is not specifically addressed in Order 5 or the statewide NTLs, the intent of those standards is to reduce bias.
The bias requirement does not apply to very-low-volume FMPs because very-low-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—a possible outcome if the operator were to decide that it is uneconomic to upgrade a meter to eliminate bias. Therefore, the BLM has determined that it is in the public interest to accept some risk of measurement bias in very-low-volume FMPs in order to maintain gas production. The BLM did not receive any comments on this section.
Section 3175.31(d) requires that all measurement equipment must allow for independent verification by the BLM. For example, if a new meter were 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 were developed that used proprietary methods that 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. As explained in the preamble to the proposed rule, this is not a change from existing policy. Order 5 and the statewide NTLs for EFCs only allow meters that can be independently verified by the BLM.
One commenter stated that the performance goal of verifiability will restrict new technology. As an example, the commenter suggested that a verifiability requirement could have prevented the development of EGM systems. The BLM disagrees with this comment and did not make any changes to the rule as result. Contrary to the suggestion by the commenter, the BLM believes that verifiability is essential to making EGM systems universally accepted by both industry and regulators. For example, over 20 percent of the main body of API 21.1 is devoted to the audit trail, reporting, and data integrity required of EGM systems, all of which encompass verifiability.
One commenter expressed concern that the provisions of the proposed rule would cause the BLM to continually re-evaluate the quantity, rate, or heating value uncertainty of particular equipment. The BLM does not agree with this comment and did not make any changes to the rule as a result. The rule is designed to minimize required testing. The PMT will establish the uncertainty of each new piece of equipment one time, and operators can
Section 3175.40 establishes the types, makes, and models of equipment and software versions that can be used at FMPs. All makes of flange-tapped orifice plates (§ 3175.41), all makes and models of mechanical recorders (§ 3175.42), and all makes and models of GCs (§ 3175.45) are automatically approved under this rule without any additional BLM review. This section also explains that for specific makes, models, and sizes of other types of equipment including transducers (§ 3175.43), flow-computer software (§ 3175.44), flow conditioners (§ 3175.46), differential primary devices other than flange-tapped orifice plates (§ 3175.47), linear measurement devices (§ 3175.48), and accounting systems (§ 3175.49) are approved for use at FMPs under the conditions and circumstances stated in those sections.
For the specified types of equipment requiring BLM approval, as explained in the section-specific discussions of this preamble, this rule requires that equipment must be reviewed by the PMT and approved by the BLM. The PMT, which consists of a team of measurement experts, will base its review of such equipment on data submitted by individual operators, companies, or equipment manufacturers. Unlike the variance process under Order 5, which limits approvals to specific facilities, and requires that operators submit separate requests to use the same equipment at different facilities, this final rule provides that once the PMT reviews and the BLM approves a piece of equipment or measurement process, that approval will be posted to the BLM website (
While the final rule provides that the PMT will review requests and make recommendations to the BLM for approval, it is the BLM's intent that such approvals will be issued by a BLM AO with authority over the oil and gas program nationally (
The BLM received many comments that expressed concerns over the role, authority, staffing, process, and approval timeframes relating to the PMT. Several comments stated that the PMT should include industry members, academia, tribal members, and State Government representatives. Comments also stated that the PMT should be chartered under the Federal Advisory Committee Act (FACA) and that all meetings should be open to the public. The BLM finds formalizing the PMT and requiring a FACA-chartered committee to be inconsistent with expediting the approval of new and existing technology. As described in the final rule, the PMT will consist of measurement experts within the BLM whose primary job function is to review test data for new and existing technology and recommend approval or denial of that technology to the BLM. While the team has not yet been assembled, the BLM believes that once the PMT is fully staffed, reviews will take 30 to 60 days, assuming that the proper testing has been done and all pertinent data have been submitted to the PMT.
Under a FACA charter, as favored by some commenters, reviews would take much longer, possibly even years. A FACA charter first requires all members to be vetted and approved by the Secretary. The BLM would then have to publish a notice in the
Substantively, the PMT's role in reviewing specific makes and models of equipment and making recommendations to the BLM for approval of particular equipment under this rule is similar to the authority for a BLM field office to issue variances under the existing Onshore Orders. The only difference between the existing variance process and the PMT is that under the existing variance process reviews are performed at the field-office level on a case-by-case basis; under this final rule these reviews will be performed once by a single entity at the Washington-Office level. Ultimately, the PMT makes recommendations for approval, and the BLM retains full discretion to concur with or reject such recommendations. In the final rule to update and replace Order 3, § 3170.8 has been revised to add a new paragraph (b) that addresses the appeals procedure for PMT recommendations that are approved by the BLM. The BLM did not make any changes to the rule based on these comments.
Other commenters stated that the rule should provide for administrative review of all recommendations made by the PMT. The BLM agrees with this comment and has added an administrative review to the PMT process as part of the final rule updating and replacing Order 3 (see 43 CFR 3170.8(b)). Under this process, any approval or denial made by the BLM based on a PMT recommendation can be administratively appealed to the Assistant Secretary for Lands and Minerals, or their designee. Using the analogy of the existing field office variance review process discussed earlier, the approval or denial of a variance for new technology under the current process could be appealed by anyone adversely affected by that approval or denial. Likewise, any decision made by the BLM regarding technology reviewed by the PMT is also subject to appeal by anyone adversely affected by that decision.
Several commenters said that the PMT would favor large companies that could afford elaborate “Cadillac” proposals. The BLM disagrees with this comment and did not make any changes as a result. The reviews performed by the PMT are not exclusive. In other words, if a large operator submitted a “Cadillac” proposal to the PMT and a small operator submitted a “Chevy” proposal (simple and inexpensive) to the PMT, the PMT would review both proposals on their merits. If the PMT and then, ultimately, the BLM determined that both proposals met the performance goals in this rule, then both proposals would be approved and posted on the BLM website. Once posted, any operator could use either the “Cadillac” or “Chevy” technology without any further approval needed.
One commenter stated that the PMT should develop testing manuals that the industry could follow. While the BLM did not make any changes to the rule based on this comment, the BLM agrees that manuals could provide useful guidance. Once formed, the PMT will consider developing nonbinding testing manuals, as suggested by the commenter.
One commenter stated that the PMT role should include the review of new gas sampling technology. The BLM agrees with this comment, but does not
Several commenters objected to the lack of information in the proposed rule regarding the PMT review and approval process and also objected to the absence of a list of approved equipment published in the proposed rule. The BLM did not make any changes to the rule based on these comments. As a procedural matter, the BLM does not believe that it is necessary or appropriate to set forth prescriptive procedures for the PMT to follow in either the proposed rule or the final rule in order to preserve the BLM's discretion in setting up this new entity. That said, the BLM notes that the rule is not silent on the PMT's review procedures. To the contrary, the rule establishes specific performance standards and requirements that equipment and methods used for gas measurement must meet. This information was clearly identified in the proposed rule, and, for the most part, has been carried forward into the final rule.
The BLM did not publish a specific list of approved equipment because no such list exists. However, the rule does provide for the automatic acceptance of certain types of equipment, such as flange-tapped orifice plates, gas chromatographs, and mechanical recorders at low- and very low-volume FMPs. The PMT will develop the list of other types of approved equipment, such as flow conditioners and differential-pressure meters, based on a review of the data that the PMT receives and a determination by the PMT that the equipment complies with the performance standards established in this rule. The need for these reviews is the reason why the final rule establishes a 2-year phase-in period for equipment approved by the PMT in order to give the PMT time to complete this work.
One commenter questioned why the BLM is entering the free market by limiting the types of devices that operators can use. The BLM is not limiting the types of devices. To the contrary, an operator can use a variety of devices as long as those devices meet the applicable performance standards specified in the rule. The BLM believes that the only way to ensure that volume and quality measurement meets the specified uncertainty performance goals is to ensure that the components that contribute to volume and quality uncertainty have been tested in a consistent and transparent manner. The BLM did not make any changes to the rule based on this comment.
One commenter asked for clarification if the BLM is approving equipment by performance or uncertainty. Although the BLM is unclear as to what the commenter means by “performance” and “uncertainty” (uncertainty is a performance goal in this rule), the answer is case-specific as indicated below:
• Transducers (§ 3175.43): Approval for transducers installed at FMPs after the effective date of the rule is granted if the transducer undergoes the tests required in the testing protocol (see § 3175.130). Alternatively, for existing transducers, the BLM will grant approval if the manufacturer supplies the BLM with a sufficient amount of existing data. In either case, the BLM will ascertain the uncertainty of the transducer and how outside conditions, such as ambient temperature, affect the device.
• Flow-computer software (§ 3175.44): Approval is granted if the flow-computer software agrees with the reference software within a specified tolerance.
• Isolating flow conditioners (§ 3175.46): Approval is granted if the device is tested under API 14.3.2, Annex D, which includes a pass-fail criterion.
• Differential primary devices other than flange-tapped orifice plates (§ 3175.47): Approval is granted if the device is tested in accordance with API 22.2. The BLM will ascertain the uncertainty of the device and how factors such as installation configurations, Reynolds number, and differential-pressure-to-static-pressure-ratio, affect the device.
• Linear meters (§ 3175.48): Approval is granted if the BLM determines that the meter can meet or exceed the performance goals of § 3175.31(a), (c), and (d).
• Accounting systems (§ 3175.49): Approval is granted if the BLM determines that the system can meet the performance goals of § 3175.31(d).
The BLM did not make any changes to the rule based on this comment.
Flange-tapped orifice plates have been rigorously tested and have proven capable of meeting the performance standards of § 3175.31(a), (c), and (d). As such, FMPs using flange-tapped orifice plates that are installed, operated, and maintained as the primary device in accordance with the standards in § 3175.80 are automatically accepted under the final rule with no additional review or approvals needed. The BLM did not receive any comments on this section.
Mechanical recorders 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 § 3175.31(c) and (d) is well established. Because mechanical recorders are limited to very-low-volume and low-volume FMPs under the rule, they do not have to meet the uncertainty requirements of § 3175.31(a). As such, low- and very-low-volume FMPs using mechanical recorders that are installed, operated, and maintained in accordance with the standards in § 3175.90 are automatically accepted under the final rule with no additional review or approvals needed. The BLM did not receive any comments on this section.
While EGM systems are widely accepted for use in custody-transfer applications, there are currently no standardized protocols by which transducers, a critical component of an EGM system, are tested to document their performance capabilities and limitations. Proposed § 3175.43 would have required transducers to be tested under the protocols in § 3175.130 in order to be used at high- or very-high-volume FMPs. Transducers used at very-low and low-volume FMPs are not subject to these requirements. The primary purpose of the testing protocol is to determine the uncertainty of the transducer under a variety of operating conditions. Because very-low and low-volume FMPs are not subject to the uncertainty requirements under § 3175.31(a), testing the performance of the transducers used at these FMPs is unnecessary.
Several commenters requested that the BLM accept transducers currently in use or approve these transducers if the manufacturer can provide test data consistent with industry practice. The BLM agrees with these comments and added the option of using the test data the manufacturers used to derive their published performance specifications. However, if the data submitted by the manufacturer are incomplete, or insufficient to justify the published performance specifications, the BLM may use performance specifications derived by the PMT from the data, or limit the use of the transducer to specific ranges of pressure, temperature, or operating conditions.
The BLM received numerous comments suggesting that the BLM should accept published API-type testing standards for transducers in lieu of the protocols in the proposed rule. However, there are no API standards in place for testing transducers. The BLM is aware that the API is developing testing protocols for transducers, but these standards have not been published. The BLM did not make any changes to the rule based on these comments.
Numerous commenters suggested that the BLM should grandfather existing transducers from the type testing requirements in this section. The reasons given in the comments include the inability to type test older equipment that is no longer manufactured or supported by the manufacturer, the opinion that there is no need to test equipment that is properly working, the lack of laboratories equipped to do the testing, and timeframes for the PMT to review and approve existing equipment to avoid shutting in production. The proposed rule would have required type testing of all transducers used on high- and very-high-volume FMPs. The BLM recognizes these concerns and has made two changes in this section as a result. First, the requirement to use type-tested equipment will not take effect until 2 years after the effective date of the rule as provided in § 3175.60(a)(4) and (b)(2). This should be adequate time for the formation of the PMT, testing of existing equipment, and review of that equipment by the PMT. Second, for existing transducers, the BLM will allow operators or manufacturers to submit the data on which the manufacturer's published performance specifications are based, in lieu of using the testing protocols specified in § 3175.130 of the rule. This will allow the PMT to review, and the BLM to approve if appropriate, existing transducers without the need for additional testing. Additional changes based on these comments are addressed in the § 3175.130 discussion in this preamble.
Several commenters expressed a concern about the cost of replacing existing transducers as a result of this requirement. The BLM does not believe that this requirement would require operators to replace existing transducers. In addition to the 2-year implementation of this requirement and the provision to allow operators and manufacturers to submit existing data instead of generating new data, the transducer testing protocol in § 3175.130 is not a pass-fail requirement. The purpose of the testing protocol is to independently define the performance of a transducer and then use that performance to determine compliance with the overall uncertainty requirements in § 3175.31(a). The BLM did not make any changes to the rule based on these comments.
One commenter suggested that instead of approving transducers by make and model using the testing protocol, the BLM should just specify performance goals. The BLM has, in fact, specified performance goals for both volume (§ 3175.31(a)) and heating value (§ 3175.31(b)) based on overall measurement uncertainty. However, in order to enforce an uncertainty standard, BLM inspectors must be able to calculate the overall uncertainty to determine if the FMP meets the requirements. Transducer performance is often the largest contributor to overall volume measurement uncertainty, especially in situations where the transducer is operated at the low end of its upper calibrated limit. Currently, the BLM uncertainty calculator uses the manufacturer's published performance specifications in the calculation of uncertainty; however, there is no standard method that manufacturers use to develop those specifications. In addition, most manufacturers consider their testing process and data as proprietary, making it impossible for the BLM to verify. The BLM believes that to enforce an uncertainty performance goal, the components that go into the uncertainty calculation must be determined in a transparent and consistent manner. Therefore, the BLM did not make any changes to the rule based on this comment.
Two commenters also suggested that the BLM could use field calibration data to validate existing equipment. While the BLM believes that field calibration could be used to validate existing equipment, it would be difficult to extract individual installation effects from the data such as ambient temperature effects, vibration effects, and static pressure effects. In addition, it would be difficult to filter the data to eliminate human error in the calibration data. The BLM did not make any changes to the proposed rule as a result of these comments.
One commenter stated that operators have no economic incentive to replace existing transducers. The BLM did not make any changes to the rule based on this comment for two reasons. First, as explained previously, the testing protocols for transducers and flow computers would not generally require replacing existing equipment. Second, we agree that operators often do not have an economic incentive to replace existing transducers (in other words, the investment in a new transducer would not necessarily result in increased revenue). If they had an economic incentive, this provision in the rule would probably not be necessary. The intent of the provision is to improve accuracy and verifiability to ensure that the public and Indian tribes and allottees receive their fair share of the value of oil and gas resources extracted from their land. The BLM did not make any changes to the rule based on this comment.
As with transducers, there are currently no standardized protocols by which flow-computer software is tested to document its capability to perform all calculations within acceptable tolerances and record and store other supporting information. Proposed § 3175.44 would have required flow-computer software at all FMPs to be tested under § 3175.140 in order to be used at an FMP.
Numerous commenters suggested that the BLM should grandfather existing flow-computer software versions from the type-testing requirements of this section. The commenters stated that it would be difficult to test software versions on older computers that are no longer supported by the manufacturer. Other commenters stated that the time required for the PMT to review and approve software versions could lead to production shut-ins.
The BLM recognizes these concerns and has made two changes in the final rule as a result. First, the requirement to use type-tested software does not take effect until 2 years after the effective date of the rule, as provided for in § 3175.60(a)(4) and (b)(2). This should be adequate time for the formation of the PMT, testing of existing software versions, review of that software by the PMT, and approval of the software by the BLM. Second, under the final rule, all software versions used at very-low- and low-volume FMPs are approved for use without testing, unless otherwise required by the BLM (§ 3175.44(c)). While this is not the complete grandfathering requested by the commenters, the BLM believes that there are very few older, unsupported flow computers in use at high- or very-high-volume FMPs.
The BLM received numerous comments suggesting that the BLM should accept published API type-testing standards for flow-computer software in lieu of the protocols in the rule. However, there are no API standards in place for flow-computer software. The BLM is aware that the API is developing testing protocols for flow-
Several commenters expressed a concern about the cost of replacing existing flow computers as a result of this requirement. The BLM does not believe that this requirement requires operators to replace existing flow computers. The testing protocol defined in § 3175.140 applies to the software in the flow computer, not the flow computer itself (although the software testing is specific to individual makes and models of flow computers). The flow-computer testing protocol is a pass-fail requirement. However, if the BLM discovers a software version that did not pass, the remedy would be to update the software and install it in the flow computer.
GCs have been rigorously tested and used in industry for custody-transfer applications, and their ability to meet the requirements of § 3175.31 has been demonstrated. Therefore, the rule allows all makes and models of GCs in determining heating value and relative density as long as they meet the requirements of §§ 3175.117 and 3175.118. The BLM did not receive any comments on this section.
Section 3175.46 requires all makes and models of flow conditioners used in conjunction with flange-tapped orifice plates at FMPs to be tested under established API test protocols, reviewed by the PMT, and approved by the BLM.
The final rule references API 14.3.2, Annex D, which provides a testing protocol for flow conditioners. In the proposed rule, based on the BLM's experience with other testing protocols, the BLM proposed using additional testing beyond what Annex D requires to meet the intent of the uncertainty limits in § 3175.31(a). Additional testing protocols would have been posted on the BLM's Web site at
One commenter asked if data for existing flow conditioners that have already been tested under Annex D will have to be resubmitted to the PMT to get approval. The PMT will require the data in order to review the flow conditioner in question. No changes to the rule were made as a result of this comment.
One commenter suggested that in lieu of establishing a new process for the PMT to follow for the approval of flow conditioners, the BLM should incorporate and use API Chapter 12.1. The commenter also stated that unless the PMT meets regularly, it will slow down the adoption of new technology. API 12.1 deals with the calculation of static petroleum liquids in upright cylindrical tanks and rail cars, which does not seem relevant here. The BLM's intent is to establish the PMT as a permanent full-time team dedicated to reviewing test data and performing other centralized measurement functions. The BLM did not make any changes to the rule based on this comment.
Section 3175.47 requires all makes and models of differential primary devices other than flange-tapped orifice plates to be tested under established API test protocols, reviewed by the PMT, and approved by the BLM in order to be used at FMPs.
This section references API 22.2 (2005), which establishes a testing protocol for differential devices. The proposed rule would have allowed the BLM to include additional testing requirements beyond those in the current version of API 22.2 to help ensure that tests are conducted and applied in a manner that meets the intent of § 3175.31 of this rule. The BLM would have posted any additional testing protocols on its Web site at
Numerous comments expressed concern over the PMT's ability to include additions to the API 22.2 testing protocol for differential primary devices. The BLM agrees and modified this provision accordingly.
Several commenters asked that the burden of testing new devices be on the manufacturer and not the operator. The BLM is not concerned with who does the testing. However, this section of the proposed rule specified that the operator must test these devices. The BLM agrees that the both the testing and the submittal of data to the PMT can be done by either the operator or the manufacturer; the BLM changed the reference to “operator” in this section to “operator or manufacturer” as a result of this comment.
Proposed § 3175.48 would have allowed the BLM to approve linear measurement devices reviewed by the PMT on a case-by-case basis to be used at FMPs. Linear measurement devices include ultrasonic meters, Coriolis meters, and turbine meters.
The BLM received numerous comments stating that linear meters should be approved on a type-testing basis, and not just on a case-by-case basis as stated in the proposed rule. The comments indicated that industry widely accepts linear meters and case-by-case approval could inhibit technological development. In addition, the commenters stated that there are existing industry standards for linear meters such as ultrasonic meters, turbine meters, and Coriolis meters. The BLM agrees with these comments and changed the wording of § 3175.48 from a “case-by-case basis” to a “type-testing basis,” similar to the requirements for other devices under § 3175.40. When the PMT receives a request to use a linear meter, it will review any applicable standards for that meter as part of the approval process. The PMT will then recommend approval or denial of that device to the BLM. If the BLM approves the device, it will be posted at
One commenter expressed concern with the language in the proposed rule stating that the BLM “may,” but does not have to, approve the make and model of a linear measurement device. The commenter indicated that this could present a regulatory hurdle that could delay the use of more technologically advanced devices like ultrasonic meters. Although the language of this section was changed based on other comments and the word “may” no longer appears, the BLM retains the discretion of approving or not approving certain makes and models of linear measurement devices based on the review of the PMT. The BLM does not agree that this will present a regulatory hurdle for the implementation of new technology. Instead, the BLM believes that having a consistent and thorough review process that ensures that the new technology can meet the uncertainty, bias, and verifiability goals of the rule will encourage acceptance of new technology that can meet these goals. The BLM did not make any changes to the rule based on this comment.
Accounting systems were not included in the proposed rule; however,
When performing a production review, the BLM typically starts by sending a written order to the operator requiring the operator to submit data supporting the reported production quality and quantity over a specified time period and for a specified lease, CA, or unit PA. These data typically include QTRs, configuration logs, event logs, and alarm logs. As discussed in the preamble to the proposed rule, it is common practice for operators to submit these data to the BLM using third party software that automatically 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.
As a result, the BLM has developed the testing protocol required in this section that compares raw data retrieved directly from flow computers to both edited and unedited data obtained from the third party software under test. The BLM will only approve software packages where the protocol demonstrates that the original, unaltered, unprocessed, and unedited data from the flow computer is provided by the software, and that edited data is clearly marked as such.
Section 3175.60 provides a timeframe for when all measuring procedures and equipment installed at any FMP must comply with the requirements of this subpart. Proposed § 3175.60(a) would have required all meters installed after the effective date of the final rule to meet the requirements of the rule. The BLM received several comments stating that the requirement to enter all gas analyses into the GARVS (see § 3175.120(f)) should be delayed because GARVS does not exist yet and the BLM did not provide enough information about GARVS in the proposed rule for operators to develop reporting formats. GARVS is a new database that the BLM is developing as part of the implementation of this rule that will have the ability to receive gas analysis reports from operators. One commenter stated that the BLM should delay this requirement up to 7 years, to give operators enough time to obtain GC models that are capable of meeting the proposed GC requirements of § 3175.118. Several other commenters suggested a delay of 2 years. The BLM agrees with the latter comments and included a 2-year phase-in period for reporting into GARVS in the final rule (§ 3175.60(a)(2)). The 2-year phase-in period is to allow the BLM time to develop the GARVS software. Based on changes in the final rule relating to GCs, the BLM believes that virtually all existing GCs will meet the standards of this rule and that no additional delay to develop new GCs is necessary. The final rule (§ 3175.60(a)(3)) also delays the implementation of variable sampling frequencies in § 3175.115(b) for 2 years. In order to implement this requirement, GARVS must be fully functioning.
Numerous comments suggested that the BLM should grandfather existing equipment from having to get approval from the PMT. The commenters expressed concern over having to shut in wells while the PMT reviews and approves existing equipment. The proposed rule would have required type testing of transducers used on high- and very-high-volume FMPs and type testing of flow-computer software, flow measurement devices, and flow conditioners at all FMPs. The BLM understands these concerns and has made two changes in the rule as a result. First, the requirement to use equipment reviewed by the PMT and approved by the BLM will not take effect until 2 years after the effective date of the rule (§ 3175.60(a)(4)). This should be adequate time for the formation of the PMT, testing of existing equipment, and review and approval of that equipment by the PMT. Second, for existing transducers, the BLM will allow operators or manufacturers to submit the data on which their published performance specifications are based in lieu of using the testing protocols specified in § 3175.130 of the rule. This will allow the PMT to approve existing transducers without the need for additional testing.
Section 3175.60(b) sets timeframes for compliance with the provisions of this rule for measuring procedures and equipment existing on the effective date of the final rule. The timeframes for compliance generally depend on the average flow rate at the FMP. Under the proposed rule, very-high-volume FMPs would have had 6 months from the effective date of the rule, high-volume FMPs would have had 1 year from the effective date of the rule, low-volume FMPs would have had 2 years from the effective date of the rule, and very-low-volume FMPs would have had 3 years from the effective date of the rule. Higher-volume FMPs would have had shorter timeframes for compliance under the proposed rule because they present a greater risk to royalty inaccuracy than lower-volume FMPs and the costs to comply could be recovered in a shorter period of time.
Numerous comments stated that the compliance timeframes in the proposed rule were too short for several reasons, including the time it takes to revise accounting systems to handle the 11-digit FMP number; the time for budgeting, engineering, purchasing, and installing new equipment; the fact that GARVS is not yet up and running; and the time it will take for the PMT to approve existing equipment. In addition, several commenters stated that the proposed rule would have created a high demand for items such as flow computers and meter tubes that would comply with the new requirements, and that demand would delay the availability of the equipment. One commenter stated that the proposed timeframes also needed to consider delays caused by weather and seasonal restrictions in some areas. Commenters' suggestions ranged from a 1-year to a 3-year phase-in period or tying the phase-in period to when the FMP is approved by the BLM. One commenter suggested tying the phase-in period to the availability of GCs capable of meeting the new requirements in the proposed rule, although it is not clear to what new requirements the commenter was referring. The BLM generally agrees with these comments and changed the compliance timeframe for very-high-volume FMPs from 6 months to 1 year to coincide with the timeframe for high-volume FMPs. The compliance timeframe for very-low and low-volume FMPs remains at 3 years and 2 years, respectively. This change, in conjunction with other changes to the rule listed below, should alleviate the concerns raised by the commenters:
• Elimination of the need to display the 11-digit FMP number, or include this number in accounting systems (§§ 3175.101(b)(4)(i) and 3175.104(a)(1) in the proposed rule). Removing the
• Grandfathering of existing meter tubes at low- and high-volume FMPs (§ 3175.61(a)). Under the final rule, operators of existing very-low-volume, low-volume, and high-volume FMPs will not have to upgrade the meter tubes to API 14.3.2 standards. The BLM believes that meter tubes at very-high-volume FMPs constructed after API 14.3.2 was issued in 2000 meet those standards and will not have to be retrofitted. As with the flow computers, therefore, only those very-high-volume FMPs that were constructed prior to 2000 will require meter tube upgrades. The BLM believes that most meter tubes at very-high-volume FMPs were constructed to the latest API standards and will not have to be retrofitted as a result.
• Allowing existing data to approve transducers at high- and very-high-volume FMPs (§ 3175.43(b)). Under the final rule, operators can submit existing test data to the PMT in lieu of performing the testing under § 3175.130, for transducers that are in use at FMPs prior to the effective date of the rule. This will dramatically reduce the time and cost that could have been associated with the required testing for all transducers under the proposed rule.
• Modifying GC requirements (§§ 3175.113 and 3175.118). The BLM made numerous changes to §§ 3175.113 and 3175.118 relating to GCs, and believes that these changes address the concerns of the commenter who suggested that the BLM tie the timeframes to the availability of GCs capable of meeting the new BLM requirements. For example, the requirement under § 3175.118(b) of the proposed rule would have required samples to be analyzed until 3 consecutive runs are within the repeatability standards listed in GPA 2261-00, Section 9. It would have been very difficult for existing GCs to meet this proposed standard and, as a result of comments received, the BLM eliminated this requirement in the final rule.
• Lengthening to 2 years the phase-in period for the implementation of GARVS (§ 3175.60(a)(2) and (b)(2)(ii)).
• Lengthening to 2 years the timeframe for getting PMT approval of existing equipment (§ 3175.60(a)(4) and (b)(2)(iii)). Allowing the PMT to approve transducers currently in use with existing data from the manufacturers will greatly reduce the approval timeframe and, in conjunction with the new, 2-year timeframe for PMT approvals, should ease operators' compliance with the new requirements.
Several commenters expressed a concern about being penalized if they cannot meet the deadlines due to delays within BLM, such as the PMT failing to issue approvals in a timely manner. In deciding how to target its enforcement actions, the BLM will take into account any evidence that BLM delays contributed to an operators' noncompliance. No changes to the rule were made based on these comments.
One commenter recommended that the BLM implement a series of training programs for operators during the phase-in periods. The BLM will consider outreach programs; however, no changes to the rule were made as a result of this comment.
Proposed § 3175.60(b)(1)(ii) and (b)(2)(ii) would have included 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 have gone into effect immediately for high-volume and very-high-volume FMPs on the effective date of the final rule. This would have allowed 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. As discussed above, however, the BLM decided to allow for a 2-year window from the effective date of the rule for the implementation of GARVS, including for FMPs existing before the effective date of the rule (§ 3175.60(b)(1)(iii)).
Although this rule will supersede Order 5 and any NTLs, variance approvals, and written orders relating to gas measurement, paragraph (c) specifies that their requirements will remain in effect through the timeframes specified in paragraph (b). Paragraph (d) establishes the dates on which the applicable NTLs, variance approvals, and written orders relating to gas measurement will be rescinded. These dates correspond to the phase-in timeframes given in paragraph (b). The BLM did not receive any comments on this paragraph.
The BLM received a few comments regarding the proposed requirement in § 3175.60(b)(2) on timeframes to retrofit chart recorders used on low- and very-low volume FMPs. The BLM did not make any changes based on these comments. The rule allows 2 years for low-volume FMPs to come into compliance with the new rule and 3 years for very-low-volume FMPs. The BLM believes that this provides enough time for operators to make the relatively few changes required for mechanical recorders in the rule. Based on other comments, the BLM raised the very-low-/low-volume threshold from 15 Mcf/day to 35 Mcf/day, which significantly decreases the number of mechanical recorders that fall into the low-volume FMP category.
Several commenters stated that the timeline to implement the required changes was unreasonable due to workforce constraints, and the end result would not increase accuracy or royalties. Based on these and other comments, the BLM extended the timeframe for very-high-volume FMPs to comply with these requirements from 6 months to 1 year. The compliance timeframes for high-, low-, and very-low-volume FMPs remain at 1 year, 2 years, and 3 years, respectively. As stated above, the 1-year compliance timeframe only applies to high- and very-high-volume FMPs, which only make up 11 percent of all FMPs nationwide under the new flow-rate category definitions.
The BLM disagrees with the statement that these rules will not increase accuracy. For one thing, the accuracy, or uncertainty, for very-high-volume FMPs must improve from the ±3 percent allowed in the statewide NTLs to ±2 percent under this rule. Similarly, the requirement to eliminate statistically significant bias in the final rule will ensure that the calculation of uncertainty only involves random error, representing a risk of mismeasurement, and not systemic error, which would result in actual mismeasurement. The BLM also notes that many of the changes in this rule are aimed at improving the verifiability of measurement, not the accuracy.
As for whether the rule will increase royalties, the BLM notes that the goal of the rule is to reduce uncertainty (improve accuracy), remove bias, and increase verifiability to ensure that the public and tribes receive their fair share of royalty on the gas removed and sold from their leases. The goal was not necessarily to increase royalty payments, but rather to ensure that all royalties due are paid. Royalty payments may increase as a result of this rule, but the BLM cannot predict whether net payments will increase in every instance as a result of this rule. The BLM did not make any changes to the rule based on these comments.
This section was added to the final rule based on numerous comments regarding the cost of some of the requirements in the proposed rule, and based on the BLM's Threshold Analysis, which re-examined some of the economic impacts based on information received during the comment period.
In the proposed rule, the BLM did not propose to “grandfather” existing equipment. Operators would have been required to upgrade measurement equipment at FMPs to meet the new standards, except at those FMPs that were specifically exempted in the rule. The BLM received many comments, however, expressing that existing equipment should be grandfathered to avoid changing out or upgrading equipment that is working.
In general, commenters expressed the concern that without grandfathering, they would be forced to plug and abandon wells—particularly low producing wells—due to the high cost of retrofitting existing facilities. Other commenters stated that equipment should be grandfathered if the operator can demonstrate it meets the performance goals under this rule or unless and until the BLM determines the equipment is inaccurate. Several commenters stated that existing equipment should be grandfathered because the BLM implicitly accepts this equipment as being accurate under Order 5. One commenter suggested that the BLM should grandfather existing equipment when the repair cost exceeds 50 percent of a new installation. One commenter stated that retroactive requirements should only apply to high- and very-high-volume FMPs. The BLM also received numerous comments requesting specifically that the BLM grandfather existing meter tubes at FMPs because meter tubes installed before the standards of API 14.3.2 came out in 2000 would not comply with some of the requirements in § 3175.80.
In addition to these general comments, the commenters also expressed concern about four specific requirements in proposed § 3175.80 pertaining to meter tubes:
• The orifice plate perpendicularity and eccentricity at all FMPs would have to meet the standards of API 14.3.2, Subsection 6.2 (Table 1 to § 3175.80). The term “perpendicularity” refers to the orifice plate being perpendicular to the direction of flow. The term “eccentricity” refers to the centering of the orifice plate in the meter tube. These standards require less eccentricity than the previous 1985 version of AGA Report No. 3.
• The meter tube construction and condition at low-, high-, and very-high-volume FMPs would have to meet the standards in § 3175.80(f). These standards refer to the requirements in API 14.3.2, Subsections 5.1 through 5.4 and require higher tolerances for meter tube roundness than the previous 1985 version of AGA Report No. 3 required.
• The design of tube bundles at low-, high-, and very-high-volume FMPs would have to meet the requirements in § 3175.80(g). These requirements refer to the tube-bundle construction requirements in API 14.3.2, Subsections 5.5.2 through 5.5.4. The previous 1985 version of AGA Report No. 3 did not specify the number of tubes that the tube-bundle straightening vane could have, whereas the API 14.3.2 standards incorporated by reference in this rule only allow 19 tubes.
• The meter tube length and tube-bundle placement for low-, high-, and very-high-volume FMPs would have to meet the requirements in § 3175.80(k). These requirements refer to API 14.3.2, Subsection 6.3. The meter tube length requirements in API standards incorporated by reference in the proposed rule were generally the same, or very close to, the meter tube length requirements in the previous 1985 version of AGA Report No. 3, especially at Beta ratios below 0.5. However, there are some specific situations where the lengths under the new API standard are much longer than those required in the 1985 standard. In addition, for Beta ratios of 0.5 or greater, the tube-bundle placement standards are much different in the new API than in the previous 1985 version.
The commenters cited multiple reasons for exempting existing meter tubes from these requirements. The commenters stated that meter tubes installed before the standards of API 14.3.2 came out in 2000 do not comply with some of the requirements in § 3175.80, and noted the high cost of replacing the large number of meter tubes installed under the 1985 standard (or under previous standards), the likely manufacturing delays that would result when operators simultaneously ordered a high number of replacement meter tubes, and the negligible revenue benefit that would result from replacing meter tubes. One commenter also recommended that the eccentricity requirements only apply to high- and very-high-volume FMPs.
The BLM partially agrees with these comments, and therefore decided to modify the final rule to provide for limited grandfathering of meter tubes and flow-computer software at certain FMPs. Specifically, the BLM changed Table 1 to § 3175.80 so that neither the eccentricity nor the pendicularity requirement applies to very-low-volume FMPs. Further, the BLM added a grandfathering clause (§ 3175.61(a)) that exempts meter tubes at low- and high-volume FMPs installed before January 17, 2017 from the perpendicularity and eccentricity requirements in Table 1 to § 3175.80; the construction and condition requirements in § 3175.80(f); and the meter tube length requirement in § 3175.80(k). However, these meter tubes have to meet the 1985 AGA Report No. 3 standards for eccentricity (see § 3175.61(a)(1)), construction and condition (see § 3175.61(a)(2)), and meter tube length (see § 3175.61(a)(3)). The rule does not grandfather the design and location of flow conditioners, including tube bundles, for reasons outlined in the discussion under § 3175.80(g) regarding tube-bundle design and § 3175.80(k) regarding tube-bundle placement.
In addition, the BLM added a clause for grandfathered meter tubes used at high-volume FMPs, which allows the BLM to add 0.25 percent to the discharge coefficient uncertainty when determining overall measurement uncertainty under § 3175.31(a)(1). The discharge coefficient uncertainty used in the BLM uncertainty calculator is based on data presented in API 14.3.1, which assumes the meter tube meets all the standards under API 14.3.2. The looser tolerances in AGA Report No. 3 (1985) likely result in higher levels of discharge coefficient uncertainty than those resulting from the tighter tolerances in API 14.3.2, although the BLM does not know specifically how much higher. Based on its experience with meter testing, the BLM believes that an increase in discharge coefficient uncertainty of 0.25 percent is reasonable to account for the looser tolerances under AGA Report No. 3 (1895). If operators submit test data to the PMT showing that meter tubes constructed under the 1985 standard result in an increase in the discharge coefficient uncertainty of less than 0.25 percent, or no increase at all, the BLM may approve a lower percentage. The 0.25 percent increase in discharge coefficient uncertainty does not apply to low-volume FMPs because low-volume FMPs are not subject to the uncertainty requirements under § 3175.31(a).
Several commenters asked that the BLM grandfather flow computers that are currently in use without requiring operators to go through the testing protocol. The BLM agrees with this comment, at least for very-low and low-volume FMPs. Accordingly, the BLM changed § 3175.44 so that the testing of
One commenter stated that the BLM should grandfather the calculation methodologies at existing flow computers and allow them to calculate supercompressibility under AGA Report No. 8, (1992), which is already programmed into the commenter's flow computers. The BLM did not make any changes to the rule based on this comment because AGA Report No. 8 (1992) is the most current method of calculating supercompressibility and is incorporated by reference (see § 3175.30). Any flow computer that is programmed with the AGA Report No. 8 software will be in compliance with the rule.
Another commenter suggested that the BLM should grandfather existing flow computers from having to comply with § 3175.103(a)(1) which requires flow rate calculations to be done in accordance with API 14.3.3 (2013) and supercompressibility calculations to be done in accordance with AGA Report No. 8 (1992). The commenter stated that older flow computers may not have the latest calculation software, and it may be difficult or impossible to upgrade the flow computers, especially if they are no longer supported by the manufacturer. In these cases, according to the commenter, operators would choose to prematurely plug and abandon wells rather than incur the cost of a new flow computer. The BLM agrees with these comments as they relate to very-low and some low-volume FMPs, and added § 3175.61(b) to the final rule to address flow computers installed at these FMPs before the effective date of the rule. A summary of the calculation methodologies of the older API and AGA standards and the response to the commenter's suggestion are addressed below.
• API 14.3.3 (1992): The primary difference between the API 14.3.3 (2013) calculation and the API 14.3.3 (1992) calculation involves the gas expansion factor. The 2013 edition of API 14.3.3 uses a different equation for the gas expansion factor which is based on a more thoroughly vetted dataset than the 1992 edition. Use of the equation from the 1992 standard results in a statistically significant bias of greater than 0.25 percent when the ratio of differential pressure to static pressure exceeds the values listed in Table G.1 of API 14.3.3 (2013), Annex G. When the differential pressure to static pressure ratio is below these values, the bias is less than 0.25 percent, which the BLM does not consider to be statistically significant.
• AGA Report No. 3 (1985): This standard, which was the predecessor to the API 14.3.3 standards, not only uses the older version of the gas expansion factor equation, it uses a different and less accurate version of the calculation used to determine the discharge coefficient. In addition, the 1985 calculation uses a non-iterative calculation approach that further contributes to reduced accuracy. Both the 1992 and 2013 API 14.3.3 calculations use an iterative process and a more accurate equation for the discharge coefficient, resulting in a more accurate calculation of flow rate. The 1992 and 2013 API standards also quantify the uncertainty of the discharge coefficient calculation in greater detail than in AGA Report No. 8 (1985).
• PRCI NX-19: This standard, which was the predecessor of AGA Report No. 8, defines a calculation method for supercompressibility that is less accurate and more limited in its application than the AGA Report No. 8 calculation. The BLM does not know if the PRCI NX-19 calculation results in statistically significant bias compared to the AGA Report No. 8 calculation, however.
Because high- and very-high-volume FMPs must meet uncertainty, bias, and verifiability requirements of § 3175.31(a), (c), and (d), respectively, the BLM believes it is appropriate to require the use of the latest calculation methodologies in API 14.3.3 (2013) and AGA Report No. 8 (1992) at these FMPs, whether they are new or existed as of January 17, 2017. Therefore, the BLM did not grandfather the calculation requirements of § 3175.103(a)(1) for high- and very-high-volume FMPs.
Low-volume FMPs do not have to meet the uncertainty requirements of § 3175.31(a), but they must still meet the bias and verifiability requirements of § 3175.31(c) and (d), respectively. Therefore, the BLM believes that allowing the use of the API 14.3.3 (1992) calculations at existing low-volume FMPs, where the differential pressure to static pressure ratio is less than those values in Table G.1, of API 14.3.3 (2013), Annex G, is acceptable. As stated previously, the use of the gas expansion equation in API 14.3.3 (1992) does not result in statistically significant bias when the differential pressure to static pressure ratio is less than those values in Table G.1.
Based on the foregoing, the BLM added § 3175.61(b)(2) which grandfathers existing low-volume FMPs from having to use the calculations in API 14.3.3 (2013) (required under § 3175.13(a)(1)(i)) when the differential pressure to static pressure ratio is less than those values specified in Table G.1 of API 14.3.3 (2013), Annex G. However, these FMPs must still use the calculations in API 14.3.3 (1992). If the differential pressure to static pressure ratio at an FMP, calculated using the monthly average values of differential pressure and static pressure, ever exceeds the values listed in Table G.1 of Annex G, the operator will have to upgrade the flow computer to use the latest calculation methodology in API 14.3.3 (2013). The BLM does not believe this restriction will result in significant cost to operators. The easiest and cheapest remedy for a high differential pressure to static pressure ratio is to install a larger orifice plate which will reduce the differential pressure and reduce the differential pressure to static pressure ratio below the limits in Table G.1.
The BLM did not grandfather the supercompressibility calculations for low-volume FMPs that use the older PRCI NX-19 equation because the BLM does not know whether the use of that equation results in statistically significant bias. In addition, the latest AGA Report No. 8 calculation has been available since 1992 and it is highly unlikely that any new or existing flow computer at a low-volume FMP would still be running the PRCI NX-19 calculations.
Very-low-volume FMPs only need to meet the verifiability requirements under § 3175.31(c). While the older calculation methodologies described above can result in higher uncertainty and statistically significant bias, the calculations are verifiable. Therefore, the BLM added § 3175.61(b)(1), which grandfathers existing very-low-volume FMPs from having to having to meet the calculation standards of § 3175.103(a)(1). However, existing very-low-volume FMPs must still run the calculations methodologies listed
One commenter suggested that if the BLM agreed to grandfather existing facilities, the operator could add 0.1 percent to the volume measured by the FMP to ensure the Federal Government or Indian tribes did not get shortchanged as a result of any inaccuracies in the existing equipment. The BLM disagrees with this comment. The BLM's goal in promulgating this rule is to ensure that the Federal Government and Indian tribes receive their fair share of royalty on the gas removed from their leases, based on accurate measurement, not to increase royalty payments. There is no reason to think that the royalty measurement problems this rule aims to address—inaccuracy, non-verifiability, and bias—result in a systematic 0.1 percent underestimate of volumes produced;
Some commenters stated that all very-low-volume wells should be automatically grandfathered. While the BLM does not provide a blanket grandfathering for all existing very-low-volume FMPs, the provisions of the final rule provide the same outcome. EGM software at very-low-volume FMPs is specifically grandfathered. In addition, all very-low-volume FMPs, existing and new, are exempt from many of the requirements of the rule, including those relating to uncertainty and bias, fluid conditions, Beta ratio limits, orifice plate inspections for newly drilled or re-fractured wells, flow conditioners, meter tube construction and condition, differential pen position (mechanical recorders), volume corrections, temperature measurement, sample probes and sample tubing, gauge lines and manifolds, EGM commissioning, and extended analysis. In addition, the BLM raised the very-low/low-volume threshold from 15 Mcf/day in the proposed rule to 35 Mcf/day in the final rule, which increased the number of FMPs falling within the very-low-volume category from approximately 21,500 FMPs to 35,700 FMPs. Thus, the BLM believes the final rule adequately addresses the commenters' concern about costs of compliance at very-low-volume wells.
Section 3175.70 requires 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 explained in subpart 3173. The BLM did not receive any comments on this section.
Section 3175.80 prescribes standards for the installation, operation, and inspection of flange-tapped orifice plate primary devices. The standards include requirements described in the rule as well as requirements described in API standards that are incorporated by reference. Table 1 to § 3175.80 is included 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 to § 3175.80 lists the subject area for which a standard exists. The second column of Table 1 to § 3175.80 contains a reference to the standard that applies to the subject area described in the first column. For subject areas where the BLM adopts an API standard verbatim, the specific API reference is shown. For subject areas where there is no API standard or the API standard requires additional clarification, the reference in Table 1 to § 3175.80 cites the paragraph in the section that addresses the subject area.
The final four columns of Table 1 to § 3175.80 indicate the categories of FMPs to which the standard applies. The FMPs are categorized by the amount of flow they measure on a monthly basis as follows: “VL” is very-low volume, “L” is low volume, “H” is high volume, and “VH” is very-high volume. Definitions for these various classifications are included in the definitions section in § 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 standard. The requirements of § 3175.80 vary depending on the average monthly flow rate being measured. In general, the higher the flow rate, the greater the risk of mismeasurement, and the stricter the requirements are.
Section 3175.80 adopts API 14.3.1, Subsection 4.1, which sets out requirements for the fluid and flowing conditions that must exist at the FMP (
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 most meters
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 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 and 4 inches in diameter. Because low-, high-, and very-high-volume FMPs all exceed 35 Mcf/day by definition, all FMPs within these categories and with line sizes of 4 inches or less, would operate at Reynolds numbers well above 4,000. Very-low-volume FMPs would be exempt from this requirement. Therefore, the requirement to maintain a Reynolds number greater than 4,000 does not represent a significant change from existing conditions. The requirement for maintaining a Reynolds number greater than 4,000 for low-, high-, and very-high-volume FMPs will 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.
Very-low-volume FMPs could fall below this limit, but are 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 very-low-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 will not significantly affect royalty, and the potential error in royalty is small compared to the potential loss of royalty if production were shut in. The BLM did not receive any comments on the adoption of API 14.3.1, Subsection 4.1, regarding required fluid and flowing conditions.
Section 3175.80 adopts API 14.3.2, Section 4, which establishes requirements for orifice plate construction and condition. Orifice plate standards in API 14.3.2, Section 4 are virtually the same as they are in the AGA Report No. 3 (1985). There are no exemptions to this requirement, 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. The BLM did not receive any comments on the adoption of API 14.3.2, Section 4 regarding orifice plate construction and condition.
Proposed § 3175.80 would have adopted API 14.3.2, Subsection 6.2, regarding orifice plate eccentricity for all categories of FMPs. As noted earlier in this preamble, the term “eccentricity” refers to the centering of the orifice plate in the meter tube. Eccentricity can affect the flow profile of the gas through the orifice and larger Beta ratio meters (i.e., meters with larger-diameter orifice bores relative to the diameter of the meter tube) are more sensitive to flow profile than smaller Beta ratio meters. For that reason, larger Beta ratio meters have a smaller eccentricity tolerance. In the proposed rule, the BLM specifically asked for data on the cost of this retrofit and on the number of meters that it may affect. The BLM received one comment objecting to the application of orifice plate eccentricity requirements to low- and very-low-volume FMPs. The commenter suggested that low- and very-low-volume FMPs should be exempt from this requirement because the only way to achieve this for older meter runs built to the 1985 API standards would be to replace the meter tube. The commenter stated that this would provide little benefit and would be cost prohibitive for these lower-volume meters. The BLM agrees with this comment and made several changes to the rule as a result. For very-low-volume FMPs, the BLM changed Table 1 to § 3175.80 to reflect that these FMPs are exempt from the eccentricity and perpendicularity requirements of API 14.3.2, Section 6.2. For low-volume FMPs, the rule grandfathers meter tubes existing at FMPs as of January 17, 2017 from meeting the eccentricity requirements of API 14.3.2, Subsection 6.2. However, the meter tube would still have to meet the eccentricity requirements of AGA Report No. 3 (1985) (see discussion of grandfathering under § 3175.61). The grandfathering also includes high-volume FMPs. Although this was not addressed in the comments, the BLM Threshold Analysis determined that it may be uneconomic to require operators to replace existing meter tubes at high-volume FMPs. All meter tubes at very-high-volume FMPs must meet the API 14.3.2, Subsection 6.2 standards for eccentricity.
Table 1 also requires the orifice plate to be installed perpendicularly to the meter tube axis as required in API 14.3.2, Subsection 6.2. Virtually all orifice plate holders, new and existing, maintain perpendicularity between the orifice plate and the meter-tube axis. The BLM did not receive any comments regarding the perpendicularity requirement.
Section 3175.80(a) defines the allowable Beta ratio range for flange-tapped orifice meters to be between 0.10 and 0.75, as recommended by API 14.3.2. The previous industry standard for orifice meters (AGA Report No. 3 (1985)) established a Beta ratio range between 0.15 and 0.70. In the early 1990s, additional testing was done on orifice meters, which resulted in an increased Beta ratio range and a more robust 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.
This section also applies the Beta ratio limits to low-volume FMPs. The elimination of statistically significant bias is one of the performance goals that applies to low-volume FMPs, and 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 14.3.2 is based on the inability to maintain edge sharpness in Beta ratios below 0.10. Therefore, if the BLM were to allow Beta ratios lower than 0.10 at low-volume FMPs, there would be the potential for bias.
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 maintains the upper Beta ratio limit in API 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.
Very-low-volume FMPs are exempt from any Beta ratio restrictions in the rule, as indicated in Table 1 to § 3175.80, because at very-low flow rates, it can be difficult to obtain a measureable amount of differential pressure with a Beta ratio of 0.10 or greater. The increased uncertainty and potential for bias associated with allowing a Beta ratio less than 0.10 on very-low-volume FMPs is offset by the ability to accurately measure a differential pressure and record flow.
The BLM received a few comments that stated that the Beta ratio range should be more restrictive, and recommended a range of 0.20 to 0.60 in
Section 3175.80(b) establishes a minimum orifice bore diameter of 0.45 inches for high-volume and very-high-volume FMPs. API 14.3.1, Subsection 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 less than 0.45 inches in diameter has not been specifically determined, the BLM cannot mathematically account for it when calculating overall measurement uncertainty under proposed § 3175.31(a). To ensure that high- and very-high-volume FMPs maintain the uncertainty required in § 3175.31(a), the BLM is prohibiting the use of orifice plates with bores less than 0.45 inches in diameter. Because there is no evidence to suggest that the use of orifice plates smaller than 0.45 inches in diameter causes measurement bias in low-volume and very-low-volume FMPs, they are allowed for use in these FMPs.
The BLM received several comments stating that this requirement should not apply to existing meters because it could force the operator to replace meter tubes in order to comply with Beta ratio requirements. The BLM does not understand why this requirement would necessitate replacing existing meter tubes and the commenters did not provide an explanation. One commenter stated that an orifice bore less than 0.45 inches is sometimes necessary in meters operating at the low end of the high-volume FMP category to raise the differential pressure to provide better measurement accuracy. The BLM disagrees with this comment. Even using the minimum high-volume FMP flow rate of 100 Mcf/day in the proposed rule, a 0.50-inch orifice plate (orifice plates are typically provided in 0.125-inch increments) would generate a differential pressure of 23 inches of water column,
Section 3175.80(c) requires orifice plate inspections upon installation and then every 2 weeks thereafter for FMPs measuring production from wells first coming into production or from existing wells that have been re-fractured. It is common for new wells and re-fractured 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. This requirement increases the orifice plate inspection frequency until it can be demonstrated that the production of particulate matter from a new well first coming into production or a re-fractured well has subsided. The once-every-2-week inspection requirement also applies to existing FMPs already measuring production from one or more other wells, which measures gas from a new well first coming into production or from a well that has been re-fractured.
Under this rule, once an inspection demonstrates that no detectable wear occurred over the previous 2 weeks, the BLM will consider the well production to have stabilized and the inspection frequency will revert to the frequency in Table 1 to § 3175.80. There are no exemptions 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 will not apply to very-low-volume FMPs anyway because rarely would a newly drilled well have only very-low-volume levels of gas production.
The BLM received several comments objecting to the once-every-2-week inspection requirement. One commenter stated that this frequency of inspections is not necessary unless there is evidence of plate degradation, while other commenters suggested the inspection frequency should be monthly instead of every 2 weeks. The BLM disagrees with these comments. The only way an operator would know if there was evidence of plate degradation is to pull and inspect the orifice plate. The BLM believes that orifice plate inspections every 2 weeks are important considering how much a dulled edge on an orifice plate can bias the measured flow rate, usually to the low side. Although the BLM did not make any changes to the inspection requirement, very-low-volume FMPs are no longer subject to this requirement because bias is not one of the performance criteria for the very-low-volume category.
The BLM received one comment stating that assessing whether there has been wear over the previous 2 weeks in order to determine if an orifice plate change is still necessary is subjective and recommended that the BLM provide guidance and training for BLM inspectors. Although the BLM does not agree that assessing an orifice plate is subjective, the BLM does agree that guidance and training are necessary. The BLM will include additional guidance in the enforcement handbook. The comment did not suggest any changes to the rule. The BLM did not make any changes to the rule based on this comment.
Several commenters objected to the proposed requirement that an operator must determine whether the orifice plate meets the eccentricity
The BLM added a phrase to the proposed rule, clarifying that the BLM considers a well that has been re-fractured to have the same impact on an orifice plate that a new well has, and therefore to require inspections every 2 weeks for re-fractured wells. Like new wells, re-fractured wells produce tremendous amounts of sand and grit during flow back and this sand and grit have the potential to quickly dull an orifice plate in the same manner as the sand and grit produced from a new well.
Section 3175.80(d) establishes a frequency for routine orifice plate inspections. The term “routine” in Table 1 to § 3175.80 is used to differentiate this requirement from § 3175.80(c) of this rule, which is related to new FMPs measuring production from new and re-fractured wells. Under this rule, the inspection frequency depends on the flow rate category the FMP is in. The required inspection frequency, in months, is given in Table 1 to § 3175.80. 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 are required. For high-volume and very-high-volume FMPs, the frequency of orifice plate inspections is every 3 months and every month, respectively. For very-low-volume FMPs, the frequency is every 12 months; and for low-volume FMPs, the frequency is every 6 months.
The BLM received multiple comments both criticizing and supporting the routine orifice plate inspection frequency required in § 3175.80(d). Those objecting to the requirement stated that the orifice plate inspection frequency should be based on need rather than on a fixed frequency, while others asserted that the proposed frequency was too high. Suggested frequencies include once every 1 or 2 years for all FMPs, annually for very-low-volume FMPs, semi-annually for low- and high-volume FMPs, and quarterly for very-high-volume FMPs. The BLM disagrees with these comments. Orifice plate condition, especially the condition of the upstream edge, is perhaps the most critical part of an orifice plate metering system. Even slight changes to the upstream edge of an orifice plate can cause significant bias in the measured flow rate, usually to the low side. The BLM believes that the frequency given in the proposed rule strikes a reasonable balance between the cost to the operator and the need for measurement accuracy. The BLM did not make any changes to the proposed rule based on these comments.
Two commenters suggested that the proposed schedule would be acceptable if the meter was equipped with a senior fitting (a fitting where the orifice plate can be removed without shutting off the flow of gas through the meter). The BLM accepts that orifice plate inspection is much easier and less costly when a senior fitting is used. If an operator makes a determination that it is in their best economic interest to install a senior fitting, they are free to do so. However, the type of plate holder has no bearing on how quickly a plate can become worn or dirty or how a worn or dirty orifice plate can affect measurement and, ultimately, royalty. The BLM did not make any changes to the rule based on this comment.
One commenter stated that orifice plate and meter tube inspection frequency should be left up to the operators, because the requirements in the proposed rule were too burdensome. Although the BLM did not make any changes to the rule based on this comment, changes to the rule based on other comments resulted in an estimated reduction in orifice plate and meter tube inspections costs to industry from $6.3 million per year in the proposed rule to $5.8 million per year in the final rule. The BLM does not consider either of these requirements to be overly burdensome.
One commenter suggested changing the terminology from “every 3 months” and “every 6 months” to “quarterly” and “semi-annually” to provide operators more flexibility. The BLM believes specifying the number of months between calibrations is clearer than the terminology suggested by the commenter. In addition, operators could imply that adoption of “quarterly” and “semi-annually” means an orifice plate inspection on a high-volume FMP could be performed at the beginning of one quarter and at the end of another quarter (January 1 and June 30, for example), which would essentially double the time between inspections. The BLM did not make any changes to the rule based on this comment.
In response to other comments on § 3175.100, the BLM changed the required verification frequency for high-volume FMPs from once every month to once every 3 months (see Table 1 to § 3175.100). This change means that routine orifice plate inspections no longer correspond to verifications for high-volume FMPs. To address this issue, the BLM removed the requirement that routine orifice plate inspections have to be performed at the same time an FMP is verified under § 3175.92 (mechanical recorders) or § 3175.102 (EGM systems).
Section 3175.80(e) requires operators to retain, and provide to the BLM upon request, documentation about 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 is a new requirement, many operators already record this information as part of their meter verifications. Thus, this requirement is not a significant change from prevailing industry practice. The BLM did not receive any comments on this paragraph.
Proposed § 3175.80(f) would have required all meter tubes to be constructed in compliance with current API standards. This proposed requirement would not have included meter tube lengths, which are addressed in proposed § 3175.80(k). The BLM has reviewed the API standards referenced and believes that they meet the intent of § 3175.31 of the rule.
Proposed § 3175.80(f)(1) and (2) would have included an exception allowing all low-volume FMPs to continue using the tolerances in the AGA Report No. 3 (1985). While the BLM recognizes this could result in higher uncertainty than meter tubes meeting the tolerances of API 14.3.2, it is not imposing uncertainty requirements for low-volume FMPs. In the final rule, this exception is moved to § 3175.61 and paragraphs (1) and (2) of proposed § 3175.80(f) were eliminated. This means that only
The BLM received numerous comments arguing that existing meter tubes should be grandfathered because the only way to comply with the new standards is to replace the meter tube, and this would be very costly. Some commenters questioned the benefit of replacing existing meter tubes. The commenters also suggested that the BLM should hold the operator to the meter-tube standard in place at the time the meter tube was installed. The BLM agrees with these comments, with respect to low- and high-volume FMPs, and has grandfathered existing meter tubes at those FMPs (see the discussion under § 3175.61). To account for the additional uncertainty that may be present in pre-2000 meter tubes, the BLM will add an uncertainty of ±0.25 percent to the discharge coefficient when determining the overall meter uncertainty, unless the operator provides sufficient data to show that the additional uncertainty in discharge coefficient when the meter tube is constructed to the tolerance of the 1985 standard is less than ±0.25 percent (see § 3175.61(a)). The BLM believes that, in the absence of data to the contrary, the ±0.25 percent uncertainty is a reasonable assumption based on its experience with orifice plate test data.
Section 3175.80(g) addresses isolating flow conditioners and tube-bundle flow straighteners. To achieve the orifice plate uncertainty stated in API 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 14.3.1 is discussed in § 3175.80(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.
Section 3175.80(g) allows isolating flow conditioners to be used at FMPs if they have been approved by the BLM pursuant to § 3175.46 of this rule, or 19-tube-bundle flow straighteners constructed in compliance with API 14.3.2, Subsections 5.5.2 through 5.5.4, and located in compliance with API 14.3.2, Subsection 6.3. Use of 19-tube-bundle flow straighteners constructed and installed under these API standards does not require BLM approval. The rule requires a tube-bundle flow straightener, if used, to comply with API 14.3.2, Subsections 5.5.2 through 5.5.4 and 6.3, because data have shown that these installations produce almost no additional uncertainty of the discharge coefficient and the small amount of additional uncertainty is accounted for in the determination of overall uncertainty. This rule prohibits 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 meters. Without the ability to use either 7- or 19-tube-bundle flow straighteners, 2-inch meters are required to be retrofitted to either: (1) Use a proprietary type of isolating flow conditioner approved in accordance with § 3175.46; or (2) Not have a flow conditioner, which typically requires much longer lengths of pipe upstream of the orifice plate. The rule's requirements with respect to isolating flow conditioners will increase consistency and eliminate the time and expense it takes to apply for and obtain a variance for each FMP.
As indicated in Table 1 to § 3175.80, very-low-volume FMPs are exempt from the requirement to retrofit because the costs involved are believed to outweigh the benefits based upon experience with these production levels.
A few comments on the proposed rule indicated that replacing 7-tube bundles on 2-inch meter tubes will be costly, and suggested that the BLM grandfather meter tubes that comply with the API standard in place when the meter tube was installed. Although the BLM has grandfathered existing meter tubes for perpendicularity, eccentricity, construction and condition, and meter tube length, the BLM did not grandfather existing flow conditioners, including tube bundles on low-, high-, and very-high-volume FMPs. While the grandfathering of the other meter tube aspects can increase the uncertainty of an orifice plate meter, the BLM is not aware of any evidence that they cause bias in the measurement. The design of tube-bundle flow straighteners can, however, cause bias. Because the elimination of statistically significant bias is one of the performance standards in § 3175.31 for low-, high-, and very-high-volume FMPs, the BLM did not make any changes in the final rule based on these comments. The BLM does not believe that requiring existing meter tubes to comply with the new API standards for the design of tube bundles is cost-prohibitive. If the meter tube has a 7-tube bundle, or a tube bundle that does not comply with API 14.3.2, Subsections 5.5.2 through 5.5.4, the operator can replace the tube bundle with an isolating flow conditioner for a few hundred dollars. If the meter tube has an isolating flow conditioner that has not been approved by the BLM, then the operator can replace that isolating flow conditioner with one that has been approved by the BLM. If the operator uses a 19-tube bundle that is located in accordance with the 1985 AGA standard, the BLM deems that this will also comply with the requirements of API 14.3.2, Subsection 6.3 if the Beta ratio is less than 0.5 (see the discussion under § 3175.80(k)).
Proposed § 3175.80(h) would have required an internal visual inspection of all meter tubes at the frequency, in years, shown in Table 1 to § 3175.80. The visual inspection would have had 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 the proposed rule.
The BLM received many comments stating that borescopes are expensive and have potential safety hazards due to the explosive environment in which they operate. The BLM agrees that the use of borescopes could require additional safety measures and could cause operators to incur significant costs. As a result of these comments, the BLM eliminated the reference to borescopes and made the standards entirely performance-based. The BLM also changed the name of the requirement to a “basic inspection”
The BLM received several comments addressing the cost burden of performing basic inspections, although no cost figures were included with the comments. The BLM did not make any changes to the proposed rule based on these comments because the BLM believes that basic inspections can be done at relatively little cost. These costs are included in the BLM Threshold Analysis and in the Economic and Threshold Analysis.
Several commenters suggested that the BLM should require a visual inspection only if an orifice plate inspection indicated problems, and that the BLM should train inspectors to recognize when a visual inspection is needed. While the BLM agrees that orifice plate inspections can give some indication as to meter tube problems (such as liquid and grease buildup), they are not reliable. For example, if debris plugged a flow conditioner or a tube-bundle flow straightener, this could have a significant effect on the accuracy of the meter and would not be detected by merely pulling and inspecting the orifice plate. The BLM did not make any changes to the proposed rule based on these comments.
One commenter stated that shutting in wells to perform visual inspections could cause reservoir damage and lower royalty. While there is always some possibility of reservoir damage when shutting in a well, the BLM does not believe this risk is significant enough to warrant the elimination of this requirement. If that were the case, then wells could never be shut in for orifice plate inspections or other routine maintenance. The commenter did not provide any data or studies to substantiate their claim. If an operator demonstrated that this was an issue for a particular well, they could request a variance from the AO. The BLM did not make any changes based on this comment.
Numerous comments objected to the frequency of visual inspections as proposed in Table 1 to § 3175.80. Suggestions for inspection frequency ranged from every 3 years to every 10 years. The BLM did not make any changes to the rule based on these comments because none of the commenters submitted a rationale for their suggested frequencies. The BLM believes the frequencies presented in the proposed rule represent a balance between economic considerations and ensuring accurate measurement of Federal and Indian gas resources.
The BLM removed paragraph (h)(5) of the proposed rule out of concern that operators could have misinterpreted it to mean that a detailed inspection would have been required to meet the standards of a basic inspection. Any type of inspection that can identify obstructions, pitting, and a build-up of foreign substances qualifies as a basic inspection, which includes a detailed inspection as described in paragraph (i) of this section. However, a detailed inspection is not required to meet the standards under § 3175.80(h).
Proposed § 3175.80(i) would have required a detailed inspection of meter tubes on high- and very-high-volume FMPs at the frequency, in years, shown in Table 1 to § 3175.80 (10 years for high-volume FMPs and 5 years for very-high-volume FMPs). Under the proposed rule, the AO could have increased this frequency, and could have required a detailed inspection of low-volume FMPs, if the visual inspection identified any issues regarding compliance with incorporated API standards, or if the meter tube operated in adverse conditions (such as corrosive or erosive gas flow), or had signs of physical damage. The goal of the inspection is to determine whether the meter is in compliance with required standards for meter-tube construction. Meter tube inspections would have been required more frequently for very-high-volume FMPs because there is a higher risk of volume errors and, therefore, royalty errors in higher-volume FMPs. Very-low-volume FMPs would have been exempt from the inspection requirement because they would be exempt from the construction standards of API 14.3.2.
Several commenters indicated that detailed meter tube inspections are expensive and present safety issues. Other commenters suggested that the BLM should only require a detailed inspection if the visual inspection indicated it was warranted. Several commenters objected to a single visual inspection leading to a frequency change in the number of detailed inspections on an FMP. Several commenters suggested that the proposed detailed meter tube inspection frequency was inadequate. The BLM agrees with the comments and made several changes to this paragraph as a result. First, the BLM eliminated routine detailed inspections; under the final rule, the BLM will require a detailed inspection only if the findings from a basic inspection warrant a detailed inspection. Second, if a basic inspection reveals the presence of obstructions or buildup of material at a low-volume FMP, the operator will only have to clean the meter tube. For high-volume FMPs, the operator must ensure the meter tube meets all the relevant standards relating to meter tubes before returning the meter to service. For meter tubes installed after January 17, 2017, the relevant standard is API 14.3.2, Subsections 5.1 through 5.4 and 6.2, incorporated by reference in this rule. For meter tubes installed before January 17, 2017, the relevant standard is AGA Report No. 3, which has been incorporated by reference in this rule. For very-high-volume FMPs, regardless of when they were installed, the operator must ensure the meter tube complies with the applicable provisions of API 14.3.2, incorporated by reference in this rule.
One commenter objected to detailed meter tube inspections under any circumstance, while another commenter recommended that the BLM could adjust the frequency of both basic and detailed meter tube inspections based on the findings of previous inspections. The BLM did not make any changes to the rule based on these comments. The BLM believes detailed inspections are required to ensure accurate measurement. While the BLM agrees that an operator could justify a change in the frequency in certain instances, this should be handled through the variance process on a case-by-case basis.
Section 3175.80(j) requires operators to keep documentation of all detailed meter tube inspections to be made available to the BLM upon request. The BLM will use this documentation to establish that the inspections meet the requirements of the rule, for auditing purposes, and to track the rate of change in meter tube condition to support an operator's request for a change of inspection frequency. Very-low-volume FMPs are exempt from this requirement because no meter tube inspections are required. The BLM did not receive any
Proposed § 3175.80(k) would have incorporated the standards of API 14.3.2 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 previous discussion of swirl and asymmetry in § 3175.80(g)). As indicated in Table 1 to § 3175.80, very-low-volume FMPs are 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, especially when the Beta ratio is 0.5 or greater. 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 14.3.2 was published in 2000 (and later updated in 2016), 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 14.3.2 in 2000 should already comply with the more stringent requirements for meter tube length and tube-bundle placement.
Because the meter tube lengths in API 14.3.2 are required to achieve the stated uncertainty, § 3175.80(k)(1) would have adopted 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 before 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. However, the BLM Threshold Analysis shows that it would be uneconomic for operators of high-volume FMPs to retrofit the meter tubes to comply with the length requirements in API 14.3.2. Therefore, the final rule grandfathers the meter tube length requirements for the anticipated handful of high-volume FMPs existing before the effective date of the rule (see § 3175.61(a)) that continue to measure high-volume flow rates of gas even after 16 years of production (from 2000 to 2016). These grandfathered FMPs would still have to meet the meter tube length requirements of AGA Report No. 3 (1985). If the meter tube contains a 19-tube bundle flow straightener or isolating flow conditioner, the location of that straightener or flow conditioner will not be grandfathered and will still have to comply with § 3175.80(g). The meter tubes at very-high-volume FMPs were not grandfathered in the final rule.
While low-volume FMPs would not be subject to the uncertainty requirements under § 3175.31(a), they still would have to be free of statistically significant bias under § 3175.31(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 also would have been subject to the meter tube length requirements of API 14.3.2 under proposed § 3175.80(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 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. The BLM received many comments requesting that the BLM grandfather existing meter tubes from the meter tube length requirements of this paragraph due to the high cost and questionable benefit of this requirement. The commenters also suggested that the BLM should hold the operator to the meter tube standard in place at the time the meter tube was installed. The BLM agrees with these comments and has grandfathered existing meter tubes at low- and high-volume FMPs (see discussion under § 3175.61). To account for the additional uncertainty that may be present on pre-2000 meter tubes, the BLM will add an uncertainty of ±0.25 percent to the discharge coefficient when determining the overall meter uncertainty, unless the operator provides sufficient data to show that the additional uncertainty in discharge coefficient when the meter tube is constructed to the tolerances of the 1985 standard is less than ±0.25 percent. The BLM believes that, in the absence of data to the contrary, the ±0.25 percent uncertainty is a reasonable assumption based on its experience with orifice plate test data.
Proposed § 3175.80(k)(2) would have allowed 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 show the shorter meter tube lengths required in the AGA Report No. 3 (1985) result in statistically significant bias.
The BLM received numerous comments requesting that the BLM grandfather existing meter tubes from the tube bundle location requirements of this paragraph, based on API 14.3.2. Test data have shown that statistically significant measurement bias can occur if the 19-tube-bundle straightening vane is placed at the location required by the 1985 API standard. Because low-, high-, and very-high-volume FMPs are subject to the performance standard in § 3175.31(c), which prohibits statistically significant bias, the BLM did not grandfather flow conditioners, including the required location of 19-tube bundle flow straighteners. However, the BLM has determined that the tube-bundle placement requirements in the 1985 API standards are generally consistent with the tube-bundle placement requirements in the 2000 API standards for Beta ratios less than 0.5. Therefore, the BLM has revised this paragraph to make it clear that the BLM considers tube bundles installed under the 1985 standard to be in compliance with the 2000 standard when the Beta ratio is less than 0.5. In addition, the BLM moved the meter tube length requirements for existing FMPs from this paragraph to the grandfathering section (see § 3175.61(a)).
Section 3175.80(l) sets standards for thermometer wells, including the adoption of API 14.3.2, Subsection 6.5, in § 3175.80(l)(1). While the provisions of the API standard proposed for adoption in the proposed rule were the same as those in the AGA Report No. 3, several additional items would have
The BLM received several comments on this section. Two of the commenters stated that the difference between the actual and measured gas temperatures at low-, high-, and very-high-volume FMPs is not significant because the flow rate is high enough to distribute the temperature within the pipe. Another commenter stated that the thermal effects are only significant if the thermometer is inserted less than 6 inches into the pipe. Neither of the commenters submitted any data to substantiate their claim, and the BLM was unable to obtain any studies on this subject. The vast majority of FMPs on Federal and Indian leases are 4 inches in diameter or less; therefore the comment regarding thermometer insertion depths of 6 inches is generally irrelevant. Because the BLM could not substantiate the claims by commenters, the BLM did not make any changes to the rule based on these comments.
The BLM also received a few comments recommending that operators could meet the intent of the requirement by insulating the meter tube, which would eliminate the need to move a thermometer well into a heated meter house, for example. The BLM agrees with these comments and added the option of insulating the meter run and adding heat tracing to the meter run. This change is also consistent with API 14.3.2, Subsection 6.6, which recommends insulating the meter tube in the case of temperature differences between the ambient temperature and the temperature of the flowing fluid. It is difficult to define with any uniformity what level of insulation is needed to meet the intent of this requirement due to regional and local variations in operating conditions. Therefore, the BLM did not establish specific requirements with respect to insulation in the final rule and, instead, opted for language that states that the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the thermometer well in relation to the orifice plate (
Section 3175.80(l)(3) applies 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 primary thermometer. API does not specify which thermometer well should be used as the primary thermometer. To minimize measurement bias, the gas temperature should be taken as close to the orifice plate as possible. When more than one thermometer well exists, the thermometer well closest to the primary device will generally result in less measurement bias, and therefore, the rule specifies that this thermometer well is the one that must be used for the flowing temperature measurement. The BLM did not receive any comments on this paragraph.
Section 3175.80(l)(4) requires 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 rule includes a new requirement that a thermally conductive liquid be used in the thermometer well because this would provide a more accurate temperature measurement. The BLM did not receive any comments on this paragraph.
Section 3175.80(m) requires operators to locate the sample probe as required in § 3175.112(b). The reference to § 3175.112(b) is in § 3175.80(m) because the sample probe is part of the primary device. Please see the discussion of § 3175.112(b) for an explanation of the requirement. The BLM did not receive any comments on this paragraph.
Proposed § 3175.80(n) would have included a 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. Because meter tube inspections would not have been required for very-low-volume FMPs under the proposed rule, they would have been exempt from this requirement.
Several commenters questioned the practicality of performing a detailed inspection on a new pre-fabricated meter tube. The commenters wondered if they would have to disassemble the meter tube in order for the BLM to witness the inspection. Other commenters stated that the 72-hour notice requirement to inspect new meter tubes is impractical for pre-fabricated meter tubes, presumably because the meter tube could be delivered to the FMP on very short notice.
The BLM agrees with these comments and made numerous changes to this section as a result of these comments and to further clarify the notification requirement. First, the BLM moved the notification requirements of proposed § 3175.80(n) into § 3175.80(h) and (i). The notification requirement in § 3175.80(h)(3) requires the operator to notify the BLM within 72 hours of performing a basic inspection or submit a monthly or quarterly schedule of basic meter tube inspections to the AO. The notification requirement in § 3175.80(i)(3) requires the operator to notify the BLM at least 24 hours before performing a detailed inspection. The requirement for notification of a detailed inspection is different from that of a basic inspection because detailed inspections are no longer routine and cannot be scheduled. Second, the BLM reduced the notification requirement from 72 hours to 24 hours for detailed inspections because some operators may perform a detailed inspection immediately after discovering problems during a basic inspection. Third, to address the comments directly, the BLM added language (see § 3175.80(i)(2)) that allows operators to submit documentation showing that the meter tube complies with the construction requirements of this rule in lieu of disassembling and inspecting the meter tube. This language specifically applies to pre-fabricated meter tubes where the pre-fabrication shop supplies the operator with a specification sheet
One commenter questioned what would happen if the BLM cannot witness a meter tube inspection. The operator's only obligation is to notify the BLM of the inspection within the required timeframes. If the BLM does not attend, the operator may proceed with the inspection. The BLM did not make any changes to the rule based on this comment.
Section 3175.90(a) limits the use of mechanical recorders, also known as chart recorders, to very-low- and low-volume FMPs. Mechanical recorders will not be allowed at high- and very-high-volume FMPs because they may not be able to meet the uncertainty requirements of § 3175.31(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 are no data indicating that the use of mechanical recorders results in statistically significant bias, mechanical recorders are allowed at very-low- and low-volume FMPs due to the limited production from these facilities.
Table 1 to § 3175.90 was developed to clarify and provide easy reference to the requirements that apply to different aspects of mechanical recorders. No industry standards are cited in Table 1 to § 3175.90 because there are no industry standards applicable to mechanical recorders. The first column of Table 1 to § 3175.90 lists the subject of the standard. The second column of Table 1 to § 3175.90 identifies the section and specific paragraph in the rule that apply to each subject area. (The standards are prescribed in §§ 3175.91 through 3175.94.)
The final two columns of Table 1 to § 3175.90 indicate the FMPs to which the standard applies. The FMPs are categorized by the amount of flow they measure on a monthly basis as follows: “VL” is a very-low-volume FMP and “L” is a low-volume FMP. As noted previously, mechanical recorders are not allowed at high- and very-high-volume FMPs; therefore, Table 1 to § 3175.90 does not include corresponding columns for them. Definitions for the various FMP categories are given in § 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 requirement.
The BLM received a comment stating that mechanical recorders should be prohibited because they cannot meet the uncertainty requirements required in § 3175.31 (§ 3175.30 in the proposed rule). The BLM did not make any changes to the rule as a result of this comment because the uncertainty requirements in § 3175.31 do not apply to very-low- and low-volume FMPs, and mechanical recorders are not allowed on any other FMPs.
One commenter stated that if the BLM was going to continue to allow mechanical recorders, the recorders at very-low-volume FMPs should meet the same requirements as mechanical recorders at low-volume FMPs. The BLM disagrees. The exemptions for very-low-volume FMPs were provided to reduce the risk that an operator might choose to shut in production instead of upgrading the meter. The BLM did not make any changes to the rule based on this comment.
Section 3175.91(a) sets requirements for gauge lines. 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 have required a minimum gauge line internal diameter of
The BLM received numerous comments regarding the proposed requirement of
Proposed § 3175.91(a)(2) would have allowed 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.
The BLM received a few comments objecting to the requirement of stainless steel gauge lines because many operators have carbon steel gauge lines that would have to be replaced, resulting in excessive cost and a negligible benefit to measurement accuracy. The commenters stated that carbon steel gauge lines should be acceptable in most situations and that stainless steel should only be required in corrosive environments. The BLM's primary concern in proposing stainless steel gauge lines is that the use of plastic lines could lead to loops or sags that could trap liquids. The BLM agrees with these comments and removed the requirement for gauge lines to be constructed of stainless steel. The BLM added language to § 3175.91(a)(2) (§ 3175.91(a)(3) in the proposed rule) that prohibits visible sag in the gauge line.
Section 3175.91(a)(2) requires 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. The BLM did not receive any comments on this section, although it added the phrase regarding sags as discussed above.
Requirements in § 3175.91(a)(3) through (6) 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 14.3.2, Subsection 5.4.3, recommends that gauge lines be the same diameter along their entire length, which the BLM adopted as a standard in § 3175.91(a)(3).
Section 3175.91(a)(4) and (5) 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 allow only the static-pressure connection in a gauge line and 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, heaters, and other equipment. Section 3175.91(a)(6) limits the gauge lines to 6 feet in length, again to minimize the gas contained in the gauge lines.
As indicated in Table 1 to § 3175.90, very-low-volume FMPs are exempt from the requirements of § 3175.91(a) because any bias or uncertainty caused by improperly designed gauge lines of very-low-volume FMPs would not have a significant royalty impact.
The BLM received a few comments objecting to these requirements because they would eliminate the use of drip pots, which, according to the commenters, are required in some areas to prevent freezing. The BLM did not make any changes to the rule based on these comments because, if freezing is an issue, then it must be resolved by properly sloping gauge lines to avoid the accumulation of liquids, rather than by using drip pots.
Section 3175.91(b) requires that the differential pressure pen record at a minimum reading of 10 percent of the differential-pressure bellows range for the majority of the flowing period. The integration of the differential pen when it is 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. Very-low-volume FMPs are exempt from this requirement due to the cost associated with compliance.
The BLM received a few comments stating that this should not apply to inverted charts since the chart inversion yields better resolution for integration. With an inverted chart, the differential pen is moved to record on the opposite side of the chart as it normally would be. In this configuration, when the differential pressure pen is reading zero, it rests on the outer line of the chart and as the differential pressure increases, it moves closer to the hub. By moving the zero line from the hub of the chart to the outer edge of the chart, the integrator is better able to distinguish the “zero” line from the differential pen trace. The BLM agrees with this comment and added an exception for inverted charts to § 3175.91(b).
Section 3175.91(c) requires the flowing temperature to be continuously recorded and used in the volume calculations under § 3175.94(a)(1) for low-volume FMPs (as provided in Table 1 to § 3175.90). Flowing temperature is needed to determine flowing gas density, which is critical to determining flow rate and volume. 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 § 3175.31(c) prohibits statistically significant bias for low-volume FMPs, the rule requires continuous recorders for low-volume FMPs, but not for very-low-volume FMPs, as specified in Table 1 to § 3175.90.
The BLM received a few comments objecting to the cost to retrofit the recording device with a third pen to continuously record temperature. The commenters stated that temperature could be based on a fixed temperature or with a separate temperature recorder. The final rule does not require the temperature to be recorded on the same chart as the differential and static pressure; therefore, recording temperature on a separate temperature recorder would satisfy this requirement. A fixed temperature would be allowed for very-low-volume FMPs, but is not allowed for low-volume FMPs because of the potential for bias. The BLM did not make any changes to the rule based on these comments. The BLM included the cost of adding a temperature recorder (assumed to cost $500) in determining the upper limit of the very-low-volume FMP category (see the BLM Threshold Analysis for subpart 3175 Flow Category Tiers).
Section 3175.91(d) requires certain information to be available onsite at the FMP and available to the AO at all times. This requirement allows the BLM to calculate the average flow rate indicated by the chart and to verify compliance with this rule. The information that is required under § 3175.91(d)(2), (3), (7), and (8) typically is already available onsite. 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.
The information that the operator must retain onsite at the FMP under § 3175.91(d)(1), (4), (5), (6), (9), (10), (11), (12), and (13) was not previously required and thus typically has not been maintained onsite as a matter of practice. The information required in these paragraphs include: The differential-pressure-bellows range; the static-pressure-element range; the temperature-element range; the relative density (specific gravity) of the gas; the units of measure for static pressure (pounds per square inch absolute (psia) or pounds per square inch gage (psig)); the meter elevation; the orifice bore or other primary-device dimensions necessary for device verification, Beta- or area-ratio determination and gas volume calculation; make, model, and location of approved isolating flow conditioner (if used); the location of the downstream end of 19-tube-bundle flow straighteners (if used); the date of the last primary-device inspection; and the date of the last meter verification.
The BLM received a few comments stating that the information was generally on the back of the flow chart and would satisfy the requirement of § 3175.91(d). The BLM did not make any changes to the rule based on these comments. The BLM inspectors are instructed not to manipulate measurement equipment, which includes removing flow charts from the recorder to access the information on the back of the chart, because of concerns for safety and liability.
Section 3175.91(e) requires 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
Section 3175.92(a) sets requirements for the verification and calibration of mechanical recorders upon installation or after repairs, and defines the procedures that operators must follow. The rule differentiates the procedures that are specific to this type of verification from a routine verification that is required under § 3175.92(b). The BLM did not receive any comments on any of the requirements under § 3175.92(a) or paragraphs (a)(1) through (7) of this section.
Section 3175.92(a)(1) requires the operator to perform a successful leak test before starting the mechanical recorder verification. The rule specifies the tests that operators must perform. The BLM is requiring 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 successful leak test is required to precede a verification.
Section 3175.92(a)(2) requires that the differential- and static-pressure pens operate independently of each other, which is accomplished by adjusting the time lag between the pens. Examples of appropriate time lag are given for a 24-hour chart and an 8-day chart because these are the charts that are normally used as test charts for verification and calibration.
Section 3175.92(a)(3) requires a test of the differential pen arc.
Section 3175.92(a)(4) requires 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-pressure- element ranges. Using this set of verification points helps 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 psia instead of 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 § 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 are not available for a newly installed or repaired recorder.
Section 3175.92(a)(5) requires 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 requirement ensures that the temperature element is recording accurately over the range of expected flowing temperature.
Section 3175.92(a)(6) establishes 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 1 to § 3175.92, 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. Our experience over the last three decades indicates that a zero error is unattainable.
Section 3175.92(a)(7) establishes standards for when the static-pressure pen is offset to account for atmospheric pressure. The equation used to determine atmospheric pressure is discussed in Appendix A to this rule. This rule adds 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.
Section 3175.92(b) establishes requirements for how often a routine verification must be performed, with the minimum frequency, in months, shown in Table 1 to § 3175.90. The rule requires verification every 3 months for a low-volume FMP and every 6 months for a very-low-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 very-low-volume FMPs because chart recorders tend to drift more than the transducers of an EGM system.
The BLM received one comment regarding the proposed 6-month routine verification frequency for very-low-volume FMPs. The commenter stated that if chart recorders are permitted, routine verification should occur every 3 months, although no rationale was given by the commenter. The BLM did not make any changes to the rule based on this comment. The BLM believes that a 6-month routine verification frequency is adequate for very-low-volume FMPs because the volumes measured by very-low-volume FMPs are low enough that errors in the mechanical recorder will not have a significant effect on royalty.
Section 3175.92(c) establishes procedures for performing a routine verification. These procedures vary from the procedures used for verification after installation or repair, which are discussed in § 3175.92(a). The BLM did not receive any comments on any of the requirements under § 3175.92 (c).
Section 3175.92(c)(1) requires that a successful leak test be performed before starting the verification. See the previous discussion of leak testing under § 3175.92(a)(1). Section 3175.92(c)(2) prohibits any adjustments to the recorder until the as-found verifications are obtained. It is general industry practice to obtain the as-found readings before making adjustments. However, some adjustments are specifically prohibited under this 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 a volume correction would be required under § 3175.92(f). This section makes it clear that no adjustments, including the previous example, are allowed before obtaining the as-found values.
Section 3175.92(c)(3) requires 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. The verification points were
Section 3175.92(c)(3)(i) requires that an as-found verification be done at a point that represents where the differential and static pens normally operate. This section requires verification at the points where the pens normally operate only if there is enough information onsite to determine where these points are.
Section 3175.92(c)(3)(ii) establishes additional requirements if there is not sufficient information onsite 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 are required at 5 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 verification points are required at the lower end to allow the calculation of flow-rate error throughout the range of the differential and static pressure elements.
Section 3175.92(c)(4) establishes 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.
Section 3175.92(c)(5) establishes 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 § 3175.92(c)(3) or (4), are not within these thresholds, the element must be calibrated. For a discussion of the thresholds, see the previous discussion in § 3175.92(a)(6) and (7).
Section 3175.92(c)(6) requires 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 in § 3175.92(a)(3) for further explanation of this requirement.
Section 3175.92(c)(7) requires a test of the differential-pen arc.
Section 3175.92(c)(8) requires an as-left verification if an adjustment to any of the meter elements was made. Obtaining as-left readings whenever a calibration is performed is standard industry practice. The purpose of the as-left verification is to ensure that the calibration process, required in § 3175.92(c)(5) through (7), was successful before returning the meter to service.
Section 3175.92(c)(9) establishes 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 § 3175.92(c)(3) and (4), are not within the thresholds shown in Table 1 to § 3175.92, the element must be replaced and verified under § 3175.92(c)(5) through (7).
Section 3175.92(c)(10) establishes standards if the static-pressure pen is offset to account for atmospheric pressure. Please see previous discussion in § 3175.92(a)(7) for further explanation of this requirement. Very-low-volume FMPs are not exempt from any of the verification or calibration requirements in § 3175.92(c) because these requirements do not result in significant additional cost and are necessary for the BLM to verify the measurement. The BLM did not receive any comments on this provision, and therefore did not make any changes to the rule.
Section 3175.92(d) specifies the documentation that must be generated and retained by operators in connection with each verification. This information includes: 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) if the orifice plate is pulled and inspected; 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.
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 § 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 rule includes 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 rule requires the primary-device documentation because the primary device is pulled and inspected at the same time that the operator performs a mechanical-recorder verification. Although the BLM did not receive any comments on this section, it added language that the primary device data are only required if the primary device is pulled and inspected during the verification. For very-low- and low-volume FMPs, operators must inspect the primary device every 12 months and every 6 months, respectively. However, for mechanical recorders, verifications are required every 6 months and every 3 months, respectively. Therefore, the operator is only required to pull and inspect the primary device every other time they perform a verification.
Proposed § 3175.92(e) would have required the operator to notify the AO at least 72 hours before verification of the recording device. A 72-hour notice would be sufficient for the BLM to rearrange schedules, as necessary, to allow the AO to be present at the verification.
The BLM received a few comments stating that the 72-hour notification would require a great deal of coordination. The BLM agrees with this comment and has included an alternative to submit a monthly or quarterly verification schedule to the AO. The submittal of monthly or quarterly schedules in lieu of the 72-
Proposed § 3175.92(f) would have required 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. 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 (as required under Order 5) 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 that would have been allowed to be measured with a chart recorder in the proposed rule. Very-low-volume FMPs are 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 were to discover that an FMP measuring 15 Mcf/day is 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 OGORs and it could take several hours for both the BLM and ONRR to review and process those reports.
This paragraph also defines 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.
Although the BLM did not receive comments on this section, an example is added to clarify the flow-rate error correction. The BLM added the example because this calculation tends to cause confusion among both the BLM staff and industry. The BLM also changed the 2 Mcf/day threshold to “2 percent or 2 Mcf/day, whichever is greater.” In the proposed rule, the low-/high-volume threshold was 100 Mcf/day; therefore, for a low-volume FMP, a flow rate error of 2 Mcf/day would always have been at or above 2 percent of the total flow rate. However, in the final rule, the low-/high-volume threshold was raised to 200 Mcf/day. For average flow rates between 100 Mcf/day and 200 Mcf/day, which can now be measured with a mechanical recorder, a fixed threshold of 2 Mcf/day would be less than 2 percent of the flow rate. Therefore, the BLM added the 2 percent threshold to be consistent with the requirements for EGM systems (§ 3175.102(g)).
Section 3175.92(g) requires verification equipment to be certified at least every 2 years. The purpose of this requirement is 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. This paragraph also requires that proof of certification be available to the BLM and sets minimum standards as to what the documentation must include. The BLM did not receive any comments on this paragraph.
Section 3175.93 establishes 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.
The BLM received one comment stating that the time of retention is not mentioned. The BLM did not make any changes to the rule based on this comment. Retention time is defined in 43 CFR 3170.7.
Section 3175.94(a) establishes the methodology for determining volume from the integration of a chart. The methodology includes the adoption of the equations published in API 14.3.3 or AGA Report No. 3 for flange-tapped orifice plates. Under this rule, operators using mechanical recorders have the option to continue using the older AGA Report No. 3 flow equation. (Operators using EGM systems, on the other hand, are required to use the flow equations in API 14.3.3 (see § 3175.103.))
There are three primary reasons for allowing mechanical recorders to use a less strict standard. First, chart recorders, unlike EGM systems, are restricted to FMPs measuring 200 Mcf/day or less. Therefore, any errors caused by using the older 1985 flow equation will not have nearly as significant an effect on measured volume or royalty as 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 200 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. In the proposed rule, the BLM sought data on the cost for chart integration companies to switch over to the new API 14.3.3 flow rate. The BLM did not receive any such data.
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 as a function of Reynolds number, Beta ratio, and line size. Further, the gas expansion factor was changed based on a more rigorous screening of valid data points. The current flow equation also requires an iterative calculation procedure instead of an equation that can be solved directly by hand, providing a more accurate flow rate. The difference in flow rate between the two equations, given the same input parameters, is less than 0.5 percent in most cases.
While API 14.3.3 provides equations for calculating instantaneous flow rate, it is silent on determining volume. Therefore, the methodology presented in API 21.1 for EGM systems is adopted 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.
The BLM received one comment that supported chart integration companies switching to the 1992/2013 volume calculation. The BLM did not make any changes to the rule based on this comment as there was no change requested.
Section 3175.94(a)(3) defines the source of the data that goes into the flow equation. The BLM did not receive any comments on this requirement.
Section 3175.94(b) establishes 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. This rule eliminates 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—a condition that is common at FMPs.
This rule also eliminates the option of operators measuring actual atmospheric pressure at the meter location for mechanical recorders. Instead, atmospheric pressure must be determined from an equation or table (see appendix A to this subpart) 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 requirement would have no significant impact on current industry practice. The treatment of atmospheric pressure for mechanical recorders is different than it is for EGM systems because many EGM systems measure absolute pressure, whereas all mechanical recorders are gauge-pressure devices. Please see the discussion of § 3175.102(a)(3) for further analysis.
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 A to this subpart, produces similar results to the equation normally used for atmospheric pressure for elevations less than 7,000 feet mean sea level (see Figure 3). The BLM did not receive any comments on the change in how atmospheric pressure must be calculated.
Section 3175.100 adopts API 21.1, Subsection 7.3, regarding EGM equipment commissioning; API 21.1, Section 9, regarding access and data security; and API 21.1, Subsection 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 21.1 (1993); therefore, this is not a significant change from existing requirements.
The BLM received several comments objecting to the application of API 21.1 to low- and very-low-volume FMPs due to its complexity and the difficulty of implementing it for wellhead measurement. The BLM recognizes the recommendations of API 21.1 as industry standards for accurate measurement of natural gas. These consensus standards are developed by operators, manufacturers, purchasers, and other recognized experts within the oil and gas industry and approved by API voting members. The authors of API 21.1 did not include any limitations for the use of the standard based on a specific application or average flow rate through the meter, nor did the commenters provide any justification as to why API 21.1 was too complex and difficult to implement on low- and very-low-volume FMPs. In addition, wellhead measurement is not a requirement of the BLM. The BLM requirement is only that measurement of gas must occur prior to removal or sales from the lease, unit PA, or CA, unless otherwise approved by the AO. Therefore, if an operator believes that API 21.1 is too complex or difficult to use for wellhead measurement, they could combine the production from multiple wells within a lease, CA, or unit PA and measure the combined stream. Combining production from multiple wells within a single lease, unit PA, or communitized area is not considered commingling for production accounting purposes and does not require BLM approval (see definition of commingling in § 3170.3(a)). The BLM did not make any changes as a result of this comment.
The BLM received a comment indicating that the description of the acronyms at the bottom of Table 1 to § 3175.100, Standards for Electronic Gas Measurement Systems, may suggest that all very-high-volume FMP requirements will be subject to immediate assessments for non-compliance. The commenter suggested adding a comma and asterisk after the phrase “Very-high-volume FMP” to delineate the acronym definition from the note on immediate assessments. The BLM agrees with this comment and changed this language to indicate that only those requirements with a superscript number 1 (
Section 3175.101(a) sets requirements for manifolds and gauge lines. The requirements regarding gauge lines for EGM systems are identical to the requirements for gauge lines for mechanical recorders. The comments that the BLM received on gauge lines are also the same for both EGM systems and mechanical recorders. Please see the discussion of gauge line requirements and comments on these requirements under § 3175.91(a).
Section 3175.101(b) and (c) specify the minimum information that the operator must maintain onsite 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 software version and transducer makes, models, and URLs have been reviewed by the PMT and approved by the BLM;
(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.
Section 3175.101 paragraphs (b)(1) through (3) requires that each EGM system include a display that is accessible to the BLM, and that shows the units of measure for each variable.
The BLM received a few comments to the proposed requirement in § 3175.101(b)(1). The commenters objected to the need for a display. The BLM did not make any changes to the rule based on these comments. The BLM believes the displayed information is required in order to verify that the flow computer is functioning properly. The BLM uses the displayed information for several purposes, including to independently check the flow-computer calculations, to determine average values of differential and static pressure in order to enforce uncertainty requirements, to compare the displayed volume to reported volume, and to determine the normal operating points for verification. The statewide NTLs, which have been in place for at least 7 years (12 years for Wyoming), all require a display, so this requirement is not new.
The BLM received one comment regarding the requirement in § 3175.101(b)(2) that the display be onsite and in a location that is accessible to the AO. The commenter objected to the requirement of accessibility by the AO if the meter house is locked. The BLM did not make any changes to the rule based on this comment. The BLM must have immediate access to the EGM display. Although some operators have offered to provide BLM inspectors with keys or combinations to locks, the BLM has determined after years of experience that this rarely works well. During the course of a year, a BLM inspector has to inspect thousands of FMPs owned by dozens of different operators. It is unworkable for BLM inspectors to maintain a list of lock combinations and keys, both of which often change over the course of time. The BLM does not believe that it is unreasonable to ask for ready access to the EGM display. Again, this requirement is essentially the same as the requirement for the display to be accessible to the BLM in the statewide NTLs.
The BLM received one comment regarding the proposed requirement in § 3175.101(b)(3) to include units of measure for each required variable in the display. The commenter objected to this requirement and proposed an alternative to post the units on a placard or card. The BLM did not make any changes to the rule based on this comment. The BLM believes that the units of measure must be with the variables in the display because they can change when a flow computer is replaced or reconfigured. The units of measure are critical when verifying the flow-computer calculations in the field. Based on the BLM's experience, virtually all flow computers are capable of displaying the units of measure; therefore, the BLM believes this is a reasonable requirement.
Proposed § 3175.101(b)(4) would have required the display to contain 13 items, including the FMP number, software version, instantaneous flow data (differential pressure, static pressure, flowing temperature, and flow rate), previous day volume and flow time, previous day average flowing data (differential pressure, static pressure, and flowing temperature), relative density, and primary device information (e.g., orifice bore diameter).
The BLM received several comments on this section, which stated that most legacy and several current models of flow computers cannot accommodate 13 lines due to software limitations and suggested that some of the required information could be posted onsite instead of being part of the display. The BLM agrees with these comments and has reduced the amount of information that must be displayed by the flow computer from 13 lines in the proposed rule to 6 lines of information in the final rule. The final rule no longer requires the FMP number (see discussion below), the relative density, or the primary device information as part of the display if this information is posted onsite. The BLM eliminated the requirement to display or post the previous day's flow time. In addition, the previous day's average differential pressure, average static pressure, and average flowing temperature do not have to be displayed if the operator posts an hourly or daily QTR (see § 3175.104(a)) that is no more than 31 days old onsite and accessible to the AO. Posting the previous day's average values will still allow the BLM to determine the normal operating points of differential pressure, static pressure, and temperature, in order to perform an uncertainty calculation and determine the normal operating points for verification.
The BLM also received numerous comments regarding the proposed requirement in § 3175.101(b)(4)(i) to include the FMP number or, if an FMP number has not yet been assigned, a unique meter-identification number in the display. The commenters stated that most EFCs are not capable of handling an 11-digit FMP number in the display. The commenters suggested only providing the FMP number during calibration, at the time of audit, or making the FMP number available by posting it onsite. The BLM agrees with these comments and has removed the proposed requirement to display the FMP number on the electronic display. Instead, the operator may post a unique meter ID number (which could include the FMP number) at the FMP. The BLM also added the term “unique meter ID number” to the definitions in § 3170.
Section 3175.101(c) sets requirements for information that must be onsite, but not necessarily on the EGM system display. The information in the proposed rule included the elevation, meter tube diameter, information regarding the flow conditioner or 19-tube-bundle flow straightener (if installed), information regarding the transducers and flow computer, static pressure tap location, and last inspection dates for both the primary and secondary devices.
The BLM did not receive any comments on § 3175.101(c). However, the BLM did add additional items to this list based on comments on § 3175.101(b), including a unique meter ID number, the relative density of the gas, and primary device information.
Section 3175.101(d) requires the differential pressure, static pressure, and flowing temperature transducers to be operated within the lower and upper calibrated limits of the transducer. Inputs that are outside of these limits are 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 not exceed the maximum value for which it
The BLM received one comment in response to § 3175.101(d) that suggested an exception for wells using a plunger lift system. A plunger lift is installed on a well to suppress flow from the well until enough pressure builds up to lift accumulated liquids out of the wellbore. When the well pressure reaches this threshold, the plunger releases and a surge of flow—both liquids and gases—comes to the surface. This results in a spike in the gas flow through the meter, which causes a corresponding spike in the differential pressure at the meter. It is often difficult to size an orifice plate and differential-pressure transducer to accurately record both the spike in flow, which typically lasts only several seconds, and the lower differential pressure for the remainder of the plunger cycle. The commenter suggested that the BLM should allow the differential-pressure transducer associated with a plunger lift system to exceed the URL by 150 percent for 1 minute. The rationale for this, as stated by the commenter, is that under the transducer testing protocol (see § 3175.133(e)), the transducer must be tested at 150 percent of URL for at least 1 minute; therefore, the BLM should accept over-range operation of the differential-pressure transducer for 1 minute because this condition has been tested. The commenter stated that the increased uncertainty of a transducer operating in an over-range condition could be derived from the testing done under § 3175.133(e).
The BLM believes that the commenter has misinterpreted the intent of the testing protocol. The testing protocol does require an “over-range effects” test where the transducer is operated at 150 percent of its URL for at least 1 minute. However, the purpose of this test is to see if, or how much, the over-ranging affects the calibration of the transducer under normal operation when the reading is below the upper calibrated limit. In some transducers, a brief over-ranging can cause the calibration of the transducer to shift, which affects all of the transducer's readings. This testing does not determine the accuracy to which an over-range pressure is recorded or if the over-range pressure is recorded at all, it only determines how an over-range condition affects the accuracy of the transducer when it is operated within its upper calibrated limit. Also, the BLM is grandfathering transducers that are used at FMPs as of January 17, 2017 from going through the testing protocol in § 3175.130. While the manufacturer must still submit the data from whatever testing they did in order to get BLM approval, this testing may not have included the over-range-effects test to which the commenter refers.
The BLM agrees that plunger lifts can cause measurement issues as described previously and added a provision to § 3175.101(d) to allow the differential pressure to exceed the upper calibrated limit for brief periods of time if approved by the BLM. The BLM does not believe the differential pressure should ever exceed the URL, because in some transducers differential pressures exceeding the URL are not recorded and included in the calculation of volume. Although operation of the differential-pressure transducer over the upper calibrated limit may exceed the uncertainty specification of the transducer, the BLM believes that this will not significantly degrade the uncertainty of the volume calculation if these instances are brief. The BLM did not make any changes regarding the commenter's suggestion to allow the exceedance for 1 minute. Although the 1-minute timeframe is a test condition in § 3175.133(e)(1), this is not relevant for normal operation of the transducer. In addition, a specific timeframe would be virtually impossible for the BLM to enforce.
Section 3175.101(e) requires the flowing temperature of the gas to be continuously recorded on all FMPs except on very-low-volume FMPs. Flowing temperature is needed to determine flowing gas density, which is critical to determining flow rate and volume. Very-low-volume FMPs would be exempt from this requirement because the potential effect on royalty would be minimal and the BLM's experience suggests that the costs would outweigh potential royalty. For very-low-volume FMPs, any errors introduced by using an estimated temperature in lieu of a measured temperature would not have a significant impact on royalties. The BLM did not receive any comments on this paragraph.
Section 3175.102(a) includes several specific requirements for the verification and calibration of transducers following installation and repair. This differentiates the procedures that are specific to this type of verification from the procedures required for a routine verification under § 3175.102(c). The primary difference between § 3175.102(a) and (c) is that an as-found verification is not required if the meter is being verified following installation or repair.
Section 3175.102(a)(1) requires a leak test before performing a verification or calibration. Please see the previous discussion regarding § 3175.92(a)(1) for further explanation of leak testing.
The BLM received one comment in response to this requirement stating support for the proposed requirement for a leak test prior to performing verification of equipment. No change was requested. The BLM did not make any changes to the rule based on this comment.
Section 3175.102(a)(2) requires a verification to be done at the points required by API 21.1, Subsection 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 includes more verification points than are required for a routine verification described in § 3175.102(c). The purpose of requiring more verification points in this section is: (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 verification is required to ensure that new or repaired equipment is working properly between the lower and upper calibrated limits of the transducer.
The BLM received several comments stating that the proposed rule implies that an operator could not recalibrate the transducer to bring it into compliance and that the only solution is to replace the transducer. The BLM does not agree with these comments. Section 3175.102(a)(2) states: “If any of these as-left readings vary from the test equipment by more than the tolerance determined by API 21.1, Subsection 8.2.2.2, Equation 24 (see § 3175.30), then that transducer must be replaced
Other commenters stated that older meters are incapable of verification at six points and should be grandfathered, and that the additional verification at the proposed points would increase time and cost without improving accuracy. The BLM does not agree. There are no limits to the number of verification points that a flow computer can provide. An operator can obtain a verification point by comparing the reading from the test equipment with the reading from the flow computer. While some flow computers may have limitations on the number of verification points that the event log will record, the BLM does not require the flow computer to log verification points. The BLM did not make any changes to the rule based on this comment.
Another commenter said the proposed rule did not allow for a working-pressure zero adjustment and, as a result, a transmitter could appear to be out of calibration when it is not. A working-pressure zero adjustment compares the differential-pressure transducer's reading, when line pressure is applied to both sides of the transducer, to the transducer's reading when atmospheric pressure is applied to both sides. This difference is then applied to all readings determined from a differential-pressure verification, which is done at atmospheric pressure. The BLM disagrees with this comment. Section 3175.102(a)(2) is specific to new FMPs or to transducers that the operator has replaced or repaired. Because the operator has just installed this transducer and it has not yet been subjected to working pressure, there would be no way do a working-pressure zero adjustment. Section 3175.102(a)(4) requires the operator to re-zero the transducer prior to returning it to service if the difference between atmospheric-pressure zero and working-pressure zero is greater than the tolerance defined in Equation 24. The BLM did not make any changes to the rule based on this comment.
Proposed § 3175.102(a)(3) would have required 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 A to this subpart, or to be based on a barometer measurement made at the time of verification for absolute-pressure transducers in an EGM system. Under this rule, use of the value for atmospheric pressure defined in the buy/sell contract is not allowed unless it meets the requirements stated in this section. The BLM is eliminating 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 requirement is different from the requirements in § 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 is allowed only when calibrating an absolute pressure transducer. It is not 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 is not allowed.
The BLM received several comments in response to this proposed requirement. One commenter stated that this does not allow for local changes in barometric pressure. The BLM agrees that a calculation of atmospheric pressure would not account for local changes in barometric pressure, presumably due to weather systems in the area. However, the additional uncertainty caused by weather systems is easy to estimate and include in the calculation of overall uncertainty (the BLM uncertainty calculator does this). Another commenter proposed using the barometric pressure reported by the National Weather Service if a barometer was not available. The BLM disagrees because a barometric pressure reported by the National Weather Service is generally corrected to mean sea level and does not represent the true atmospheric pressure at the FMP location. Even if the National Weather Service, or other weather service, were to provide a true uncorrected barometric pressure, it would be specific to the elevation of an airport or other fixed location and would most likely not represent the true atmospheric pressure at the FMP location. The BLM did not make any changes to the rule based on these suggestions.
One commenter suggested the option of using a static pressure calibration device that applies absolute pressures to the static-pressure transducer (virtually all calibration devices in use today apply gauge pressure to the static-pressure transducer), as long as it is twice as accurate as the transducer under calibration. The BLM agrees with this suggestion and added this option to § 3175.102(a)(3). However, the absolute pressure calibration device would not have to be twice as accurate as the transducer being calibrated, as long as it meets the requirements of a calibration device in § 3175.102(h).
Proposed § 3175.102(a)(4) would have required 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 have been a new requirement that would eliminate measurement errors caused by
Section 3175.102(b) establishes requirements for how often a routine verification must be performed where the minimum frequency, in months, is shown in Table 1 to § 3175.100. The proposed rule would have required 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 very-low-volume FMPs. Because there is a greater risk of measurement error in the volume calculation for a given transducer error at higher-volume FMPs, the proposed rule would have increased the verification frequency as the measured volume increases.
The BLM received several comments in response to this proposed requirement. One commenter stated that they wanted the terminology changed from the number of months between verifications to the number of times per year the verification had to be accomplished. For example, instead of “every 3 months,” the requirement should read “quarterly.” The BLM did not make any changes to the rule as a result of this comment because the BLM believes the frequency of required verifications given in Table 1 to § 3175.100, is clear as written. In addition, a term such as “quarterly” could be interpreted to mean that a routine verification could be done at the beginning of one quarter and at the end of another quarter, essentially doubling the time between verifications that the BLM intended.
Several commenters stated that the calibration frequency was excessive on very-high-volume FMPs while other commenters stated that the calibration frequency should be increased to every 6 months on very-low-volume FMPs. The BLM agrees that modern equipment does not drift significantly and calibration can cause more error than it solves due to human error during the calibration process. As a result, the BLM changed the required verification frequency for very-high-volume FMPs from once every month to once every 3 months. The BLM did not change the verification frequency for very-low-volume FMPs because it is based on an economic model that does not justify a calibration frequency higher than annual.
Section 3175.102(c) adopts the procedures in API 21.1, Subsection 8.2, for the routine verification and calibration of transducers with several additions and clarifications. The primary difference between § 3175.102(a) and (c) is that an as-found verification is required for routine verifications in § 3175.102(c).
Section 3175.102(c)(1) requires a leak test before performing a verification. A leak test is not specified in API 21.1, Subsection 8.2; however, the BLM believes that performing a leak test is critical to obtaining accurate measurement. Please see the previous discussion of § 3175.92(a)(1) for further explanation of leak testing.
The BLM received one comment in response to the proposed requirement in § 3175.102(c)(1) on performing a leak test. The commenter stated that a leak test should not be required on non-regulated pressure sources because leaks are readily detectable without having to perform a leak test. The BLM believes that the commenter is using the term “regulated” pressure source to refer to devices such as deadweight testers. A regulated pressure source could mask a leak because, if a leak were present, it would continuously add air or gas to the system to maintain a constant pressure. In theory, a non-regulated pressure source would not mask a leak. However, a leak could still be masked with a non-regulated pressure source if, for example, the valve on the pressure source is not shut off completely during the calibration. The BLM did not make a change to the rule based on this comment. The BLM believes a leak test is the only definitive way to determine if leaks are present and it is neither onerous nor time consuming to perform.
Section 3175.102(c)(2) requires that the operator perform an as-found verification at the normal operating point of each transducer. This clarifies the requirements in API 21.1, Subsection 8.2.2.3, which requires a verification at either the normal point or 50 percent of the upper user-defined operating limit. This paragraph also defines how the normal operating point is determined because this is a common point of confusion for operators and the BLM.
The BLM received one comment in response to the proposed requirement in § 3175.102(c)(2) on the verification at the normal operating point of each transducer. The commenter requested clarification on how close they have to be to the normal point when verifying a transducer. For example, the commenter stated that they already do a 10-point verification on the differential-pressure transducer and wondered if that would be sufficient to comply with the normal point requirement. The BLM agrees with the commenter that clarification is needed, and added clarification in the final rule that for differential and static-pressure transducers, the pressure applied to the transducer for this verification must be within five percentage points of the normal operating point, while for the temperature transducer, the water bath or test-thermometer well must be within 20 °F of the normal operating point.
In addition to making the changes to this section in response to comments, the BLM added a new § 3175.102(c)(3) that requires operators to replace transducers when the as-found verification exceeds the manufacturer's specification for stability or drift, as adjusted for static pressure and ambient temperature, on two consecutive verifications. The BLM added this requirement in lieu of the long-term stability test that was eliminated from § 3175.133(g). Because the BLM does not have any way to verify the long-term stability specification provided by the manufacturer without testing, the BLM will enforce the manufacturer's specifications during field verification. There is no reason that a properly functioning transducer should be outside of the stability or drift specification once adjustments for static pressure (on differential-pressure transducers) and ambient temperature are factored out. Manufacturer's specifications include both static pressure effects on differential-pressure transducers and ambient temperature effects. The BLM plans to add the capability of determining the maximum allowable drift to the BLM uncertainty calculator to make this requirement easier to enforce.
Section 3175.102(c)(4) also requires that the operator perform an as-left verification at the normal operating point of each transducer. The BLM did not receive any comments on this paragraph.
Section 3175.102(c)(5) (§ 3175.102(c)(4) in the proposed rule) requires 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. Please see the previous discussion of proposed § 3175.102(a)(4) for further explanation of zero shift. API 21.1, Subsection 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 21.1, Annex H, is required in this section. The BLM did not receive any comments on this paragraph.
Section 3175.102(c)(6) (§ 3175.102(c)(5) in the proposed rule) adopts the allowable tolerance between the test device and the device being tested as stated in API 21.1, Subsection 8.2.2.2. This tolerance is based on the reference uncertainty of the transducer and the uncertainty of the test equipment.
The BLM received several comments in response to this proposed requirement. One commenter stated that the verification tolerances in API 21.1, Subsection 8.2.2.2, are complex and restrictive and that the BLM should not require operators to follow it. The BLM disagrees. The purpose of establishing a verification tolerance is to ensure that a calibration is only required when the transducer readings have drifted outside of the combined accuracy of both the transducer and the test equipment. The API requirement for verification tolerance is similar to the verification tolerance in the BLM statewide NTLs for EFCs. Because API 21.1 no longer requires the test equipment to be twice as accurate as the equipment being tested, the added uncertainty of the test equipment can no longer be ignored and must be included in the determination of verification tolerance. The BLM did not make any changes to the rule based on this comment.
Another commenter suggested tying the verification tolerance of the temperature transmitter to the uncertainty of the temperature transmitter rather than establishing a set value of 0.5 °F as required in the proposed rule. The BLM agrees that tying the verification tolerance to the uncertainty is consistent with the requirement for differential and static-pressure transducers. The BLM added that the verification tolerance for temperature transmitters is equivalent to the uncertainty of the temperature transmitter or 0.5 °F, whichever is greater.
Section 3175.102(c)(7) (§ 3175.102(c)(6) in the proposed rule) clarifies that all required verification points must be within the verification tolerance before returning the meter to service. This requirement is implied by API 21.1, Subsection 8.2.2.2, but is not clearly stated. The BLM did not receive any comments on this paragraph.
Proposed § 3175.102(c)(8) (§ 3175.102(c)(7) in the proposed rule) would have required the differential-pressure transducer to be zeroed at working pressure before returning the meter to service. This is implied by API 21.1, Subsection 8.2.2.3, but not required. Refer to the discussion of zero shift under § 3175.102(a)(4) for further information.
The BLM received several comments in response to this proposed requirement. The commenters stated that it was an unnecessary step to re-zero the differential transducer if it was already reading zero. The BLM agrees with the commenters and changed the proposed rule to require operators to re-zero the differential-pressure transducer only if the absolute value of the transducer reading under pressure is greater than the reference accuracy of the transducer, expressed in inches of water column. See the discussion under § 3175.102(a)(4).
Section 3175.102(d) allows for redundancy verification in lieu of a routine verification under § 3175.102(c). Redundancy verification was added to the current version of API 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 EGM systems. If the readings vary by more than a set amount, both sets of transducers would have to be calibrated and verified. Operators have the option of performing routine verifications at the frequency required under § 3175.102(b) or employing redundancy verification under this paragraph. Operators may realize cost savings by adopting redundancy verification, especially on high- or very-high-volume FMPs. The rule adopts API 21.1, Subsection 8.2, procedures for redundancy verifications with several additions and clarifications as follows.
Section 3175.102(d)(1) requires the operator to identify separately the primary set of transducers from the set of transducers that is used as a check. This requirement allows the BLM to know which set should be used for auditing the volumes reported on the OGOR.
Section 3175.102(d)(2) requires the operator to compare the average differential pressure, static pressure, and temperature readings taken by each transducer set every calendar month. API 21.1, Subsection 8.2, does not specify a frequency at which this comparison should be done.
Section 3175.102(d)(3) establishes the tolerance between the two sets of transducers that will trigger a verification of both sets of transducers under § 3175.102(c). API 21.1 does not establish a set tolerance. This section also requires the operator to perform a verification within 5 days of discovering the tolerance has been exceeded.
The BLM did not receive any comments on § 3175.102(d).
Section 3175.102(e) establishes requirements for retaining documentation related to each verification and calibration. This section also establishes the information that the operator must retain onsite for redundancy verifications. Section 3175.102(e)(1)(i) refers to § 3170.7 (§ 3170.6 in the proposed rule), which lists the information that operators must include on all source records.
The BLM received a few comments in response to the proposed requirement in § 3175.102(e). The commenters stated that the retention of the FMP number required in proposed § 3170.6 (§ 3170.7 in the final rule) would take some time to implement, and that the citation to § 3170.6 should be changed to § 3170.7. The BLM agrees with the commenters, corrected the citations, and, in final subpart 3170, changed § 3170.7 to require operators to use either an FMP number or the lease, unit PA, or CA number, along with a unique meter identification number, on verification documentation. (Operators still have the option of using the FMP number.)
The BLM also added a provision to the first sentence of this paragraph clarifying that the documentation requirements of this paragraph also apply to transducers that are replaced to ensure that operators document how much in error the broken transducers were prior to replacement.
Proposed § 3175.102(f) would have required the operator to notify the BLM at least 72 hours before verification of an EGM system. A 72-hour notice would be sufficient for the BLM to rearrange schedules, as necessary, to be present at the verification.
The BLM received a few comments in response to this proposed requirement. The commenters stated that the 72-hour notification before performing verification would require a great deal of coordination. The BLM agrees with these comments and has included an alternative to submit a monthly or quarterly verification schedule to the AO for routine verifications performed under § 3175.102(c). The submittal of monthly or quarterly schedules in lieu of the 72-hour notice is already common practice in many field offices. For verifications performed after installation or following repair, however, the 72-hour notice requirement in the proposed rule was retained because it would be difficult for operators to schedule these on a monthly or quarterly basis.
Proposed § 3175.102(g) would have required correction of flow-rate errors greater than 2 percent or 2 Mcf/day, whichever is less, if the errors are due to the transducers being out of calibration, by submitting amended reports to ONRR. 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 adds an additional threshold of 2 Mcf/day to exempt amended reports on low-volume, small-error FMPs.
The BLM received numerous comments in response to this proposed requirement stating that this would be an onerous requirement and that the term “less” should be changed to “greater.” The BLM agrees with the comments on changing the term “less” to “greater.” That was an oversight in the proposed rule. To further clarify flow rate error volume correction when the date on which the error occurred is unknown, this section refers to an example in § 3175.92(f).
One commenter suggested that volume corrections should only be required when the flow rate error is greater than 2 percent or 100 Mcf/month, whichever is less. The BLM did not make any changes to the rule based on this comment because there was no compelling rationale for this change given by the commenter. The value of 100 Mcf/month is approximately 3 Mcf/day, which is essentially the same as the 2 Mcf/day threshold the BLM adopted in this rule.
Section 3175.102(g) also defines 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 1 to § 3175.100, very-low-volume FMPs are 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).
Section 3175.102(h)(1) requires verification equipment to be certified at least every 2 years. The purpose of this requirement is 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 21.1; however, the BLM believes that periodic certification is necessary. This requirement is consistent with requirements in the previous edition of API 21.1 (1993), which was adopted by the statewide NTLs for EFCs. This section also requires that proof of certification be available to the BLM at the time of inspection and sets minimum standards as to what the documentation must include. The minimum documentation standard represents common industry practice.
Section 3175.102(h)(2) adopts language in API 21.1, Subsection 8.4, regarding the accuracy of test equipment. The statewide NTLs, which adopted the standards of API 21.1 (1993), required that the test equipment be at least two 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 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 is not two times more accurate than the transducer being tested. For example, verifying a transducer with a reference accuracy of 0.10 percent of the 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 better of the upper calibrated limit of the device being tested. This level of accuracy is very difficult to achieve outside of a laboratory. As a result, API 21.1, Subsection 8.4, and § 3175.102(h) 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 must be accounted for when determining overall measurement uncertainty. The BLM will 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.
The BLM received several comments in response to this proposed requirement. The commenters stated that improvements in the accuracy of transducers are outpacing improvements in the accuracy of test equipment, and it is difficult to find test equipment that is twice as accurate as the transducers under test outside of a laboratory setting. The commenters recommended granting a variance in this situation. The BLM recognizes that many transducers are accurate enough that field test equipment cannot achieve double the accuracy of the transducer under test. That is why the BLM added paragraph (h)(2)(ii) to this section. Paragraph (h)(2)(ii) allows operators to use test equipment with an accuracy of 0.10 percent of the upper calibrated limit of the transducer under test even if it is not twice as accurate as the transducer under test. The additional uncertainty resulting from test equipment that is not at least twice as accurate as the transducer under test is accounted for in the calculation of overall measurement uncertainty. The BLM made no changes based on these comments.
Section 3175.103(a) would have prescribed the equations that must be used to calculate the flow rate for all FMPs. Proposed § 3175.103(a)(1) would have applied to flange-tapped orifice plates and would have represented a change from the statewide EFC NTLs because the NTLs allowed the use of either the API 14.3.3 or the AGA Report No. 3 (1985) flow equation. The proposed rule would not have allowed the use of the AGA Report No. 3 (1985) flow equation because it is not as accurate as the API 14.3.3 flow equation and can result in measurement bias. The NTLs also allowed the use of either AGA Report 8 (API 14.2) or NX-19 to calculate supercompressibility. The proposed rule would have only allowed API 14.2 because it is a more accurate calculation.
The BLM received several comments in response to this proposed requirement stating that AGA report No. 3 (1992 and 1985) and AGA Report No. 8 (1992) should be allowed since these are very similar to the latest standard and any change to a newer standard would put significant expense upon the operator. The BLM agrees that updating older flow computers with the latest calculation software may be cost prohibitive for low- and very-low-volume FMPs, especially if the manufacturer no longer supports software upgrades. Additionally, the difference in volume calculated with the latest API equations as compared to older versions of the API equations is not that significant for low- and very-low-volume FMPs. For these reasons, the BLM grandfathered low- and very-low-volume FMPs installed prior to the effective date of this rule from having to use the latest API equations. Please see the discussion under § 3175.61.
The BLM has incorporated AGA Report No. 8 (1992) in the final rule; therefore, any flow computer using the calculations in AGA Report No. 8 would be in compliance with this rule. Very-low-volume FMPs are grandfathered from the requirement to calculate supercompressibility under API 14.3; however these flow computers still have to calculate supercompressibility under NX-19. The BLM made no changes based on these comments.
Proposed § 3175.103(a)(2) would have required 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 are 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 have required that only the equation used during testing be used in the field.
The BLM received several comments stating that the BLM should use equations established by API and AGA rather than those provided by the PMT. Under the proposed rule, the BLM would have only approved a make and model of a meter if it was a differential type of meter other than a flange-tapped orifice plate. The flange-tapped orifice meter is the only differential type flow meter for which there is an AGA or API standard; there are no AGA or API standards for any other differential type flow meters requiring testing and review by the PMT. As a result, the PMT would have to verify and approve the flow equations proposed by the manufacturer based on the testing of that device. In the final rule, the BLM has added linear meters to the types of meters that the BLM could approve by make and model in § 3175.48. There are standards for many linear meters currently on the market, such as ultrasonic meters, Coriolis meters, and turbine meters. In light of the revised approval process for linear meters, the BLM added a provision to this paragraph to clarify that the flow rate equations recommended by the PMT and approved by the BLM would apply only if there are no industry standards for that device.
One commenter stated that the flow rate calculation method developed by the PMT should be effective within 6 months of approval by the BLM. The flow rate calculation method would be effective immediately after approval by the BLM. The BLM did not make any changes to the rule based on this comment.
Section 3175.103(b) establishes a standard method for determining atmospheric pressure that is used to convert psig to psia. The BLM received one comment supporting the proposed requirement. The BLM made no changes based on this comment.
Section 3175.103(c) requires that volumes and other variables used for verification be determined under API 21.1.4 and Annex B of API 21.1. The BLM did not receive any comments on this paragraph.
Section 3175.104(a) establishes minimum standards for the data that must be provided in a daily and hourly QTR. The data requirements are listed in API 21.1, Subsection 5.2. In the proposed version of § 3175.104(a), the BLM would have required that the QTR include the FMP number (by referencing § 3170.7), that certain data be reported to five significant digits, and that the data must be original, unaltered, unprocessed, and unedited. API 21.1, Subsection 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 QTR. The BLM proposed to add 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 are sufficient to recalculate the reported volumes to the necessary level of accuracy.
Section 3175.104(a) also requires 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 proposed § 3175.104(a), the BLM would not have accepted reports generated by third-party software at all. This provision has been revised in the final rule to clarify that the BLM will accept data that was generated by third-party software, so long as that software is approved through the PMT process.
The BLM received several comments in response to these proposed requirements. Several commenters stated that many accounting systems are not capable of handling an 11-digit FMP number. The BLM agrees with these commenters and eliminated the requirement in § 3170.7(g) to store the FMP number in the accounting system. Instead, operators must use either an
The BLM received several comments stating that reporting to five significant digits would be unworkable and recommending reporting to a specified number of decimal places. The BLM agrees with this comment and changed the final rule to require five decimal places for volume, flow time, extension, and three decimal places for average differential pressure, static pressure, and temperature.
The commenters also stated that the BLM should allow data to be collected and stored in third party software that meets the requirements of this section and has been reviewed by the PMT. One commenter stated that hand collection of data from each FMP would require significant additions in staffing. Another commenter suggested that approving third party software packages should be the role of the PMT. The BLM agrees with these comments and established a provision for the PMT to review accounting systems and recommend approval by the BLM it if it meets the requirements under § 3175.49.
Section 3175.104(b) establishes 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 21.1. In addition, the BLM proposed to require:
• The FMP number, once established;
• The software/firmware identifiers that would allow the BLM to determine if the software or firmware version was approved by the BLM;
• For very-low-volume FMPs, the fixed temperature, if the temperature is not continuously measured, that would allow the BLM to recalculate volumes;
• The static-pressure tap location that would allow the BLM to recalculate volumes and verify the flow rate calculations done by the flow computer; and
• A snapshot report that would allow the BLM to verify the flow-rate calculation of the flow computer.
As described under § 3175.104(a), configuration logs generated by third-party software would not have been accepted. Based on the comments received under § 3175.104(a), the PMT will review and recommend approval of third-party software under § 3175.49.
In the final rule, the BLM adopted all of the proposed requirements listed above, with the exception of the FMP number requirement. The comments received by the BLM on § 3175.104(a), regarding the FMP number also apply to this section. As discussed above, the final rule does not require operators to place the FMP number in the configuration log.
The BLM received one comment stating that since the default location of the static-pressure tap is upstream per API 14.3.4.1, the static-pressure tap location should not have to be maintained in the configuration log unless it is located downstream. The BLM disagrees with the comment. It is not burdensome to identify the location of the static-pressure tap, and it will avoid confusion when performing audits.
Section 3175.104(c) establishes minimum standards for the data that must be provided in the event log. This section requires that the event log retain all logged changes for the time period specified in proposed § 3170.7 (see 80 FR 40768 (July 13, 2015)). This provision will ensure that a complete meter history is maintained to allow verification of volumes. Proposed § 3175.104(c)(1) would have been a new requirement to record power outages in the event log. This is not currently required by API 21.1 or the statewide NTLs for EFCs.
The BLM received several comments in response to the proposed requirement in § 3175.104(c)(1) (final § 3175.104(c)) that the event log must record all power outages that inhibit the meter's ability to collect and store new data. The commenters stated that it is impossible to record a power off event with no power. Although the BLM believes that flow computer manufacturers could comply with this requirement by simply adding an additional clock, the BLM eliminated this requirement from the final rule because, apparently, flow computers do not currently have this capability.
Section 3175.109(d) requires the operator to retain an alarm log following API 21.1, Subsection 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. The BLM did not receive any comments on this section.
Based on comments the BLM received on § 3175.104(a), the BLM added § 3175.104(e) to the final rule, which requires any accounting system used to submit QTRs, configuration logs, or even logs to the BLM, to be approved by the BLM based on a recommendation from the PMT. Please see § 3175.49 for further discussion.
This section sets standards for gas sampling and analysis at FMPs. Although there are industry standards for gas sampling and analysis, none of these standards are adopted 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 are 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 developed requirements that address where a sample must be taken, how it must be taken, how the sample is analyzed, and how heating value is reported.
Table 1 to § 3175.110 contains a summary of requirements for gas sampling and analysis. The first column of Table 1 to § 3175.110 lists the subject of the standard. The second column contains a reference for the standard (by section number and paragraph) that applies to each subject area. The final four columns indicate the categories of FMPs for which the standard applies. The FMPs are categorized by the amount of flow they measure on a monthly basis. As in other tables, “VL” is very-low-volume FMP, “L” is low-volume FMP, “H” is high-volume FMP, and “VH” is very-high-volume FMP. Definitions of the various classifications are included in § 3175.10. An “x” in a column indicates that the standard listed applies to that category of FMP.
The BLM received numerous comments objecting to the proposed requirements in § 3175.110, suggesting that the BLM should use the API, AGA, and GPA gas sampling standards as written instead of developing new standards, or work with these organizations to develop new or revised standards if needed. The BLM incorporated the API and GPA sample standards to the extent possible. However, the BLM added clarification to the standards to ensure they are enforceable and to ensure that heating values are not under-reported by excluding liquids that may be flowing through the meter. Further explanation of these and other comments are discussed in the individual sections relating to gas sampling and analysis.
One commenter stated that the cost of gas sampling and meter inspection frequencies would require them to increase staff by two-fold. However, the commenter did not offer any data to support this assertion. The BLM has accounted for this cost in the Economic and Threshold Analysis by accounting for the cost of taking a gas sample and performing a meter inspection. These costs include the labor costs of taking a sample which would also account for hiring additional staff if needed. The BLM did not make any changes to the rule based on this comment.
Another commenter stated that increased gas sampling frequency could negatively impact royalties from Coalbed Methane (CBM) production because the heating value of CBM tends to decline over time as the amount of carbon dioxide increases. Specifically, the presence of carbon dioxide in CBM gas decreases its heating value. As stated earlier, the goal of the rule is to improve measurement accuracy and verifiability, not to increase total royalty revenue. Therefore, it is the BLM's intent that the reported heating value needs to reflect, to the extent possible, the actual heating value of the gas being produced.
Section 3175.111(a) establishes 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. The BLM did not receive any comments on this paragraph.
Proposed § 3175.111(b) would have set standards for heating requirements based on several industry references requiring the heating of all sampling components to at least 30 °F above the HCDP. The purpose of the heating requirement is to prevent the condensation of heavier components, which could bias the heating value. This proposed section would have applied to all sampling systems, including spot sampling using a cylinder, spot sampling using a portable GC, composite sampling, and on-line GCs. Because most of the onshore FMPs will be downstream of a separator, the HCDP is defined in § 3175.10 as the flowing temperature of the gas at the FMP, unless otherwise approved by the AO. This would have required 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.
The BLM received numerous comments objecting to § 3175.111(b) in the proposed rule. Several commenters stated that the 30 °F requirement in API 14.1 was intended to prevent condensation and not to vaporize the gas being sampled. Other commenters stated that the 30 °F requirement applies when the HCDP is calculated and is not required if the HCDP is known. Because the BLM assumed the HCDP is the same as the flowing temperature of the gas in most cases, the commenters state that heating to 30 °F above flowing temperature is not required. One commenter suggested the BLM change the proposed rule to require operators to maintain the temperature of all gas sampling components at or above the flowing gas temperature. The BLM agrees with these comments and changed this paragraph to give operators the option of maintaining all sampling components at or above the flowing temperature of the gas or 30 °F above a calculated HCDP, whichever is less. The latter option would most likely apply to lean gases where the calculated HCDP is well below the flowing gas temperature.
One commenter stated that it is not necessary to assume the HCDP equals flowing temperature, and the HCDP can be calculated off of a previous sample. While the BLM agrees with this statement, nothing in the definition of HCDP would prevent an operator from proposing this method to the BLM for determining the HCDP at a particular FMP. The calculated HCDP would, however, be subject to the 30 °F heating requirement under the rule. The BLM did not make any changes to the rule based on this comment.
Another commenter stated that heating is not necessary for a dry gas. The BLM agrees that this may be true depending on the circumstances and what the commenter considers a “dry gas.” If, for example, a dry (lean) gas has a calculated HCDP of 25 °F (and the AO approved the use of a calculated HCDP), and the sample was taken when the ambient temperature was 60 °F, no heating would be required because the ambient temperature, and hence the temperature of the sampling equipment, would be greater than 30 °F above the calculated HCDP. The BLM did not make any changes to the rule in response to this comment because the rule already accommodates this scenario.
One commenter stated that sampling without heating could bias the heating value to the high side. While the commenter did not elaborate on why they believe this is true, the BLM agrees that heating is necessary to obtain an accurate heating value. The BLM did not make any changes to the proposed rule based on this comment.
As specified in Table 1 to § 3175.110, very-low-volume FMPs are exempt from all requirements in § 3175.112 because, based on BLM experience with this level of production, a requirement to install or relocate a sample probe in very-low-volume FMPs could cause the well to be shut in.
Section 3175.112(a) requires that all gas samples must be taken from a probe that complies with requirements of this section. The intent of the standard is to obtain a representative sample of the gas flowing through the meter. Samples taken from the wall of a pipe or a meter manifold are not representative of the gas flowing through the meter and could bias the heating value used in royalty determination. The BLM did not receive any comments on this paragraph.
Proposed § 3175.112(b)(1) would have placed 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 had 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 7 and 8) ranges from 2.8 to 4.5 pipe diameters, depending on the Beta ratio. Therefore, the sample probe would have had 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 HCDP. It is likely that the gas at many FMPs is at or below the HCDP because many FMPs are immediately downstream of a separator. A separator necessarily operates at the HCDP, 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
The BLM requested data supporting or contradicting any correlation between sample probe location and heating value or composition. The BLM also requested alternatives to this proposal, such as wet gas sampling techniques. The BLM did not receive any data or alternatives.
The BLM received numerous comments objecting to § 3175.112(b)(1) in the proposed rule. Many of the commenters stated that there is no technology currently available to extract entrained liquids to determine an accurate heating value, and that API 14.1 and GPA 2166 are only applicable to single-phase gas streams at or above the HCDP of the gas. Other commenters stated that the required sample probe location in the proposed rule is in direct conflict with API and GPA standards, and the BLM should just adopt those standards as written. Some comments stated that moving sample probes to comply with the proposed requirement would be cost prohibitive, could interfere with the pressure recovery downstream of the orifice plate, and would make it difficult to comply with both the sample probe placement requirements in API 14.1 as well as the proposed requirement. Several comments stated that low and very-low-volume FMPs should be exempt from the requirement. The BLM agrees with these comments and changed the final rule to adopt the sample probe placement requirements in API 14.1. However, the BLM retained the requirement that the sample probe be the first obstruction downstream of the primary device.
The BLM received one comment stating that the proper place to sample the gas is upstream of the orifice plate because liquids are less likely to fall out. Because the commenter did not provide any data to substantiate this claim, the BLM did not make any changes to the rule based on this comment.
Section 3175.112(b)(2) requires that the sample probe must be exposed to the same ambient temperature as the primary device. Locating the sample probe in the same ambient temperature as the primary device 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 primary device and the sample point, thereby biasing the heating value and relative density of the gas.
The BLM received several comments objecting to the proposed requirement. The example provided for this requirement was specific to moving the sample probe into a heated meter house. The commenters believe it is impractical and cost prohibitive for the sample probe to be moved to a location where it is at the same ambient temperature as the primary device. The BLM agrees with this comment and added language to the final rule that allows the operator to comply with this standard by adding insulation or heat tracing along the entire meter run in lieu of moving the probe. Because it is difficult to define with any uniformity what level of insulation is needed to meet the intent of this requirement due to regional and local variations in operating conditions, the BLM did not establish specific requirements with respect to insulation in the final rule and, instead, added language which states that the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the sample probe in relation to the orifice plate (
One commenter stated that this requirement is not necessary because of the requirement in § 3175.111(b) to maintain the temperature of all sampling equipment at or above the flowing temperature of the gas. The BLM does not agree with this comment. While the heating requirement in § 3175.111(b) ensures that liquids will not form once the gas leaves the meter tube, it does nothing to ensure that the liquids do not form inside the meter tube. Any drop in temperature between the orifice plate and the sample probe could cause liquids to form. Because liquids tend to travel along the walls of the pipe, there is less chance that they would be collected in the sample even without a membrane filter installed in the sample probe. This increases the potential for liquids forming after the orifice plate to be unaccounted for. In practice, by complying with the requirement in § 3175.80(l), for thermometer wells to sense the same gas temperature that exists at the orifice plate, and with § 3175.112(b)(1) requiring the sample probe to be the first obstruction downstream of the orifice plate, operators would automatically comply with this requirement. In other words, if an operator insulated a meter run to comply with § 3175.80(l), the insulation would also cover the sample probe, which must be placed upstream of the thermometer well. The BLM did not make any changes to the rule as a result of this comment.
Section 3175.112(c)(1) through (3) sets standards for the design and type of the sample probe, which are based on API 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. The BLM did not receive any comments on these two paragraphs.
Proposed § 3175.112(c)(3) would have required that the collection end of the probe be placed in the center third of the pipe cross-section.
The BLM received a comment objecting to this requirement. The commenter believes this requirement is appropriate for pipe up to 6 inches in diameter; however, for any pipe diameter above 8 inches there is a risk of failure because of resonant vibration fatiguing the probe. The commenter recommended that the BLM use API 14.1, Subsection 7.4.1, Table 1, for sample probes used in 8-inch and greater runs. The BLM agrees with the comment and has changed the requirement by requiring the sample
Section 3175.112(c)(4) prohibits 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 HCDP, 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 could result in heating values lower than the actual heating value of the fluids passing through the meter. This could result in a bias that would be in violation of § 3175.30(c).
The BLM received numerous comments objecting to the proposed requirement in § 3175.112(c)(4). Most of the commenters objected to the potential introduction of liquids into the gas sample which could significantly bias the heating value. The commenters stated that API 14.1 and GPA 2166 do not apply to multi-phase flow and there are currently no methods to accurately determine the heating value from multi-phase flow. Commenters also stated that prohibiting filters in the sample probe is contrary to API 14.1 and GPA 2166 and the BLM should adopt these standards as written.
The BLM disagrees with these comments and did not make any changes to this requirement as a result. The BLM recognizes that the sampling standards in API 14.1 and GPA 2166 are only intended for single-phase gas streams and that prohibiting membrane filters could potentially bias the heating value if liquids are present. However, the commenters ignore the reality that liquids are often present at the FMP. The mere fact that sample probe filters are manufactured and used is an admission by the gas measurement community that liquids are present. If there were no liquids present, there would be no need for filters designed to keep liquids from entering the sampling system. By intentionally excluding liquids from the sample, the heating value derived from the sample will not represent the true value of the molecules flowing through the meter and will be biased to the low side, resulting in an underpayment of royalty. The BLM also disagrees with the implication by the commenters that filters are required to obtain an accurate heating value. The BLM does not understand how the commenters can deem a heating value to be accurate when the sampling system is designed to reject those components which have the greatest impact on the heating value. The BLM also believes that there are other, perhaps better ways to minimize the liquids at an FMP. For example, installing properly sized and functioning separators and insulating or heat tracing the meter run would help to avoid liquids. Unlike the membrane filter, these would minimize liquids at their source without biasing the heating value of a gas sample.
The BLM received several comments stating that the prohibition of filters in the sample probe conflicts with the requirement to clean GC filters in § 3175.113(d)(2) of the proposed rule, and that GC filters are necessary to protect the GC. The BLM believes that the commenters have misinterpreted this requirement. The BLM is not prohibiting filters at the inlet to GCs. The prohibition of filters in § 3175.112(c)(4) is specific to filters in the sampling probe. The BLM did not make any changes to the rule based on these comments.
Section 3175.112(d) sets standards for the sample tubing that are based on API 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. The BLM did not receive any comments on this paragraph.
Section 3175.113(a) provides an automatic extension of time for the next sample if the FMP is not flowing at the time the sample was due. Sampling a non-flowing meter would not provide any useful data. Under the proposed rule, a sample would have been required to be taken within 5 days of the date the FMP resumed flow.
The BLM received numerous comments objecting to the 5-day extension in § 3175.113(a). The commenters stated that 5 days is not sufficient time to determine whether a meter has resumed flow and to schedule a technician to go out to the site and collect a sample, especially for meters that flow intermittently or are in a remote location requiring extended travel time. Suggestions for increasing the timeframe ranged from 10 days to 1 month, although no specific rationale was given for these timeframes. The BLM agrees that 5 days may not be long enough and has changed the timeframe from 5 days to 15 days as a result. The BLM believes that 15 days should be adequate time to identify the resumption of flow and schedule a technician to travel to the site and collect a sample. Most locations have telecommunications systems that allow the flow rate of a meter to be monitored remotely, and the resumption of flow could be detected almost immediately. For those locations that do not have telecommunications, personnel are typically onsite on a daily basis to monitor and inspect the equipment. The BLM rejected a 30-day timeframe because, especially for high- and very-high-volume FMPs, this could overlap with the due date of the next required sample. In addition to the comments suggesting specific timeframes, one commenter suggested requiring the sample be taken as soon as practical after flow resumes, while another commenter suggested the language specify that the meter has to resume continuous flow. The BLM did not make any changes as a result of these comments because the terms “as soon as practical” and “continuous flow” are not readily enforceable.
Proposed § 3175.113(b) would have required the operator to notify the BLM at least 72 hours before gas sampling. A 72-hour notification period was proposed to allow sufficient time for the BLM to arrange schedules as necessary to be present when the sample is taken.
The BLM received many comments objecting to this proposed requirement. The majority of the commenters believe that 72-hour notification is unreasonable and burdensome. Several commenters suggested that the BLM should allow for the submission of monthly schedules which gives the BLM the ability to witness samples. The BLM agrees with these comments and included the option to submit monthly or quarterly sampling schedules to the BLM.
Section 3175.113(c) establishes requirements for sample cylinders used in spot or composite sampling. Proposed § 3175.113(c)(1) and (2) would have adopted requirements for cylinder construction material and minimum capacity that are based on API and GPA standards.
The BLM received a few comments objecting to the proposed requirement in § 3175.113(c)(1). The commenters suggested that the BLM allow the use of aluminum cylinders because they are approved by the Department of Transportation for shipping samples and have been used without metal contamination issues. Some commenters indicated that the requirement in this paragraph to use stainless-steel cylinders would result in excessive cost to industry. Several commenters stated that the rule should allow their use in low-pressure applications. The BLM agrees with these comments and changed the rule to incorporate API 14.1, Subsection 9.1, regarding the allowable materials of construction, rather than requiring that sample cylinders be constructed of stainless steel. Under API 14.1, Subsection 9.1, sample cylinders can be made out of aluminum, but only if the aluminum is hard anodized.
Section 3175.113(c)(3) requires that sample cylinders be cleaned according to GPA standards. This section also requires operators to have documentation of the cylinder cleaning.
The BLM received a few comments either supporting or objecting to this proposed requirement. Several commenters supported the idea of cleaning the sample cylinders and maintaining a record of cleaning, which could include the use of a disposable tag indicating the cylinder was cleaned. Other commenters objected to both the need for cleaning sample cylinders and the need to keep a record of the cleaning. These commenters stated that this requirement is costly and burdensome with negligible benefit, and that a contaminated cylinder would be obvious (the commenter did not provide any information as to why that would be obvious). Another commenter believed cleaning and the associated documentation is the responsibility of the lab, not the operator. The BLM believes that clean sample cylinders are crucial in obtaining a representative sample of the gas, and that documentation of the cleaning is the only way BLM inspectors can ensure the cylinders are clean. Although the BLM did not change the rule based on these comments, we did change the wording of this requirement in the final rule to clarify that the operator must maintain this documentation onsite during sampling and make the documentation available to the BLM on request.
Proposed § 3175.113(c)(4) would have required clean sample cylinders to be sealed in a manner that prevents opening the sample cylinder without breaking the seal. It is important to be able to verify that sample cylinders are clean before sampling to avoid contaminating a sample. Therefore, the BLM sought comments 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 that the cylinders are clean. The BLM did not receive any suggestions as to how a sample cylinder could be sealed. The BLM is not aware of any industry standard or common industry practice that requires a seal to be used.
The BLM received several comments objecting to the proposed requirement in § 3175.113(c)(4). Most commenters stated that sealing the cylinders is not an industry practice and will result in extra expense that will have minimal gain. Several commenters stated that there is no way to seal a cylinder while other commenters stated that it was unclear in the proposed rule when the cylinder would have to be sealed (before or after the sample was taken) and what type of seal would be acceptable to the BLM. The BLM agrees with the comments stating there is no cost-effective method to seal sample cylinders and deleted this requirement in the final rule. The BLM believes that the documentation required in § 3175.113(c)(3) will ensure that sample cylinder cleaning is taking place to the best extent possible.
Section 3175.113(d) sets standards for spot sampling using a portable GC. This section primarily addresses the sampling aspects; the analysis requirements are prescribed in § 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 GC, can also cause significant bias in heating value if not used properly. Section 3175.113(d)(1) adopts GPA standards for the material of construction, heating, cleaning, and operation of sampling separators. It also requires documentation that the sample separator was cleaned as required under GPA 2166-05 Appendix A.
The BLM received several comments objecting to this requirement. One commenter cautioned against the use of separators because of the potential for liquids to condense in the cylinder and get into the GC. Another commenter stated that this requirement is impractical to do prior to taking each sample because the cleaning equipment cannot be carried to the field. The commenter suggested the BLM only require sample separator cleaning on a periodic basis. The BLM considered prohibiting the use of sample cylinders altogether because API 14.1, Subsection 8.7, cautions against their use. However, the BLM also believes that if used properly they can protect the GC while not contaminating the sample. In order to ensure that the sample separator does not contaminate a sample, the BLM believes it is essential to require the separator to meet the same standards as a sample cylinder regarding cleaning. The BLM disagrees with the comments suggesting only periodic cleaning and did not make any changes to the rule based on these comments. The BLM did add language to the final rule clarifying that the same documentation and availability of the documentation required for sample cylinders is required for separators.
Proposed § 3175.113(d)(2) would have required the filter at the inlet to the GC 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.
The BLM received numerous comments objecting to the proposed requirement in § 3175.113(d)(2). Most of the commenters stated that cleaning the GC filter prior to each sample is expensive and impractical because it would require the operator to carry cleaning agents to the field which are difficult to transport. Several commenters stated that the filter should only be cleaned or replaced as necessary or when the operator suspects the filter is contaminated. The BLM agrees with these comments and deleted this requirement as a result. While the BLM believes that a contaminated filter could cause an errant analysis, there is no way to inspect or enforce a requirement for periodic or “as needed” cleaning or replacement frequency.
Several commenters expressed concern over the removal of the filter at the inlet to the GC because liquids, such as glycol and compressor oil, could damage the GC. The BLM did not make any changes to the rule based on this comment because nowhere has the BLM proposed removing the filter at the inlet of the GC.
Section 3175.113(d)(2) (§ 3175.113(d)(3) in proposed rule) requires 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
The BLM received a few comments on this section. While the commenters did not object to this requirement, they suggested that the BLM reword the requirement to clarify that the purging must be done with the gas being sampled, not with air. One commenter recommended that the BLM change the phrase “before sealing the connection” to “before completing the connection.” The BLM agrees with these comments and made the requested wording changes in the final rule.
Section § 3175.113(d)(3) (§ 3175.113(d)(4) in the proposed rule) would have required portable GCs to adhere to the same minimum standards as laboratory GCs under proposed § 3175.118. The requirements of proposed § 3175.118 would have included provisions regarding the design, operation, verification, and calibration of GCs, the number of consecutive samples that must be run, the verification frequency, when a calibration had to be done, standards for calibration gas, and the GC calibration report.
The BLM received one comment requesting clarification of § 3175.113(d)(3) (§ 3175.113(d)(4) in proposed rule). The commenter stated that the requirement for a GC to be “designed” in accordance with GPA 2261-13 (GPA 2261-00 was referenced in the proposed rule) does not provide sufficient flexibility for the development of new technology and processes. The BLM agrees with this comment and reworded the requirement in the final rule to read: “The portable GC must be operated, verified, and calibrated . . .” instead of “The portable GC must be designed, operated, and calibrated . . . .” The BLM believes that removing the word “designed” will help provide flexibility for new technology and adding the word “verified” will help ensure that both the verification and calibration of a GC is done under § 3175.118.
The BLM added § 3175.113(d)(4) to the final rule in response to changes made to § 3175.118(c)(1). In the proposed rule, this section would have required portable GCs to be verified not more than 24 hours before sampling at an FMP. This proposed requirement would have facilitated the BLM's ability to ensure that the portable GC was verified properly prior to sampling. In response to comments arguing against the practicality of verifying a portable GC every 24 hours, the BLM eliminated this requirement in the final rule. However, the BLM believes that in order to ensure portable GCs have been verified in accordance with the provisions of § 3175.118, the operator must have the documentation of the verification onsite and available to the BLM when using a portable GC.
Proposed § 3175.113(d)(5) would have prohibited the use of portable GCs if the flowing pressure at the sample port was less than 15 psig, which can affect accuracy of the device. This proposed requirement was based on GPA 2166-05.
The BLM received a few comments objecting to proposed § 3175.113(d)(5). The commenters stated that GCs can sample with pressures down to 5 psig because of newer technology and the use of vacuum pumps to help step up the pressure in accordance with API 14.1, Subsection 11.10. One commenter suggested the BLM not allow portable GCs to take samples below 15 psig unless the GC is approved by the PMT to handle pressures below 15 psig. Based on these comments, the BLM removed this requirement in the final rule. The BLM believes that setting a minimum pressure for portable GCs would tie the regulation to existing technology. The BLM generally agrees with the comment that review and approval of new GC technology could be a role for the PMT.
The BLM also added § 3175.113(d)(5) and (6) to the final rule in response to changes made to § 3175.118(b). Under the proposed rule, § 3175.118(b) would have required that for both portable and laboratory GCs, samples would have to be analyzed until three consecutive samples were within the repeatability standards of GPA 2261-00, Section 9. Based on comments received on this section, this requirement was eliminated in the final rule. Please see the discussion on § 3175.118(b). Portable GCs are subject to a less controlled environment than are laboratory GCs and also analyze a live gas stream with varying composition. Laboratory GCs analyze fixed-composition samples stored in sample cylinders. For these reasons the BLM believes that additional quality control standards are needed for portable GCs to ensure the gas sampling and analyses are accurate. Section 3175.113(d)(5) establishes the minimum number of samples that must be taken and analyzed. For very-low- and low-volume FMPs, a minimum of three samples and analyses are required. For high- and very-high-volume FMPs, the final rule establishes tolerances between the highest and lowest heating values for three consecutive samples. The basis for the tolerances is explained under the discussion for § 3175.118(b). The BLM believes that three samples provide a reasonable balance between cost and statistical representation of the gas being sampled.
Section 3175.113(d)(6) sets standards on how the heating value and relative density from the samples and analyses taken under § 3175.113(d)(5) are determined. One method that is explicitly allowed in the final rule is to calculate the heating value and relative density by taking the average of the heating values and relative densities determined from the three samples taken. The other method explicitly allowed by the rule is to use the median heating value and relative density from the three samples taken. The BLM also added a provision where the BLM can approve additional methods.
Section 3175.114 adopts three spot sampling methods using a cylinder and one method using a portable GC. The three allowable methods using a cylinder were selected for their ability to accurately obtain a representative gas sample at or near the HCDP, 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 adopted them verbatim.
The most common method currently in use at FMPs is the “purging—fill and empty” method, which is one of the methods that is allowed in the rule (§ 3175.114(a)(1)); therefore, it is not expected that this requirement will result in any significant changes to current industry practice. Section 3175.114(a)(2) also allows the helium “pop” method and § 3175.114(a)(3) allows the “floating piston cylinder” method. The fourth spot sampling method (§ 3175.114(a)(4)) is the use of a portable GC, which is discussed in § 3175.113(d). Section 3175.114(a)(5) provides that the BLM would post other approved methods on its website once they are reviewed by the PMT and approved by the BLM.
Section 3175.114(b) allows 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, Subsection 11.10, 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, the “floating piston cylinder” method is not allowed in conjunction with a vacuum gathering system. Based
Several comments objected to the BLM's piecemeal adoption of API 14.1 and GPA 2166 and stated that the BLM should have incorporated both documents in whole, including all of the sampling methods referred to in Appendix F of API 14.1. One commenter also objected to the BLM's incorporating these standards and then using the standards to sample gas containing liquids. The commenter stated that both of these standards are only intended for single phase gas sampling and should not be applied when liquids are present. The BLM did not make any changes as a result of these comments. The issue of sampling with liquids present is discussed under § 3175.112. The BLM is only enforcing specific parts of API 14.1 and GPA 2166 because these parts are directly relevant to the BLM's goal of ensuring that samples are properly taken and are clear and enforceable as written.
The BLM selected the sampling methods described in this section because data show they work well at the HCDP under the controlled temperature conditions, and both the “purging—fill and empty” and helium “pop” methods are repeatable, as documented in the July 2004 study,
Section 3175.115(a) requires that gas samples be taken at least every 6 months at low-volume FMPs and at least annually at very-low-volume FMPs. The BLM determined that annual sampling has the potential for biasing the heating value. If, for example, an annual sample is 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 § 3175.31(c), which requires the absence of significant bias in low-volume FMPs. The BLM believes that sampling at low-volume FMPs at least every 6 months will reduce the potential for bias.
Section 3175.115(a) will 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 1 to § 3175.110 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 other factors that were included in the study. Instead, the study found that heating value variability appears 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 practices 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 practices. The frequencies shown in Table 1 to § 3175.110 for high- and very-high-volume FMPs are typical of the sampling frequency required to obtain the heating value certainty levels that are required in § 3175.31(b)(1) and (2).
The BLM received several comments on the proposed sampling frequencies in Table 1 to § 3175.110 of the proposed rule. One commenter did not believe the proposed sampling frequencies occurred often enough and proposed a frequency of once every 6 months for very-low-volume and low-volume FMPs, and once per month for high- and very-high-volume FMPs. The commenter did not submit any data or rationale for the proposed frequencies. Another commenter suggested that increased sampling is not needed for “dry” gas wells, although no definition of what constitutes a “dry” gas well was given by commenter, nor did the commenter provide any data to support that a lower frequency for these FMPs is justified. Another commenter stated that the frequencies are too high in general and do not account for driving time. Again, the commenter did not submit any data justifying this comment. The BLM did not make any changes to the proposed rule based on these comments because the BLM believes the frequencies are reasonable as written in the proposed rule and no data were provided to justify a different frequency.
One commenter stated that it is a violation of existing contracts to change required sampling frequencies. The BLM did not make any changes to the rule based on this comment because all existing Federal oil and gas leases require compliance with the applicable Federal regulations, even if those regulations are stricter than the provisions of a gas sales contract attached to any particular lease.
One commenter expressed a concern that the BLM was intending to assign a Btu value to a particular zone. The BLM has no intention of assigning Btu values to particular zones. If that were the intent, the BLM would have required that in the proposed rule instead of proposing provisions to ensure the accuracy and verifiability of heating values measured at each FMP. No changes to the rule were made as a result of this comment.
Section 3175.115(b) will 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 is required in § 3175.31(b)(1) and (2). Under § 3175.115(b), the BLM can increase or decrease the required sampling frequency given in Table 1 to § 3175.110. To implement this requirement, the BLM is developing a database called GARVS. This database will be used to collect gas sampling and analysis information from Federal and Indian oil and gas operators. GARVS will analyze those data to implement other gas sampling requirements as well. The sample frequency calculation in GARVS will be based on the heating values entered into the system under § 3175.120(f).
Several comments asserted that the method of calculating a sampling frequency was not provided in the proposed rule. While the BLM did not propose a calculation method in the proposed rule, a calculation method was included in the BLM Gas Variability Study that was included with the documentation on the proposed rule. The BLM did not make any changes as a result of these comments.
Many commenters stated that the sampling frequency should be based on volume, not variability. The BLM disagrees. While there is some economic rationale for sampling less frequently at lower-volume meters, any volume-based sampling frequency is arbitrary and ignores statistical methods. As stated by other commenters, the uncertainty of any given heating value is only a function of the analytic procedures used to obtain and analyze the sample. To clarify the comment, if, for example, a particular sampling and analysis method provides a heating value uncertainty of ±2 percent, more frequent sampling would not eliminate that uncertainty. In other words, if an operator took one sample per year and was confident that the process was done properly and the heating value derived from that sample was ±2 percent, there would be no benefit to sampling any more frequently. The reason for more frequent sampling is not related to the uncertainty of each sample; rather, it is related to the uncertainty of deriving heating values over a period of time from snapshots of heating values taken during that time period. If, for example, the heating value at a particular meter were always the same, there would be no reason to take spot samples from this meter regardless of how much volume it measured. On the other hand, if the heating value at a particular meter were known to vary greatly from sample to sample, the heating value from one sample could misrepresent the average heating value of the gas flowing through the meter and result in significant underpayment or overpayment of royalty. The solution would be to take more samples of the highly fluctuating meter to obtain a better representation of the true heating value over time. The difference in sampling frequency between the first example and the second example is not related to the volume measured; rather, it is related to the degree of heating value variability at that meter. The cause of the high degree of fluctuation in the second example—whether it be actual changes in the gas composition, poor sampling practice, or environmental conditions during sampling—is largely irrelevant. Volume has bearing on sampling frequency only in that sampling entails a cost and at lower-volume meters, the cost of more frequent sampling due to high variability is simply not worth the potential loss or gain in revenue resulting from less frequent sampling. The BLM incorporated statistically based sampling frequencies for high- and very-high-volume FMPs where economics is not as important a consideration and volume-based sampling frequencies for lower-volume FMPs where economics is a consideration. The BLM did not make any changes to the proposed rule as a result of these comments.
One commenter stated that based on their experience performing gas analyses, fluctuations in heating value are typically due to changes in pressure, temperature, or down-hole equipment and have nothing to do with volume. The BLM Gas Variability Study did not find any correlation between heating value variability and pressure, temperature, or down-hole equipment. The BLM did not make any changes to the rule because no changes were requested by the commenter.
One commenter wondered if the BLM is requiring increased sampling frequency because it believes that operators use poor sampling practices. The BLM has no data to conclude that poor sampling practices are the cause of high heating value variability. However, there are only two potential causes of high variability: The actual composition of the gas is changing significantly over time or the operator is using poor sampling practices. Regardless of the cause, the only way to achieve a set level of average annual heating value uncertainty is to change the sampling frequency to achieve the required level of uncertainty. As explained elsewhere in this preamble, the sampling frequency can change (become more or less frequent) depending on what the data shows for a particular facility over time. The BLM did not make any changes to the rule based on this comment.
The BLM received numerous comments stating that uncertainty and variability are two unrelated concepts, and the BLM should not use variability as a trigger for increased sampling frequency. The BLM agrees that variability should not be the trigger. That is why the BLM is using average annual heating value uncertainty as the trigger. The relationship between variability and average annual heating value uncertainty is explained in the discussion of § 3175.31(b). The BLM did not make any changes to the rule based on this comment.
Several comments suggested that the BLM provide industry with the sampling frequency algorithm. The BLM agrees with this comment and has provided the algorithm in the final rule. It is the same algorithm provided in the BLM Gas Variability Study, which was posted at
Several commenters suggested that the BLM should work with industry to develop sampling schedules or conduct further study before implementing this requirement. While the BLM does not believe further study is needed to support this method, the rule allows the BLM to approve other methods that achieve the same goal (see § 3175.31(a)(4)). These other methods could be developed jointly with industry. One commenter stated that they were in favor of the requirement to allow sampling frequency adjustment. The BLM did not make any changes to the rule based on this comment, as no changes were requested by the commenter.
One commenter stated that changing the required sampling frequencies for high- and very-high-volume FMPs when there is a change in the variability of previous heating values would create uncertainty for operators of these FMPs, posing an excessive burden on industry. Based on this and other comments, the BLM added a provision in the final rule (§ 3175.115(b)(1)) that would prohibit the BLM from changing the sampling frequency for a high-volume FMP for 2 years after the FMP starts measuring gas (or 4 years from the effective date of the rule, whichever is later). For very-high volume FMPs, the BLM could not change the sampling frequency for 1 year after the FMP starts measuring gas (or 3 years from the effective date of the rule, whichever is later). Based on the initial 3-month sampling frequency required for high-volume FMPs in Table 1 to § 3175.110, this would result in the collection, analysis, and reporting of at least eight samples before the BLM could change the sampling frequency. For very-high-volume FMPs, the monthly sampling required in Table 1 to § 3175.110 would yield at least 12 samples. Assuming the operator is tracking the variability of these samples using the equation given under the definition of heating value variability (see § 3175.10(a)), the operator will have ample indication that an FMP has a variability that is high enough to warrant an increased sampling frequency. The operator would also have the opportunity to address the high variability by implementing additional training or quality-control measures in the sampling and analysis of that FMP.
Section 3175.115(b)(3) clarifies 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. In proposed § 3175.115(b)(3) (§ 3175.115(b)(4) in the final rule), GARVS would have rounded 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. Several comments stated that the increased sampling frequency would be difficult logistically, especially if it is once per week as in the proposed rule. Because the BLM agrees that weekly sampling is probably not practical in many situations, the BLM eliminated the requirement for weekly sampling in the final rule. A 2-week sampling frequency is the maximum sampling frequency that the BLM will require under § 3175.115(b)(4) of the final rule. In addition, the BLM eliminated the entry in Table 1 to § 3175.115 that corresponded to weekly sampling.
One commenter stated that the cost of performing additional gas sampling and entering the gas analyses into GARVS would be prohibitive, although the commenter did not submit any data to substantiate this claim. The BLM does not believe that the new gas sampling requirements are cost prohibitive. Under the new volume thresholds, very-low-volume meters, for which no increase in gas sampling frequency is required as compared to Order 5, constitute 51 percent of all FMPs. The rule only requires one additional sample per year at low-volume FMPs. The estimated cost increase for low-volume FMPs, which constitute 38 percent of all FMPs, is $100 per year per FMP. The rule only requires higher sampling frequencies at FMPs flowing more than 200 Mcf/day, which only constitute 11 percent of FMPs. The BLM's analysis indicates that even at a maximum sampling frequency of once every 2 weeks, the requirement is not cost prohibitive. The BLM does not anticipate a significant cost of entering the gas analyses into GARVS because GARVS will allow a direct download of gas analysis data from approved third-party software packages that most operators already use. The BLM did not make any changes to the rule as a result of this comment.
Proposed § 3175.115(b)(4) (§ 3175.115(b)(5) in the final rule) would have required the operator to install a composite sampling system or an on-line GC if sampling every week would still not be sufficient to achieve the certainty levels that would be required under § 3175.31(b)(1) or (2).
The BLM received several comments stating that composite samplers and on-line GCs are only cost-effective on high-volume meters. One commenter stated that composite samplers are not cost-effective unless the flow rate is over 5,000 Mcf/day and on-line GCs are not cost-effective unless the flow rate is over 15,000 Mcf/day. Another commenter stated that composite samplers and on-line GCs are not cost-effective on high-volume FMPs (as defined in the proposed rule) and the “low end” of the very-high-volume threshold. Installed cost estimates for on-line GCs given by commenters ranged from $45,000 to $110,000. The BLM generally agrees with these comments and eliminated the requirement in the proposed rule for high-volume FMPs to use composite samplers or on-line GCs if operators could not achieve an average annual heating value uncertainty of ±2 percent through spot sampling. The BLM believes that the use of composite samplers would not be cost prohibitive at very-high-volume FMPs. Although the BLM did not receive any cost estimates for composite sampling systems in the comments, research shows that a heated composite sampling system costs about $8,000 and using a 2.5 multiplier for the installed cost, as recommended by several commenters, results in an installed cost of about $20,000. A $20,000 cost would have a payout of less than 10 days at a flow rate of 1,000 Mcf/day.
One commenter expressed the opinion that the BLM is trying to force the use of composite sampling systems or on-line GCs at every FMP. Neither the proposed rule nor the final rule would force every FMP to have a composite sampling system or on-line GCs. Although the BLM did not make any changes to the rule based on this comment, the BLM is aware that these devices are expensive and removed the proposed requirement for composite sampling systems or on-line GCs at high-volume FMPs. The BLM estimates that as a result, only 900 FMPs nationwide will fall into the very-high-volume category. From the BLM Gas Variability Study, approximately 25 percent of all FMPs included in the study would not be able to meet a 1 percent average annual heating value uncertainty with a 2-week sampling frequency, the maximum spot sampling frequency required in the rule. Some of the data in the study also suggest that variability tends to be less for higher flow rate meters, although the sample size was too small to reach any definite conclusion. Therefore, the BLM estimates that composite sampling systems or on-line GCs would only be required on a maximum of 225 FMPs, or 0.3 percent of all FMPs nationwide.
One commenter stated that composite samplers and on-line GCs may not perform well with two-phase flow and would have no demonstrated benefit. The BLM does not believe that FMPs flowing at 1,000 Mcf/day or greater will have significant issues with two-phase flow. Generally, two-phase flow occurs at lower-volume meters where it is difficult to obtain adequate separation and control temperature drop between the separator and meter. The commenter did not provide any data to substantiate their argument that two-phase flow would be an issue with higher-volume FMPs. The BLM also disagrees that a composite sampler would have no benefit. A properly designed and operating composite sampling system will result in a heating value that is truly integrated over time, thereby eliminating the uncertainty caused by basing heating value over a time period on heating value “snapshots” in time. The BLM did not make any changes as a result of this comment.
One commenter stated that composite samplers or on-line GCs may still have more than ±2 percent uncertainty. The commenter did not provide any data to substantiate this claim, however. As stated earlier, the performance requirement in § 3175.31(b) relates to average annual heating value uncertainty, not to the uncertainty of a single sample or analysis. To address this comment, the BLM added language to § 3175.115(b)(5) that states, “Composite sampling systems or on-line gas chromatographs that are installed and operated in accordance with this section comply with the uncertainty requirement of § 3175.31(b)(2).” This should eliminate any confusion with this requirement.
Section 3175.115(c) establishes the maximum allowable time between samples for the range of sampling frequencies that the BLM would require, as shown in Table 1 to § 3175.115. This allows 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). In the final rule, the BLM
If a composite sampling system or on-line GC is required by the BLM under § 3175.115(b)(5) or opted for by the operator, § 3175.115(d) requires that device to be installed and operational within 30 days after the due date of the next sample. For example, if the required sampling frequency is every 2 weeks and the next sample is due on April 18th, the composite sampling system or on-line GC must be operational by May 18th. The operator is not required to take spot samples within this 30-day time period. The BLM considers both composite sampling and the use of on-line GCs 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.
Numerous comments argued that the 30-day timeframe to install a composite sampling system or on-line GC under § 3175.115(d) is too short to account for the time to design, order, and install the system. The comments suggested timeframes ranging from 3 months for composite sampling systems to 6 months for both composite sampling systems and on-line GCs. The BLM disagrees with these comments because the BLM added a provision under § 3175.115(b) that will delay the requirement to install a composite sampling system or on-line GC at very-high-volume FMPs until 1 year of gas analysis data are gathered. For very-high-volume FMPs, this will result in a minimum of 12 samples based on the initial monthly sampling frequency required in Table 1 to § 3175.110.
The BLM believes that an operator of a very-high-volume FMP should have ample indication after 6 months of production (i.e., six samples) whether the FMP will have a high enough heating value variability that a composite sampling system or on-line GC will likely be required. If the operator begins the process of ordering a composite sampling system or on-line GC after 6 months, it would be ready to go within the 30-day timeframe of when the BLM requires it to be installed as required in § 3175.115(d). The BLM did not make any changes as a result of these comments. However, the BLM made two other revisions based on other comments that should result in many fewer composite samplers or on-line GCs being required as compared to the proposed rule. First, given the high production-decline rate of many wells on Federal and Indian leases, the 1-year delay will most likely be enough time for many FMPs that were originally categorized as very-high-volume to drop to lower-volume categories that are not subject to the requirement to install on-line GCs or composite sampling systems. Second, for FMPs that measure gas from newly drilled wells, the BLM will no longer include any production from that well prior to the second full month of its production, when determining the flow rate category for an FMP (see the definition of “averaging period” in 43 CFR 3170.3). As a result, with these changes, it is likely that many FMPs that would have been initially categorized as very-high-volume in the proposed rule will no longer meet the very-high-volume threshold in the final rule.
Section 3175.115(e) addresses FMPs where a composite sampling system or on-line GC was removed from service. In these situations, the spot sampling frequency for that meter reverts to the requirement under § 3175.115(a) and (b). The BLM did not receive any comments on this section.
Section 3175.116 sets standards for composite sampling. The BLM used API 14.1, Subsection 13.1, as the basis for § 3175.116(a) through (c). Section 3175.116(d) requires the composite sampling system to meet the heating-value uncertainty requirements of § 3175.31(b).
Although the BLM did not receive any comments on this section, we removed proposed paragraph (d) , which would have required the composite sampling system to meet the heating value uncertainty requirements of § 3175.31(b). Based on comments received on § 3175.115, the BLM added a statement to § 3175.115(b)(5) declaring that composite sampling systems and on-line GCs comply with the heating value uncertainty requirements of § 3175.31(b). Therefore, paragraph (d) is no longer necessary.
Section 3175.117 sets standards for on-line GCs. Because there are few industry standards for these devices, the BLM was particularly interested in comments on the proposed requirements or whether different or alternative standards should be adopted.
The BLM received one comment that questioned the use of GPA 2261 for extended analysis relating to on-line GCs. The BLM agrees with the comment and has incorporated by reference GPA 2286-14, which relates to the procedures for obtaining an extended analysis. Because extended analyses apply to more than just on-line GCs, this standard is referenced under § 3175.118(e) (discussed below).
The BLM also removed proposed paragraph (b) from this section, which would have required the on-line GC to meet the heating value uncertainty requirements of § 3175.31(b). Based on comments received on § 3175.115, the BLM added a statement to § 3175.115(b)(5) declaring that composite sampling systems and on-line GCs comply with the heating value uncertainty requirements of § 3175.31(b). Therefore, paragraph (b) of this section is no longer necessary. As a result of this change, paragraph (d) of this section was moved to paragraph (b).
This section establishes requirements for the analysis of gas samples.
Under proposed § 3175.118(a), these minimum standards would have applied to all GCs, including portable, on-line, and stationary laboratory GCs. These requirements were derived primarily from two industry standards: GPA 2261-00 and GPA 2198-03. The BLM received several comments that GPA 2261-00 has been updated with GPA 2261-13, and that the BLM should be incorporating the most recent version of this standard. The BLM agrees with these comments and incorporates GPA 2261-13 into the final rule. The BLM also deleted the word “designed” from the requirement because GC technology may progress faster than the GPA standards can be updated and requiring GCs to be designed to a specific GPA standard could impede the acceptance of new technology.
Proposed § 3175.118(b) would have required that gas samples be run until three consecutive runs met the repeatability standards stated in GPA 2261-00. Obtaining three consistent analysis results would have ensured that any contaminants in the GC system have been purged and that system repeatability is achieved. This proposed section would have also required that the sum of the un-normalized mole percentages of the gas components detected are between 99 percent and 101 percent to ensure proper functioning of the GC system. This requirement was based on GPA 2261-
The BLM received numerous comments objecting to the proposed requirement to run analyses until the sum of the un-normalized mole percentage is between 99 percent and 101 percent. The commenters stated that this is only applicable when verifying the GC and not for the actual analysis. The comments stated that this is often unachievable for portable GCs because of changes in atmospheric pressure during the analysis, especially when the inlet pressure to the GC is less than 30 psig. Suggestions included a range of 97 to 103 mole percent and 98 to 102 mole percent. The BLM agrees with these comments and changed the rule to read “97 to 103” mole percent. This would apply to both portable GCs and laboratory GCs.
The BLM received numerous comments objecting to the proposed requirement to perform analyses until three consecutive runs are within the repeatability tolerance listed in GPA 2261-00. The commenters stated that the repeatability tolerances are not applicable to the analysis of field samples and that they only apply to calibration gas. One commenter stated that it can be difficult to extract more than three samples from a sample cylinder due to its limited volume and several commenters stated that it would be expensive and time consuming to meet the GPA repeatability standard for each sample. Several commenters stated that this is not applicable for portable GCs because the composition of the gas may actually change as more samples are run through the GC. Some commenters suggested that the rule require two consecutive runs, but only for calibration and verification. The BLM agrees with these comments and deleted this requirement altogether for laboratory GCs.
The BLM believes that some criteria for portable GCs are needed and added a repeatability requirement to § 3175.113(d)(5) as a result. For high-volume FMPs, the operator must continue to analyze samples until three consecutive samples result in a difference between the maximum and minimum heating value of 16 Btu/scf or less. For very-high-volume FMPs, the limit is 8 Btu/scf. These limits were derived from the statistical method used in API 4.2, Appendix C, for determining the maximum allowable difference between proving runs necessary to achieve a set level of uncertainty. The equation used for this determination in Appendix C is:
This equation is equally applicable to heating value deviation in successive gas analysis runs and is rewritten by substituting “HV” (heating value) for “MF” (meter factor):
The accuracy of the heating value uncertainty in the data analysis set is defined as the average annual uncertainty in § 3175.31(b), which is 2 percent for high-volume FMPs and 1 percent for very-high-volume FMPs. The BLM realizes that average annual heating value uncertainty is not the same as the uncertainty of average heating value in the data analysis set. In reality, the uncertainty of the average heating value in the data analysis set should be much less than the average annual heating value uncertainty, perhaps as much as five times less. For example, in § 3174.11, the allowable meter factor difference between provings is 0.25 percent, while the maximum allowable deviation between meter factors during a proving is 0.05 percent. The allowable meter factor difference is analogous to the average annual heating value and the maximum allowable deviation between meter factors during a proving is analogous to the maximum allowable deviation between consecutive heating values when using a portable GC. For high-volume FMPs, a value of 2 percent is substituted for
The result of this equation (0.013 or 1.3 percent) is the maximum deviation allowed between the maximum and minimum heating value determined over three consecutive samples that will result in a data set uncertainty of 2 percent. Using an average heating value of 1,200 Btu/scf, the maximum allowable deviation in heating value is 16 Btu/scf. For very-high-volume FMPs (one percent uncertainty), the maximum allowable deviation is 8 Btu/scf. The BLM believes that, in practice, heating value variability over three consecutive samples is well within this tolerance in most cases.
In the final rule, the BLM combined § 3175.118(c) through (h) of the proposed rule into § 3175.118(c) because all of these paragraphs address the calibration of GCs. Therefore, comments relating to the provisions of § 3175.118(c) through (h) of the proposed rule are all addressed here.
Proposed § 3175.118(c) would have set a minimum frequency for verification of GCs. More frequent verifications would have been required for portable GCs (§ 3175.118(c)(1) of the proposed rule) 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
The BLM received several comments objecting to the requirement in § 3175.118(c)(1) of the proposed rule to verify a portable GC within 24 hours of taking a sample at an FMP. The commenters stated that daily verification of a GC is impractical because of the time it takes to do the verification and that the calibration facility is at a fixed location. One commenter stated that daily verification is not needed if the lab follows strict quality control procedures. The BLM agrees with these comments and changed the verification frequency for portable GCs to coincide with that for laboratory GCs (once every 7 days) and moved the requirement to § 3175.118(c)(1).
Proposed § 3175.118(d) would have required that the gas used for verification be different than the gas used for calibration. This requirement was 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 GC would not be detected if the same gas is used for verification, which could lead to a biased heating value.
The BLM received several comments objecting to the requirement in proposed § 3175.118(d). These comments recommended deleting this provision because compromised calibration gas can be detected with quality control procedures such as monitoring the response factors of the calibration gas. The commenters also stated that neither GPA nor API require this and the operator would have to have two bottles of certified calibration gas which is expensive. The BLM agrees with these comments and deleted the requirement as a result. However, in its place, the BLM added minimum quality control requirements to the final rule. These requirements are in: § 3175.118(c)(3), which requires the operator to authenticate all new gases under the standards of GPA 2198-03, Section 5; § 3175.118(c)(4), which requires the operator to maintain the gas under GPA 2198-03, Section 6; and § 3175.118(c)(5), which requires a GC to be calibrated if the composition of the calibration gas as determined by the GC varies from the certified composition of the calibration gas by more than the reproducibility values listed in GPA 2261-13, Section 10.
Section 3175.118(c)(5) (§ 3175.118(e) in the proposed rule) would have required a calibration of the GC if the repeatability identified in GPA 2261-00, Section 9, could not be achieved during a verification.
Numerous comments objected to this and said that the intent of the GPA standard cited was only for replication of the same sample. The BLM agrees with these comments and changed the wording to reference the “reproducibility” standard in GPA 2261-13, instead of the repeatability standard. The BLM believes this change is appropriate because it accounts for differences in analyzing the same sample between different laboratories. The different laboratories are, in this case, the laboratory from which the calibration gas originated and the laboratory receiving and testing the calibration gas. The BLM also updated the reference from GPA 2261-00 in the proposed rule to GPA 2261-13 in the final rule.
Section 3175.118(f) in the proposed rule, requiring a GC to be re-verified if a calibration was performed, was moved to § 3175.118(c)(6) in the final rule. The BLM did not receive any comments on this section.
The requirement in § 3175.118(h) of the proposed rule for all calibration gases to meet the standards of GPA 2198-03 was moved to § 3175.118(c)(2) of the final rule. The BLM did not receive any comments on this paragraph.
Section 3175.118(d) requires documentation of the verification, calibration, and quality control process, which includes the requirements from § 3175.118(i) in the proposed rule. This section requires the documentation to be retained as required under the record-retention requirements in 43 CFR 3170.6 and provided to the BLM on request. For portable GCs, the rule (§ 3175.113(d)(4)) requires documentation to be available onsite. The purpose of the latter requirement is that it allows the BLM to inspect the verification documents while witnessing a spot sample that is taken with a portable GC. If the verification has not been performed in accordance with the requirements of § 3175.118(d), the GC cannot be used to analyze the sample.
The BLM added three new requirements to the documentation requirements in this section (proposed § 3175.118(i)). These new requirements will help ensure that operators are implementing the quality-control measures required in the final rule in lieu of the requirement in the proposed rule to use a different gas for verification than was used for calibration. Section 3175.118(d)(7)(ii) requires documentation that new calibration gas was authenticated under § 3175.118(c)(3), and § 3175.118(d)(7)(iii) requires documentation that calibration gas was maintained under § 3175.118(c)(4). Section 3175.118(d)(8) also requires the documentation to include the chromatograms generated during the verification process.
The BLM received several comments stating that GPA 2261-13 is intended for analyses through hexanes-plus and should not be used for the extended analysis that the BLM is requiring under § 3175.119(b). The commenters recommended that the BLM incorporate by reference GPA 2286-14, which is used for extended analysis. The BLM agrees with these comments and added § 3175.118(e) to the final rule to require extended analyses to be taken in accordance with GPA 2286-14, which is incorporated by reference in the final rule. This paragraph allows the BLM to approve other methods as well.
Section 3175.119(a) of the final rule requires gas analyses through hexane+ (C
Analysis through C
Proposed § 3175.119(b) would have required an extended analysis of the gas sample, through nonane+, if the concentration of C
The BLM received multiple comments objecting to the requirement to perform an extended analysis because, according to the commenters, extended analyses are expensive and provide little royalty or revenue benefit. The BLM received one comment that the 60-30-10 split of C
One commenter indicated that the difference in heating value between a C
The BLM does not believe that Figure 2, generated from the data supplied by the commenters, supports the commenter's conclusions that the difference between an extended analysis and a C
Because this analysis compares data points to each other, the uncertainty of both data sets “a” and “b” is ±2 Btu/scf, which yields a threshold of significance of ±2.8 Btu/scf. In other words, any difference between two data points that is greater than ±2.8 Btu/scf is statistically significant, and is outside the uncertainty associated with the gas chromatograph that derived these data
Commenters also made various suggestions regarding extended analysis that included not requiring an extended analysis in any circumstance and adjusting the C
The BLM notes that Figure 2 is based on one data set that contains a fairly narrow range of heating values (1,086 Btu/scf to 1,181 Btu/scf) and, as such, may not be representative of potential bias or correlations that exist outside of that heating value range. Based on the threshold of significance analysis describe above, the BLM agrees that the 0.25 mole percent threshold from the proposed rule is too low and most likely would be less than the uncertainty of most GCs. However, the BLM believes that a threshold of 1 mole percent of C
Several commenters suggested that instead of requiring an extended analysis every time the C
One commenter suggested basing the threshold on the Btu content in combination with the mole percentage of C
One commenter provided some cost data to show the additional cost of requiring extended analyses as compared to a standard C
Several commenters objected to the BLM simulation used to determine the 0.25 mole percent threshold and the significant variance in heating value which resulted from the simulation. Other commenters requested that the simulation be provided for review, and suggested further review prior to implementing this rule. Multiple commenters expressed concern over the availability or ability of many labs to provide the extended analysis, and whether measurement systems are able to handle the extended analysis input. The BLM did not make any changes to the rule based on these comments. The BLM did not provide the simulation because it only established the basis for the proposed threshold. The BLM specifically asked for data showing the difference between C
Section 3175.120 establishes minimum standards for the information that must be included in a gas analysis report. This information allows the BLM to verify that the sampling and analysis comply with the requirements in § 3175.110, and enables the BLM to independently verify the heating value and relative density used for royalty determination.
Section 3175.120(a) establishes the minimum requirements for the information required in a gas analysis report. The BLM did not receive any comments on this paragraph.
Section 3175.120(b) requires that gas components not tested be annotated as such on the gas analysis report. It is common practice for industry to include a mole percentage 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 percentage for hydrogen sulfide to be “0.00 percent,” when, in fact, the sample was not tested for hydrogen sulfide.
The BLM received several comments objecting to this requirement because they said it would take time and money to implement and may require reprogramming of some systems. For the following reasons, the BLM did not make any changes to the rule based on these comments. The BLM believes that the current practice of reporting zero concentration for untested components is misleading and potentially dangerous, especially for components such as hydrogen sulfide. For example, if a gas analysis report shows a concentration of zero for hydrogen sulfide, the person looking at the analysis could falsely conclude that there is no hydrogen sulfide present. This could have serious safety consequences. Unless an extended analysis is run, concentrations of hexanes, heptanes, octanes, and nonanes are not individually tested; however, many gas analyses report zero for these concentrations. Because the BLM is requiring extended analyses in some cases (see § 3175.119(b)), the reporting of zero for hexanes, heptanes, octanes, and nonanes, when these components are not tested, is misleading because it could indicate that an extended analysis was run when it was not. Although the commenters did not quantify for the BLM the additional time and expense they would incur from this requirement, the BLM believes that it would be negligible. One commenter suggested that a blank or null entry of a component in a gas analysis could be used to indicate that it was not tested. While the BLM agrees with this comment, no changes were made to the rule because the suggestion would satisfy the requirement as written.
Section 3175.120(c) specifies that heating value and relative density must be calculated under API 14.5, while § 3175.120(d) specifies that supercompressibility be calculated under AGA Report No. 8. The BLM changed the reference from API 14.2 in the proposed rule to AGA Report No. 8 in the final rule because the BLM determined that the API 14.2 standard primarily referenced the AGA Report No. 8 standard. The BLM believes that the latter is the most appropriate source for the supercompressibility calculations.
One commenter stated that the rule needs to specify the version and date of API 14.5 and API 14.2, and went on to suggest that the BLM should adopt the new standards for calculating the thermodynamic properties of gas in 14.2.1 and 14.2. The BLM did not make any changes to the rule as a result of this comment because the incorporation by reference section of the rule (§ 3175.30) already specifies the version and date. The new version of API 14.2 that the commenter refers to is not yet publically available; therefore the BLM cannot incorporate it. As noted above, the BLM references AGA Report No. 8 in the final rule instead of API 14.2.
Proposed § 3175.120(e) would have required 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 allows the BLM to verify heating-value and relative-density calculations and it allows 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 43 CFR 3170.4.
The BLM received many comments objecting to the 5-day timeframe to submit gas analyses to the BLM. The comments stated that 5 days is not reasonable because of the process required to obtain the analysis, send it out to a laboratory, get it analyzed, and then evaluate the analysis. Commenters suggested timeframes ranging from 15 days to 30 days. The BLM agrees with
One commenter questioned how an operator would meet the 5-day reporting timeframe in the proposed rule if the well is not flowing at the time the sample was due. The BLM addresses this situation in § 3175.113(a) of both the proposed and final rule. If the FMP is not flowing at the time the sample is due, the operator has 15 days from the resumption of flow to sample the FMP.
Proposed § 3175.120(f) would have required operators to submit all gas analysis reports to the BLM using the GARVS online computer system that the BLM is developing. Under the proposed rule, operators would have been required to submit all gas analyses electronically, unless the operator is a small business, as defined by the U.S. Small Business Administration, and does not have access to the Internet. The BLM received numerous comments on this requirement stating that the BLM should delay implementation of this requirement until GARVS is developed and the industry knows what the system requirements will be. The BLM agrees with this comment and is delaying this requirement for 2 years from the effective date of this rule. For further discussion of GARVS implementation, see the earlier discussion of § 3175.60.
Proposed § 3175.121 would have established an effective date for the heating value and relative density determined from spot or composite sampling and analysis. Section 3175.121(a) establishes 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. Section 3175.121(b) establishes that the effective date can 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 accounts 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. Section 3175.121(b) 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 have required 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 proposed rule would have established the effective date as the date on which the composite sample cylinder was installed.
The BLM received multiple comments objecting to the requirement that the installation date of the composite sample cylinder should be the effective date of the sample. The commenters argued that sample cylinders on composite samplers are typically removed the last week of the month and the heating value and relative density from that sample are applied for the whole month. The new cylinder is installed immediately after the old cylinder is removed. If the effective date is the day the cylinder is installed, as required in the proposed rule, the heating value and relative density would be extrapolated back nearly a month. This, according to commenters, is not consistent with industry practice. The BLM agrees with these comments and made two changes to the rule as a result. First, the BLM changed the effective date for the composite sample from the first of the month that the sample cylinder was installed, to the first of the month that the sample cylinder was removed. Second, the BLM added language that allows the BLM to accept other methods, as long as they are specified on the gas analysis report.
The BLM received one comment suggesting that the proposed effective date of spot or composite gas sample would cause retroactive adjustments on past volumes, heating value and prior period corrections resulting in resubmission of OGORs, with little or no impact on royalty significance. In response to this comment, the BLM added § 3175.121(d) to clarify that the requirements of this section only apply to reports generated after January 17, 2017.
Section 3175.125(a) defines how the operator must calculate heating value. Section 3175.125(a)(1) and (2) define how to calculate the gross and real heating value. The calculation and reporting of gross and real heating value are standard industry practices.
Section 3175.125(b)(1) establishes 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), this method requires the use of a volume-weighted average heating value to be reported. Section 3175.125(b)(2) establishes 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. This 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. The BLM did not receive any comments on this section.
Section 3175.126 defines the conditions under which operators must report the heating value and volume for royalty purposes.
The reporting of gross and real heating value in § 3175.126(a) is consistent with standard industry practice. The BLM did not receive any comments on this paragraph.
Section 3175.126(a)(1) requires operators to report the “dry” heating value (no water vapor) unless they make an onsite measurement of water vapor using a method approved by the BLM. This could be a change for some operators because gas sales contracts often call for “wet” or as-delivered 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
The BLM would have considered 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 had been presented in the public comments to determine under what flowing conditions the assumption is valid; however, no data were submitted with the public comments.
This section also defines the acceptable methods to measure water vapor: The BLM may approve a chilled mirror, a laser detection system, and other methods reviewed by the PMT and approved by the BLM. Stain tubes and other similar measurement methods are not allowed because of the high degree of uncertainty inherent in these devices.
The BLM received multiple comments objecting to the proposed requirement that heating value must be reported “dry.” These comments indicate that “dry” Btu creates a bias, and recommend that the BLM adopt the water-vapor adjustment methods in GPA 2172. One commenter stated that water saturation was closer to as-delivered than dry. While the BLM agrees that most gas may have some degree of water saturation, the commenters did not submit any data to substantiate their argument that the gas is saturated or the degree to which the gas is saturated. The BLM received proprietary data from one operator outside of the comment period on the proposed rule that clearly show that gas is not consistently saturated with water vapor. According to this data, saturation levels range from 20 percent to 100 percent. Again, no data to the contrary was submitted by any of the commenters. Assuming that gas is always 100 percent saturated with water vapor would cause a bias in the reported heating value, which would result in the underpayment of royalty. The BLM does not contest that the requirement to report all heating values on a dry basis probably results in a bias as well. However, under paragraph (a)(1) of this section, industry has the option of measuring water vapor or developing other methods to remove this potential bias. The BLM would have no recourse for the low bias resulting from allowing operators to report on an as-delivered basis. The BLM did not make any changes to the rule as a result of these comments.
Several comments indicated that the water saturation levels on low pressure wells (e.g., coalbed methane wells) are nearly impossible to obtain with current technologies, and determining water saturation is prohibitively expensive in general gas analysis. One comment suggested that all wells should have water vapor content measured and that water vapor saturation should be measured on the same frequency as Btu determination. The BLM is not requiring operators to measure water vapor; this is an economic decision the operator must make. If the operator believes that the additional royalty they are paying on a dry heating value is more than the cost of installing and operating water vapor measurement equipment, the operator would have an economic incentive to purchase the equipment. If the operator chooses not to install water vapor measuring equipment, then the public and Indian tribes will not suffer any financial loss as a result. In addition, the BLM does not require wellhead measurement, but measurement prior to removal or sales from the lease, unit PA, or CA, unless otherwise approved by the AO. Therefore, if an operator believes that wellhead measurement of water vapor is prohibitively expensive, the operator could combine the production from multiple wells within a lease, CA, or unit PA and measure the combined stream without needing approval from the BLM. The BLM did not make any changes to the rule as a result of these comments.
Other comments suggested that the BLM should accept the as-delivered basis until operators and the BLM can figure out a better way to estimate water vapor content, and that the presence of free water during an inspection indicates that the gas is saturated. The BLM rejects the idea of using the as-delivered basis as the default until the BLM and industry can figure out a better way to estimate water-vapor content. If the BLM were to accept the as-delivered basis as the default, industry would have no economic incentive to pursue more accurate measurement techniques. The BLM also rejects the notion that the presence of free water indicates the gas is saturated with water vapor. While that argument may be true at the time when the inspection was made, it is also possible that the free water will disappear when, for example, the temperature rises, thereby increasing the amount of water vapor the gas can hold. The BLM did not make any changes to the rule as a result of these comments.
One commenter requested more time to collect data. The BLM rejects the idea of granting more time for industry to collect data. The BLM has been publicly asking for water vapor data at API meetings for at least 6 years. The BLM did not make any changes to the rule as a result of this comment.
Another commenter expressed concerns over the conflict between BLM regulations requiring a dry heating value and State regulations requiring the heating value to be reported on some other basis. The BLM did not make any changes as a result of these comments. The BLM does not believe that the requirement to report a dry heating value conflicts with State regulations. The BLM understands that State reporting requirements may differ from the BLM and ONRR's requirements for reporting of Federal and Indian production. This difference is currently seen in reporting of gas volumes, in that some states require a pressure base of 15.05 psia, or 14.65 psia, whereas the BLM requirement is 14.73 psia. The BLM does not see this difference as a conflict, just a variable way to report heating value. The BLM did not make any changes to the rule as a result of this comment.
Section 3175.126(a)(2) requires the heating value to be reported at 14.73 psia and 60 °F. This requirement is consistent with ONRR regulations at 30 CFR 1202.152(a)(1)(ii). The BLM received a comment cautioning that heating value and volume must be reported at the same pressure or temperature and objecting to the requirement to report heating value at any other standard (such as 14.73 psia and 60 °F), than that specified in the sales contract. The BLM did not make any changes as a result of this comment. The BLM acknowledges that the volume and heating value reported on the monthly OGOR should be at the same pressure and temperature. ONRR requires that all volumes and heating value be reported at a standardized pressure of 14.73 psia and 60 °F, even when this standard conflicts with the gas sales contract. Both the gas volume calculation methods (§§ 3175.94 and 3175.103) and the heating value calculation methods (see § 3175.126(a)(2)) require a base pressure of 14.73 psia and 60 °F.
The composition of C
The BLM received one comment suggesting that if an operator has better data for this split, they should be able to use it, and requested an example of how the BLM would implement this. Another comment indicated that the “actual” composition, not the “deemed” composition should be used. The BLM agrees with these comments and added a paragraph to the final rule that would allow operators to use a hexane-heptane-octane split that is derived from an extended analysis taken under § 3175.119(c). In this scenario, operators would take periodic extended analyses when the composition of C
One commenter requested the reference for using the 60-30-10 split. The BLM did not make any changes to the rule based on this comment. The reference for this split was given in the preamble to the proposed rule (see 80 FR 61678).
Section 3175.126(b) describes the way in which gas volume must be reported by operators for royalty purposes. Section 3175.126(b)(1) prohibits 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 would have considered allowing a volume adjustment for water vapor if sufficient data were submitted during the public comment period to support an adjustment, as discussed above. No data were submitted, however.
Section 3175.126(b)(2) will require the unedited volume on a QTR (EGM systems) or an integration statement (mechanical recorders) to match the volume reported for royalty purposes, unless edits to the data can be justified and documented by the operator. The BLM did not receive any comments on this paragraph.
Proposed § 3175.126(c) would have established new requirements for edits and adjustments to volume or heating value. Section 3175.126(c)(1) would have set requirements as to how operators would adjust volumes and heating values if measuring equipment is out of service or malfunctioning. The BLM received several comments regarding the methodology required for error correction and/or adjustment of volume or heating value on a QTR. One comment indicated the methods were too prescriptive, and a second comment recommended adding wording to § 3175.126(c)(1)(i). The BLM agrees that the required methodology in proposed § 3175.126(c)(1)(i) and (ii) was too prescriptive, and determined that documentation required by § 3175.126(c)(2) and (3) allows adequate determination of the cause of the error and the adjustment methodology utilized to correct volume errors. Therefore, The BLM deleted § 3175.126(c)(1)(i) and (ii).
Section 3175.126(c)(2) requires 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 requires operators to thoroughly justify and document the edits made. This includes QTRs and integration statements. The operator must retain the documentation as required under 43 CFR 3170.7 and submit it to the BLM upon request. The BLM did not receive any comments on this section.
Section 3175.126(c)(3) requires 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 includes QTRs and integration statements. The BLM received one comment stating that the requirement to clearly identify all volumes that have been changed or edited would result in changes to industry accounting systems, and require the development of a new interface with OGOR comment reporting. The BLM did not make any changes as a result of this comment. The BLM does not intend to require “comments” on OGORs due to changes or edits to volumes and heating value. The intent of the requirement is to have the operator, purchaser, or transporter document changes, edits and provide justification. The operator must then maintain this documentation and make it available to the BLM upon request.
Section 3175.126(c)(4) requires OGORs submitted to ONRR to be amended when inaccuracies are discovered at an FMP. The BLM did not receive any comments on this paragraph, and made no changes in the final rule.
Section 3175.130 establishes a testing protocol for differential-pressure, static-pressure, and temperature transducers used in conjunction with differential-flow meters at FMPs. This section was added to implement the requirements in § 3175.31(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 the 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 (e.g., an orifice plate). Therefore, the uncertainty of these variables is dependent on the uncertainty of the transducer's ability to convert the physical parameters measured into a digital value that the flow computer can use to calculate flow rate and, ultimately, volume.
Currently, methods used to determine uncertainty (i.e., the BLM Uncertainty Calculator) rely on performance specifications published by the transducer manufacturers. However, the methods that manufacturers use to determine and report these performance specifications are typically proprietary, performed in-house, and the BLM cannot verify them. In addition, the BLM believes that there is little consistency among manufacturers regarding the standards and methods used to establish and report performance specifications.
The testing procedures in §§ 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. Based on numerous comments received under § 3175.43, the BLM will mandate this protocol only for new transducers that are not used at FMPs by the effective date of this rule (see the discussion under § 3175.43).
Numerous comments suggested that the BLM eliminate this requirement and use existing American National Standards Institute (ANSI), International Society of Automation (ISA), National Fire Protection Association (NFPA), GPA, AGA, and API standards instead. The BLM did not make any changes to the rule based on these comments because the BLM is not aware of any standards for testing transducers specific to oil and gas operations.
One commenter asked if the BLM was intending to incorporate the draft API standards 22.4 (transducer testing protocol) and 22.5 (flow-computer software testing protocol) into the final rule. The BLM would have considered incorporating the draft API standards into the rule if they had been published in time. As an alternative, the BLM may seek to amend the regulations once the new API standards are published. The BLM participated in the working groups for both of the draft API standards and believes that, in general, the provisions of the draft standards would be beneficial in accomplishing the goals of a testing protocol. No changes to the proposed rule were made as a result of this comment.A17NO0.
Several comments stated that testing should be the responsibility of the manufacturer, not the operator, and that the BLM should use performance standards rather than require testing of components. See the response to these comments under § 3175.43.
One commenter suggested that the BLM only require testing of those transducers commonly used in the field. The BLM is only requiring testing of transducers that manufacturers or operators want to use on Federal and Indian leases. Therefore, if a manufacturer or operator wants to use a particular transducer, they must have it tested in accordance with this rule. The fact that the transducer is commonly or not commonly used has no bearing on the BLM's acceptance of transducers. The BLM did not make any changes to the rule in response to this comment.
Section 3175.131(a) establishes standards for test facilities qualified to perform the transducer-testing protocol. Proposed § 3175.130(a)(1) would have required 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) was based on IEC Standard 1298-1, section 7.1.
One comment expressed concerns that limiting the standards body to NIST would prevent the use of international labs. The BLM agrees with these comments and added a definition of qualified test facility that refers to NIST or an equivalent international standard.
Numerous comments suggested that the BLM allow in-house testing of transducers because sending transducers to an independent facility would be burdensome and cost prohibitive. In addition, the comments stated, there are very few independent facilities that could perform this testing and they would be overwhelmed by manufacturers trying to comply with this requirement, making it difficult to get the testing done in a timely manner. Some of the commenters suggested that the BLM should allow in-house facilities if they are certified by a national or international standards body such as NIST or ISO. The BLM agrees that transducer testing is specialized and there may not be many independent laboratories capable of performing these tests. Therefore, in the final rule, the BLM does not require this testing to be performed by an independent lab as long as it meets the definition of a “qualified test facility.”
In general, the testing requirements in § 3175.131(c) through (h) 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 requiring (in § 3175.131(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 requested comments on whether the testing of five transducers is a statistically representative sample. The BLM received no comments on paragraphs (c) through (h) of this section.
Section 3175.131(b) requires 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.
One commenter asked if an existing transmitter would have to be replaced if the model was not type tested. First, the requirement to type test transducers does not apply to very-low-volume or low-volume FMPs. Second, under the final rule, existing transducers at high- and very-high-volume FMPs would not have to be replaced as long as the operator or manufacturer submitted the test data the manufacturer used to derive their published performance specifications. The BLM did not make any changes to the rule as a result of these comments.
Two commenters expressed a concern that testing each model number could extend to tens of thousands of variations of transducers. The BLM agrees that there could be confusion over how many combinations of models need to be tested under this section and added language to § 3175.131(b) to clarify what constitutes a “model” (§ 3175.131(b)(3)) and how the testing applies to multi-variable transducers (§ 3175.131(b)(4)). The BLM is only concerned with testing aspects of a transducer that affect its performance. For example, one manufacturer makes the following models of a multi-variable transducer:
Test equipment requirements for field calibrations are listed under § 3175.102(c). One commenter stated that the BLM should not require test equipment used to calibrate transducers in the field to meet the accuracy requirement in § 3175.131(d), which requires the test equipment to be four times more accurate than the equipment being tested. The test equipment accuracy requirements in § 3175.131(d) are specific to transducer type testing. The BLM did not make any changes to the rule in response to this comment.
Sections 3175.132 and 3175.133 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. The testing described in the proposed rule would have required a long-term stability test that would have cycled each transmitter through several influence effects over a period of 24 weeks.
Numerous comments expressed concern about the long-term stability test that would have been required in the proposed rule. The comments stated that this test would cost hundreds of thousands of dollars to perform for each make, model, and range tested, and that there are very few test facilities with the capability to perform this test. The BLM agrees with these comments and removed the requirement for a long term stability test in the final rule. However, removing this requirement raised issues about how the BLM would address long-term stability in the field. To address these issues, the BLM added § 3175.102(c)(3) that requires the operator to replace any transducer if, on two consecutive routine verifications, the as-found values were off by more than the manufacturer's specification for long-term stability, as adjusted for static pressure and ambient temperature. The BLM believes that this requirement will ensure that transducers that exhibit a high degree of drift are identified and replaced.
Section 3175.134 requires documentation of the transducer testing (under §§ 3175.131 through 3175.133 of this subpart) and the submission of the documentation to the PMT. The PMT will use the documentation to determine the uncertainty and influence effects of each make, model, and range of transducer tested. The BLM did not receive any comments on this section.
Section 3175.135 establishes 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 §§ 3175.131 through 3175.134, the PMT will review the results. Once the BLM approves the device, the BLM will 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. The BLM did not receive any comments on this section.
Section 3175.140 provides that the BLM will approve a particular version of flow-computer software for use in a specific make and model of flow computer only if the testing is performed under the testing protocol in §§ 3175.141 through 3175.144, to ensure that calculations meet API standards. Unlike the testing protocol for transducers in § 3175.130, which is used to derive performance specifications, the testing protocol for flow computers includes pass-fail criteria. Testing is only required for those software revisions that affect volume or flow rate calculations, heating value, or the audit trail.
Numerous comments suggested that the BLM eliminate this requirement and use existing ANSI, ISA, NFPA, GPA, AGA, and API standards instead. One commenter asked if the BLM was intending to incorporate the draft API standards 22.4 (transducer testing protocol) and 22.5 (flow-computer software testing protocol) into the final rule. See the response to these comments under § 3175.130. The BLM did not make any changes to the rule in response to these comments.
One commenter stated that flow-computer testing will take 3 years to get approved. The BLM disagrees with this comment and did not make any changes to the rule. Assuming the manufacturers perform the testing in accordance with the requirements of this section and submit all required data to the PMT, the review process should be simple and fast.
One commenter stated that the BLM should use uncertainty performance standards instead of requiring testing under this section. The BLM established uncertainty performance goals in § 3175.30 of the proposed rule (§ 3175.31 in the final rule). However, the BLM does not believe that verifying the calculations done by EGM systems is an uncertainty issue. There is no reason that flow-computer software should not be able to accurately calculate the flow rate, volume, heating values, and other parameters, within a very small tolerance of the true values. If the flow-computer software calculates incorrect values, that miscalculation does not reflect uncertainty but bias, because the error in the EGM's software will systematically generate values that are too low (or too high). The BLM did not make any changes to the rule in response to this comment.
Several comments stated that the BLM should have provided the reference software for review. The BLM did not provide the reference software for review because it has not yet been developed. The BLM intends to work with API in developing reference software that is acceptable to all parties. Because the BLM delayed the implementation of the flow-computer software requirements by 2 years, there will be time to establish reference software. The BLM did not make any changes to the rule in response to this comment.
One commenter stated that there should be a process in place to avoid various companies having to test the same software. All software testing required under this section will be reviewed by the PMT. Once a software version is reviewed by the PMT and approved by the BLM, it will be posted on the BLM website and will be approved for use by anyone. This will avoid the potential for different
One commenter asked if a software version that is run in different flow computers would require separate tests for each flow computer under this section. The answer is yes. Because of the potential for software to run differently on different hardware platforms, the BLM will approve software versions that are specific to a make and model of flow computer on which it was tested. Although no changes to the intent of the final rule were made as a result of this comment, the BLM did add some language to both this section and to § 3175.44 to clarify this intent.
The testing procedures in this section are based, in large part, on a testing protocol in API 21.1, Annex E. Section 3175.141(a) requires that all testing be done by an independent laboratory to avoid any real or perceived conflict of interest in the testing.
Several commenters stated that the BLM should allow in-house testing of flow-computer software under this section. The BLM disagrees with these comments because independent testing prevents any real or perceived conflict of interest between the manufacturer and the testing process and it is in the public interest. The BLM is allowing in-house testing of transducers (§ 3175.131(a)) only because transducer testing requires highly specialized equipment that only manufacturers are likely to have and requiring transducer testing at an independent qualified test facility could create an economic burden and delays. However, flow-computer software testing does not require highly specialized equipment and can readily be done by many testing facilities. Because the commenters did not provide any compelling arguments as to why independent testing of flow-computer software is onerous, the BLM did not make any changes to the rule in response to these comments.
Section 3175.141(b)(1) requires that each make, model, and software version tested must be identical to the software version installed at an FMP. Section 3175.141(b)(2) requires that each software version be given a unique identifier, which must be part of the display (see § 3175.101(b)(4)) and the configuration log (see § 3175.104(b)(2)) to allow the BLM to verify that the software version has been tested under the protocol in this section.
One commenter asked how the BLM would handle software versions that do not require testing under this section. For example, if the manufacturer of an EGM system installs a new version of software that does not need to be tested under this section, the commenter asked how this version of the software would get on the approved software list. Although the details of this process will be resolved within the 2-year implementation timeframe that is part of the final rule (see § 3175.60(a)(4) and (b)(1)(iv)), the BLM added a phrase to § 3175.44(b)(2) that states that the operator or manufacturer must provide the BLM with a list of the software versions that do not require testing, along with a brief description of what changes were made from the previous version. If the PMT agrees, the PMT will confirm that the changes described by the manufacturer do not require testing, and then add the software version to the list of approved software versions.
One commenter asked who would determine whether a version of software needs to be tested under this section. The BLM will have to rely on the manufacturer to make that determination, although the process described in the previous paragraph will allow the PMT to verify that the software version did not need to be tested. The BLM did not make any changes to the rule in response to this comment.
Section 3175.141(c) provides 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. The BLM did not receive any comments on this section.
Section 3175.141(d) establishes a pass-fail criterion for the software testing. The digital values obtained for the testing in §§ 3175.142 and 3175.143 are entered into BLM-approved reference software, and the resulting values of flow rate, volume, integral value, flow time, and averages of the live input variables are compared to the values determined from the software under test. A maximum allowable error of 50 parts per million (0.005 percent) is established in § 3175.141(d)(2). The BLM did not receive any comments on this section.
Section 3175.142(a) sets out six required tests to ensure that the instantaneous flow rate is being properly calculated by the flow computer. The parameters for each of the six tests set out in Tables 1 and 2 to § 3175.142 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. The BLM did not receive any comments on this section.
Section 3175.142(b) tests 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. The BLM did not receive any comments on this section.
Section 3175.142(c) of the final rule requires that additional tests be performed that assess the ability of the event log to capture all required events, and the software's ability to handle inputs to a transducer that are beyond its calibrated span. Proposed § 3175.142(c)(3) would have required testing 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. Based on comments received under § 3175.104(c)(1), the BLM eliminated the need for the event log to retain a record of all power outages that inhibit the meter's ability to collect and store new data. Therefore, the BLM removed the provision in this paragraph that would have required testing of this event-logging feature.
Section 3175.143 establishes required dynamic tests that 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. The BLM did not receive any comments on this section.
After a software version has been tested under §§ 3175.141 through 3175.143, the PMT would review the results and make a recommendation to the BLM. If the BLM determines that the
Section 3175.150 identifies violations that are subject to immediate assessments. The BLM received several comments in response to the proposed immediate assessments in § 3175.150. The commenters stated that the immediate assessments were not necessary and duplicative in that an operator could receive an assessment and, potentially, a civil penalty for the same infraction. The commenters further stated that there was an absence of due process in that these immediate assessments were based on “non-transparent rules” and a BLM internal Inspection and Enforcement Handbook, which has not yet been developed (See discussion of Inspection and Enforcement Handbook in section II.B of this preamble—General Overview of Comments Received). The commenter suggested that the proposed rule required perfection from the operators on items that are performed a thousand times a day. A few commenters suggested breaking the immediate assessment into a major and minor category with a $1,000 assessment for major violations and $250 for minor violations.
As discussed in the preamble to the proposed rule, the immediate assessments provided for in § 3175.150 are promulgated pursuant to the Secretary of the Interior's general rulemaking authority under the MLA (30 U.S.C. 189), as well as her specific authority to stipulate remedies for the breach of lease obligations (30 U.S.C. 188(a)). See 80 FR 61646, 61680 (Oct. 13, 2015).
Some commenters argued that the immediate assessments in § 3175.150 are inconsistent with due process because there is no opportunity for an operator to correct its violations before an assessment is imposed. To the contrary, the use of immediate assessments for breaches of the oil and gas operating regulations is well-established and is consistent with the notice requirements of due process. Operators obligate themselves to fulfill the terms and conditions of the Federal or Indian oil and gas leases under which they operate. These leases incorporate the operating regulations by reference. Thus, the immediate assessments contained in the regulations act as “liquidated damages” owed by operators who have breached their leases by breaching the regulations. See, e.g.,
Several commenters argued that the proposed revision of § 3175.150 exceeded the BLM's statutory authority under FOGRMA insofar as the proposed revision sought to impose immediate assessments on purchasers and transporters. Upon further review and analysis of FOGRMA and other authorities, the BLM has been persuaded to remove the immediate assessments on purchasers and transporters from the final rule.
One commenter stated that operators should be provided with a 1-year phase-in period before they could be assessed for violations. The BLM agrees with this comment, but did not make any changes because the phase-in periods given in § 3175.60 also applies to immediate assessments. The shortest phase-in period is 1 year for high- and very-high-volume FMPs, which is the same phase-in period requested by the commenter.
Some commenters asked that the final rule allow for administrative review of immediate assessments. The BLM always envisioned that immediate assessments would be subject to administrative review pursuant to 43 CFR 3170.8.
The BLM sought comment on whether the immediate assessments in proposed § 3175.150 should be higher or lower and what other factors the BLM should consider in setting these assessments. (See 80 FR 61646, 61680 (Oct. 13, 2015)). The BLM noted that it proposed assessment amounts that approximate the average cost to the agency of identifying and remediating the violations. Some commenters argued that the assessments should be increased to $15,000 per violation per day—a punitive amount that would deter noncompliance. However, as liquidated damages, these assessments should not be punitive; rather, these assessments should be designed to reasonably compensate the BLM for damages associated with the violations. (See 80 FR 61646, 61680 (Oct. 13, 2015), quoting 52 FR 5384, 5387 (Feb. 20, 1987)). Because the BLM is not persuaded that the proposed assessment amounts were inappropriate, the BLM has chosen to retain the proposed assessment amounts in the final rule.
As noted at the beginning of the Section-by-Section discussion of this preamble, this final rule also makes changes to certain provisions of 43 CFR part 3160. Specifically, the final rule makes changes to 43 CFR 3162.7-3, 3163.1, and 3164.1. While some of these changes have already been discussed in connection with other provisions of the final rule to which they relate, each one is also explained below.
1. Consistent with the proposed rule, the final rule revises § 3162.7-3, Measurement of gas, to reflect the fact that the standards governing oil and gas measurement are now found in subpart 3175.
2. Section 3163.1, Remedies for acts of noncompliance, is being revised, consistent with the proposed rule, in several respects. As explained in connection with § 3175.150 of this final rule, the BLM's existing regulations contain provisions authorizing the BLM to impose assessments on operators and operating rights owners for violations of lease terms and conditions 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 the violations. These assessments are not intended to be punitive and are distinct from any civil penalties or other remedies that may be sought in connection with any particular violation.
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) of § 3163.1. As explained in the preamble to the proposed rule and with respect to § 3175.150 of the final rule, there are also currently four specific violations where the BLM's existing rules authorize the imposition of immediate assessments. Through this final rule, the BLM is modifying the approach to assessments in its regulations.
Rather than having certain specific violations be subject to immediate assessments, while major and minor violations are only subject to assessments after notice and an opportunity to cure, this final rule revises § 3163.1 so that all assessments under that section may be imposed immediately, consistent with the purpose of those assessments. As explained in the preamble to the proposed rule, the BLM believes that for these assessments, which represent liquidated damages rather than punitive fines, the notice and opportunity to cure provided for in existing regulations is
In addition to better reflecting the purpose for which these assessments were established, this change will also result in administrative efficiencies. Under the current regulations, the BLM has to first identify a violation; then, if the violation identified is not one of the small number of violations currently subject to an immediate assessment, the BLM has to issue a notice identifying the violation and specifying a corrective period. The BLM then has to follow up and determine whether corrective actions have been taken in response to the notice before an assessment can be imposed. All of these steps cause the BLM to incur additional costs and commit additional inspection resources.
Therefore, the final rule revises 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 revisions to paragraphs (a)(1) and (2) maintain the BLM's discretion to impose such assessments on a case-by-case basis. The revisions are also consistent with § 3175.150 because they increase the immediate assessment for major violations to $1,000, which is appropriate given the types of violations that would be considered major. These changes do not affect § 3163.1(a)(3) through (6).
In addition to revising the approach to assessments, this final rule also revises paragraph (a) to make it apply to “any person.” Under this final rule, the civil assessments under § 3163.1 are no longer limited to operating rights owners and operators. This change enables the BLM 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.
The authority for these immediate assessments was discussed extensively in the preamble to the proposed rule in connection with proposed changes to §§ 3163.1 and 3175.150 and is not restated here. As explained there, the immediate assessments provided for in § 3163.1 are promulgated pursuant to the Secretary's general rulemaking authority under the MLA (30 U.S.C. 189), as well as her specific authority to stipulate remedies for the breach of lease obligations (30 U.S.C. 188(a)). See 80 FR 61646, 61680 (Oct. 13, 2015).
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. Since these assessments are already imposed immediately, paragraph (b)'s approach to these assessments is retained; however, the final rule does make two revisions to paragraph (b).
First, it makes paragraph (b) consistent with the revised paragraph (a) and acknowledges that certain additional immediate assessments are identified in subparts 3173, 3174, and 3175.
Second, paragraph (b) is revised to make the first two assessments found in paragraph (b) flat assessments of $1,000 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. Section 3163.1(b)(3) is unchanged by this final rule.
Since the final rule shifts 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) are no longer necessary. Therefore, the final rule deletes paragraph (c). Similarly, existing paragraph (d), which provides that continued noncompliance subjects the operating rights owner or operator to civil penalties under § 3163.2 of this subpart, is also removed because the BLM determined that it was redundant and unnecessary. 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. As a result of these specific changes, the current paragraph (e) is re-designated as paragraph (c).
As for § 3175.150, some commenters asserted that the immediate assessments identified in the proposed rule were excessive, unnecessary, and duplicative in that an operator could receive an assessment and, potentially, a civil penalty under § 3163.2 for the same infraction. Other commenters express concern that there is an absence of due process in that these immediate assessments would be based on “non-transparent rules” and a BLM Internal Inspection and Enforcement Handbook, which has not yet been developed. The commenter suggested that the proposed rule required perfection from the operators on items that are performed a thousand times a day.
The BLM does not agree with these comments. The use of immediate assessments for breaches of the oil and gas operating regulations is well-established and is consistent with the notice requirements of due process. Operators obligate themselves to fulfill the terms and conditions of the Federal or Indian oil and gas leases under which they operate. These leases incorporate the operating regulations by reference. Thus, the immediate assessments contained in the regulations act as “liquidated damages” owed by operators who have breached their leases by breaching the regulations. See, e.g.,
Another commenter expressed concern about the effect of this change on the BLM's workload and staffing. Still another commenter asked the BLM to provide an economic justification for the shift in approach with respect to immediate assessments and inspection and enforcement more generally. All of these concerns have already been addressed in this preamble in Section II(B)—General Overview of Comments Received.
One commenter asserted that the BLM lacks authority over contractors. The BLM does not agree with this assertion. While the operating rights owner or
Some commenters asked that the final rule allow for administrative review of immediate assessments. The BLM always envisioned that immediate assessments would be subject to administrative review pursuant to 43 CFR 3170.8.
Some commenters argued that the assessments should be increased to $15,000 per violation per day—a punitive amount that would deter noncompliance. However, as explained above, the purpose of these assessments is to approximate the average cost to the BLM of identifying and remediating violations. As liquidated damages, these assessments should not be punitive, but rather, should be designed to reasonably compensate the BLM for damages associated with the violations. (See 80 FR 61646, 61680 (Oct. 13, 2015), quoting 52 FR 5384, 5387 (Feb. 20, 1987)). The BLM did not make any changes in response to these comments.
3. Section 3164.1, Onshore Oil and Gas Orders, the table will be revised to remove the reference to Order 5 because this proposed rule would replace Order 5.
The BLM conducted extensive public and tribal outreach on this rule both prior to its publication as a proposed rule and during the public comment period on the proposed rule. Prior to the publication of the proposed rule, the BLM held both tribal and public forums to discuss potential changes to the rule. In 2011, the BLM held three tribal meetings in Tulsa, Oklahoma (July 11, 2011); Farmington, New Mexico (July 13, 2011); and Billings, Montana (August 24, 2011). On April 24 and 25, 2013, the BLM held a series of public meetings to discuss draft proposed revisions to Orders 3, 4, and 5. The meetings were webcast so tribal members, industry, and the public across the country could participate and ask questions either in person or over the Internet. Following those meetings, the BLM opened a 36-day informal comment period, during which 13 comment letters were submitted. The comments received during that comment period were summarized in the preamble for the proposed rule (80 FR 58952).
The proposed rule was made available for public comment from October 13, 2015 through December 14, 2015. During that period, the BLM held tribal and public meetings on December 1 (Durango, Colorado), December 3 (Oklahoma City, Oklahoma), and December 8 (Dickinson, North Dakota). The BLM also held a tribal webinar on November 19, 2015. In total, the BLM received 106 comment letters on the proposed rule, the substance of which are addressed in the Section-by-Section analysis of this preamble.
As explained in the background section of this preamble, three outside independent entities—the Subcommittee, the OIG, and the GAO—have repeatedly found that the BLM's oil and gas measurement rules do not provide sufficient assurance that operators pay the royalties due. Specifically, these groups found that the BLM needed updated guidance on oil and gas measurement technologies, to address existing technological advances, as well as technologies that might be developed in the future. These groups have all found that the BLM's existing guidance is “unconsolidated, outdated, and sometimes insufficient,” and more specifically with respect to Order 5, that:
• The BLM's gas measurement rules are generally outdate and do not reflect modern measurement technologies or practices;
• There were not sufficient goals/requirements related to gas sampling, BTU sampling and reporting, and orifice plate and meter tube inspections; and
• Some BLM State offices have issued their own guidance, which lacks a national perspective, creating the potential for inconsistent application of requirements.
The final rule addresses these recommendations by specifically recognizing modern industry practices and measurement technologies with respect to each of these, while also updating relevant documentation and recordkeeping requirements in order to ensure that all production is properly accounted for.
E.O. 12866 provides that the Office of Information and Regulatory Affairs (OIRA) in the Office of Management and Budget will review all significant rules. OIRA has determined that this final rule is not significant because it will not have an annual effect on the economy of $100 million or more and does not raise novel legal or policy issues. E.O. 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 E.O. 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 final rule will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601
U.S. Census data show that in 2013, of the 6,460 domestic firms involved in crude petroleum and natural gas extraction, 99 percent (or 6,370) had fewer than 500 employees. This means that all or nearly all U.S. firms involved in crude petroleum and natural gas extraction in 2013 fell within the SBA's size standard of fewer than 1,250 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 will be affected by the
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 changes will increase the regulated community's annual costs by about $12.1 million, or an average of about $3,300 per entity per year. There will also be an estimated $6.2 million, or $1,700 per entity per year, in additional royalty payments from operators to the BLM. However, these are considered transfer payments, and are thus not included in the estimate of the final rule's net economic impact. In addition to annual costs, there will be one-time costs associated with implementing the changes of as much as $23.3 million, or an average of approximately $6,300 per entity affected by the rule. These costs are phased in over a 3-year period, at an average cost of $7.8 million per year or $2,100 per entity per year. When these annualized one-time costs are combined with annual costs, industry's average annual cost is $19.9 million per year (or $5,400 per entity per year) for the first three years following enactment of the final rule, after which it experiences just the annual burden of $12.1 million or $3,300 per entity per year. For further information on these costs estimates, please see the Economic and Threshold Analysis prepared for this final rule.
Recognizing that the SBA definition for a small business for a crude petroleum and natural gas extraction firm is one with fewer than 1,250 employees, which represents a wide range of possible oil and gas producers, the BLM, as part of the 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 lease 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 will 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 provisions will apply to entities regardless of size. However, entities with the greatest activity (e.g., numerous FMPs) will likely experience the greatest increase in compliance costs.
Based on the available information, we conclude that the rule will 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 final rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule will not have an annual effect on the economy of $100 million or more.
This final rule will update and replace the requirements of Order 5 to ensure that gas produced from Federal and Indian oil and gas leases is accurately measured and accounted for. As explained in the Economic and Threshold Analysis, the rule will increase, by about $12.1 million annually ($3,300 per entity), the cost associated with the development and production of gas resources under Federal and Indian oil and gas leases, plus an estimated $6.2 million in increased royalty payments ($1,700 per entity) to the BLM that are considered transfer payments with no net economic impact. There will also be a one-time cost estimated to be $23.3 million, phased in over a 3-year period ($6,300 per entity). For the first 3 years following enactment of the final rule, annual plus annualized one-time cost average $19.9 million per year ($5,400 per entity). After the first 3 years, the estimated burden on industry is just the estimated annual cost of $12.1 million ($3,300 per entity).
This final rule:
• Will not cause a major increase in costs or prices for consumers, individual industries, Federal, State, tribal, or local government agencies, or geographic regions; and
• Will 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 final rule will not “significantly or uniquely” affect small governments. A Small Government Agency Plan is unnecessary.
• This final rule will 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 final rule is not a “significant regulatory action” under the Unfunded Mandates Reform Act. The changes in this final rule will not impose any requirements on any State or local governmental entity.
This rule will not have significant takings implications as defined under E.O. 12630. Therefore, a takings implication assessment is not required. This rule revises 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 rule will not impose requirements or limitations on private property use or require dedications or exactions from owners of private property, and as such, the rule is not a governmental action capable of interfering with constitutionally protected property rights. Therefore, the rule will not cause a taking of private property or require further discussion of takings implications under this E.O.
Under E.O. 13132, the BLM finds that the rule will not have significant Federalism implications. A Federalism assessment is not required. This rule will 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 Departmental Manual 2, the BLM evaluated possible effects of the final rule on federally recognized Indian tribes. The BLM approves proposed
• Tulsa, Oklahoma on July 11, 2011;
• Farmington, New Mexico on July 13, 2011; and
• Billings, Montana on August 24, 2011.
• Tribal workshop and webcast in Washington, D.C. on April 24, 2013.
• The BLM hosted a webinar to discuss the requirements of the proposed rule and solicit feedback from affected tribes on November 19, 2015; and
In-person meetings were held in:
○ Durango Colorado, on December 1, 2015;
○ Oklahoma City, Oklahoma, on December 3, 2015; and
○ Dickinson, North Dakota, on December 8, 2015.
The BLM also met with interested tribes on a one-on-one basis as requested to address questions on the proposed rule prior to the publication of the final rule. In each instance, the purpose of these meetings was to solicit feedback and comments from the tribes. The primary concerns expressed by tribes related to the subordination of tribal laws, rules, and regulations by the proposed rule; tribal representation on the Department's Gas and Oil Measurement Team; and the BLM's Inspection and Enforcement program's ability to enforce the terms of this rule.
In addition, some tribes expressed concern about the cost of performing detailed meter tube inspections, the proposed requirement for the location of the sample probe because it would be contrary to API specification, the requirement to report a dry heating value when water vapor is known to be present, and the cost and benefit of requiring sample cylinders to be sealed after they are cleaned. In general, the tribes, as royalty recipients, expressed support for the goals of the rulemaking, namely accurate measurement. With respect to tribal representation on the Department's Gas and Oil Measurement Team, it should be noted that the team is internal only. That said, the BLM will continue to consult with tribes on measurement issues that impact them and their resources. The BLM did make changes to the rule based on these and other comments received by industry. In response to the concern over the cost of performing detailed meter tube inspections, the BLM eliminated the requirement to perform routine detailed meter-tube inspections; these inspections will now only be triggered by a basic inspection that reveals the need to perform a detailed inspection. In addition, the detailed inspection will only be required on high- and very-high-volume FMPs under the final rule. The final rule also re-defined the thresholds separating low-, high-, and very-high-volume FMPs, which reduced the estimated percentage of high- and very-high-volume FMPs subject to detailed inspections from 22 percent under the proposed rule to 11 percent under the final rule.
In response to concerns expressed over the proposed requirement for the location of the sample probe, the BLM eliminated the proposed requirement and reverted to placing the sample probe as required by API standards. The BLM did not make any changes to the requirement in the proposed rule to report heating value on a dry basis because industry did not submit any data that would justify an alternative. On the contrary, the data that the BLM did receive indicated that the assumption of water vapor saturation as the basis for heating value, suggested by one tribal member, would result in under reporting of heating value. In response to concerns over the costs and benefits of the proposed requirement to seal sample cylinders after cleaning, the BLM determined that it was not a feasible requirement and deleted it in the final rule.
Under E.O. 12988, we have determined that the rule will 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 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 E.O. 13352, the BLM has determined that this rule will not impede facilitating cooperative conservation and takes appropriate account of the interests of persons with ownership or other legally recognized interests in land or other natural resources. The rulemaking process involved Federal, State, local and tribal governments, private for-profit and nonprofit institutions, other nongovernmental entities and individuals in the decision-making via the public comment process for the rule. The process ensured 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. The PRA and OMB regulations (see 5 CFR 1320.3(c) and (k)) provide that collections of information include requests and requirements that an individual, partnership, or corporation obtain information, and report it to a Federal agency.
This final rule contains information collection activities that require approval by the OMB under the Paperwork Reduction Act. The BLM included an information collection request in the proposed rule. OMB has approved the information collection for the final rule under control number 1004-0210.
The information collection activities in the final rule are discussed 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.
Some of these information collection activities are usual and customary because they are required by gas sales contracts and/or industry standards. To the extent they are usual and customary, they are not “burdens” under the PRA (see 5 CFR 1320.3(b)(2)). To the extent these regulations increase the frequency of data gathering beyond what is usual and customary, or require more information than is usual and customary, the incremental burdens are included in the burdens disclosed here.
Where these regulations require operators to maintain records and submit information at the request of the BLM (usually during production audits), the burdens of disclosure to the respondent and to the Federal Government are included in the estimated burdens for “Required Recordkeeping and Records Submission” for 43 CFR 3170.7, a regulation that is part of the rulemaking for site security (RIN 1004-AE15, control no. 1004-0207). The recordkeeping burdens are included among the information collection activities for this rule.
The information collection activities in this rule can be organized in the following categories:
A. Testing of Makes and Models of Gas-Measurement Equipment;
B. Inspection and Verification; and
C. Determining and Reporting Volumes, Heating Value, and Relative Density
Each category is discussed below.
Some provisions in the final rule provide for the listing of approved makes and models of gas-measurement equipment or software at
The PMT reviews the report, and then recommends that use of the device or software be approved, disapproved, or approved with conditions. Approval or approval with conditions by the PMT is a pre-requisite for BLM approval of a device or software that is not included on a list of approved makes and models in the regulations. These information collection activities assist the BLM in ensuring that the equipment and software used in gas measurement are in compliance with the relevant performance standards.
We estimate that a limited number of respondents will choose to seek approval of makes and models of equipment or software, and the frequency of such requests will be limited. For the most part, we anticipate one-time, start-up requests during the first 3 years after the effective date of the rule. We calculated cumulative burden estimates for these activities for the first 3 years after the effective date of the rule. We annualized these burden estimates for inclusion in the total estimated hour burdens of this rule.
Most of these procedures begin when the operator or manufacturer arranges for testing of the equipment or software by a qualified testing facility. Because the qualified testing facility will generally be a contractor, and not employees of a respondent, we estimated non-hour burdens for those procedures. The exception is the procedure for requesting approval of makes and models of transducers that are used before the effective date of this rule. For those makes and models, the final rule allows operators or manufacturers to submit existing test data in lieu of arranging for testing by a qualified testing facility. We estimate no non-hour burdens in those circumstances.
The information collection activities within this category are:
1. Transducers—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.43 and 3175.130);
2. Transducers—Test Data Collection and Submission for Future Makes and Models (43 CFR 3175.43 and 3175.130);
3. Flow-Computer Software—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.44 and 3175.140);
4. Flow-Computer Software—Test Data Collection and Submission for Future Makes and Models (43 CFR 3175.44 and 3175.140);
5. Isolating Flow Conditioners—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.46);
6. Differential Primary Devices Other than Flange-Tapped Orifice Plates—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.47);
7. Linear Measurement Devices—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.48);
8. Linear Measurement Devices—Test Data Collection and Submission for Future Makes and Models (43 CFR 3175.48);
9. Accounting Systems—Test Data Collection and Submission for Existing Makes and Models (43 CFR 3175.49); and
10. Accounting Systems—Test Data Collection and Submission for Future Makes and Models (43 CFR 3175.49).
Inspection and verification activities assist the BLM in ensuring that the equipment used to measure gas is in good working order. The information that is required in each “inspection” depends on what type of equipment must be examined. The information that is required in each “verification” is in accordance with the definition of that term at 43 CFR 3175.10(a): “The amount of error in a differential pressure, static pressure, or temperature transducer or element by comparing the readings of the transducer or element with the
Virtually all gas contracts and industry standards require periodic removal and inspection of equipment that is used to measure and analyze the content of natural gas. To the extent these regulations increase the frequency of inspection beyond what is usual and customary, or require more information than is usual and customary, the incremental burdens are disclosed here. Where these regulations require operators to submit information at the request of the BLM (usually during production audits), the burdens to the respondent and to the Federal Government are included in the estimated burdens for “Required Recordkeeping and Records Submission” for 43 CFR 3170.7, a regulation that is part of the rulemaking for site security (RIN 1004-AE15, control no. 1004-0207).
The information collection activities within this category are:
1. Schedule of Basic Meter Tube Inspection (43 CFR 3175.80(h)(3));
2. Basic Inspection of Meter Tubes—Data Collection and Submission (43 CFR 3175.80(h)(5));
3. Detailed Inspection of Meter Tubes—Data Collection and Submission (43 CFR 3175.80(i) and (j));
4. Request for Extension of Time for a Detailed Meter Tube Inspection (43 CFR 1375.80(i));
5. Redundancy Verification Check for Electronic Gas Measurement Systems (43 CFR 3175.102(e)(2));
6. Notification of Verification (43 CFR 3175.92(e) and 3175.102(f));
7. Sample Cylinder Cleaning—Documentation (43 CFR 3175.113(c)(3));
8. Sample Separator Cleaning—Documentation (43 3175.113(d)(1));
9. Evacuation and Pre-charge for the Helium Pop Method—Documentation (43 CFR 3175.114(a)(2));
10. O-ring and Lubricant Composition for the Floating Piston Method—Documentation (43 CFR 3175.114(a)(3));
11. Schedule for Spot Sampling (43 CFR 3175.113(b));
12. Submission of On-line Gas Chromatograph Specifications (43 CFR 3175.117(c)); and
13. Gas Chromatograph Verification—Documentation (43 CFR 3175.118(d)).
Natural gas consists mainly of methane and also includes varying amounts of other hydrocarbons, nitrogen, and carbon dioxide. These regulations assist in determining what components are in samples of natural gas, and in what percentages. They also assist in determining the volumes of natural gas produced. These measurements are necessary for calculating royalties accurately.
The information collection activities within this category are:
1. Quantity Transaction Record (43 CFR 3175.104(a));
2. Configuration Log (43 CFR 3175.104(b)); and
3. Gas Analysis Report—Entry Into Gas Analysis Reporting and Verification System (43 CFR 3175.120(f)).
The BLM estimates 276,797 responses, 77,950 hours, and $5,030,088 hour burdens annually for industry for the first three years after the rule is enacted and 276,720 responses, 76,340 hours, and $4,926,201 hour burdens annually for industry after that. These estimates include both annual estimates of recurring burdens and one-time burdens for initial implementation of the rule. The one-time burdens are shown as the average of the total burdens divided by three (i.e., spread over the next three years).
The burdens to respondents include time spent for compiling and preparing information. The frequency of response for each of the information collections is “on occasion,” with the exception of 43 CFR 3175.120, which requires submission of gas analysis reports to the BLM within 15 days following due dates for spot samples as specified in § 3175.115:
• Gas spot samples at very-low-volume FMPs are required at least annually;
• Gas samples at low-volume FMPs are required at least every 6 months, and
• Spot samples at high- and very-high-volume FMPs are required at least every 3 months and every month, respectively, unless the BLM determines that more frequent analysis is required under § 3175.115(c).
The following table itemizes the hour burdens.
The BLM prepared an environmental assessment (EA), a Finding of No Significant Impact (FONSI), and a Decision Record (DR) that concludes that the final rule will not constitute a major Federal action significantly affecting the quality of the human environment under Section 102(2)(C) of the National Environmental Policy Act (NEPA), 42 U.S.C. 4332(2)(C). Therefore, a detailed statement under NEPA is not required. Copies of the EA, FONSI, and DR are available for review and on file in the BLM Administrative Record at the address specified in the
As explained in the EA, FONSI, and DR, the final rule will not have a significant effect on the human environment because, for the most part, its requirements involve changes that are of an administrative, technical, or procedural nature that apply to the BLM's and the lessee's or operator's administrative processes. For example, the final rule clarifies the acceptable methods for estimating and documenting reported volumes of gas when metering equipment is malfunctioning or out of service. The final rule also establishes new
A draft of the EA was shared with the public during the public comment period on the proposed rule. As part of that process, the BLM received comments on the EA. Commenters questioned the BLM's level of NEPA documentation, whether or not the BLM had met the “hard look” test of describing the environmental consequences of the proposed action, and the BLM's ability to reach a FONSI based on the level of analysis. One commenter requested a complete NEPA revision with formal scoping of the EA and a meaningful socioeconomic analysis. Many commenters questioned the use of three separate EAs to disclose the impacts of three separate rulemakings, stating CEQ regulations that require connected actions to be evaluated in a single document. These commenters suggested that the BLM should prepare a single EIS to address all three rules.
The BLM did not make any changes in response to these comments. CEQ's NEPA regulations at 40 CFR 1508.18 do identify new or revised agency rules and regulations as an example of a Federal action, but new agency regulations that are procedural or administrative in nature are categorically excluded from NEPA review pursuant to 43 CFR 46.210(i). Nevertheless the BLM chose to complete an EA for the rule, to assess the potential environmental impacts of the few provisions that could result in on-the-ground changes to measurement facilities. As noted in the EA, the BLM concludes that those few provisions will not have a significant impact on the environment.
With respect to whether the three rulemakings to replace BLM's existing Onshore Orders 3, 4, and 5 are connected actions for purposes of NEPA, the BLM does not agree with the commenter's suggestion. While the BLM acknowledges that the rules are related and have been designed to work together, each rule is an independent and freestanding effort; none of the rules automatically triggers other actions that may impact the environment; none of the rules requires for its implementation that other actions be taken previously or simultaneously; and none depends on a larger action for its justification. Thus, the BLM reasonably decided to go forward with three EAs rather than a single overarching EIS.
With respect to economic impacts, the BLM has determined that the economic analysis referred to in this preamble and in the EA prepared for this rule adequately discloses that the rule will increase costs to operator, but that those increased costs will be small compared to the costs of operating an oil and gas well. Therefore, the BLM did not make any changes in response to that comments.
Other commenters stated the BLM did not adequately address potential surface impacts to private land, did not minimize surface impacts, did not address a reasonable range of alternatives, and did not adequately describe the Affected Environment. The BLM did not make any changes in response to these comments. The BLM anticipates that in the majority of cases, operators will use existing surface disturbances to come into compliance with the final rule, such as using existing well pad locations. Use of existing disturbance will minimize new surface construction and surface impacts. Since any new facilities will likely be constructed, relocated, or retrofitted on lease at an existing facility, the likelihood that the regulations will result in new impacts to private surface is low. In the rare instance new pipelines or other facilities prove to be necessary on private surface, BLM authorization for activities on split estate will include site-specific NEPA documentation, with appropriate project-level mitigation and best management practices. In short, surface disturbance on private lands is likely to be minimal, and any attempt to estimate these impacts at this time would be speculative.
Finally, commenters asserted that BLM did not satisfy its obligation under NEPA to analyze alternatives that would meet the bureau's purpose and need and allow for a reasoned choice to be made. As described in the EA, a number of alternatives were considered, but eliminated from detailed study because they did not meet the purpose and need. Discussion of the affected environment should only contain data and analysis commensurate in detail with the importance of the impacts, which are anticipated to be minimal. The EA, FONSI, and DR were updated to address these comments, but the revisions did not change the BLM's overall analysis of the potential environmental impacts of the rule.
This final rule will 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 final rule will strengthen the BLM's accountability requirements for operators under Federal and Indian oil and gas leases. As discussed above, these changes will prescribe specific requirements for production measurement, including sampling, measuring, and analysis protocol; categories of violations; and reporting requirements. The final rule also establishes specific requirements related to the physical makeup of meter components. All of the changes will increase the regulated community's annual costs by about $19.9 million in annual and annualized one-time costs (or $5,400 per entity per year) for the first 3 years after the final rule is enacted, and then $12.1 million, or an average of approximately $3,300 per entity per year after that plus an additional $6.2 million in royalty payments from industry to the BLM that are considered a transfer payment and thus not a net economic impact. Entities with the greatest activity (e.g., numerous FMPs) will incur higher costs. Additional information on these costs estimates can be found in the Economic and Threshold Analysis prepared for this final rule.
We expect that the final rule will 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 rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Information Quality Act (Pub. L. No. 106-554, Appendix C Title IV, Section 515, 114 Stat. 2763A-153).
The principal authors of this rule are Richard Estabrook, Petroleum Engineer, BLM Washington Office; Rodney Brashear, Petroleum Engineer Technician, BLM Tres Rios Field Office; Jim Hutchinson, Assistant Field Manager, BLM Newcastle Field Office; Jeff Jette, Petroleum Engineering Technician, BLM Buffalo Field Office; Clifford Johnson of the BLM Vernal Field Office; Gary Roth, Petroleum Engineering Technician, BLM Buffalo Field Office; and Noell Sturdevant, I&E Coordinator, BLM New Mexico State Office. The team was assisted by
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 is amending 43 CFR parts 3160 and 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 chapter. 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 chapter.
(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 chapter, 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 of the assessment, the State Director will state in the record the reasons for such determination.
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 at an FMP must comply with the standards prescribed in this subpart, except as otherwise approved under § 3170.6 of this part.
(a) Certain material identified in 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. Operators must comply with all incorporated standards and material as they are listed in this section. To enforce any edition other than that specified in this section, the BLM must publish a rule in the
(b) American Gas Association (AGA), 400 North Capitol Street NW., Suite 450, Washington, DC 20001; telephone 202-824-7000.
(1) AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Second Edition, September, 1985 (“AGA Report No. 3 (1985)”), IBR approved for §§ 3175.61(a) and (b), 3175.80(k), and 3175.94(a).
(2) AGA Transmission Measurement Committee Report No. 8, Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases; Second Edition, November 1992 (“AGA Report No. 8”), IBR approved for §§ 3175.103(a) and 3175.120(d).
(c) 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—Natural Gas Fluids Measurement, Section 1, Collecting and Handling of Natural Gas Samples for Custody Transfer; Seventh Edition, May 2016 (“API 14.1”), IBR approved for §§ 3175.112(b) and (c), 3175.113(c), and 3175.114(b).
(2) API MPMS, Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 1, General Equations and Uncertainty Guidelines; Fourth Edition, September 2012; Errata, July 2013 (“API 14.3.1”), IBR approved for § 3175.31(a) and Table 1 to § 3175.80.
(3) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 2, Specification and Installation Requirements; Fifth Edition, March 2016 (“API 14.3.2”), IBR approved for §§ 3175.46(b) and (c), 3175.61(a), 3175.80(c) through (g) and (i) through (l), and Table 1 to § 3175.80.
(4) API MPMS Chapter 14, Section 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids—Concentric, Square-edged Orifice Meters, Part 3, Natural Gas Applications; Fourth Edition, November 2013 (“API 14.3.3”), IBR approved for §§ 3175.94(a) and 3175.103(a).
(5) API MPMS Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric, Square-Edged Orifice Meters, Part 3, Natural Gas Applications, Third Edition, August, 1992 (“API 14.3.3 (1992)”), IBR approved for § 3175.61(b).
(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; Reaffirmed February 2014 (“API 14.5”), IBR approved for §§ 3175.120(c) and 3175.125(a).
(7) API MPMS Chapter 21, Section 1, Flow Measurement Using Electronic Metering Systems—Electronic Gas Measurement; Second Edition, February 2013 (“API 21.1”), IBR approved for Table 1 to § 3175.100, §§ 3175.101(e), 3175.102(a) and (c) through (e), 3175.103(b) and (c), and 3175.104(a) through (d).
(8) API MPMS Chapter 22—Testing Protocol, Section 2, Differential Pressure Flow Measurement Devices; First Edition, August 2005; Reaffirmed August 2012 (“API 22.2”), IBR approved for § 3175.47(b) through (d).
(d) 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”), IBR approved for §§ 3175.113(c) and (d), 3175.114(a), and 3175.117(a).
(2) GPA Standard 2261-13, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography; Revised 2013 (“GPA 2261-13”), IBR approved for § 3175.118(a) and (c).
(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(c).
(4) GPA Standard 2286-14, Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography; Revised 2014 (“GPA 2286-14”), IBR approved for § 3175.118(e).
(e) Pipeline Research Council International (PRCI), 3141 Fairview Park Dr., Suite 525, Falls Church, VA 22042; telephone 703-205-1600.
(1) PRCI Contract-NX-19, Manual for the Determination of Supercompressibility Factors for Natural Gas; December 1962 (“PRCI NX 19”), IBR approved for § 3175.61(b).
(2) [Reserved]
(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)(i) through (iii) (for differential meters).
(4) The uncertainty must be calculated under API 14.3.1, Section 12 (incorporated by reference, see § 3175.30) or other methods approved by the AO.
(b)
(2) For very-high-volume FMPs, the measuring equipment must achieve an annual average heating value uncertainty within ±1 percent.
(3) Unless otherwise approved by the AO, the average annual heating value uncertainty must be determined as follows:
(c)
(d)
The measurement equipment described in §§ 3175.41 through 3175.49 is approved for use at FMPs under the conditions and circumstances stated in those sections, provided it meets or exceeds the minimum standards prescribed in this subpart.
Flange-tapped orifice plates that are constructed, installed, operated, and maintained in accordance with the standards in § 3175.80 are approved for use.
Chart recorders used in conjunction with approved differential-type meters that are installed, operated, and maintained in accordance with the standards in § 3175.90 are approved for use for low-volume and very-low-volume FMPs only, and are not approved for high-volume or very-high-volume FMPs.
(a) A transducer of a specific make, model, and URL is approved for use in conjunction with differential meters for high-volume or very-high-volume FMPs if it meets the following requirements:
(1) It has been type-tested under § 3175.130;
(2) The documentation required in § 3175.134 has been submitted to the PMT; and
(3) It has been approved by the BLM and placed on the list of type-tested equipment maintained at
(b) A transducer of a specific make, model, and URL, in use at an FMP before January 17, 2017, is approved for continued use if:
(1) Data supporting the published performance specification of the transducer are submitted to the PMT in lieu of the documentation required in paragraph (a)(2) of this section; and
(2) It has been approved by the BLM and placed on the list of type-tested equipment maintained at
(c) All transducers are approved for use at very-low- and low-volume FMPs.
(a) A flow computer of a particular make and model, and equipped with a particular software version, is approved for use at high- and very-high-volume FMPs if the flow computer and software version meet the following requirements:
(1) The documentation required in § 3175.144 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, except as provided in paragraph (b) of this section; and
(3) The BLM has approved the flow computer and software version and has placed them on the list of approved equipment maintained at
(b)
(2) Software revisions that do not affect or have the potential to affect the determination of flow rate, determination of volume, determination of heating value, or data and calculations used to verify flow rate, volume, or heating value are not required to be type-tested, however, the operator must provide the BLM with a list of these software versions and a brief description of what changes were made from the previous version. (The software manufacturer may provide such information instead of the operator.)
(c)
GCs that meet the standards in §§ 3175.117 and 3175.118 for determining heating value and relative density are approved for use.
The BLM will list on
(a) All testing required under this section must be performed at a qualified test facility not affiliated with the flow-conditioner manufacturer.
(b) The operator or manufacturer must test the flow conditioner under API 14.3.2, Annex D (incorporated by reference, see § 3175.30) and submit all test data to the BLM.
(c) The PMT will review the test data to ensure that the device meets the requirements of API 14.3.2, Annex D (incorporated by reference, see § 3175.30) and make a recommendation
(d) If approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at
A make, model, and size of differential primary device listed at
(a) All testing required under this section must be performed at a qualified test facility not affiliated with the primary device manufacturer.
(b) The primary device must be tested under API 22.2 (incorporated by reference, see § 3175.30).
(c) The operator must submit to the BLM all test data required under API 22.2 (incorporated by reference, see § 3175.30). (The manufacturer of the primary device may submit such information instead of the operator.)
(d) The PMT will review the test data to ensure that the primary device meets the requirements of API 22.2 (incorporated by reference, see § 3175.30) and § 3175.31(c) and (d) 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.
(e) If the primary device is approved by the BLM, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at
A make, model, and size of linear measurement device listed at
(a) The linear measurement device must be tested at a qualified test facility not affiliated with the linear-measurement-device manufacturer;
(b) The operator or manufacturer must submit to the BLM all test data required by the PMT;
(c) The PMT will review the test data to ensure that the linear measurement device meets the requirements of § 3175.31(c) and (d) 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; and
(d) If the linear measurement device is approved, the BLM will add the approved make and model, and any applicable conditions of use, to the list maintained at
An accounting system with a name and version listed at
(a) For daily QTRs (see § 3175.104(a)), an operator or vendor must submit daily QTRs to the BLM both from the accounting system and directly from the flow computer for at least 6 consecutive monthly reporting periods;
(b) For hourly QTRs (see § 3175.104(a)), an operator must submit hourly QTRs to the BLM both from the accounting system and directly from the flow computer for at least 15 consecutive daily reporting periods. (A vendor may submit such information on behalf of an operator);
(c) For configuration logs (see § 3175.104(b)), an operator must submit at least 10 configuration logs to the BLM taken at random times covering a span of at least 6 months both from the accounting system and directly from the flow computer. (A vendor may submit such information on behalf of an operator);
(d) For event logs (see § 3175.104(c)), an operator must submit an event log to the BLM containing at least 50 events both from the accounting system and directly from the flow computer. (A vendor may submit such information on behalf of an operator);
(e) For alarm logs (see § 3175.104(d)), an operator must submit an alarm log to the BLM containing at least 50 alarm conditions both from the accounting system and directly from the flow computer (a vendor may submit such information on behalf of an operator);
(f) The BLM may require additional tests and records that may be necessary to determine that the software meets the requirements of § 3175.104(a);
(g) The records retrieved directly from the flow computer in paragraphs (a) through (d) of this section must be unedited;
(h) The records retrieved from the accounting system in paragraphs (a) through (d) must include both edited and unedited versions; and
(i) The BLM will approve the accounting system name and version for use with the make and model of flow computer used for comparison, and add the system name and version to the list of approved systems maintained at
(1) The BLM compares the records retrieved directly from the flow computer with the unedited records from the accounting system and there are no significant discrepancies; and
(2) The BLM compares the records retrieved directly from the flow computer with the edited records from the accounting system and all changes are clearly indicated, the reason for each change is indicated or is available upon request, and the edited version is clearly distinguishable from the unedited version.
(a)
(2) The gas analysis reporting requirements of § 3175.120(e) and (f) will begin on January 17, 2019.
(3) High- and very-high-volume FMPs must comply with the sampling frequency requirements of § 3175.115(b) starting on January 17, 2019. Between January 17, 2017 and January 17, 2019, the initial sampling frequencies required at high- and very-high-volume FMPs are those listed in Table 1 to § 3175.110.
(4) Equipment approvals required in §§ 3175.43, 3175.44, and 3175.46 through 3175.49 will be required after January 17, 2019.
(b)
(2) High- and very-high-volume FMPs must comply with:
(i) All of the requirements of this subpart except as specified in paragraphs (b)(2)(ii) and (iii) of this section by January 17, 2018;
(ii) The gas analysis reporting requirements of § 3175.120(e) and (f) starting on January 17, 2019; and
(iii) Equipment approvals required in §§ 3175.43, 3175.44, and 3175.46 through 3175.49 starting on January 17, 2019.
(3) Low-volume FMPs must comply with all of the requirements of this subpart by January 17, 2019.
(4) Very-low-volume FMPs must comply with all of the requirements of this subpart by January 17, 2020.
(c) During the phase-in timeframes in paragraph (b) of this section, measuring procedures and equipment in place before January 17, 2017 must comply with the requirements in place prior to the issuance of this rule, including Onshore Oil and Gas Order No. 5, Measurement of Gas, and applicable NTLs, COAs, and written orders.
(d) Onshore Oil and Gas Order No. 5, Measurement of Gas, statewide NTLs, variance approvals, and written orders that establish requirements or standards related to gas measurement and that are in effect on January 17, 2017 are rescinded as of:
(1) January 17, 2018 for high-volume and very-high-volume FMPs;
(2) January 17, 2019 for low-volume FMPs; and
(3) January 17, 2020 for very-low-volume FMPs.
(a)
(1) Orifice plate eccentricity must comply with AGA Report No. 3 (1985), Section 4.2.4 (incorporated by reference, see § 3175.30).
(2)
(3)
(ii) If the upstream meter tube contains a 19-tube bundle flow straightener or isolating flow conditioner, the installation must comply with § 3175.80(g);
(b)
(2) EGM software installed at low-volume FMPs before January 17, 2017 is exempt from the requirements at § 3175.103(a)(1)(i) if the differential-pressure to static-pressure ratio, based on the monthly average differential pressure and static pressure, is less than the value of “
(a)
(b)
Except as stated in this section, as prescribed in Table 1 to this section, or grandfathered under § 3175.61, the standards and requirements in this section apply to all flange-tapped orifice plates (Note: 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.).
(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, or from existing wells that have been re-fractured (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, Section 4 (incorporated by reference, see § 3175.30), the operator must replace the orifice plate. When the inspection shows that the orifice plate complies with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30), 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 to this section. The operator must replace orifice plates that do not comply with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30), 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) for mechanical recorders, or § 3175.102(e) for EGM systems). 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 part;
(2) Plate orientation (bevel upstream or downstream);
(3) Measured orifice bore diameter;
(4) Plate condition (compliance with API 14.3.2, Section 4 (incorporated by reference, see § 3175.30));
(5) The presence of oil, grease, paraffin, scale, or other contaminants 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, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30).
(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) or 19-tube-bundle flow straighteners constructed in compliance with API 14.3.2, Subsections 5.5.2 through 5.5.4, and located in compliance with API 14.3.2, Subsection 6.3 (incorporated by reference, see § 3175.30).
(h)
(1) Perform a basic inspection of meter tubes within the timeframe (in years) specified in Table 1 to this section;
(2) Conduct a basic inspection that is able to identify obstructions, pitting, and buildup of foreign substances (e.g., grease and scale);
(3) Notify the AO at least 72 hours in advance of performing a basic inspection or submit a monthly or quarterly schedule of basic inspections to the AO in advance;
(4) Conduct additional inspections, as the AO may require, if warranted by conditions, such as corrosive or erosive-flow (e.g., high H
(5) Maintain documentation of the findings from the basic meter tube inspection including:
(i) The information required in § 3170.7(g) of this part;
(ii) The time and date of inspection;
(iii) The type of equipment used to make the inspection; and
(iv) A description of findings, including location and severity of pitting, obstructions, and buildup of foreign substances; and
(6) Complete the first inspection after January 17, 2017 within the timeframes (in years) given in Table 1 to this section.
(i)
(i) For low-volume FMPs, clean the meter tube of obstructions and foreign substances;
(ii) For high- and very-high-volume FMPs, physically measure and inspect the meter tube to determine if the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 and API 14.3.2, Subsection 6.2 (incorporated by reference, see § 3175.30), or the requirements under § 3175.61(a), if the meter tube is grandfathered under § 3175.61(a). If the meter tube does not comply with the applicable standards, the operator must repair the meter tube to bring the meter tube into compliance with these standards or replace the meter tube with one that meets these standards; or
(iii) Submit a request to the AO for an extension of the 30-day timeframe, justifying the need for the extension.
(2) For all high- and very-high volume FMPs installed after January 17, 2017, the operator must perform a detailed inspection under paragraph (i)(1)(ii) of this section before operation of the meter. The operator may submit documentation showing that the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30) in lieu of performing a detailed inspection.
(3) The operator must notify the AO at least 24 hours before performing a detailed inspection.
(j) The operator must retain documentation of all detailed meter tube inspections, demonstrating that the meter tube complies with API 14.3.2, Subsections 5.1 through 5.4 (incorporated by reference, see § 3175.30), and showing all required measurements. The operator must provide such documentation to the BLM upon request for every meter-tube inspection. Documentation must also include the information required in § 3170.7(g) of this part.
(k)
(2) For Beta ratios of less than 0.5, the location of 19-tube bundle flow straighteners installed in compliance with AGA Report No. 3 (1985), Section 4.4 (incorporated by reference, see § 3175.30), also complies with the location of 19-tube bundle flow straighteners as required in paragraph (k)(1) of this section.
(3) If the diameter ratio (β) falls between the values in Tables 7, 8a, or 8b of API 14.3.2, Subsection 6.3 (incorporated by reference, see § 3175.30), the length identified for the larger diameter ratio in the appropriate Table is the minimum requirement for meter-tube length and determines the location of the end of the 19-tube-bundle flow straightener closest to the orifice plate. For example, if the calculated diameter ratio is 0.41, use the table entry for a 0.50 diameter ratio.
(l)
(2) Thermometer wells must be located in such a way that they can sense the same flowing gas temperature that exists at the orifice plate. The operator may accomplish this by physically locating the thermometer well(s) in the same ambient temperature conditions as the primary device (such as in a heated meter house) or by installing insulation and/or heat tracing along the entire meter run. If the operator chooses to use insulation to comply with this requirement, the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the thermometer well in relation to the orifice plate (i.e., inside or outside of a meter house).
(3) Where multiple thermometer wells have been installed in a meter tube, the flowing temperature must be measured from the thermometer well closest to the primary device.
(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).
(a) The operator may use a mechanical recorder as a secondary device only on very-low-volume and low-volume FMPs.
(b) Table 1 to this section lists the standards that the operator must follow to install, operate, 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 a nominal diameter of not less than 3/8 inch, including ports and valves;
(2) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length with no visible sag;
(3) Be the same internal diameter along their entire length;
(4) Not include tees, except for the static-pressure line;
(5) Not be connected to more than one differential-pressure bellows and static-pressure element, or to any other device; and
(6) Be no longer than 6 feet.
(b) The differential-pressure pen must record at a minimum reading of 10 percent of the differential-pressure-bellows range for the majority of the flowing period. This requirement does not apply to inverted charts.
(c) The flowing temperature of the gas must be continuously recorded and used in the volume calculations under § 3175.94(a)(1).
(d) 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) Differential-pressure-bellows range;
(2) Static-pressure-element range;
(3) Temperature-element range;
(4) Relative density (specific gravity) of the gas;
(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 meter 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 operator must adjust the time lag between the differential- and static-pressure pens, 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 able to duplicate the test chart's time arc over the full range of the test chart, and must be adjusted, if necessary.
(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 Table 1 to this section, the operator must replace and verify the element for which 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 appendix A to this subpart; and
(ii) The pen must be offset prior to obtaining the as-left verification values required in paragraph (a)(4) of this section.
(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 readings listed in paragraph (a)(4) of this section, 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 paragraph (c)(3) or (4) of this section are not within the tolerances shown in Table 1 to this section, when compared to the values applied by the test equipment.
(6) The operator must adjust the time lag between the differential- and static-pressure pens, 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
(10) If the static-pressure pen is offset for atmospheric pressure:
(i) The atmospheric pressure must be calculated under appendix A to 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 part, 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) if the orifice plate is pulled and inspected;
(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)
(2) For routine verifications, the operator must notify the AO at least 72 hours before conducting the verification or submit a monthly or quarterly verification schedule to the AO in advance.
(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 percent or 2 Mcf/day, whichever is greater, 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. For example: Meter verification determined that the meter was reading 4 Mcf/day high at the normal operating points. The average flow rate measured by the meter is 90 Mcf/day. There is no indication of when the inaccuracy occurred. The date of the current verification was December 15, 2015. The previous verification was conducted on June 15, 2015. The royalty volumes reported on OGOR B that were based on this meter must be corrected for the 4 Mcf/day error back to September 15, 2015.
(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 part;
(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 (e.g., C
(b) Atmospheric pressure used to convert static pressure in psig to static pressure in psia must be determined under appendix A to this subpart.
Except as stated in this section, as prescribed in Table 1 to this section, or grandfathered under § 3175.61, the standards and requirements in this section apply to all EGM systems used at FMPs (Note: The following table lists the standards in this subpart and the API standards that the operator must follow to install and maintain EGM systems. 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 a nominal diameter of not less than
(2) Be sloped upwards from the pressure taps at a minimum pitch of 1 inch per foot of length with no visible sag;
(3) Have the same internal diameter along their entire length;
(4) Not include tees except for the static-pressure line;
(5) 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
(6) 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 software version and previous-day's volume, as well as the following variables consecutively:
(i) Current flowing static pressure with units (psia or psig);
(ii) Current differential pressure (inches of water);
(iii) Current flowing temperature (°F); and
(iv) Current flow rate (Mcf/day or scf/day); and
(5) Either display or post on site and accessible to the AO an hourly or daily QTR (see § 3175.104(a)) no more than 31 days old showing the following information:
(i) Previous-period (for this section, previous period means at least 1 day prior, but no longer than 1 month prior) average differential pressure (inches of water);
(ii) Previous-period average static pressure with units (psia or psig); and
(iii) Previous-period average flowing temperature (°F).
(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) The unique meter ID number;
(2) Relative density (specific gravity);
(3) Elevation of the FMP;
(4) Primary device information, such as orifice bore diameter (inches) or Beta or area ratio and discharge coefficient, as applicable;
(5) Meter-tube mean inside diameter;
(6) Make, model, and location of approved isolating flow conditioners, if used;
(7) Location of the downstream end of 19-tube-bundle flow straighteners, if used;
(8) For self-contained EGM systems, make and model number of the system;
(9) For component-type EGM systems, make and model number of each transducer and the flow computer;
(10) URL and upper calibrated limit for each transducer;
(11) Location of the static-pressure tap (upstream or downstream);
(12) Last primary-device inspection date; and
(13) 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. The BLM may approve the differential pressure to exceed the upper calibrated limit of the differential-pressure transducer for brief periods in plunger lift operations; however, the differential pressure may not exceed the URL.
(e) The flowing temperature of the gas must be continuously measured and used in the flow-rate calculations under API 21.1, Section 4 (incorporated by reference, see § 3175.30).
(a)
(2) The operator must verify the points listed in API 21.1, Subsection 7.3.3 (incorporated by reference, see § 3175.30), 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, Subsection 8.2.2.2, Equation 24 (incorporated by reference, see § 3175.30), then that transducer must be replaced and the new transducer must be tested 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 A to this subpart, measured by a NIST-certified barometer with a stated accuracy of ±0.05 psi or better, or obtained from an absolute-pressure calibration device.
(4) Before putting a meter into service, the differential-pressure transducer must be tested at zero with full working pressure applied to both sides of the transducer. If the absolute value of the transducer reading is greater than the reference accuracy of the transducer, expressed in inches of water column, the transducer must be re-zeroed.
(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).
(2) An as-found verification for differential pressure, static pressure and temperature must be conducted at the normal operating point of each transducer.
(i) The normal operating point is the mean value taken over a previous time period not less than 1 day or greater than 1 month. Acceptable mean values include means weighted based on flow time and flow rate.
(ii) For differential and static-pressure transducers, the pressure applied to the transducer for this verification must be within five percentage points of the normal operating point. For example, if the normal operating point for differential pressure is 17 percent of the upper calibrated limit, the normal point verification pressure must be between 12 percent and 22 percent of the upper calibrated limit.
(iii) For the temperature transducer, the water bath or test thermometer well must be within 20 °F of the normal operating point for temperature.
(3) If any of the as-found values are in error by more than the manufacturer's specification for stability or drift—as adjusted for static pressure and ambient temperature—on two consecutive
(4) If a 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.
(5) 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 § 3175.30).
(6) The verification tolerance for differential and static pressure is defined by API 21.1, Subsection 8.2.2.2, Equation 24 (incorporated by reference, see § 3175.30). The verification tolerance for temperature is equivalent to the uncertainty of the temperature transmitter or 0.5 °F, whichever is greater.
(7) All required verification points must be within the verification tolerance before returning the meter to service.
(8) Before putting a meter into service, the differential-pressure transducer must be tested at zero with full working pressure applied to both sides of the transducer. If the absolute value of the transducer reading is greater than the reference accuracy of the transducer, expressed in inches of water column, the transducer must be re-zeroed.
(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 averages of differential pressure, static pressure, and temperature readings from the primary transducers with those from the check transducers;
(3)(i) If for any transducer the difference between the averages exceeds the tolerance defined by the following equation:
(ii) The operator must verify both the primary and check transducer under paragraph (c) of this section within the first 5 days of the month following the month in which the redundancy verification was performed. For example, if the redundancy verification for March reveals that the difference in the flow-time linear averages of differential pressure exceeded the verification tolerance, both the primary and check differential-pressure transducers must be verified under paragraph (c) of this section by April 5th.
(e) The operator must retain documentation of each verification for the period required under § 3170.7 of this part, including calibration data for transducers that were replaced, 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 (e.g., clean, sharp edge, or surface 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 § 3175.30);
(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)
(2) For routine verifications, the operator must notify the AO at least 72 hours before conducting the verification or submit a monthly or quarterly verification schedule to the AO in advance.
(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 greater, 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. See the example in § 3175.92(f).
(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) The equipment must have a stated accuracy of at least 0.10 percent of the
(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, Section 4 and API 14.3.3, Section 5 (incorporated by reference, see § 3175.30); and
(ii) AGA Report No. 8 (incorporated by reference, see § 3175.30), for supercompressibility.
(2) For primary devices other than flange-tapped orifice plates, for which there are no industry standards, 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, Subsection 8.3.3 (incorporated by reference, see § 3175.30).
(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 must be determined under API 21.1, Section 4 and API 21.1, Annex B (incorporated by reference, see § 3175.30).
(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, Subsection 5.2 (incorporated by reference, see § 3175.30), with the following additions and clarifications:
(1) The information required in § 3170.7(g) of this part;
(2) The volume, flow time, and integral value or average extension must be reported to at least 5 decimal places. The average differential pressure, static pressure, and temperature as calculated in § 3175.103(c), must be reported to at least three decimal places; 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, Subsection 5.4 (including the flow-computer snapshot report in API 21.1, Subsection 5.4.2), and API 21.1, Annex G (incorporated by reference, see § 3175.30), 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, Subsection 5.3 (incorporated by reference, see § 3175.30);
(3) For very-low-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, Subsection 5.5 (incorporated by reference, see § 3175.30), with the following additions and clarifications: 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, Subsection 5.6 (incorporated by reference, see § 3175.30).
(e) Records may only be submitted from accounting system names and versions and flow computer makes and models that have been approved by the BLM (see § 3175.49).
Except as stated in this section or as prescribed in Table 1 to this section, the standards and requirements in this section apply to all gas sampling and analyses. (Note: The following table lists the standards in this subpart and the API standards that the operator must follow to take a gas sample, analyze the gas sample, and report the findings of the gas analysis. 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 through 3175.115;
(2) Flow-proportional composite sampling under § 3175.116; or
(3) On-line gas chromatograph under § 3175.117.
(b) At all times during the sampling process, the minimum temperature of all gas sampling components must be the lesser of:
(1) The flowing temperature of the gas measured at the time of sampling; or
(2) 30° F above the calculated hydrocarbon dew point of the gas.
(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 temperature as the primary device. The operator may accomplish this by physically locating the sample probe in the same ambient temperature conditions as the primary device (such as in a heated meter house) or by installing insulation and/or heat tracing along the entire meter run. If the operator chooses to use insulation to comply with this requirement, the AO may prescribe the quality of the insulation based on site specific factors such as ambient temperature, flowing temperature of the gas, composition of the gas, and location of the sample probe in relation to the orifice plate (i.e., inside or outside of a 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 the shorter of:
(i) The length necessary to place the collection end of the probe in the center one third of the pipe cross-section; or
(ii) The recommended length of the probe in Table 1 in API 14.1, Subsection 6.4 (incorporated by reference, see § 3175.30).
(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 15 days after flow is re-initiated. Documentation of the non-flowing status of the FMP must be entered into GARVS as required under § 3175.120(f).
(b) The operator must notify the AO at least 72 hours before obtaining a spot sample as required by this subpart, or submit a monthly or quarterly schedule of spot samples to the AO in advance of taking samples.
(c)
(1) Comply with API 14.1, Subsection 9.1 (incorporated by reference, see § 3175.30);
(2) Have a minimum capacity of 300 cubic centimeters; and
(3) Be cleaned before sampling under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.30), or an equivalent method. The operator must maintain documentation of cleaning (see § 3170.7), have the documentation available on site during sampling, and provide it to the BLM upon request.
(d)
(i) Be constructed of stainless steel;
(ii) Be cleaned under GPA 2166-05, Appendix A (incorporated by reference, see § 3175.30), or an equivalent method, prior to sampling. The operator must maintain documentation of cleaning (see § 3170.7), have the documentation available on site during sampling, and provide it to the BLM upon request; and
(iii) Be operated under GPA 2166-05, Appendix B.3 (incorporated by reference, see § 3175.30).
(2) The sample port and inlet to the sample line must be purged using the gas being sampled before completing the connection between them.
(3) The portable GC must be operated, verified, and calibrated under § 3175.118.
(4) The documentation of verification or calibration required in § 3175.118(d) must be available for inspection by the BLM at the time of sampling.
(5)
(ii) For high-volume FMPs, samples must be taken and analyzed until the difference between the maximum heating value and minimum heating value calculated from three consecutive analyses is less than or equal to 16 Btu/scf;
(iii) For very-high-volume FMPs, samples must be taken and analyzed until the difference between the maximum heating value and minimum heating value calculated from three consecutive analyses is less than or equal to 8 Btu/scf.
(6) The heating value and relative density used for OGOR reporting must be:
(i) The mean heating value and relative density calculated from the three analyses required in paragraph (d)(5) of this section;
(ii) The median heating value and relative density calculated from the three analyses required in paragraph (d)(5) of this section; or
(iii) Any other method approved by the BLM.
(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, Subsection 11.10 (incorporated by reference, see
(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 1 to § 3175.110.
(b) After the time frames listed in paragraph (b)(1) of this section, 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 1 in § 3175.110 is not sufficient to achieve the heating value uncertainty levels required in § 3175.31(b).
(1)
(ii) For very-high-volume FMPs, the BLM may change the sampling frequency or require compliance with paragraph (b)(5) of this section no sooner than 1 year after the FMP begins measuring gas or January 17, 2020, whichever is later.
(2) The BLM will calculate the new sampling frequency needed to achieve the heating value uncertainty levels required in § 3175.31(b). The BLM will base the sampling frequency calculation on the heating value variability. The BLM will notify the operator of the new sampling frequency.
(3) The new sampling frequency will remain in effect until the heating value variability justifies a different frequency.
(4) The new sampling frequency will not be more frequent than once every 2 weeks nor less frequent than once every 6 months.
(5) For very-high-volume FMPs, the BLM may require the installation of a composite sampling system or on-line GC if the heating value uncertainty levels in § 3175.31(b) cannot be achieved through spot sampling. Composite sampling systems or on-line gas chromatographs that are installed and operated in accordance with this section comply with the uncertainty requirement of § 3175.31(b)(2).
(c) The time between any two samples must not exceed the timeframes shown in Table 1 to this section.
(d) If a composite sampling system or an on-line GC is installed under § 3175.116 or § 3175.117, either on the operator's own initiative or in response to a BLM order for a very-high-volume FMP under paragraph (b)(5) 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) of this section.
(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.
(a) On-line GCs must be installed, operated, and maintained under GPA 2166-05, Appendix D (incorporated by reference, see § 3175.30), and the manufacturer's specifications, instructions, and recommendations.
(b) The GC must comply with the verification and calibration requirements of § 3175.118. The results of all verifications must be submitted to the AO upon request.
(c) Upon request, the operator must submit to the AO the manufacturer's specifications and installation and operational recommendations.
(a) All GCs must be installed, operated, and calibrated under GPA 2261-13 (incorporated by reference, see § 3175.30).
(b) Samples must be analyzed until the un-normalized sum of the mole percent of all gases analyzed is between 97 and 103 percent.
(c) A GC may not be used to analyze any sample from an FMP until the verification meets the standards of this paragraph (c).
(1) GCs must be verified under GPA 2261-13, Section 6 (incorporated by reference, see § 3175.30), not less than once every 7 days.
(2) All gases used for verification and calibration must meet the standards of GPA 2198-03, Sections 3 and 4 (incorporated by reference, see § 3175.30).
(3) All new gases used for verification and calibration must be authenticated prior to verification or calibration under the standards of GPA 2198-03, Section 5 (incorporated by reference, see § 3175.30).
(4) The gas used to calibrate a GC must be maintained under Section 6 of GPA 2198-03 (incorporated by reference, see § 3175.30).
(5) If the composition of the gas used for verification as determined by the GC varies from the certified composition of the gas used for verification by more than the reproducibility values listed in GPA 2261-13, Section 10 (incorporated by reference, see § 3175.30), the GC must be calibrated under GPA 2261-13, Section 6 (incorporated by reference, see § 3175.30).
(6) If the GC is calibrated, it must be re-verified under paragraph (c)(5) of this section.
(d) 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. 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 (d)(4) and (5) of this section, expressed in relative percent;
(7) Evidence that the gas used for verification and calibration:
(i) Meets the requirements of paragraph (c)(2) of this section, including a unique identification number of the calibration gas used, the name of the supplier of the calibration gas, and the certified list of the mole percent of each component in the calibration gas;
(ii) Was authenticated under paragraph (c)(3) of this section prior to verification or calibration, including the fidelity plots; and
(iii) Was maintained under paragraph (c)(4) of this section, including the fidelity plot made as part of the calibration run;
(8) The chromatograms generated during the verification process;
(9) The time and date the verification was performed; and
(10) The name and affiliation of the person performing the verification.
(e) Extended analyses must be taken in accordance with GPA 2286-14 (incorporated by reference, see § 3175.30) or other method approved by the BLM.
(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) When the concentration of C
(1) Hexanes;
(2) Heptanes;
(3) Octanes; and
(4) Nonanes +.
(c) In lieu of testing each sample for the components required under paragraph (b) of this section, the operator may periodically test for these components and adjust the assumed C
(1) For high-volume FMPs, once per year; and
(2) For very-high-volume FMPs, once every 6 months.
(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 (i.e., GC, calorimeter, or mass spectrometer);
(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 sampling;
(13) The ambient air temperature at the time of sampling;
(14) Whether or not heat trace or any other method of heating was used;
(15) The type of sample (i.e., spot-cylinder, spot-portable GC, composite);
(16) The sampling method if spot-cylinder (e.g., fill and empty, helium pop);
(17) A list of the components of the gas tested;
(18) The un-normalized mole percents 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 hexane+ split, if applicable;
(23) The pressure base and temperature base;
(24) The relative density; and
(25) 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 § 3175.30).
(d) The base supercompressibility must be calculated under AGA Report No. 8 (incorporated by reference, see § 3175.30).
(e) The operator must submit all gas analysis reports to the BLM within 15 days of the due date for the sample as specified in § 3175.115.
(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 to the electronic-submission requirement 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) Unless otherwise specified on the gas analysis report, the effective date of a composite sample is the first of the month in which the sample was removed.
(d) The provisions of this section apply only to OGORs, QTRs, and gas sample reports generated after January 17, 2017.
(a) The heating value of the gas sampled must be calculated as follows:
(1) Gross heating value is defined by API 14.5, Subsection 3.7 (incorporated by reference, see § 3175.30) and must be calculated under API 14.5, Subsection 7.1 (incorporated by reference, see § 3175.30); and
(2) Real heating value must be calculated by dividing the gross heating value of the gas calculated under paragraph (a)(1) of this section 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).
(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), 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, 30 percent n-heptane, and 10 percent n-octane; or
(ii) The composition determined under § 3175.119(c).
(b) The volume for royalty purposes must be reported on the OGOR in units of Mcf as follows:
(1) The volume 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; 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)
(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.
(a) All testing must be performed by a qualified test facility.
(b)
(2) The serial number of each transducer selected must be documented. The date, location, and batch identifier, if applicable, of manufacture must be ascertainable from the serial number.
(3) For the purpose of this section, the term “model” refers to the base model number on which the BLM determines the transducer performance. For example: A manufacturer makes a transmitter with a model number 1234-XYZ, where “1234” identifies the transmitter cell, “X” identifies the output type, “Y” identifies the mounting type, and “Z” identifies where the static pressure is taken. The testing under this section would only be required on the base model number (“1234”), assuming that “X”, “Y”, or “Z” does not affect the performance of the transmitter.
(4) For multi-variable transducers, each cell URL must be tested only once under this section. For example: A manufacturer of a transducer measuring both differential and static pressure makes a model with available
(c)
(1)
(2)
(3) Alternating current harmonic distortion: Less than 5 percent; and
(4)
(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 (d), 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 (i.e., spanned down), then each test required in §§ 3175.132 and 3175.133 must be carried out at least at both the URL and the minimum upper calibrated limit specified by the manufacturer. For upper calibrated limits between the maximum and the minimum span that are not tested, the BLM will use the greater of the uncertainties measured at the maximum and minimum spans in determining compliance with the requirements of § 3175.31(a).
(g) After initial calibration, no calibration adjustments to the transducer may be made until all required tests in §§ 3175.132 and 3175.133 are completed.
(h) For all of the testing required in §§ 3175.132 and 3175.133, 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 paragraphs (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 be tested at least three times for accuracy under § 3175.131(h). The results of these tests must be used to determine the transducer's reference accuracy under § 3175.135.
(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.
(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).
(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).
(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 vertical plane required in paragraphs (d)(1) and (2) of this section; and
(4) At an angle of +10° from a vertical plane perpendicular to the vertical plane required in paragraphs (d)(1) and (2) of this section.
(e)
(2) After removing the applied pressure, the transducer must be tested for accuracy under § 3175.131(h).
(3) No more than 5 minutes must be allowed between performing the procedures described in paragraphs (e)(1) and (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) Twenty frequency sweeps from 10 Hz to 2,000 Hz to 10 Hz must be applied to the transducer at a rate of 1 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.
(a) Each test required by §§ 3175.131 through 3175.133 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 PMT. If the PMT determines that all testing was completed as required by §§ 3175.131 through 3175.133, it will make a recommendation that the BLM approve the transducer make, model, and range, along with the reference uncertainty, influence effects, and any operating restrictions, and posts them to the BLM's website at
(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)
(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 a specific make and model of flow computer only if the testing performed on the software meets all of the standards and requirements in §§ 3175.141 through 3175.144. 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. Software updates or changes that do not affect these items do not require BLM approval.
(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 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 website 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):
(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); and
(2) Inputs simulating a 15 percent and 150 percent over-range of the differential and static-pressure transducer's calibrated span must be entered to verify that the over-range condition triggers an alarm or an entry in the event 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):
(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):
(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):
(i) Volume;
(ii) Integral value;
(iii) Flow time;
(iv) Average differential pressure;
(v) Average static pressure; and
(vi) Average flowing temperature.
(d)
(2) At the end of the 7-day test period, the accumulated volume must meet the criteria in § 3175.141(d).
(a) The test facility performing the tests must fully document each test required by §§ 3175.141 through 3175.143. 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 by the operator or the manufacturer. If the PMT determines all testing was completed as required by this section, it will make a recommendation that the BLM approve the software version and post it on the BLM's website at
(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:
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